Document
Table of Contents
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, 2017
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from          to          

Commission file number: 001-07964

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12068740&doc=26

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, 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
 
(Do not check if a smaller reporting 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. 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, 2017: $13.8 billion.
Number of shares of Common Stock outstanding as of December 31, 2017: 486,902,907.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders to be held on April 24, 2018, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2017, are incorporated by reference into Part III.



Table of Contents
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.



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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 and natural gas liquids (NGLs) resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
the impact of governmental fiscal regulation, including federal, state, local, and foreign host tax regulations, and/or terms, such as that involving the protection of the environment or marketing of production, as well as other regulations;
our ability to make and integrate acquisitions; 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 is an independent crude oil and natural gas exploration and production company with a diversified high-quality portfolio spanning three continents. Founded in 1932, Noble Energy is a Delaware corporation, incorporated in 1969, and has been publicly traded on the New York Stock Exchange (NYSE) since 1980. We have a unique history of growth, evolving from a regional crude oil and natural gas producer to a global exploration and production company included in the Standard & Poor's 500 (S&P 500).
Our purpose, Energizing the World, Bettering People's Lives®, reflects our commitment to find and deliver affordable energy through crude oil, natural gas and NGL exploration and production while living our commitment to contribute to the betterment of people's lives in the communities in which we operate. We strive to build trust through stakeholder engagement, act on our values, provide a safe work environment, respect our environment and care for our employees and the communities where we operate.
Our portfolio of assets is diversified through US and international projects and production mix among crude oil, natural gas, and NGLs. In particular, our business is focused on both US unconventional basins and certain global offshore conventional basins. In US onshore unconventional basins, we have demonstrated competence in applying geological, drilling, completion, and midstream design and operational expertise. In US onshore, we typically apply a major project development concept to an unconventional basin by utilizing an Integrated Development Plan (IDP) approach. In the global offshore, we have had notable exploration and major project successes over the past twelve years, which have led to production from numerous offshore major development projects which have provided long-lived cash flows to our business.
Approximately 70% of our 2018 capital program is allocated to US onshore development, primarily focused on liquids-rich opportunities in the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including initial development costs associated with the Leviathan project, represent more than 25% of the total. The remaining portion of our 2018 capital program is designated for exploration for lease acquisition, seismic and other

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geological analysis in support of future exploration prospects for potential development post 2020, as well as other corporate activities.
In addition, the majority of our assets are held by production, which allows for further investment and financial flexibility. Occasional strategic acquisitions of producing or non-producing properties, combined with the periodic divestment of assets, have allowed us to pursue our objective of a well-positioned and diversified portfolio to maximize strategic value.
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, natural gas and NGL production, provide continual 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 processing and transportation of our US onshore production. See Midstream - Properties and Activities, below.
The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12068740&doc=23
Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer. Our reportable segments include: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland, Suriname, and other new ventures); and Midstream.
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production, or E&P). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative cost are recorded at the corporate level. See Item 8. Financial Statements and Supplementary Data – Note 14. Segment Information.
Development Activities Our development projects have resulted from both exploration success as well as periodic strategic acquisitions. 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, while on 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

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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 technology and operational efficiencies.
Offshore, we engage in long-cycle development projects, such as progressing the first phase of development at the Leviathan natural gas field, offshore Israel, the largest natural gas discovery in our history. Our development activities are discussed in more detail in the sections below.
Divestiture and Acquisition Activities We maintain an ongoing portfolio management program. Accordingly, we may periodically divest assets through asset or equity sales, exchanges or other transactions. During 2017, we closed several transformative portfolio transactions, demonstrating our continued focus on enhancing profit margins and company returns. We generated cash of $2.1 billion from asset sales, including divestiture of the Marcellus Shale upstream assets, as well as other non-strategic US onshore assets. 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, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) in 2017 and the merger (Rosetta Merger) of Rosetta Resources Inc (Rosetta) in 2015. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources, Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition, and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
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 attractive 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 Gulf of Mexico, the Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major development projects. In 2017, we performed limited exploration activities due to the commodity price environment.
Proved Oil and Gas Reserves  Proved reserves at December 31, 2017 were as follows:
 
 
December 31, 2017
 
 
Proved Reserves
 
 
Crude Oil and
Condensate
 
NGLs
 
Natural Gas
 
Total
Reserves Category
 
(MMBbls)
 
(MMBbls)
 
(Bcf)
 
(MMBoe) (1)
Proved Developed
 
 
 
 
 
 
 
 
United States
 
176

 
119

 
983

 
458

Israel
 
3

 

 
1,793

 
302

Equatorial Guinea

 
29

 
11

 
411

 
108

Total Proved Developed Reserves
 
208

 
130

 
3,187

 
868

Proved Undeveloped
 
 

 
 
 
 

 
 

United States
 
243

 
99

 
838

 
482

Israel
 
6

 

 
3,655

 
615

Total Proved Undeveloped Reserves
 
249

 
99

 
4,493

 
1,097

Total Proved Reserves
 
457

 
229

 
7,680

 
1,965

(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 1,965 MMBoe as of December 31, 2017 as compared with 1,437 MMBoe as of December 31, 2016. Changes included the following:
revisions of 135 MMBoe, including positive revisions of 105 MMBoe driven by performance related to the US onshore horizontal drilling programs and offshore Israel associated with the enhanced geologic modeling across the Tamar reservoir, as well as an increase of 30 MMBoe driven by positive price revisions;
extensions, discoveries and other additions of 736 MMboe, including additions of 551 MMBoe related to the sanction of the first phase of development of the Leviathan natural gas project, as well as extensions of 185 MMBoe related to US onshore horizontal drilling programs due to successful expansion of our extended reach lateral well programs;
acquisition of 57 MMBoe primarily related to the Clayton Williams Energy Acquisition;

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offset by:
production volumes of 139 MMBoe; and
divestiture of reserves of 261 MMBoe, primarily due to the Marcellus Shale upstream divestiture and other smaller US onshore divestitures.
Our proved reserves are 48% US and 52% international, and the commodity mix is 35% global liquids (crude oil and NGLs), 50% international natural gas and 15% US natural gas.
See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for further discussion of proved reserves.
Oil and Gas Exploration and Production - Properties and Activities
United States
We have been engaged in crude oil, natural gas and NGL exploration and development activities throughout US onshore since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 72% of 2017 total consolidated sales volumes and 48% of total proved reserves at December 31, 2017. Approximately 45% of the proved reserves in the US is crude oil and condensate, 32% is natural gas and 23% is NGLs.
Sales volumes and proved reserves estimates for our US operating areas were as follows: 
 
 
Year Ended December 31, 2017
 
December 31, 2017
 
 
Sales Volumes
 
Proved Reserves
 
 
Crude Oil &
Condensate
 
NGLs
 
Natural
Gas
 
Total
 
Crude Oil &
Condensate
 
NGLs
 
Natural
Gas
 
Total
 
 
(MBbl/d)
 
(MBbl/d)
 
(MMcf/d)
 
(MBoe/d)
 
(MMBbls)
 
(MMBbls)
 
(Bcf)
 
(MMBoe)
DJ Basin
 
59

 
19

 
193

 
110

 
203

 
99

 
1,094

 
484

Delaware Basin
 
17

 
4

 
24

 
26

 
166

 
38

 
199

 
238

Eagle Ford Shale
 
11

 
28

 
186

 
70

 
29

 
79

 
501

 
191

Marcellus Shale (1)
 
1

 
5

 
174

 
34

 

 

 

 

Gulf of Mexico
 
21

 
2

 
21

 
26

 
18

 
2

 
21

 
23

Other US Onshore
 
2

 

 
9

 
4

 
3

 

 
6

 
4

Total
 
111

 
58

 
607

 
270

 
419

 
218

 
1,821

 
940

(1) We divested our Marcellus Shale upstream assets in second quarter 2017.
Wells completed in 2017 and productive wells at December 31, 2017 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2017
 
December 31, 2017
 
 
Gross Wells Completed
or Participated in 
 
Gross Productive
Wells
DJ Basin
 
138

 
6,226

Delaware Basin
 
75

 
1,898

Eagle Ford Shale
 
47

 
344

Gulf of Mexico
 

 
14

Other US Onshore
 
12

 
1

Total
 
272

 
8,483



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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. Locations of our US onshore operations as of December 31, 2017 are shown on the map below:
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DJ Basin In 2017, we focused our drilling and development activity in the Wells Ranch and East Pony areas that produce a high oil mix. The IDP concept allows us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 80,000 acres). Our IDP approach has provided an opportunity to efficiently and economically support production growth by leveraging infrastructure, such as gas, oil and water, including both fresh and produced water, assets.
2017 Activity Operationally, our focus on drilling longer laterals and obtaining better results from enhanced completions has led to stronger new well performance. Coupled with expansion of midstream infrastructure and execution of synergies as well as prudent management of costs, we are delivering enhanced profit margin returns. During the year, we completed 103 horizontal wells and 101 wells initiated production. We also participated in approximately 35 non-operated development wells during 2017.
As part of ongoing portfolio management, we entered into an agreement to divest approximately 30,200 net acres, the majority of which were undeveloped, in the Greeley Crescent area of Weld County, Colorado for $608 million. We received proceeds of $568 million at closing and expect to receive the remaining proceeds in mid-2018. As part of the transaction, all of the acreage in the Greeley Crescent Bronco IDP remains subject to dedications to Noble Midstream Partners LP (Noble Midstream Partners) for crude oil gathering, and produced and fresh water services.
Since 2015, we have been working with the State of Colorado to improve emission control systems as required under a joint consent decree (Consent Decree). Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells, the majority of which are vertical, and associated tank batteries. Costs associated with these abandonment activities will be incurred over several years.
We exited 2017 with one drilling rig and intend to increase to two rigs in 2018. Our current 2018 development program contemplates expansion into the Mustang IDP area where we have a large, contiguous acreage position.
Delaware Basin Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams Energy Acquisition on April 24, 2017, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings. We also executed strategic leasing initiatives and entered into a bolt-on acquisition, for $295 million, which closed in January 2017, adding additional production near our producing properties and increasing our

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contiguous acreage position in the Reeves County area. As of December 31, 2017, we held approximately 117,000 net acres in the Delaware Basin.
2017 Activity In 2017, we successfully integrated the Clayton Williams Energy assets and initiated execution of the Delaware Basin IDP with a focus on long laterals, pad drilling, multi-zone completions and infrastructure development. As demonstrated in the DJ Basin, our IDP approach provides an opportunity to more efficiently and economically develop our acreage.
We successfully transformed our 2017 development program's focus from a single well development approach to an IDP to capture the full resource potential for the Delaware Basin. This was achieved with eight pads that developed multiple zones within the Wolfcamp A formation zone, including two pads that successfully included the shallower 3rd Bone Springs zone. With successful wells in the deeper Wolfcamp zones, as well as expanded understanding of the resource potential and our IDP approach, we are well positioned to efficiently and economically develop our acreage over future years.
We began 2017 with three drilling rigs and exited the year with six drilling rigs. During the year, we completed 45 wells and commenced production on 44 wells, of which 23 were multi-zone pads. We also participated in approximately 30 non-operated development wells during 2017. In addition, we added two central gathering facilities (CGFs).
For 2018, we will continue asset development through long laterals, pad drilling, multi-zone development and an infrastructure build-out initiative that will include an additional three CGFs.
Eagle Ford Shale We hold approximately 35,000 net acres located in the highly prolific liquids-rich area of the play, including producing assets in Webb and Dimmit counties. Since acquiring these assets, we have continued to apply IDP learnings and enhancements to optimize development of these assets, including optimizing drilling and completion designs through testing varying clusters per stage, lateral lengths, and proppant quantities to increase investment efficiency. We have also focused on testing co-development of both the Upper and Lower Eagle Ford formation zones utilizing our IDP approach.
2017 Activity Our 2017 capital program was focused within Webb and Dimmit counties where we operated up to two drilling rigs, completed 47 horizontal wells and commenced production on 49 horizontal wells. All wells drilled during 2017 were on multi-well pads leveraging centralized infrastructure. We also sold certain assets located in Gonzales and DeWitt counties, where we had not engaged in drilling activities since the completion of the merger (Rosetta Merger) with Rosetta Resources Inc. (Rosetta) and received proceeds of $45 million.
We exited 2017 with a two rig drilling program. Our capital program in 2018 focuses on developing the Upper and Lower Eagle Ford formation zones within the Gates Ranch area.
Marcellus Shale  On June 28, 2017, we closed the sale of the Marcellus Shale upstream assets, receiving net proceeds of $1.0 billion and recorded a loss on sale of $2.38 billion. The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver production and cash flow growth.
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 4. Acquisitions, Divestitures and Merger.

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Gulf of Mexico   Locations of our operations in the Gulf of Mexico as of December 31, 2017 are shown on the map below:
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We have several producing fields and an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options.
We currently hold leases on approximately 63 deepwater blocks, representing approximately 52,000 net developed acres and approximately 171,000 net undeveloped acres. We are the operator on nearly 80% of our leases.
Subsequent Event On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
2017 Activity Our activity in 2017 primarily focused on optimizing production and progressing our Katmai project. See Offshore Producing Properties and Update to Gulf of Mexico Major Projects, below.
During 2017, we completed our geological evaluation of certain leases and determined that several leases, representing $60 million of undeveloped leasehold cost, should be impaired and expensed.
We have remaining capitalized undeveloped leasehold cost of approximately $44 million related to prospects that have not yet been drilled. Leases representing over 60% of this cost are scheduled to expire over the years 2018 to 2020. In addition, some leases may become impaired if production is not established or should we not take action to extend the terms of the leases. As a result of our exploration activities, capitalized undeveloped leasehold costs could become impaired. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Potential for Future Impairments.
Offshore Producing Properties   
Gunflint (Mississippi Canyon Block 948; 31% operated working interest)  Gunflint is a 2008 crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar platform. Production commenced in July 2016 and the development contributed 7 MBoe/d of sales volumes in 2017.
Rio Grande Development including Big Bend (Mississippi Canyon Block 698; 54% operated working interest) and Dantzler (Mississippi Canyon Block 782; 45% operated working interest) The Rio Grande crude oil development project consists of a single producing well from Big Bend, a 2012 crude oil discovery, and two producing wells from Dantzler, a 2013 crude oil discovery, flowing to the Thunder Hawk platform for which we assumed operatorship in 2016. The Rio Grande development commenced production in October 2015 and contributed an average of 12 MBoe/d of sales volumes in 2017.
Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest), Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest) and Santiago (Mississippi Canyon Block

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519; 23.25% operated working interest) The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. The Galapagos development began producing in 2012 and is connected to existing infrastructure through subsea tiebacks. A well stimulation commenced in the fourth quarter of 2017 to enhance recovery. The Galapagos project contributed an average of 4 MBoe/d of sales volumes in 2017.
Swordfish (Viosca Knoll Blocks 917; 961 and 962; 85% operated working interest)   Swordfish is a 2001 crude oil discovery and began producing in 2005. The Swordfish project currently includes two producing wells flowing to the Neptune Spar, our 100%-owned floating offshore production platform, and contributed an average of 3 MBoe/d of sales volumes in 2017. We currently plan to begin abandonment activities in 2019.
Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) Ticonderoga is a 2004 crude oil discovery and began producing in 2006. The project currently includes two producing wells, which contributed an average of 1 MBoe/d of sales volumes in 2017. These properties are connected to existing infrastructure through subsea tiebacks.
Update to Gulf of Mexico Major Projects
Katmai (Green Canyon Block 40; 50% operated working interest) During 2014, we announced successful final well results at the Katmai exploratory well. Katmai was drilled to a total depth of 27,900 feet in 2,100 feet of water. Wireline logging data indicated a total of 154 net feet of crude oil pay discovered in multiple reservoirs, including 117 net feet in Middle Miocene and 37 net feet in Lower Miocene reservoirs. In 2016, we spud our Katmai 2 appraisal well (38% operated working interest), located in Green Canyon Block 39, and encountered high pressure in the untested fault block. In response, we temporarily abandoned the well and are assessing plans to complete appraisal as well as development scenarios for the Katmai project.
Troubadour (Mississippi Canyon Block 699; 60% operated working interest) Troubadour was a 2013 natural gas discovery. In 2017, we determined that the asset was impaired in the current forward outlook for natural gas prices and development scenarios, and charged $63 million to impairment of oil and gas properties and $5 million to undeveloped leasehold impairment expense.
Regulatory Environment Various federal agencies overseeing certain of our activities in the Gulf of Mexico have adopted new regulations and are considering others. See Regulations - US Offshore Regulatory Developments below, and Item 1A. Risk Factors.
International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash flow growth over the last decade. Previous exploration successes in these areas have also identified additional multiple major development projects that have the potential to contribute to long-term production and cash flow growth in the future.
During 2017, we progressed development of offshore Israel assets by completing the Tamar 8 development well and commencing drilling activities for the Leviathan 5 development well. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by progressing multiple natural gas sales and purchase agreements (GSPAs). See Eastern Mediterranean (Israel and Cyprus) and West Africa (Equatorial Guinea, Cameroon and Gabon), below.
Operations in Equatorial Guinea, Cameroon, Gabon, Cyprus, and Suriname are conducted in accordance with the terms of Production Sharing Contracts (PSCs). Operations in Israel, Newfoundland (Canada) and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors.

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Sales volumes and proved reserves estimates for our international operating areas were as follows:
 
 
Year Ended December 31, 2017
 
December 31, 2017
 
 
Sales Volumes
 
Proved Reserves
 
 
Crude Oil &
Condensate
 
NGLs
 
Natural Gas
 
Total
 
Crude Oil &
Condensate
 
NGLs
 
Natural
Gas (1)
 
Total
 
 
(MBbl/d)
 
(MBbl/d)
 
(MMcf/d)
 
(MBoe/d)
 
(MMBbls)
 
(MMBbls)
 
(Bcf)
 
(MMBoe)
International
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Israel
 

 

 
272

 
46

 
9

 

 
5,448

 
917

Equatorial Guinea
 
18

 

 
239

 
57

 
29

 
11

 
411

 
108

Total International
 
18

 

 
511

 
103

 
38

 
11

 
5,859

 
1,025

Equity Investee
 
2

 
6

 

 
8

 

 

 

 

Total
 
20

 
6

 
511

 
111

 
38

 
11

 
5,859

 
1,025

Equity Investee Share of Methanol Sales (MMgal)
 
163

 
 

 
 
 
 
 
 

(1) Includes 3.3 Tcf proved undeveloped reserves related to initial Leviathan field development offshore Israel.

Wells completed in 2017 and productive wells at December 31, 2017 in our international operating areas were as follows:
 
 
Year Ended December 31, 2017
 
December 31, 2017
 
 
Gross Wells Completed
or Participated in (1)
 
Gross Productive
Wells
International
 
 
 
 
Israel
 
1

 
7

Equatorial Guinea
 

 
28

Total International
 
1

 
35

(1) 
Excludes the Araku-1 exploration well, offshore Suriname.
Eastern Mediterranean (Israel and Cyprus)  One of our operating areas is the Eastern Mediterranean, where we have identified the existence of substantial natural gas resources since we obtained our first exploration license offshore Israel in 1998.
Israel, the only producing country in our Eastern Mediterranean area, contributed an average of 272 MMcf/d of natural gas sales volumes in 2017, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field. With the addition of proved undeveloped reserves associated with Leviathan field development in 2017, Israel represented approximately 47% of total proved reserves at December 31, 2017. Our leasehold position in the Eastern Mediterranean at December 31, 2017, included four leases and three licenses operated offshore Israel. Offshore Cyprus, we operate under the terms of a PSC.
At December 31, 2017, the Eastern Mediterranean position included approximately 78,000 net developed acres and 116,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. The license offshore Cyprus covers approximately 33,000 net undeveloped acres adjacent to our Israel acreage.

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Locations of our operations in the Eastern Mediterranean as of December 31, 2017 are shown below:
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Offshore Israel Noble Energy and our partners have delivered reliable and affordable natural gas to Israeli citizens for over a decade. During this time, we have delivered approximately 2.3 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
We are the first company to construct, operate and produce from a major natural gas development project offshore Israel. Our Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed the Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry standards for an offshore natural gas project of this magnitude and complexity.
In 2010, we discovered the Leviathan field, our largest natural gas discovery to date. The quantity of discovered natural gas resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predicted to continue to grow over the next decade, primarily driven by increased use of natural gas over coal to fuel electric power generation. During 2017, growth in power, industrial and residential demand in Israel and first exports to Jordan, coupled with almost 100% asset uptime, enabled us to set a new sales volume record of 956 MMcfe/d, gross, from fields offshore Israel.
In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil discoveries at greater depths. We conducted preliminary exploration activities in 2012 and are analyzing the potential for future exploration.
Domestic Natural Gas Demand As the Israeli economy continues to grow, the demand for natural gas used primarily for electricity generation is also expected to grow. Demand for natural gas in the industrial sector, including refineries, chemical, desalination, cement and other plants, as well as residential uses, is also increasing. These sectors are gaining confidence that a long-term supply of affordable natural gas will be available and are now investing the capital necessary to convert facilities and infrastructure to use natural gas. In addition, government requirements for emissions reductions have also driven incremental demand for natural gas beginning in 2016. We have executed numerous GSPAs with domestic customers. See International Marketing Activities and Delivery and Firm Transportation Commitments, below.
Regional Demand and Exports The Eastern Mediterranean presents an opportunity to match our affordable, abundant supply of natural gas with a substantially undersupplied regional market, including customers in Jordan and Egypt. With the Tamar field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to supply natural gas to the region for many years.

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Israel Natural Gas Projects  
Tamar Natural Gas Project (32.5% operated working interest) The Tamar project began production in March 2013 and has peak flow rates of approximately 1.1 Bcf/d, gross, to support seasonal high demand periods. In 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT) and in 2017, we completed and commenced production from the Tamar 8 development well. The Tamar 8 well increases supply reliability as domestic demand for natural gas continues to grow.
In 2017, we installed subsea equipment to allow for future tie-back of our 2013 Tamar Southwest discovery into the Tamar platform and other existing infrastructure. We continue to work with the Government of Israel to obtain regulatory approval of the development plan, which would help reinforce the reliability for the Tamar project and support increased customer demand.
We are also assessing the possibility for expansion of the Tamar project. The project would expand field deliverability from the current capacity level of approximately 1.2 Bcf/d to up to approximately 2.1 Bcf/d, a quantity that would allow for additional regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources as well as regulatory approvals from respective governments.
The Israel Natural Gas Framework (Framework) provides for reduction in our ownership interest in the Tamar and Dalit fields from 36% to 25% by year-end 2021. In 2016, we divested 3.5% of our interest in these respective fields, partially fulfilling this commitment required by the Framework. Further, on January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in these respective fields to Tamar Petroleum Ltd (TASE: TMRP). See Item 8. Financial Statements and Supplementary Data – Note. 4. Acquisitions, Divestitures and Merger.
Leviathan Natural Gas Project (39.66% operated working interest)   In early 2017, we announced project sanction of the Leviathan natural gas project and recorded initial proved reserves of 3.3 Tcf (551 MMBoe) associated with the first phase of development. The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station and the Israel Natural Gas Lines (INGL) pipeline network. We expect our share of development costs to total approximately $1.5 billion and to be funded from our share of cash flows from the Tamar asset and expected proceeds to be received from the sell-down of our ownership interest in Tamar as noted above. In addition, we have the ability to borrow under the Leviathan Term Loan Facility (defined below). As we progress the first phase of development, we have included volume capacity expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas demand.
During 2017, we commenced drilling and continued detailed design and engineering activities and fabrication of onshore facilities, topsides, jacket and subsea equipment. We will continue drilling activities and commence well completions in 2018 as we progress the project towards first gas sales by the end of 2019. As of December 31, 2017, the project remained within budget and on schedule at approximately 35% complete, with all critical path equipment and major contracts secured.
The marketing and development of natural gas from this asset is intended to serve both domestic demand and regional export. We are actively engaged in natural gas marketing activities and have progressed multiple GSPAs totaling up to approximately 525 MMcf/d, gross (approximately 208 MMcf/d, net) of natural gas from the Leviathan field.
Our largest Leviathan GSPA, with the National Electric Power Company Ltd. (NEPCO) of Jordan, provides for sales of natural gas intended for consumption in power production facilities over a 15-year period. Sales to NEPCO are anticipated to commence at field startup. We continue to market natural gas from the Leviathan field toward realizing full utilization of the 1.2 Bcf/d of production capacity. See Israel Natural Gas Framework and Regulatory Environment, below.
Alon D License In August 2017, the Petroleum Commissioner of Israel granted us a 32-month extension of the Alon D license (47.059% operated working interest) to drill an exploration well. We are performing geologic and environmental studies necessary to progress the prospect to an investment decision.
Other Discoveries Offshore Israel   Our development plan for the Dalit field (32.5% operated working interest), a 2009 natural gas discovery, was approved by the Government of Israel. Development includes a tieback to the Tamar platform. We are also analyzing 3D seismic data to evaluate the additional potential of the area, including the possible existence of hydrocarbons at deeper intervals. 
Asset Impairments No impairment expense was recorded during 2017. During 2016, we recorded impairment expense of $88 million related to certain Leviathan field development concepts which were not selected. During 2015, we recorded impairment expense of $36 million, primarily due to an increase in field abandonment costs. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.
Israel Natural Gas Framework and Regulatory Environment We are subject to certain fiscal, antitrust and other regulatory challenges in Israel. These challenges have been addressed with the enactment of the Framework by the Government of Israel.

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See Regulations – Israel Regulatory Environment and Item 1A. Risk FactorsOur Eastern Mediterranean discoveries bear certain geopolitical, regulatory, financial and technical challenges that could adversely impact our ability to monetize these natural gas assets.
Cyprus Natural Gas Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. We received initial proceeds of $131 million related to the farm-out agreement in 2016 and received the remaining consideration, subject to post-close adjustments, in January 2017. We continue to operate with a 35% interest. As part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.
In September 2017, we submitted an updated development plan to the Government of Cyprus. We continue to work with the Government of Cyprus to obtain approval of the development plan and the issuance of an Exploitation License for the Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite natural gas, will allow us and our partners to perform the necessary FEED studies and progress the project to final investment decision. In preparation for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential development of the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. During 2017, we progressed capital project cost improvements and continued regional natural gas marketing efforts.
West Africa (Equatorial Guinea, Cameroon and Gabon)   West Africa is one of our operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC, offshore Cameroon, and one block offshore Gabon. In West Africa, our interests can be burdened by overriding royalty interests and/or other government interests. As such, our working interests may differ from our revenue interests. Equatorial Guinea is currently our only producing country in our West Africa segment and, excluding the impact of equity investees, Equatorial Guinea contributed an average of 57 MBoe/d of sales volumes in 2017 and represented approximately 15% of total consolidated sales volumes. At December 31, 2017, Equatorial Guinea represented approximately 5% of total proved reserves. We held approximately 118,000 net developed acres and 30,000 net undeveloped acres in Equatorial Guinea, 168,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres in Gabon at December 31, 2017.
Locations of our upstream operations in Equatorial Guinea and Cameroon, as of December 31, 2017 are shown on the map below:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12068740&doc=34
Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest), offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold, and natural gas and water are reinjected into the reservoir to maintain pressure and maximize crude oil recoveries. During 2017, the Aseng field produced approximately 7 MBoe/d, net.

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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 over 99% production uptime and, as of December 31, 2017, has produced 89 MMBbls of cumulative gross crude oil production.
Alen Field   Alen is a natural gas and condensate field primarily on Block O (51% operated working interest, 45% revenue interest), offshore Equatorial Guinea, which includes three production wells and three natural gas injection wells connected to a production platform that utilizes the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and produced approximately 4 MBoe/d, net, during 2017. As of December 31, 2017, Alen has produced over 33 MMBbls of cumulative gross condensate production.
The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization, below.
In October 2017, we executed a unitization agreement on the Alen field with our partners and the Government of Equatorial Guinea. The agreement was between Block O and Block I interest owners. We expect the impact on our allocated future sales volumes to be de minimis.
Alba Field   Alba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest, 32% revenue interest), which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, a liquefied petroleum gas (LPG) processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2017, Alba field sales volumes totaled 54 MBoe/d, net, reflecting 46 MBoe/d attributable to total sales volumes and 8 MBoe/d attributable to an equity investee.
In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government of Equatorial Guinea. The agreement was between Alba Block and Block D interest owners. As a result of the unitization, our revenue interest going forward changed from 34% to 32%, and our non-operated working interest changed from 35% to 33%. As anticipated, our 2017 sales volumes from the Alba field were lower as a result of the unitization, and the impact on our proved reserves was de minimis. We expect the impact on our allocated future sales volumes to be de minimis.
We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated liquefied natural gas (LNG) plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices.
We account for both Alba Plant and AMPCO as equity method investments and present our share of income as a component of revenues. We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing operations in our West Africa operating area. Our Alba asset teams are fully engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba Plant. We hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters.
West Africa Natural Gas Monetization  We continue our efforts to monetize the significant natural gas resources represented by our discoveries offshore West Africa, including our 2007 Yolanda discovery (Block I), the YoYo discovery, offshore Cameroon, as well as natural gas from our Aseng and Alen fields.
As part of our monetization efforts, a natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, we believe these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial returns.
Cameroon We have an interest in approximately 168,000 undeveloped acres offshore Cameroon in our YoYo PSC (100% operated working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options, which will provide a more robust framework directly related to oil and gas operational activities. In June 2017, we converted our mining concession license for the YoYo block into a PSC.
Offshore Gabon We are the operator of Block Doukou Dak (60% working interest), an undeveloped, deepwater area, covering approximately 671,000 gross acres. Our exploration commitment includes an obligation for 3D seismic, which was acquired

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and processed throughout 2016 and the first half of 2017. We received the final product mid-year 2017 and are currently evaluating the seismic data results.
See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Other International
Other international operations include the following:
Offshore Newfoundland (Canada) In November 2016, we acquired a non-operated 25% working interest in exploration parcels (blocks) 3, 4 and 8, and a non-operated 40% working interest in exploration parcel (block) 10. BP Canada Energy Group ULC is the operator of the blocks. We have acquired 3D seismic data which will allow us to assess the economic viability of this exploration prospect.
Offshore Suriname  We hold a non-operated 20% working interest in Block 54 offshore Suriname in the Atlantic Ocean. In October 2017, our partner spud the Araku-1exploration well and subsequently plugged and abandoned the well. As a result, we recorded dry hole expense of $7 million and are currently analyzing the well results to update modeling of the basin and review further prospectivity. See Note 5. Asset Impairments.
Offshore Falkland Islands In 2016, following completion of our geological assessment, we exited all licenses, excluding the PL-001 which contains the Rhea prospect. The exit resulted in a $25 million undeveloped leasehold impairment expense. As of December 31, 2017, there is no remaining net book value associated with the assets.
North Sea  The non-operated MacCulloch field is currently undergoing decommissioning activities. Due to its size and location, field abandonment is a multi-year process, requiring several phases. Therefore, our share of estimated field abandonment costs, recorded as an asset retirement obligation, may change over time. For example, during 2017, the operator of the MacCulloch field notified working interest owners that the scope and magnitude of decommissioning activities has been revised downward, resulting in lower projected field abandonment costs. As such, we recorded a revision of $42 million in 2017 that decreased our estimated asset retirement obligation for the remediation project. The discounted obligation totaled 44 million at December 31, 2017. We will continue to monitor the status and costs of the project and will adjust our estimate accordingly.
Midstream – Properties and Activities
We continue to develop our Midstream business, which includes gathering, treating, and transportation assets as well as water-related infrastructure, including fresh water delivery and produced water disposal assets, that support our upstream operations. Our Midstream assets are strategically located with our exploration and production activities in the DJ and Delaware Basins. These assets also provide services to third party customers.
Our Midstream operations include those of Noble Midstream Partners, a publicly traded consolidated subsidiary and limited partnership that owns, operates, develops, and acquires a wide range of domestic midstream infrastructure assets. Noble Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized in a development company structure. At December 31, 2017, our ownership interest in Noble Midstream Partners consisted of a 45.5% limited partner interest, the entire non-economic general partner interest, and all of the incentive distribution rights. On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided access to capital markets to support funding of our US onshore midstream investment program.
The following diagram depicts our organizational structure as of December 31, 2017. Development companies identified in red and blue indicate the location of the assets as either in the DJ Basin or Delaware Basin, respectively.

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http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12068740&doc=28
Advantage Joint Venture In April 2017, Noble Midstream Partners, along with its partner, Plains Pipeline, L.P., formed the Advantage joint venture (Advantage Joint Venture) and subsequently completed the acquisition of Advantage Pipeline L.L.C. (Advantage Pipeline). Noble Midstream Partners serves as the operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline (Advantage Delaware Basin Pipeline) in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of capacity (expandable to over 200 MBbls per day) and 490 MBbls of storage capacity. Noble Midstream Partners owns a 50% interest in the joint venture.
Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of Blanco River DevCo, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy. Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.
Black Diamond Gathering and Acquisition of Saddle Butte Pipeline In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC (Greenfield Midstream) formed an entity, Black Diamond Gathering LLC (Black Diamond Gathering), to acquire Saddle Butte Rockies Midstream, LLC and affiliates (Saddle Butte). The acquisition includes a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation and 300 MBbls per day of delivery capacity. Saddle Butte has approximately 141,000, net dedicated acres from six customers under fixed fee arrangements.
The transaction closed on January 31, 2018, with Noble Midstream Partners funding $319.9 million of the total cash consideration of $638.5 million. Noble Midstream Partners received a 54.4% equity ownership and Greenfield Midstream will own the remaining 45.6% of Black Diamond Gathering. Noble Midstream Partners will operate the Saddle Butte system.
Marcellus Shale CONE Gathering Divestiture In late 2017, we announced the signing of a definitive agreement to divest our 50% interest in CONE Gathering, LLC (CONE Gathering). CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream). As of December 31, 2017, the net book value of the assets held by Noble Energy

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was approximately $181 million. In January 2018, we closed the sale of CONE Gathering, receiving cash proceeds of $308 million. We now hold 21.7 million common units representing limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.
See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger and Item 8. Financial Statements and Supplementary Data – Note 7. Equity Method Investments.
Major Construction Projects Our activity in 2017 primarily focused on construction and development of midstream infrastructure assets, including:
completion of a produced water expansion project servicing the Wells Ranch IDP area;
completion of crude oil and produced water gathering systems servicing the Greeley Crescent IDP area;
completion of the connection from the CGF in the Delaware Basin to the Advantage Pipeline, which began allowing crude oil to flow from the completed facility to the Advantage Pipeline in third quarter 2017;
completion of the construction of two CGFs in the Delaware Basin; and
continued construction activities on expansion of our freshwater system servicing the Mustang IDP area and the commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed in early 2018.
In 2018, we expect to continue our midstream investment to focus on the DJ and Delaware Basins to meet the needs of our upstream operations.
Third Party Sales During 2017, we began providing crude oil and produced water gathering and fresh water delivery services to an unaffiliated third party in the Greeley Crescent IDP area of the DJ Basin.
Proved Reserves Disclosures
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 the Securities and Exchange Commission (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, newly sanctioned development projects, and certain fields selected on a rotational basis, 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 different geographical regions. These reserves estimates are reviewed and approved by regional 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 37 years of industry experience 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, including the material additions to the 2017 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.

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Third-Party Reserves Audit   In each of the years 2017, 2016, and 2015, we retained NSAI to perform audits of proved reserves. The reserves audit for 2017 included a detailed review of six of our major US onshore and international fields, which covered approximately 92% of US proved reserves and 99% of international proved reserves (95% of total proved reserves). The reserves audit for 2016 included a detailed review of nine of our major US onshore and international fields, which covered approximately 88% of US proved reserves and 99.9% of international proved reserves (92% of total proved reserves). The reserves audit for 2015 included a detailed review of nine of our major fields and covered approximately 91% of total proved reserves.
In connection with the 2017 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserves quantities, future production rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves categorization, using the definitions for proved reserves set forth in Rule 4-10(a) of Regulation S-X and subsequent SEC staff interpretations and guidance.
In the conduct of the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
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, 2017, 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 is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. For proved reserves at December 31, 2017, on a quantity basis, the NSAI field estimates ranged from 18 MMBoe or 8% below to 9 MMBoe or 2% above as compared with our estimates on a field-by-field basis. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. Reserves differences at December 31, 2017 were, in the aggregate, approximately 17 MMBoe, or less than 1%.
Proved Reserves
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,
 
 
2017
 
2016
 
2015
(MMBoe)
 
 
 
 
 
 
Proved Reserves Beginning of Year
 
1,437

 
1,421

 
1,404

Revisions of Previous Estimates
 
135

 
64

 
(216
)
Extensions, Discoveries and Other Additions
 
736

 
179

 
100

Purchase of Minerals in Place
 
57

 
4

 
269

Sale of Minerals in Place
 
(261
)
 
(77
)
 
(6
)
Production
 
(139
)
 
(154
)
 
(130
)
Proved Reserves End of Year
 
1,965

 
1,437

 
1,421

Revisions   Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, development costs or abandonment costs. Revisions primarily included the following:
positive price revisions of 30 MMBoe globally, as well as positive performance revisions of 49 MMBoe for the Tamar field, offshore Israel, 30 MMBoe for the Delaware Basin and 22 MMBoe for the Eagle Ford Shale, partially offset by abandonment cost increases for US onshore in 2017;

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positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Delaware Basin, and 10 MMBoe for the Alba field, offshore Equatorial Guinea, due to increased performance and/or lower development or operating costs; partially offset by negative revisions of 53 MMBoe due to lower commodity prices in 2016; and
negative price revisions of 307 MMBoe, partially offset by positive performance revisions of 81 MMBoe for the Marcellus Shale and 17 MMBoe for the Delaware Basin in 2015.
Extensions, Discoveries and Other Additions   These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions primarily included the following:
increases primarily relate to 99 MMBoe in the DJ Basin and 77 MMBoe in the Delaware Basin as a result of enhanced completion techniques in our horizontal drilling programs and an increase of 551 MMBoe due to the sanction of the first phase of development at the Leviathan natural gas field in 2017;
increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Delaware Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs in 2016; and
increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs in 2015.
Approximately 70% of our 2018 capital program is allocated to US onshore, primarily the DJ Basin, Delaware Basin and Eagle Ford Shale, and more than 25% is allocated to offshore Israel. In turn, we expect that future reserves additions will primarily come from our development projects in the US onshore and offshore Israel. Potential new discoveries resulting from our exploration programs in our operational areas as well as global new ventures programs could also lead to future reserve additions. In addition, we may also purchase proved properties in strategic acquisitions. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Acquisition, Capital Expenditures and Other Exploration Expenditures.
Purchase of Minerals in Place  We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases primarily included the following:
an increase of 57 MMBoe in the Delaware Basin primarily as a result of the Clayton Williams Energy Acquisition in 2017; and
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Delaware Basin in Texas in 2015 in connection with the Rosetta Merger.
Sale of Minerals in Place   We maintain an ongoing portfolio management program through which we may periodically divest assets. Sales primarily included the following:
a reduction of 241 MMBoe related to the Marcellus Shale upstream divestiture, as well as 20 MMBoe associated with divestment of non-strategic US onshore assets in 2017;
a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, as well as a 29 MMBoe divestment in the Marcellus Shale in 2016; and
the sale of non-strategic US onshore assets in 2015.
See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.
Production   See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - E&P - Revenues and Critical Accounting Policies and Estimates – Reserves and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).

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Proved Undeveloped Reserves (PUDs)   As of December 31, 2017, our PUDs totaled 249 MMBbls of crude oil and condensate, 4.5 Tcf of natural gas, and 99 MMBbls of NGLs for a total of 1,097 MMBoe, or 56% of proved reserves. Changes in PUDs that occurred during the year are summarized below:
 
 
United
 States
 
Israel
 
Total
(MMBoe)
 
 
 
 
 
 
Proved Undeveloped Reserves Beginning of Year
 
422

 
64

 
486

Revisions of Previous Estimates
 
26

 

 
26

Extensions, Discoveries and Other Additions
 
174

 
551

 
725

Purchase of Minerals in Place
 
36

 

 
36

Sale of Minerals in Place
 
(54
)
 

 
(54
)
Conversion to Proved Developed
 
(122
)
 

 
(122
)
Proved Undeveloped Reserves End of Year
 
482

 
615

 
1,097

Revisions of previous estimates include the transfer of PUDs to unproved reserve categories as a result of changes in development plans and/or the impact of changes in commodity prices, and the addition of new PUDs arising from current development plans. Positive revisions of 26 MMBoe in the US for 2017 included 7 MMBoe related to positive price revisions and 19 MMBoe related to enhancements of our horizontal drilling programs.
Extensions, discoveries and other additions include the addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields. During 2017, we recorded the following additions as a result of successful expansion of our long lateral well programs in US onshore and recording of reserves for Leviathan:
94 MMBoe in the DJ Basin;
74 MMBoe in the Delaware Basin;
6 MMBoe in the Eagle Ford Shale; and
551 MMBoe in the Leviathan field.
Conversion to proved developed reserves included the following transfers:
34 MMBoe in the DJ Basin;
17 MMBoe in the Delaware Basin;
60 MMBoe in the Eagle Ford Shale; and
11 MMBoe in the Marcellus Shale, prior to divestiture.

US PUDs Locations In 2017, we converted 122 MMBoe of our US PUDs, or 29% of our US PUDs beginning balance, to developed status. 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, 2017 to be converted to proved developed reserves within five years of initial disclosure.
As of December 31, 2017, our US PUDs included:
263 MMBoe in the DJ Basin;
181 MMBoe in the Delaware Basin; and
38 MMBoe in the Eagle Ford Shale.
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, 2017, we had approximately 32 MMBoe of PUDs associated with DUC well locations related to our US onshore operations, approximately 75% of which are in the DJ Basin and the remainder are in the Delaware Basin and Eagle Ford Shale.
International PUDs Locations As of December 31, 2017, our international PUDs included 615 MMBoe in Israel, of which 551 MMBoe relate to the Leviathan field, which is currently in the first phase of development. The Tamar field contains 35 MMBoe, and the Tamar Southwest field, which is awaiting government approval of the development plan, contains 29 MMBoe. Our Tamar Southwest PUDs of 29 MMBoe, or less than 5% of our international 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 the approval of the development plan and have continued capital investment within this field, including laying subsea equipment in 2017 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 those associated with the initial phase of development at the Leviathan field, to be converted to proved developed reserves within five years of initial disclosure.

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Development Costs   Costs incurred to convert PUDs to proved developed reserves were approximately $1.2 billion in 2017, $656 million in 2016, and $1.5 billion in 2015. Costs incurred in 2017 primarily related to the DJ Basin, Delaware Basin and Eagle Ford Shale development projects, as well as certain costs incurred for the development of the Tamar 8 well. In addition, we incurred approximately $416 million in 2017 to advance the development of the Leviathan PUDs which are expected to be converted to proved developed reserves in 2019.
Estimated future development costs relating to the development of all PUDs are projected to be approximately $1.7 billion in 2018, $1.9 billion in 2019, and $1.4 billion in 2020. 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 disclosure, 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 plans, subject to local government approval. Initial production from all PUDs is expected to begin during the years 2018 to 2022.
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 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, 2017, we had no PUDs with a negative present worth when discounted at 10%.
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 disclosure. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2018 Capital Investment Program.
For more information see the following:
Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil, NGL and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.

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Sales Volumes, Price and Cost Data  Sales volumes, price and cost data are as follows:
 
 
Sales Volumes
 
Average Sales Price
 
Production 
Cost (1)
 
 
Crude Oil &
Condensate
MBbl
 
NGLs
MBbl
 
Natural Gas
MMcf
 
Crude Oil &
Condensate
Per Bbl
 
NGLs Per
Bbl
 
Natural Gas
Per Mcf
 
Per BOE
Year Ended December 31, 2017 (2)
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 
 
 
 
 
 
 
 
 
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

 
N/M

  Total Israel
 
130

 

 
99,240

 
46.95

 

 
5.32

 
2.01

Equatorial Guinea (3)
 
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 (4)
 
662

 
2,162

 

 
55.13

 
38.48

 

 
N/M

Total
 
47,806

 
23,248

 
407,976

 
$
49.84

 
$
24.81

 
$
3.01

 
N/M

Year Ended December 31, 2016 (2)
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 
 
 
 
 
 
 
 
 
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

 
N/M

  Total Israel
 
140

 

 
102,808

 
36.67

 

 
5.21

 
2.60

Equatorial Guinea (3)
 
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 (4)
 
629

 
1,993

 

 
45.44

 
26.30

 

 
N/M

Total
 
46,529

 
21,825

 
511,115

 
$
40.46

 
$
15.96

 
$
2.42

 
N/M

Year Ended December 31, 2015 (2)
 
 

 
 
 
 

 
 

 
 
 
 

United States
 
 

 
 

 
 
 
 

 
 

 
 
 
 

DJ Basin
 
20,909

 
6,910

 
85,369

 
$
44.37

 
$
14.21

 
$
2.53

 
$
5.75

Marcellus Shale
 
673

 
3,480

 
143,465

 
22.39

 
14.04

 
1.75

 
1.38

Other US
 
7,680

 
3,705

 
29,806

 
42.83

 
13.25

 
2.56

 
7.15

Total US
 
29,262

 
14,095

 
258,640

 
43.46

 
13.91

 
2.10

 
4.46

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
121

 

 
91,884

 
46.91

 

 
5.34

 
3.12

  Other Israel
 

 

 
136

 

 

 
3.01

 
N/M

  Total Israel
 
121

 

 
92,020

 
46.91

 

 
5.34

 
3.15

Equatorial Guinea (3)
 
11,416

 

 
82,729

 
48.85

 

 
0.27

 
5.22

United Kingdom
 
88

 

 
49

 
55.52

 

 
6.32

 
N/M

Total Consolidated Operations
 
40,887

 
14,095

 
433,438

 
45.00

 
13.91

 
2.44

 
$
4.54

Equity Investee (4)
 
554

 
1,850

 

 
48.85

 
28.40

 

 
N/M

Total
 
41,441

 
15,945

 
433,438

 
$
45.05

 
$
15.59

 
$
2.44

 
N/M

N/M Amount is not meaningful.
(1) 
Average production cost includes crude oil and natural gas operating costs and workover and repair expense and excludes production and ad valorem taxes and transportation expense.

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(2) 
For each respective year, reserves associated with the Delaware Basin or the Eagle Ford Shale did not comprise 15% or more of total reserves on a BOE basis.
(3) 
Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
(4) 
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
Revenues from sales of crude oil, NGLs and natural gas have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.
At December 31, 2017, 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, 2017 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
3,565

 
2,682

 
4,918

 
4,382

 
8,483

 
7,064

Israel
 

 

 
7

 
2

 
7

 
2

Equatorial Guinea
 
5

 
2

 
23

 
8

 
28

 
10

Total
 
3,570

 
2,684

 
4,948

 
4,392

 
8,518

 
7,076

 
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 gross wells is the total number of wells 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.
Developed and Undeveloped Acreage  Developed and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 2017 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore
 
754

 
504

 
564

 
358

Gulf of Mexico
 
93

 
52

 
247

 
171

Total United States
 
847

 
556

 
811

 
529

International
 
 

 
 

 
 

 
 

Israel
 
185

 
78

 
284

 
116

Equatorial Guinea (1)
 
284

 
118

 
81

 
30

Suriname
 

 

 
2,095

 
419

Newfoundland, Canada
 

 

 
2,331

 
681

Gabon
 

 

 
671

 
403

Cyprus
 

 

 
95

 
33

Cameroon
 

 

 
168

 
168

Other International
 
2

 

 
284

 
211

Total International
 
471

 
196

 
6,009

 
2,061

Total
 
1,318

 
752

 
6,820

 
2,590

(1) 
Undeveloped acreage includes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which had expired in 2016. The lease was subsequently negotiated with the government of Equatorial Guinea in 2017 and was extended.

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. 

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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 0.9 million (including 0.4 million in Suriname and 0.4 million in Gabon), 0.3 million, and 0.1 million net acres will expire in 2018, 2019, and 2020, respectively.

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, 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

Year Ended December 31, 2015
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 
1.5

 
4.0

 
5.5

 
212.5

 

 
212.5

 
218.0

Equatorial Guinea
 

 

 

 
0.3

 

 
0.3

 
0.3

Cameroon
 

 
0.5

 
0.5

 

 

 

 
0.5

Other International
 

 
0.4

 
0.4

 

 

 

 
0.4

Total
 
1.5

 
4.9

 
6.4

 
212.8

 

 
212.8

 
219.2

 
In addition to the wells drilled and completed in 2017 included in the table above, wells that were in the process of drilling or completing at December 31, 2017 were as follows: 
 
 
Exploratory(1)
 
Development(2)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
1

 
0.5

 
114

 
105.0

 
115

 
105.5

Israel 
 
1

 
0.3

 
5

 
2.0

 
6

 
2.3

Equatorial Guinea
 
2

 
0.9

 

 

 
2

 
0.9

Cameroon
 
1

 
1.0

 

 

 
1

 
1.0

Cyprus
 
1

 
0.4

 

 

 
1

 
0.4

Total
 
6

 
3.1

 
119

 
107.0

 
125

 
110.1

(1) 
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
(2) 
Includes wells pending completion activities. Israel development wells include the Leviathan 3, 4, 5 and 7 development wells and the Tamar Southwest 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.
Domestic Marketing Activities  Crude oil, natural gas, condensate and NGLs produced in the US onshore and Gulf of Mexico are sold under short-term and long-term contracts at market-based prices adjusted for location and quality. Onshore production of crude oil and condensate is distributed through pipelines and by trucks and rail cars to gatherers, transportation companies and refineries. Gulf of Mexico production is distributed through pipelines.
With the advent of US onshore shale gas, demand has increased for access to takeaway pipelines for ballooning production volumes. For example, in the Permian Basin, midstream suppliers are working to construct new gathering, transportation and processing facilities or to repurpose existing infrastructure in an effort to proactively outpace anticipated production growth as well as expected future LNG demand from export facilities on the Gulf Coast.
International Marketing Activities  Our share of crude oil and condensate from the Aseng and Alen fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Our share of crude oil and condensate from the Alba field is sold to Glencore Energy under a short-term sales contract, subject to renewal. These products are transported by tanker. 

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Natural gas from the Alba field is sold for $0.25 per MMBtu to a methanol plant, an LPG plant, an unaffiliated LNG plant and a power generation plant. The sales contract with the methanol plant runs through 2026, and the sales contract with the LNG plant runs through 2023. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
In Israel, we sell natural gas from the Tamar field, and have agreements with multiple customers to sell natural gas under long-term contracts, with initial terms ranging from 15 to 17 years. See Delivery and Firm Transportation Commitments, below. 
Delivery and Firm Transportation Commitments  
Domestic Contracts We have entered into various long-term gathering, processing and transportation contracts for some of our US onshore production, with remaining terms of one to 11 years. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost.
Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments.
For 2017, 2016, and 2015, we incurred expense of approximately $47 million$58 million, and $33 million, respectively, related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are recorded as marketing expense in our consolidated statements of operations.
We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term.
Our financial commitments under these contracts are included in our contractual obligations disclosures. In addition, we have retained certain other firm transportation agreements after the completing the Marcellus Shale upstream divestiture. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual Obligations.
Israel Natural Gas Sales and Purchase Agreements We currently sell natural gas from our Tamar field, offshore Israel, to the IEC and numerous other Israeli purchasers, including independent power producers, cogeneration facilities and industrial companies. Most contracts provide for the sale of natural gas over an initial term of 15 to 17 years. Some of the contracts provide for an increase or reduction in total quantities, and some contracts are interruptible during certain contract periods. Sales prices may be based on an initial base price subject to price indexation over the life of the contract and have a contractual floor. The IEC contract provides for price reopeners in certain years with limits on the increase/decrease from the contractual price.
Under the contracts, we and our partners have a financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and will be reflected as a reduction in sales price to the purchaser for periods in which we are delivering partial contract quantities, or as a direct payment to the customer under certain circumstances and with a cap. The cap is subject to force majeure considerations. We believe that any such sales price adjustments or direct payments would not have a material impact on our earnings or cash flows.
As of December 31, 2017, a total of approximately 5.4 Tcf, gross (1.7 Tcf, net), of natural gas remained to be delivered under our Tamar contracts. As of December 31, 2017, we have recorded 2.0 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.8 Tcf, net, and PUD reserves of 212 Bcf, net, for the Tamar field. Based on current production levels and future development plans, our available quantities of proved reserves are more than sufficient to meet near-term delivery commitments associated with Tamar sale agreements without further capital investment.
We are also actively engaged in domestic and regional marketing activities for future sales of the natural gas reserves recorded for the Leviathan field. See Eastern Mediterranean (Israel and Cyprus), above.
Significant Purchasers  BP North American Funding (BP) and Shell Trading (US) (Shell) were the largest single purchasers of our 2017 production. Sales to BP accounted for 10% of 2017 total crude oil, natural gas and NGL sales, or 15% of 2017 crude oil sales. Sales to Shell accounted for 13% of our 2017 total crude oil, natural gas and NGL sales, or 22% of crude oil sales. Both BP and Shell purchased crude oil and condensate domestically from our US onshore operations and Gulf of Mexico operations.

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No other single purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2017. We maintain credit insurance associated with specific purchasers and believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production. 
Hedging Activities  Commodity prices continue to be volatile and are affected by a variety of factors beyond our control. We use derivative instruments to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas. As a result of hedging, a portion of near-term cash flow volatility is reduced.
We exercise strong management of our hedging program with strong oversight by our Board of Directors. For additional information, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities.
Regulations 
Exploration for, and production and marketing of, crude oil, natural gas and NGLs are extensively regulated at the federal, state, and local levels in the US, and internationally. Crude oil, natural gas and NGL development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, transportation, prevention of waste and pollution, and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion over time and frequently impose more stringent requirements on crude oil and natural gas companies.
Our ability to economically produce and sell crude oil, natural gas and NGLs is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules, regulations and orders that require extensive efforts to ensure compliance, that impose incremental costs to comply, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil, natural gas and NGL production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
Internationally, our operations are subject to legal and regulatory oversight by energy-related ministries or other agencies of our host countries, each having certain relevant energy or hydrocarbons laws. Examples include: 
the Ministry of Mines and Hydrocarbons, which, under such laws as the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial Guinea;
the Ministry of Energy, which regulates our exploration and development activities offshore Israel and the Israeli electricity market into which we sell our natural gas production;
the Israeli Antitrust Commission, which reviews Israel's domestic natural gas sales and ownership in offshore blocks and leases; and
the Ministry of Energy, Commerce, Industry and Tourism, which regulates our exploration and development activities offshore Cyprus.
Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil, natural gas and NGLs include: 
the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain authority over our operations on federal lands and waters, particularly in the Rocky Mountains and Gulf of Mexico;
the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982, has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety matters affecting our operations;
the US Fish and Wildlife Service (FWS) and US National Marine Fisheries Service, which under the Endangered Species Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines and roads;
the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the Gulf of Mexico; and

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the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our US onshore and Gulf of Mexico operations.
Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In addition, we are governed by the rules and regulations of the NYSE, upon which shares of our common stock are traded.
Among the laws affecting our operations are the following:
Environmental Matters We take into account the cost of complying with environmental regulations in planning, designing, drilling, operating, and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production wastes, water and air pollution control procedures, facility siting and construction, prevention of and responses to leaks and spills, and the remediation of petroleum-product contamination. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations.
Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us, or by prior owners or operators, in accordance with current laws, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups. The EPA and various state agencies have limited the disposal options for hazardous and non-hazardous wastes and may continue to do so. The owner and operator of a site, and persons that treated, disposed of, or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from the definition of hazardous waste may in the future be subject to considerably more rigorous and costly operating and disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary.
Under federal and state occupational safety and health laws, we must develop and maintain information about hazardous materials used, released, or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not believe that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
The following is a summary of the more significant US environmental developments and requirements that may affect our operations.
Various state and federal statutes such as the Endangered Species Act (ESA) prohibit certain actions that adversely affect endangered or threatened species and their habitat, wetlands, migratory birds, marine mammals, or natural resources. Where the taking or harm of such species occurs or may occur, or where damages to wetlands or natural resources may occur, the government or private parties may act to prevent crude oil and natural gas exploration activities. In particular, a federal or state agency could order a complete halt to drilling activities in certain locations or during certain seasons when such activities could result in a serious adverse effect upon a protected species. The presence of a protected species in areas where we operate could adversely affect future production from those areas and government agencies frequently add to the lists of protected species. For example, listing of the Lesser Prairie Chicken likewise could impact our operations in the Delaware Basin. The Lesser Prairie Chicken was removed from the ESA list of endangered species in July 2016 after a federal court invalidated the FWS’s listing of the bird as threatened because the FWS failed to give proper consideration to voluntary conservation measures; however, the FWS announced in November 2016 an ongoing new status review of the Lesser Prairie Chicken to determine whether listing is still warranted.

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The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act” or “CWA,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters. Provisions of the CWA require authorization from the US Army Corps of Engineers, or the “Corps”, prior to the placement of dredge or fill material into jurisdictional waters. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.
On June 29, 2015, the EPA and Corps jointly published the final rule defining the scope of the EPA’s and Corps’ jurisdiction, known as the “Clean Water Rule.” The Clean Water Rule has been challenged in multiple federal courts; however, at this time, we cannot predict the outcome of this litigation. Subsequently, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, and also announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Both agencies also published a proposed rule in November 2017 delaying implementation of the Clean Water Rule for two years. As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to spill prevention, storm water management, and wetlands permitting. We are continuing to monitor the regulatory updates and to evaluate the impact of the new rule on our operations.
Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.
The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
There also have been a series of recent air regulations and proposals that affect, or that may affect, our operations. In 2012, for example, the EPA issued New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants to control air emissions associated with crude oil, natural gas and NGL production, including natural gas wells that are hydraulically fractured. In addition to addressing emissions from storage tanks and other equipment, those regulations required technologies and processes that, while reducing emissions, enable companies to collect additional natural gas that can be sold. Specifically, as of January 2015, owners and operators of natural gas wells must use emissions reduction technology called “green completions,” technologies that were already widely deployed at wells. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the EPA was directed to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. To date, these rules have had minimal impact on our business since the reduction of greenhouse gas (GHG) emissions already was one of our priorities and we had been working to improve our methods to reduce GHGs through operational and business practices. For example, we have undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture natural gas that would otherwise be flared on a substantial number of our tank batteries.

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Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements, which could increase our compliance costs and may require facility siting and design changes.
As another prong of the previous US Administration's methane strategy, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations. On March 28, 2017, the BLM was directed by executive order to review the above rule and, if appropriate, to initiate a rulemaking to rescind or revise it. Accordingly, on December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016 methane rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. It also bears noting that substantially all of our US onshore properties are subject to EPA’s requirements for reporting annual GHG emissions. Information in such reports could form the basis of further GHG regulations.
In another air development, the EPA announced in October 2015 that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, areas that cannot meet the new standard eventually will need to impose additional requirements on sources of VOCs and other ozone precursors which could increase the cost of siting and operating our facilities.
Apart from these federal matters, most of the states where we operate have separate authority to regulate operational and environmental matters.  
Colorado In February 2013, the Colorado Oil and Gas Conservation Commission (COGCC) approved setback rules for crude oil and natural gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC had allowed setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a uniform 500 feet statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. In addition, the rules require advance notice to surface owners, the owners of occupied buildings and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment as well as outreach and communication efforts by an operator.
The COGCC also has implemented rules making Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Those statewide rules require sampling of up to four water wells within a half mile radius of a new crude oil and natural gas well before drilling, between six and 12 months after completion, and between five and six years after completion. For the Greater Wattenberg Area, the COGCC requires operators to sample only one water well per quarter governmental section before drilling and between six to 12 months after completion. Further, the COGCC has adopted rules increasing the maximum penalty for violations of its requirements.
The state environmental agency, the Colorado Department of Public Health and Environment, likewise has adopted measures to regulate air emissions, water protection, and waste handling and disposal relating to our crude oil and natural gas exploration and production. For air, the Colorado Department of Public Health and Environment has extended the EPA’s emissions standards for crude oil and natural gas operations to directly control methane. The final rules, which cover the life cycle of oil and gas development, production, and maintenance, reflect a collaborative effort by the Environmental Defense Fund, Noble Energy and other oil and gas operators.
Some of the counties and municipalities where we operate in Colorado have adopted their own regulations or ordinances that impose additional restrictions on our crude oil and natural gas exploration and production. To date these have not significantly impacted our operations. However, a few localities in Colorado have tried to prohibit certain exploration and production activities, particularly use of hydraulic fracturing within their boundaries. In May 2016, the Colorado Supreme Court found that the local laws intended to increase regulatory requirements on oil and gas development were preempted by existing state law and were therefore invalid. See Hydraulic Fracturing, below.
In April 2015, we entered into a joint consent decree (Consent Decree) with the EPA, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court of Colorado on June 2, 2015 and requires us to perform certain activities. All fines required under the Consent Decree were paid in 2015; however, the required injunctive relief remains ongoing. Based on currently available information, we have concluded that the remaining obligations will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 1A. Risk Factors – Our operations require us to comply with a number of US and international laws

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and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business and Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.
Texas  Texas has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells.
In February 2012, the Texas Railroad Commission (RRC) implemented a hydraulic fracturing disclosure rule, requiring Texas oil and gas operators to disclose on the FracFocus website, chemical ingredients and water volumes used in hydraulic fracturing treatments.
In May 2013, the RRC issued an updated “well integrity rule” that addresses requirements for drilling, casing and cementing wells. The rule also includes new testing and reporting requirements, including clarifying that cementing reports must be submitted after well completion or after cessation of drilling, whichever is earlier.
In October 2014, the RRC adopted new permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. The RRC has used this authority to deny permits for waste disposal wells.
US Offshore Regulatory Developments Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject to regulation by BSEE and BOEM. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (OCSLA). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, were imposed by BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident.
In April 2016, the BSEE issued a final rule entitled “Oil and Gas and Sulfur Operations in the Outer Continental Shelf - Blowout Preventer Systems and Well Control,” which updates standards for blowout prevention systems and other well controls for offshore oil and gas activities conducted in US federal waters, including the Gulf of Mexico. The final rule, which went into effect on July 28, 2016, increases the costs associated with well design, drilling and completion operations, as well as ongoing monitoring costs for our wells in the Gulf of Mexico. More recently, pursuant to executive orders dated March 28, 2017, and April 28, 2017, the BSEE initiated a review of whether the final rule is consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. On October 24, 2017, the BSEE announced - in a report published by the Department of Interior - that it is considering several revisions to the rule and that it is in the process of determining the most effective way to engage stakeholders in the process.
Also, in April 2016, the BOEM published a proposed air quality rule that would significantly broaden the obligations of operators and lessees in the Outer Continental Shelf, including the Gulf of Mexico, to assess, report and, when appropriate, control emissions. Among other items, the proposed rule would expand the types of emissions that must be measured, change the boundary for evaluating air emissions, and increase the scope of sources that must be addressed. If adopted as proposed, the new rule would likely increase the cost associated with our activities in the Gulf of Mexico. Pursuant to the Executive Orders, the BOEM is reviewing the proposed air quality rule. On October 24, 2017, the Department of Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.
Additionally, in order to cover the various decommissioning obligations of lessees on the OCS, the BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The BOEM recently updated its regulations and program oversight to establish more robust risk management, financial assurance and loss prevention requirements for oil and gas operations in the Outer Continental Shelf, including the Gulf of Mexico. On July 14, 2016, the BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures the agency will be using to determine a lessee’s or operator's ability to carry out decommissioning obligations for activities in the Outer Continental Shelf, including the Gulf of Mexico. This revised policy institutes new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active in the Outer Continental Shelf. If the BOEM determines under the revised policy that a lessee or operator does not have the financial ability to meet its decommissioning and other obligations, that lessee or operator will be required to post additional financial security as assurance. The revised policy originally became effective September 12, 2016; however, the BOEM extended the implementation timeline for six months in certain circumstances. Pursuant to the Executive Orders, the BOEM is reviewing the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, the BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. We estimated the impact of the new financial criteria on our operations in the Gulf of Mexico and do not believe that the revised policy will have a material impact on our operations in the Gulf of Mexico, or on our financial position or cash flows.

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The National Oceanic and Atmospheric Administration (NOAA) is proposing to expand the boundaries of the Flower Garden Banks National Marine Sanctuary in the Gulf of Mexico. NOAA released its draft environmental impact statement (DEIS) on the proposed expansion in June 2016, in which it proposed five alternatives for expanding existing sanctuary regulations to new geographic areas. Two of these alternatives for sanctuary expansion have the potential to impact certain of our leases which could increase drilling, operating and decommissioning costs. The comment period for the expansion alternatives outlined in the DEIS expired on August 19, 2016 and the issuance of NOAA's report recommending alternatives is expected in early 2018. We are currently evaluating the expansion alternatives and assessing any potential impact on our operations in the Gulf of Mexico.
Climate Change In recent years, the EPA has finalized a series of greenhouse (GHG) gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. In addition, almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs.
At the international level, in December 2015, the United States signed the Paris Agreement on climate change and pledged to take efforts to reduce GHG emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, in August 2017, the United States notified the United Nations that it would be withdrawing from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. While the Administration expressed a clear intent to cease implementing the Paris Agreement, it is not clear how it plans to accomplish this goal, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
The current state of development of the ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of renewable energy, could have a significant impact on our future operations and reduce demand for our products. See also Items 1. and 2. Business and Properties - Regulations and Item 1A. Risk Factors.
Impact of Dodd-Frank Act Section 1504 In June 2016, the Securities and Exchange Commission (SEC) adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount of payments made to a foreign government, including subnational governments (such as states and/or counties), or the US federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).
However, on February 14, 2017, through the signing of a joint resolution passed by the United States Congress under the Congressional Review Act, the Resource Extraction Issuer Payment Rules were eliminated. It should be noted that Section 1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement rules to implement Section 1504 of the Dodd-Frank Act, and that under the Congressional Review Act a rule may not be issued in “substantially the same form” as the disapproved rule unless it is specifically authorized by a subsequent law. We cannot predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated pursuant to the Congressional Review Act.
Israel Regulatory Environment
Natural Gas Policy and Antitrust Authority The Framework, as adopted by the Government of Israel, provides clarity on numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters. The Framework provides for the reduction of our ownership interest in the Tamar and Dalit fields to 25% by year-end 2021, while enabling the marketing of Leviathan natural gas to Israeli customers. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestiture and Merger.
Israeli Tax Law  Effective December 21, 2016, the Israeli government decreased the corporate income tax rate from 25% to 24% for 2017 and announced a further rate decrease from 24% to 23% effective January 2018. The change decreased the deferred tax expense for 2017 by $12 million. Furthermore, our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011, which imposes a separate additional tax on profits from oil and gas activities (Profits Tax). See Item 8. Financial Statements and Supplementary Data – Note 11. Income Taxes.
Hydraulic Fracturing 
Hydraulic fracturing techniques have been used for decades on the majority of all new onshore crude oil and natural gas wells drilled domestically. The process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply

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with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into those aquifers. To help reduce our operational demand for freshwater and need for disposal, we are currently developing technology and infrastructure to expand our water recycling capacity in the DJ and Delaware Basins. We believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the environment or public health. 
Although hydraulic fracturing is regulated primarily at the state level, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.
In addition, on March 26, 2015, the Bureau of Land Management (BLM) published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. On March 28, 2017, an executive order was signed, directing the BLM to review the rule and, if appropriate, to initiate a rulemaking to rescind or revise it. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.
Furthermore, governments and agencies at all levels from federal to municipal are studying the potential environmental impacts of hydraulic fracturing and evaluating the need for further requirements. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
In June 2012, OSHA and the National Institute of Occupational Safety and Health (NIOSH) issued a joint hazard alert for workers who use silica (sand) in hydraulic fracturing activities. The following year saw the agency formally propose to lower the permissible exposure limit for airborne silica. In 2016, OSHA finalized a lower exposure limit for silica along with stricter silica work practices. For hydraulic fracturing, the new obligations start to take effect in 2018. OSHA also has prepared guidance identifying additional workplace hazards resulting from hydraulic fracturing and ways to reduce exposure to those hazards.
To date, hydraulic fracturing has been regulated primarily at the state level, and all of the states where our US onshore operations are located (including Colorado and Texas) have developed such requirements. See Regulations - Colorado and Texas, above. Also, state and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity, which some have termed "induced seismicity." In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies have modified their regulations to account for induced seismicity with regard to the operation of injection wells used for oil and gas waste disposal. Increased regulation and attention given to induced seismicity in the states where we operate could lead to greater opposition, including litigation, to oil and gas activities utilizing injection wells for waste disposal. 
Several states, including Colorado and Texas, have adopted regulations requiring disclosure of certain information regarding the components and chemicals used in the hydraulic-fracturing process. These state regulations allow disclosure through the public registry FracFocus.org, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council. Disclosure through the FracFocus web site includes ways to protect proprietary information and we are currently providing disclosure information on FracFocus.org for all US onshore areas in which we operate. 
Additional Information See: 

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Risk and Insurance Program
As protection against financial loss resulting from many, but not all operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of production income), employer's liability, third party liability, worker's compensation insurance and certain insurance related to cyber security. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and availability of insurance and the company's ability to sustain uninsured losses, and revise our insurance program accordingly.
Availability of insurance coverage, subject to customary deductibles and recovery limits, for certain perils such as war or political risk is often excluded or limited within property policies. In Israel and Equatorial Guinea, we insure against acts of war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally, as being part of critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery through the fund is not guaranteed.
We have a risk assessment program that analyzes safety and environmental hazards, including cyber threats, and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We also use third party consultants to help us identify and quantify our risk exposures at major facilities. We have a robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial condition, results of operations and cash flows. See Item 1A. Risk Factors.
Undeveloped Oil and Gas Leases
Oil and gas exploration is a lengthy process of obtaining data, evaluating, and de-risking prospects, and it takes time to develop resources in a responsible manner. The period of time from lease acquisition to discovery can take many years of ongoing effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the host government. It may take years for us to assemble sufficient acreage to cover the areal extent of a prospect that we wish to explore.
Once the acreage position is assembled, we obtain seismic data either through purchase of available data or by contracting for seismic services. Our exploration staff then begin a lengthy process of analyzing the seismic and other data in order to identify a potential optimal location for drilling an initial exploratory well. Once we decide to drill an exploratory well, we must obtain permits and contract a drilling rig with the specifications for the depth and well pressures which we expect to drill.
If there is a discovery, we may need to obtain additional data and/or drill appraisal wells in order to estimate the extent of the reservoir and the volume of resources that could potentially be recovered. Appraisal or development drilling requires additional time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies.
Competition 
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors.
Employees 
As of December 31, 2017, we had 2,277 full-time employees.

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Offices 
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional regional exploration and/or production offices primarily in Denver, Colorado; Greeley, Colorado; Pecos, Texas; Dilley, Texas; and in Israel, Cyprus, and Equatorial Guinea. 
Title to Properties 
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under PSCs or exploration licenses. We have also dedicated certain of our US onshore acreage to Noble Midstream Partners for the provision of midstream services to us.
Furthermore, while the majority of our assets are held by production, certain of our assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Title Defects Subsequent to a lease or fee interest acquisition transaction, the buyer usually has a period of time in which to examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement, which may provide for arbitration between the buyer and seller.
Conflicts with Surface Rights Mineral rights are property rights that include the right to use land surface that is reasonably necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently pending in several states. In several cases, owners of surface rights are suing various companies to prevent companies from using their land surface to drill horizontal wells to explore for or produce hydrocarbons from neighboring mineral tracts. If a plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well pads and/or limit the length of horizontal wells drilled from a pad.
Available Information
Our website address is www.nblenergy.com. Available on this website under “Investors – Financial Information – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.
Also posted on our website under “Our Story – Transparency – Corporate Governance - Committee Charters”, and available in print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Environment, Health and Safety Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are also posted on our website under the “Other Governance Documents” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. 
If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks. 
The oil and gas industry is cyclical and an extended period of suppressed commodity prices could have material adverse effects on our operations, our liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our cash flow and pay dividends on our common stock depend upon the prices we receive for our crude oil, natural gas, and NGL production. Commodity prices are cyclical and subject to supply and demand dynamics. For the past three years, following the significant decline that began in late 2014, crude oil prices, in particular, have been trading in a much lower range. While we have witnessed a certain degree of commodity price improvement, we expect that economic, geopolitical, and supply and demand forces will remain volatile. As a

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result we may continue to operate in a soft market, with sustained lower commodity prices, subject to further decline if the excess of supply over demand increases.
If commodity prices continue to trade at low or lower levels for an extended period, one or more of the following could occur:
significant reductions of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically, leading to shut-in or early abandonment of producing wells and increased capital requirements for abandonment operations;
certain properties in our portfolio becoming economically unviable;
impairments of proved or unproved properties or other long-lived assets;
loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
reduction, or suspension, of our 2018 or future capital investment programs, resulting in a reduced ability to develop our reserves;
delay, postponement or cancellation of some of our exploration or development projects;
inability to meet exploration commitments, leading to loss of leases or exploration rights;
divestments of properties to generate funds to meet cash flow or liquidity requirements;
limitations on our financial condition, liquidity, including access to sources of capital, such as debt and equity, and/or ability to finance planned capital expenditures and operations;
failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows;
inability to meet scheduled interest and/or debt payments or payments due under operating or capital leases;
a series of credit rating downgrades or other negative rating actions which could increase our cost of financing and may increase our requirements to post collateral as financial assurance of performance under certain other contracts which, in turn, could have a negative impact on our liquidity;
changes in corporate structure that could lead to loss of key personnel and interrupt our business activities; and
reduction or suspension of dividends on our common stock.
In addition, lower commodity prices, including declines in commodity forward price curves, may result in the following:
declines in our stock price;
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
a reduction in the carrying value of goodwill.
Our hedging arrangements in place will not fully mitigate the effects of commodity price volatility.
Furthermore, certain crude oil demand estimates suggest a hypothetical point in the future when global oil demand reaches its peak demand level. The International Energy Agency's 450 Scenario sets out an energy pathway consistent with the goal of limiting the global increase in temperature to 2°C by limiting concentration of greenhouse gases in the atmosphere to around 450 parts per million of CO2. Under this scenario, global oil demand peaks by 2020, and the subsequent decline in demand accelerates year-on-year, so that by the late 2020s global demand is falling by over one million barrels per day every year. This decline in demand, if it occurs, would negatively impact commodity prices as well as our ability to explore for and develop our crude oil and natural gas resources.
Markets and prices for crude oil, natural gas and NGLs depend on factors beyond our control, factors including, among others:
global demand for crude oil, natural gas and NGLs as impacted by economic factors that affect gross domestic product growth rates of countries around the world;
global supply for crude oil, natural gas and NGLs as impacted by OPEC and non-OPEC countries (e.g. US, Russia, Canada);
technology advances that increase crude oil, natural gas and NGL production, thereby increasing supply;
new technologies that promote fuel efficiency and reduce energy consumption;
developments in the global LNG market, including exports from the US;
geopolitical conditions and events, including generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, or instability/armed conflict in hydrocarbon-producing regions;
fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is generally denominated;
the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels, as well as the availability of battery storage;
the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on demand for crude oil as a transportation fuel;

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the availability of pipeline capacity/infrastructure as well as refining capacity;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
the effectiveness of worldwide conservation measures;
weather conditions;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Sector cost inflation could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and third party oilfield materials, service and supply costs are also subject to supply and demand dynamics. During periods of decreasing levels of industry exploration and production, the demand for, and cost of, drilling rigs and oilfield services decreases. Conversely, during periods of increasing levels of industry activity, the demand for, and cost of, drilling rigs and oilfield services increases.
During 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equipping and operating wells and infrastructure began to experience some inflation. If this trend continues, and if the commodity price recovery is robust, we expect industry exploration and production activities to continue to increase, resulting in even higher demand for oilfield services and supplies, which could result in significant sector price inflation. In addition, the costs of such items could increase and their availability may become limited, particularly in basins of relatively higher activity. Potential scarcity of competent service personnel may impact our ability to execute our exploration and development plans in a timely and profitable manner.
In addition, regulatory changes, such as those related to hydraulic fracturing or water disposal, may also result in reduced availability and/or higher costs for rigs and services. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment.
Our international operations may be adversely affected by economic and geopolitical developments.
We have significant international operations, with approximately 27% of our 2017 total consolidated sales volumes and approximately 52% of our total proved reserves as of December 31, 2017 attributable to our international operations in Israel and Equatorial Guinea. We also conduct exploration activities in other international areas. Our operations may be adversely affected by political and economic developments, including the following:
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;
disruptions caused by territorial or boundary disputes in certain international regions;
changes in drilling or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events, and regional instability or armed conflict in the region;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business;
war, piracy, acts of terrorism or civil unrest; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such political and economic developments could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
Our operations may be adversely affected by changes in the fiscal regimes and related government policies and regulations in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access along with government participation in oil and gas projects, royalties and taxes. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government financial take from developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular

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country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in or uncertainties related to the fiscal regimes of these countries could have a significant impact on our operations and financial performance. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws or the effect such interpretations could have on our business.
Many governments globally are seeking additional revenue sources, including, potentially, increases in government financial take from oil and gas projects. In developing nations, governments may seek additional revenues to support infrastructure and economic development and for social spending. In many nations of the Organisation for Economic Cooperation and Development (OECD), governments continue to incur significant budget deficits and growing national debt levels, as well as pressure from financial markets to address structural spending imbalances.
The OECD Base Erosion and Profit Sharing (BEPS) initiative aims to standardize and modernize global tax policy and disclosure of financial and operational data with tax authorities. The BEPS's recommendations are being widely adopted by the majority of the foreign jurisdictions in which we operate and many of these jurisdictions are party to the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting. Progress on the implementation of BEPS measures and development of tax authority interpretation could result in changes to tax policies, including transfer pricing policies. To the extent such changes significantly increase the overall tax imposed on currently producing projects, these projects could become less economic, or wholly uneconomic, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges.
Changes in fiscal regimes have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations and our stock price in the following ways, among others:
restrict resource access or investment in lease holdings;
limit or cancel exploration and/or development activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
have a negative impact on the ability of us and/or our partners to obtain financing;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow; and/or
restrict our ability to compete with imported volumes of crude oil or natural gas.

Tax laws and regulations may change over time, and could adversely affect our business and financial condition.
On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation). The Tax Reform Legislation, among other things, (i) permanently reduces the US corporate income tax rate to 21% beginning in 2018, (ii) repeals the corporate alternative minimum tax (AMT) allowing for corresponding refunds of prior period AMT credits,  (iii) provides for a five year period of 100% bonus depreciation followed by a phase-down of the bonus depreciation percentage, (iv) imposes a new limitation on the utilization of net operating losses generated in taxable years beginning after December 31, 2017, and (v) provides for more general changes to the taxation of corporations, including changes to the deductibility of interest expense, the adoption of a modified territorial tax system, assessing a repatriation tax or “toll-charge” on undistributed earnings and profits of US-owned foreign corporations, and introducing certain anti-base erosion provisions. The Tax Reform Legislation is complex and far-reaching and could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs.  The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and our business and financial condition could be adversely affected.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to US federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Reform Legislation, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. The elimination of such US federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.

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We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
Our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil, natural gas and NGLs. As the various government and/or regulatory bodies issue or rescind various regulations, our operations are subject to significant volatility in response to the issuance, interpretation and application of these regulations.
Changes in price controls, taxes and environmental laws relating to our industry have the ability to substantially affect crude oil, natural gas and NGL production, operations and economics. Environmental laws, in particular, can change frequently, often become stricter and at times may force us to incur additional costs as changes are implemented.
We cannot always predict with certainty how agencies or courts will interpret existing laws and regulations or the effect these interpretations may have on our business or financial condition.
Additionally, the unintentional discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to liabilities on our part to government agencies and/or third parties, and may require us to incur costs to achieve remediation objectives and/or requirements.
In April 2015, for example, we entered into a Consent Decree with the US EPA, US Department of Justice and State of Colorado to improve emission control systems at a number of our condensate storage tanks in the DJ Basin. The Consent Decree required us to pay a civil penalty and to perform certain injunctive relief activities, mitigation projects, and supplemental environmental projects. We continue to incur costs associated with these activities. In addition, compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries within the Non-Attainment Area of the DJ Basin.
Noncompliance with existing or future legislation or regulations could potentially result in an increased risk of civil or criminal fines or sanctions. For example, fines or sanctions associated with a well incident or spill could well exceed the actual cost of containment and cleanup.
Further expansion of environmental, safety and performance regulations or an increase in liability for drilling or production activities, including punitive fines, may have one or more of the following impacts on our business:
increase the costs of drilling exploratory and development wells;
cause delays in, or preclude, the development of our projects resulting in longer development cycle times;
result in additional operating and capital costs;
divert our cash flows from capital investments in order to maintain liquidity;
increase or remove liability caps for claims of damages from oil spills;
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
Any of the above operating or financial factors may result in a reduction of our cash flows, profitability, and the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in our financial responsibility could result in certain of our planned projects becoming uneconomic. See Items 1. and 2. Business and Properties – Regulations.
We face various risks associated with global populism and general political uncertainty.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in previous decades. This has resulted in economic stagnation for certain citizens and, as a result, there are concerns around jobs, economic well-being and wealth distribution. Globally, certain individuals and organizations are attempting to focus the public's attention on income and wealth distribution and implement income and wealth redistribution policies.
In addition, if efforts to challenge and change individual and/or corporate taxation are successful, they could result in increased taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions. These measures would further burden companies and individuals with additional tax costs.
Recent events have intensified these risks. In the US, the growing trends toward populism and political polarization, has resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations and international trade policies. Global uncertainty and/or reductions in global trade activities could contribute to slower economic growth which could negatively impact business and commerce.
Potential changes in relationships among the US, China and Russia, or among China, Russia and other countries, can have significant impacts on the balance of power, as well as on global trade, with further impacts on both global and local

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economies. In addition, changes in the relationships between the US and its neighbors, such as Mexico, can have significant, potentially negative, impacts on commerce. In Europe, the populist movement has resulted in the Brexit vote and increasing populist demands and rises in nationalism could have a negative impact on economic policy and consequently pose a potential threat to the unity of the European Union.
Our ability to respond to these developments or comply with any resulting new legal or regulatory requirements, including those involving economic and trade sanctions, as well as any potential increased tax expense, could reduce our ability to negotiate the sale of our products, increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.
We face various risks associated with the trend toward increased anti-oil and gas development activity.
In recent years, we have seen significant growth in opposition to oil and gas development both in the US and globally. 
Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition is focused on attempting to limit or stop hydrocarbon development. Examples of such opposition include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting or banning industry techniques such as hydraulic fracturing, and/or adding restrictions on or the use of water and associated disposal; imposition of set-backs on oil and gas sites; delaying or denying air-quality permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. We have experienced these efforts in Colorado in the past and it is likely they will continue into the future. Recent efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, financial condition and results of operations. 
Restricted land access could reduce our ability to explore for and develop crude oil, natural gas and NGL reserves.
Our ability to adequately explore for and develop crude oil, natural gas and NGL resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:
new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
landowner, community and/or governmental opposition to infrastructure development;
regulation of federal and Indian land by the BLM;
anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;
the presence of threatened or endangered species or of their habitat;
disputes regarding leases; and
disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.
Loss of access to land for which we own mineral rights could result in a reduction in our proved reserves and a negative impact on our results of operations and cash flows. Reduced ability to obtain new leases could constrain our future growth and opportunity set by limiting the expansion of our upstream portfolio. In addition, loss of rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, could disrupt or prohibit our ability to construct or operate midstream assets and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
A change in international and/or US federal and state climate policy could have a significant impact on our operations and profitability.
Domestic and international response to climate and related energy issues are matters of public policy consideration. We are currently in a period of increasing uncertainty as to these matters, and, at this time, it is difficult to anticipate how the current US Administration, or other entities, may act on exiting or new laws and regulations. As compared with certain large multi-national, integrated energy companies, we do not conduct fundamental research regarding the scientific inquiry of climate change. However, we will continue to closely monitor all relevant developments in this regard. Changes in international, federal or state laws and regulations regarding climate policy could have a significant negative impact on our ability to explore for and develop crude oil and natural gas resources or reduce demand for our products.

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In recent years, international, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of states in the US have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties - Regulations.
In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or other entities may make claims against us for alleged personal injury, property damage, or other potential liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured.
Our Eastern Mediterranean discoveries bear certain geopolitical, regulatory, financial and technical challenges that could adversely impact our ability to monetize these natural gas assets.
We have entered into and are currently negotiating various long-term GSPAs for our Eastern Mediterranean natural gas assets. Some of these agreements would require the export of natural gas from either Israel or Cyprus to other countries in the region, such as Egypt and Jordan. These agreements are subject to a variety of risks, including geopolitical, regulatory, financial and other uncertainties. War, political violence, civil unrest or lack of intergovernmental cooperation could affect both our and our counterparties’ abilities to cooperate and to perform under these agreements, and could potentially lead to a breach or termination of such agreements. In addition, economic conditions or financial duress of our counterparties could jeopardize their ability to fulfill their payment obligations under these contracts. Furthermore, if material disruptions occur, including events or circumstances constituting force majeure under contract provisions, such that they inhibit us or our counterparties from performing under these GSPAs, or our counterparties are unable to pay us for a sustained period of time, we could incur significant financial losses. While the State of Israel continues to maintain its ability to generate electricity via coal-fired power plants, as they transition from coal-fired power plants to natural gas-fired power plants, they become more dependent on us and our partners for their source of natural gas supply. Any material disruption in our ability to deliver natural gas to the State of Israel could have a material impact on our expected profitability, financial performance and reputation.
We are subject to certain regulatory provisions under the Framework, as adopted by the Government of Israel, including a requirement to reduce our ownership in the Tamar and Dalit fields to 25% by the end of 2021. We recently signed a definitive agreement to divest a 7.5% working interest in each of the fields to Tamar Petroleum Ltd., closing of the transaction is subject to satisfactory conclusion of certain conditions, including Tamar Petroleum's debt financing. Upon closing, we will receive consideration of both cash and Tamar Petroleum Ltd. shares, approximating 70% and 30%, respectively, of the transaction value, which will fluctuate based on market conditions. In accordance with the Framework, we must divest Tamar Petroleum Ltd. shares received by the end of 2021. In addition, changes in Israel's fiscal and/or regulatory regimes or energy policies occurring as a result of government policy on natural gas development and/or exports could delay or reduce the profitability of our Tamar and/or Leviathan development projects, and/or render future exploration and development projects uneconomic.
Development of our Eastern Mediterranean natural gas assets requires substantial investment and will take several years to complete. Our partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. If our project partners' cash flows or ability to maintain adequate financing are negatively impacted through similar risks factors described herein, the development of a project could be delayed and the timing and receipt of planned cash flows and expected profitability could be negatively impacted.

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Due to the scale of our Leviathan (Israel) and Aphrodite (Cyprus) discoveries, realization of their full economic value depends on our ability to execute successful phased, development scenarios, the failure or delay of which could reduce our future growth and have negative effects on our future operating results. Offshore projects of this magnitude entail significant technical complexities including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. In addition, we depend on third-party technology and service providers and other supply chain participants for these complex projects. Delays and differences between estimated and actual timing of critical events related to these projects could have a material adverse effect on our results of operations.
Concentration of capital in, and production and cash flows from, certain operations may increase our exposure to risks enumerated herein.
A significant portion of our production and revenues is highly concentrated and is generated from a limited number of conventional deepwater wells. These wells, located in the Gulf of Mexico, offshore Israel and offshore Equatorial Guinea, contributed approximately 33% of our 2017 total consolidated revenues and 34% of our 2017 total consolidated sales volumes. In addition, with the recording of reserves associated with the initial development of the Leviathan field, we now have a major concentration of reserves offshore Israel, with approximately 47% of our year-end 2017 proved reserves attributable to this area. These fields are also capital and resource-intensive.
Although we carry contingent business interruption for these producing assets, as well as other insurance, the insurance may be insufficient to cover all of risks including, a disruption to downstream operations impacting the processing, marketing and distribution of our production, such as from an accident, natural disaster, government intervention or other event, would have a significant impact on our production profile, cash flows, profitability, and overall business plan.
We also have significant concentrations of capital and production in unconventional basins including the DJ Basin, Delaware Basin and Eagle Ford Shale, and we expect to invest approximately 65%, of our total capital investment program to development activities in these areas in 2018. Restrictions in land access, rapid changes in drilling and completion technology, significant increases in drilling and completion costs, lack of availability of downstream services, changes in regulations and other risks impacting these areas, as enumerated in certain risk factors described herein, can have immediate, significant negative impacts on our production, cash flows, profitability and financial position.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities in deepwater, ultra-deepwater and shale, as well as technologies supporting midstream operations and global competition for oil and gas resources make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.

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Index to Financial Statements

Certain regions, such as the Middle East and Africa, continue to experience varying degrees of political instability, public protests and terrorist attacks. We operate in regions of the world that have experienced such incidents or are in close proximity to areas where violence has occurred. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued or escalated civil and political unrest and acts of terrorism in the regions in which we operate could result in curtailment of our operations. In the event that regions in which we operate experience civil or political unrest or acts of terrorism, especially in areas where such unrest leads to regime change, our operations in such regions could be materially impaired.
We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results, among others:    
increased volatility in global crude oil, natural gas and NGL prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
negative impact on the global crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel or supplies to enter or exit the countries where we are conducting operations;
disruption of our operations due to evacuation of personnel;
inability to deliver our production due to disruption or closing of transportation routes;
reduced ability to export our production due to efforts of countries to conserve domestic resources;
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of natural gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;
inability of our service and equipment providers to deliver items necessary for us to conduct our operations;
lack of availability of drilling rigs, oilfield equipment or services if third party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
Loss of property and/or interruption of our business plans resulting from civil unrest could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.
Exploration, development and production activities carry inherent risk. These activities, as well as natural disasters or adverse weather conditions, could result in liability exposure or the loss of production and revenues.
Our crude oil and natural gas operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil, natural gas and NGLs, including:
pipeline ruptures and spills;