Noble Energy Inc.
NOBLE ENERGY INC (Form: 10-K, Received: 02/14/2017 10:49:49)
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, 2016
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

IMAGE0A16.JPG

NOBLE ENERGY, INC .
(Exact name of registrant as specified in its charter)
Delaware
 
73-0785597
(State of incorporation)
 
(I.R.S. employer identification number)
1001 Noble Energy Way
 
 
Houston, Texas
 
77070
(Address of principal executive offices)
 
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, $0.01 par value
 
New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ý Yes o No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes ý No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o No 
Indicate by check mark whether the registrant has submitted electronically 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 or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting 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
 
(Do not check if a smaller reporting company)
 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, 2016 : $15.4 billion .
Number of shares of Common Stock outstanding as of December 31, 2016 : 430,524,340 .
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2017 Annual Meeting of Stockholders to be held on April 25, 2017, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2016 , are incorporated by reference into Part III.



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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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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, development, and acquisition activities;
our ability to make and integrate acquisitions;
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; 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 a leading independent crude oil and natural gas exploration and production company with a diversified high-quality portfolio spanning three continents and consisting of both US unconventional and global offshore conventional assets. 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 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 conventional basins. We endeavor to maintain a high-quality, growth-oriented portfolio of assets that are well-positioned on the global industry cost supply curve. In addition, our asset portfolio offers operational and investment flexibility.
In US unconventional basins, we have demonstrated competence in applying geological capabilities, drilling and completion expertise and midstream synergies to deliver incremental value. In onshore US, we typically apply a major project development concept to a US unconventional basin by utilizing an Integrated Development Plan (IDP) approach. In the global offshore, we have had notable exploration successes over the past decade, which have led to our entry into new conventional offshore basins, and have executed several major offshore development projects both on schedule and within budget which have provided long-lived cash flows to our business.

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Approximately 75% of our 2017 capital program is allocated to US onshore development, primarily focused on liquids-rich opportunities in the DJ Basin, Delaware Basin and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including initial development costs associated with the Leviathan project, represent over 20% of the total. As we manage our asset portfolio, we will consider expanding the portfolio to include additional long-term and/or large-scale exploration opportunities.
In addition, the majority of our assets are held by production, which provides 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-diversified, growing portfolio delivering attractive financial returns.
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 numerous areas of interest. Our activities include geophysical and geological evaluation; analysis of commercial, regulatory and political risks; and exploratory drilling, 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 midstream assets primarily used in the processing and transportation of our onshore US production.
The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
GLOBALMAPOFOPERATIONSA04.JPG
Operating Segments We manage our operations by region. Our segments, each of which is primarily in the business of crude oil, natural gas and NGL exploration, development, production and acquisition, include:
United States, including the onshore DJ Basin, Permian Basin, Eagle Ford Shale, Marcellus Shale, and offshore deepwater Gulf of Mexico, as well as the consolidated accounts of Noble Midstream Partners LP (Noble Midstream Partners), which completed its initial public offering of common units in 2016;
Eastern Mediterranean, including offshore Israel and Cyprus;
West Africa, including offshore Equatorial Guinea, Cameroon, and Gabon; and
Other International and Corporate, including new ventures such as offshore the Falkland Islands, Suriname, and Newfoundland.  
Development Activities Our development projects have resulted from both exploration success as well as periodic strategic acquisitions. These projects provide multiple opportunities for consistent 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 offer sustained cash flows and attractive financial returns, while generally increasing net asset value over the oil and gas business cycle.

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Onshore US, our low production-risk development programs, typically centered around IDPs, provide a stable base of production. These programs, which have delivered significant historical production growth, 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 the Tamar natural gas development, offshore Israel, which is currently undergoing expansion. We are also progressing a final investment decision for 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.
Exploration Activities   We primarily focus on organic growth from exploration and development drilling activities, concentrating on basins or plays where we have strategic competitive advantages. 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 deepwater 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 over the past decade.
In 2016, we performed limited exploration activities due to the commodity price environment. Also, after review of additional 3D seismic data, modeling and economic assessment, we determined that certain discoveries offshore West Africa were impaired in the current forward outlook for crude oil prices and wrote off related capitalized costs of $468 million , which is included in exploration expense. See International – West Africa (Equatorial Guinea, Cameroon and Gabon) discussion, below.
For 2017, we anticipate engaging in seismic acquisition and processing and potentially drilling an exploratory well offshore Suriname.
Acquisition and Divestiture Activities We maintain an ongoing portfolio management program. Accordingly, we may 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. We may also periodically divest assets through asset or equity sales, exchanges, dissolutions of joint ventures or other transactions.
During 2016, we generated cash of approximately $1.5 billion through asset sales and the initial public offering of Noble Midstream Partners common units.
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 3. Acquisitions, Divestitures and Merger .
Pending Acquisition of Clayton Williams Energy, Inc. On January 13, 2017, we executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc. (Clayton Williams Energy) for $2.7 billion in Noble Energy stock and cash. The acquisition includes 71,000 highly contiguous net acres in the core of the Southern Delaware Basin in Reeves and Ward counties in Texas (directly adjacent to our existing 47,200 net acres). In addition, there are an additional 100,000 net acres in other areas of the Permian Basin. The acquisition provides for increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential, adds to our midstream assets and provides future midstream buildout opportunities.
The transaction has been unanimously approved by the Boards of Directors of both Noble Energy and Clayton Williams Energy and is subject to approval by stockholders of Clayton Williams Energy. If approved, Clayton Williams Energy stockholders will receive 2.7874 shares of Noble Energy common stock and $34.75 in cash for each share of common stock held. In the aggregate, this totals 55 million shares of Noble Energy stock and $665 million in cash. The enterprise value of the transaction, based on Noble Energy's closing stock price as of January 13, 2017, is approximately $3.2 billion in the aggregate including the assumption of approximately $500 million in net debt. We intend to fund the cash portion of the acquisition through a draw on our revolving credit facility.
Closing is expected to occur second quarter 2017 and is subject to customary regulatory approvals, approval by the holders of a majority of Clayton Williams Energy common stock, and certain other conditions.

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Proved Oil and Gas Reserves    Proved reserves at December 31, 2016 were as follows:
 
 
December 31, 2016
 
 
Proved Reserves
 
 
Crude Oil and
Condensate
 
Natural Gas
 
NGLs
 
Total
Reserves Category
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe) (1)
Proved Developed
 
 
 
 
 
 
 
 
United States
 
138

 
1,817

 
113

 
554

Israel
 
3

 
1,600

 

 
270

Equatorial Guinea

 
34

 
486

 
12

 
127

Total Proved Developed Reserves
 
175

 
3,903

 
125

 
951

Proved Undeveloped
 
 

 
 

 
 

 
 

United States
 
158

 
1,021

 
94

 
422

Israel
 

 
384

 

 
64

Total Proved Undeveloped Reserves
 
158

 
1,405

 
94

 
486

Total Proved Reserves
 
333

 
5,308

 
219

 
1,437

(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 1,437 MMBoe as of December 31, 2016 as compared with 1,421 MMBoe as of December 31, 2015 . Changes primarily included the following:
positive revisions of 117 MMBoe related to our onshore US horizontal drilling programs and Alba field, offshore Equatorial Guinea, driven by increased well performance and/or lower operating or development costs in onshore US and the startup of the Alba B3 compression platform; and
extensions and other additions of 179 MMBoe related to our onshore US horizontal drilling programs due to successful expansion of our extended reach lateral well programs;
offset by:
production volumes of 154 MMBoe;
negative revisions of 53 MMBoe that were commodity price driven; and
reduction of 77 MMBoe primarily due to our 3.5% reduction in ownership in Tamar, the impact of the Marcellus Shale acreage exchange, and other smaller onshore US divestitures.
Our proved reserves are 68% US and 32% international, and the mix is 38% global liquids (crude oil and NGLs), 29% international natural gas and 33% 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.

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United States
We have been engaged in crude oil, natural gas and NGL exploration and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 73% of 2016 total consolidated sales volumes and 68% of total proved reserves at December 31, 2016 . Approximately 48% of the proved reserves in the US are natural gas, 30% are crude oil and condensate and 22% are NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows: 
 
 
Year Ended December 31, 2016
 
December 31, 2016
 
 
Sales Volumes
 
Proved Reserves
 
 
Crude Oil &
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
Crude Oil &
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
 
(MBbl/d)
 
(MMcf/d)
 
(MBbl/d)
 
(MBoe/d)
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe)
DJ Basin
 
56

 
225

 
21

 
114

 
177

 
981

 
80

 
421

Eagle Ford Shale
 
10

 
129

 
22

 
54

 
30

 
453

 
76

 
181

Permian Basin
 
6

 
9

 
2

 
9

 
56

 
75

 
13

 
82

Marcellus Shale
 
1

 
486

 
8

 
91

 
5

 
1,275

 
36

 
253

Deepwater Gulf of Mexico
 
25

 
20

 
1

 
30

 
24

 
30

 
2

 
31

Other Onshore US
 
1


12




3

 
4

 
24

 

 
8

Total
 
99

 
881

 
54

 
301

 
296

 
2,838

 
207

 
976

Wells drilled in 2016 and productive wells at December 31, 2016 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2016
 
December 31, 2016
 
 
Gross Wells Drilled
or Participated in  (1)
 
Gross Productive
Wells
DJ Basin
 
134

 
6,961

Eagle Ford Shale
 
22

 
318

Permian Basin
 
19

 
242

Marcellus Shale
 
17

 
238

Deepwater Gulf of Mexico
 
2

 
15

Other Onshore US
 

 
21

Total
 
194

 
7,795

(1)  
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being assessed for economic viability. See Drilling Activity, below.

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US Onshore
Our onshore US operations are located in proven basins with long-life production profiles and are typically developed utilizing an IDP, such as in the DJ Basin and now in the Permian Basin. These assets provide low production-risk drilling opportunities that offer predictable and long-term production, and a balanced commodity mix of crude oil, natural gas and NGLs. Locations of our onshore US operations as of December 31, 2016 are shown on the map below:
ONSHOREUSMAP.JPG
DJ Basin With the advent of horizontal drilling technology, the DJ Basin is recognized as a premier US crude oil resource play and is a key driver of our business and future growth. Our position in the area covers approximately 350,000 net acres.
In 2016 and currently, we are focusing our drilling and development activity on IDP areas, such as Wells Ranch and East Pony, allowing us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 80,000 acres). IDP’s are areas of highly contiguous acreage where we can accelerate drilling and completion activities and drill a much higher percentage of extended reach lateral wells. Additionally, our IDP approach has provided an opportunity to efficiently and economically support production growth by constructing and expanding our infrastructure, including constructing our own centralized production facilities, gathering systems, and water infrastructure, across the DJ Basin.
2016 Activity In response to the current commodity price environment, we adopted a reduced but flexible 2016 capital program, and drilling efficiencies gained through longer laterals allowed us to continue an active drilling program in the basin. Operationally, we focused on reducing per unit operating costs while increasing operating efficiencies to support project returns and margin improvements. Through material efficiency gains in drilling, midstream expansions and synergies, and enhanced completion techniques, we were able to deliver 2016 production at lower capital and per unit operating costs than 2015.
Through strategic acreage transactions, we expanded our extended reach lateral well program to approximately 50% of wells drilled in 2016 . During the year, we spud 106 horizontal wells, of which 55 were extended reach lateral wells, and 124 wells initiated production. We also participated in approximately 28 non-operated development wells during 2016.
Through continued active management of our portfolio, we facilitated certain asset monetizations which allow for the acceleration of asset development. In 2016, we:
closed an acreage exchange agreement to receive approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco development area, located southwest of Wells Ranch. The exchange enhances our ability to develop the field by improving our contiguous acreage position, increasing our lateral length potential and optimizing our access to central gathering facilities;
entered into an agreement to divest approximately 33,100 producing and undeveloped net acres in the Greeley Crescent area of Weld County, Colorado for $505 million, representing approximately 8% of our total DJ Basin acreage. We received proceeds of $486 million in 2016 and expect to receive the remaining proceeds in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss. As part of the transaction, all of the acreage in the Greeley Crescent IDP remains subject to dedications to Noble Midstream Partners for crude oil gathering, produced water services and fresh water services; and

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sold certain other producing and non-producing assets, generating net proceeds of $20 million, which were applied to the field basis, with no recognition of gain or loss.
See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for discussion of proved reserves.
The DJ Basin contributed an average of 114 MBoe/d of sales volumes in 2016 , representing approximately 28% of total consolidated sales volumes. DJ Basin sales volumes were approximately 49% crude oil and 18% NGLs. At December 31, 2016 , proved reserves in the DJ Basin represented approximately 29% of our total proved reserves. See Proved Reserves Disclosures, below.
We exited 2016 with a two rig drilling program and intend to increase to three rigs in the second quarter of 2017. We remain engaged in a comprehensive effort to focus on capital and cost efficiencies and have adopted a capital spending program for 2017 that is supported by operating cash flows. Our spending program further provides flexibility to reassess activity levels in response to the commodity price environment as it evolves during the remainder of 2017.
Midstream Activity 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 onshore US midstream investment program. Noble Midstream Partners owns, operates and will develop certain of our DJ Basin crude oil, natural gas and water-related midstream infrastructure and will also develop crude oil and produced water midstream infrastructure in our Delaware Basin position of the Permian Basin.
Permian Basin Our Permian Basin and Eagle Ford assets were added to our portfolio through the merger with Rosetta Resources Inc., on July 20, 2015 (Rosetta Merger), which increased our development inventory and further diversified our portfolio. Our operations in the Permian Basin are focused in Reeves County in the Southern Delaware Basin and as of December 31, 2016 , we held approximately 40,000 net acres in the Delaware Basin and approximately 10,000 net acres in the Midland Basin.
Encouraged by our 2016 well results, we executed strategic leasing initiatives and entered into a bolt-on acquisition, for $295 million, which closed in early 2017. The acquisition included seven producing wells, of which four will be operated by us. The combined transactions added approximately 7,200 net acres with 2,400 Boe/d, net, of production near our producing properties and increased our contiguous acreage position in the Reeves County area.
Including our recently-announced acquisition of Clayton Williams Energy, which is expected to close in second quarter 2017, our Southern Delaware Basin acreage position will increase to approximately 120,000 net acres. See Pending Acquisition of Clayton Williams Energy, Inc., above.
2016 Activity We have tested multiple drilling and completion techniques utilizing slickwater, high intensity completions, increased proppant concentrations and longer laterals, which have led to stronger well performance and capital efficiencies.
In 2016, we operated one to three drilling rigs, drilled nine horizontal wells and commenced production on nine operated wells. In addition, we engaged in the construction of certain midstream assets, including our first central gathering facility, which we expect will be online in 2017.
For 2016 , our assets in the Permian Basin contributed an average of 9 MBoe/d of sales volumes, representing approximately 2% of total consolidated sales volumes, and were approximately 67% crude oil and 17% NGLs. These assets represented approximately 6% of total proved reserves at December 31, 2016 .
For 2017, we started the year with three rigs operating on our current acreage in the Permian Basin, and Clayton Williams Energy started the year with one rig operating on its acreage. We plan to add a second rig to the new acreage in second quarter 2017, following closing of the Clayton Williams Energy acquisition, and a third rig later in the year, in order to exit 2017 with a combined six rigs running in the Delaware Basin. While our 2017 capital program will focus on long laterals, pad drilling and multi-zone testing for our Permian Basin assets, it provides for flexibility and can be modified in response to changes in the commodity price environment.
Eagle Ford Shale Since our entry into the Eagle Ford Shale, we have applied IDP learnings from other onshore US assets to realize cost efficiencies, enhance completion designs and optimize well placement, thereby positively impacting costs and performance associated with our Texas assets.
We hold approximately 35,000 net acres located in the liquids-rich area of the play, including producing assets in Webb and Dimmit counties. Since acquiring these assets, we have worked to optimize drilling and completion designs to further develop both the Upper and Lower Eagle Ford zones, including the utilization of slickwater as a completion fluid and testing varying cluster spacing, lateral lengths and proppant quantities.

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2016 Activity Our 2016 capital program was primarily focused within Webb and Dimmit counties where we operated one to two drilling rigs, drilled 22 horizontal wells and commenced production on 27 operated wells. We also closed the divestiture of certain assets located in La Salle, Atascosa, Live Oak and Dimmit counties where we had not engaged in drilling activities since the Rosetta Merger. Proceeds received totaled $68 million and were applied to the field's basis with no recognition of gain or loss.
For 2016 , our assets in the Eagle Ford Shale contributed an average of 54 MBoe/d of sales volumes, representing approximately 13% of total consolidated sales volumes, and were approximately 19% crude oil and 41% NGLs. These assets represented approximately 13% of total proved reserves at December 31, 2016 .
We exited 2016 with a two rig drilling program and in 2017, we will continue to evaluate results from our development program. Our capital program in 2017 provides flexibility to prudently manage our resources in response to changes in the commodity price environment.
Marcellus Shale   The Marcellus Shale contains a significant quantity of natural gas resources, and its proximity to high-demand East Coast markets has made it a desirable area for development. Infrastructure improvements and expanding firm transportation capacity are expected to improve export of product to areas outside the basin, reduce basis differentials, and have a positive impact on project economics.
In an effort to allow flexibility and enhance control over the pace and scale of development of our Marcellus Shale investment, we and our joint venture partner, CONSOL Energy Inc. (CONSOL), agreed to terminate our 50-50 Joint Development Agreement (JDA) on October 29, 2016 with an effective date of October 1, 2016. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. As a result, we now hold an almost 100% interest in approximately 363,000 acres, primarily located in the wet gas area of northwest West Virginia and a small acreage position in southwest Pennsylvania, with associated sales volumes of approximately 450 MMcfe/d. We anticipate a decline in sales volumes of approximately 100 MMcfe/d in 2017 and our proved reserves as of December 31, 2016 reflect divestment of approximately 185 Bcf (or 25 MMBoe, net of 4 MMBls of NGL reserves acquired) in the Marcellus Shale driven by our asset exchange. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding contingent carry cost obligation of $1.6 billion due from us.
2016 Activity Prior to the termination of the JDA, the joint venture completed 17 wells and initiated production on 42 wells. During the year, we focused on well completions, while not performing any drilling activities in response to low commodity prices. However, operational performance remained strong, with volumes increasing 18% compared to 2015 and we achieved material reductions in operating expense as compared with the prior year.
Our allocated capital investment in the Marcellus Shale was limited to the completion of previously-drilled wells in our non-operating dry gas areas. After the termination of the JDA, we focused on the completion of two wells in our wet gas areas.
The Marcellus Shale contributed an average of 546 MMcfe/d of sales volumes, approximately 22% of total consolidated sales volumes in 2016 , and represented approximately 18% of total proved reserves at December 31, 2016 . See also Proved Reserves Disclosures, below.
Our 2017 capital program is flexible and includes the completion of previously drilled wells. We currently have no rigs running in the Marcellus Shale but have the potential to add one rig at year-end 2017.
CONE Gathering We and CONSOL each own a 50% interest, and have joint control of CONE Gathering LLC (CONE Gathering), which constructs, owns and operates midstream infrastructure servicing our production in the Marcellus Shale. CONE Gathering owns the general partner controlling interest in CONE Midstream Partners LP (CONE Midstream), a master limited partnership, formed in late 2014. Through our 50% ownership interest in the general partner of CONE Midstream, we have significant influence over the management and operations of CONE Gathering and CONE Midstream in accordance with overall strategic plans, including the maintenance and development of our Marcellus Shale assets and monetization of natural gas production within the basin.
During 2016, CONE Midstream continued to increase both revenues and average throughput as a result of new well connections and the impact of de-bottlenecking projects coming online. 
In fourth quarter 2016, CONE Midstream completed an acquisition of assets from CONE Gathering, which increased our ownership of CONE Midstream common units from 32.1% to 33.5%. CONE Gathering distributed cash of $70 million to us. See Item 8. Financial Statements and Supplementary Data – Note 7. Equity Method Investments .
Bowdoin Sale  During 2016, we completed the sale of our Bowdoin property (north central Montana), generating proceeds of $43 million, and recognizing a $23 million loss.

Deepwater Gulf of Mexico     Locations of our operations in the deepwater Gulf of Mexico as of December 31, 2016 are shown on the map below:
GULFOFMEXICOMAP.JPG

Our deepwater Gulf of Mexico operations resulted from lease acquisition, expansion of our 3D seismic database, and an oil-levered drilling program. 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 70 deepwater Gulf of Mexico blocks, representing approximately 51,000 net developed acres and approximately 192,000 net undeveloped acres. We are the operator on nearly 80% of our leases. See also Developed and Undeveloped Acreage Future Acreage Expirations , below.
2016 Activity Our activity in 2016 primarily focused on commencing production from our Gunflint crude oil discovery, drilling our exploratory Silvergate prospect and the Katmai 2 appraisal well and performing certain remediation activities. We also successfully completed the planned decommissioning of the Raton field and the plug and abandonment work for Lorien. See Offshore Producing Properties and Update to Major Gulf of Mexico Projects, below.
The deepwater Gulf of Mexico contributed an average of 30 MBoe/d of sales volumes in 2016, approximately 7% of total consolidated sales volumes, and represented approximately 2% of total proved reserves at December 31, 2016 .
Our 2016 capital program included the use of the Atwood Advantage drillship, which is under a multi-year contract for services and has been redeployed to offshore Israel. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations . Our 2017 exploration budget has been reduced, but provides flexibility to respond to commodity price changes.
During 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico leases and determined that several leases, representing $91 million of undeveloped leasehold cost, should be impaired and written off. As a result, we recognized $58 million of undeveloped leasehold impairment expense and recorded a $33 million decrease in our valuation pool of individually insignificant leases.
We have remaining capitalized undeveloped leasehold cost of approximately $105 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. Leases representing over 75% 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, future undeveloped leasehold amortization and impairment expense could be significant.
Offshore Producing Properties    

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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 contributed 4 MBoe/d of sales volumes in 2016.
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 16 MBoe/d of sales volumes in 2016.
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 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. During 2016, workover activities were conducted at Isabela to remediate the well, production commenced in the second half of 2016, and well stimulation was performed in fourth quarter 2016 to enhance recovery. Galapagos contributed an average of 5 MBoe/d of sales volumes in 2016.
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 floating offshore production platform.
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. These properties are connected to existing infrastructure through subsea tiebacks.
Update to Major Gulf of Mexico Projects
Silvergate (Mississippi Canyon Block 339; 50% operated working interest) Drilling operations were completed at our Silvergate exploration well. The well did not encounter commercial quantities of hydrocarbons and has been plugged and abandoned.  In 2016 , we recorded dry hole expense of $87 million associated with this well.
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 second quarter 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 of December 31, 2016 , we have capitalized approximately $43 million of costs associated with our Katmai 2 appraisal well.
Troubadour (Mississippi Canyon Block 699; 60% operated working interest) Troubadour is a 2013 natural gas discovery for which we are currently evaluating development scenarios, including subsea tieback to existing infrastructure.
Asset Impairments We recorded property impairment expense of $ 158 million in 2015. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments .
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 , Item 1A. Risk Factors , and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Oil and Gas Exploration Expense .
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 contributed substantially to our growth over the last decade.
Previous exploration successes offshore Israel, West Africa, and Cyprus have identified multiple major development projects that have the potential to contribute to production growth in the future.
On the development side, during 2016, we began drilling the Tamar 8 development well and advanced Eastern Mediterranean regional natural gas export opportunities. Offshore Equatorial Guinea, the operator of the Alba field completed the Alba field compression project, resulting in extension of field life and improved field economics. We also wrote off capitalized exploratory costs related to certain discoveries offshore West Africa. See Eastern Mediterranean (Israel and Cyprus) and West Africa (Equatorial Guinea, Cameroon and Gabon), below.

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International operations accounted for 27% of total consolidated sales volumes in 2016 and 32% of total proved reserves at December 31, 2016 . International proved reserves are approximately 89% natural gas and 11% crude oil, NGLs and condensate.
Operations in Cyprus, Equatorial Guinea, Gabon and Suriname are conducted in accordance with the terms of Production Sharing Contracts (PSCs). In Cameroon, we operate in accordance with the terms of a mining concession. Operations in Israel, the Falkland Islands, and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors .
Locations of our international operations as of December 31, 2016 are shown on the map below:
INTERNATIONALOPERATIONSA02.JPG  
Sales volumes and estimates of proved reserves for our international operating areas were as follows:
 
 
Year Ended December 31, 2016
 
December 31, 2016
 
 
Sales Volumes
 
Proved Reserves
 
 
Crude Oil &
Condensate
 
Natural Gas
 
NGLs
 
Total
 
Crude Oil &
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
 
(MBbl/d)
 
(MMcf/d)
 
(MBbl/d)
 
(MBoe/d)
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe)
International
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Israel
 

 
281

 

 
47

 
3

 
1,984

 

 
334

Equatorial Guinea
 
26

 
235

 

 
65

 
34

 
486

 
12

 
127

Total International
 
26


516




112


37


2,470


12

 
461

Equity Investee
 
2

 

 
5

 
7

 

 

 

 

Total
 
28

 
516

 
5

 
119

 
37

 
2,470

 
12

 
461

Equity Investee Share of Methanol Sales (MMgal)
 
162

 
 

 
 
 
 
 
 


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Wells drilled in 2016 and productive wells at December 31, 2016 in our international operating areas were as follows:
 
 
Year Ended December 31, 2016
 
December 31, 2016
 
 
Gross Wells Drilled
or Participated in
 
Gross Productive
Wells
International
 
 
 
 
Israel
 

 
8

Equatorial Guinea
 

 
26

Total International
 

 
34

Eastern Mediterranean (Israel and Cyprus )   One of our operating areas is the Eastern Mediterranean, where we have drilled 12 successful exploration and appraisal wells and 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 281 MMcf/d of natural gas sales volumes in 2016, approximately 11% of total consolidated sales volumes, and represented approximately 23% of total proved reserves at December 31, 2016 . Our leasehold position in the Eastern Mediterranean at December 31, 2016 , included four leases and three licenses operated offshore Israel and one license operated offshore Cyprus.
At December 31, 2016 , 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.
Locations of our operations in the Eastern Mediterranean as of December 31, 2016 are shown below:
EMEDMAPA03.JPG
Offshore Israel Noble Energy and our partners have delivered reliable and cost effective natural gas to Israeli citizens for over a decade. During this time, we have reliably and consistently delivered approximately 1.9 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

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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.
We continue to partner with customers and the Government of Israel to provide a reliable fuel source to support affordable energy for the people of Israel. 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 power generation.
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 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 has also driven incremental demand for natural gas beginning in 2016. We have executed numerous natural gas sales and purchase agreements (GSPAs) with domestic customers. See International Marketing Activities and Delivery Commitments, below.
Regional Demand and Exports The Eastern Mediterranean presents an opportunity to match our low cost, 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 Leviathan Plan of Development approved by the Government of Israel and nearing final investment decision, we are well positioned to supply natural gas to the region for many years.
Israel Natural Gas Projects  
Tamar (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). Growth in power, industrial and residential demand in Israel, coupled with almost 100% uptime, enabled us to set new records for sales from our Tamar field, both on a quarterly basis of 313 MMcfe/d, net, during third quarter 2016 and on a cumulative gross production milestone of one trillion cubic feet from our Tamar field since initial production in first quarter 2013. Net production from Tamar averaged 281 MMcfe/d for 2016. In late October 2016, we spud the Tamar 8 development well which will increase supply reliability as demand for natural gas increases domestically.
The Israel Natural Gas Framework (Framework) provides for reduction in our ownership interest in Tamar to 25% by year-end 2021. In mid-2016, we signed a definitive agreement to divest a portion of our interest in the Tamar field, and in December 2016, we closed the divestiture of 3.5% ownership interest, partially fulfilling this commitment required by the Framework. The total sales price was $431 million. After consideration of timing and tax adjustments, we received cash proceeds of $316 million at closing. Proceeds received were ratably allocated to the field's basis and resulted in the recognition of a $261 million gain. Our proved reserves as of December 31, 2016 reflect a reduction of 214 Bcf of natural gas driven by the divestiture.
Tamar Southwest (32.5% operated working interest) We continue to work with the Government of Israel to obtain regulatory approval of the development plan for our 2013 Tamar Southwest discovery, which is intended to utilize current Tamar infrastructure. Timely development of Tamar Southwest would help reinforce the reliability for our Tamar project and support increased customer demand.
Tamar Expansion Project (32.5% operated working interest) We have also engaged in the planning phase for the Tamar expansion project. The project would expand field deliverability to approximately 2.1 Bcf/d, a quantity that would allow for regional export. Expansion would include a third flow line component and additional producing wells.
Leviathan Natural Gas Project (39.66% operated working interest)   The development of Leviathan will substantially expand our capacity to deliver natural gas to Israel and the region, as well as provide a second source of domestic natural gas supply and redundancy of infrastructure. Due to Leviathan's size, full field development is expected to require several development phases. Our Plan of Development was approved by the Government of Israel during mid-2016 and we and our partners are performing front-end engineering design (FEED) studies necessary to progress the project to final investment decision (project sanction) in early 2017 and are targeting production by the end of 2019.
The initial Leviathan field development will be a subsea tie-back to a shallow-water platform with a connection to the Israel Natural Gas Lines (INGL) pipeline network. In fourth quarter 2016, we wrote off $88 million of capitalized concept selection costs associated with certain abandoned development concepts that are no longer viable. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments .

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Timing of Leviathan project sanction depends on numerous factors, including completion of necessary marketing activities, engineering and construction planning and availability of funds from us and our partners to invest in the project. We have made significant progress on these fronts and are nearing project sanction.
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 executed multiple GSPAs for a total of up to approximately 525 MMcf/d, gross, or approximately 180 MMcf/d, net to Noble Energy, 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.  The execution of this agreement is subject to regulatory approvals from both Israel and Jordan. Sales to NEPCO are anticipated to commence at field startup. See Israel Natural Gas Framework and Regulatory Environment, below.
Karish and Tanin The Framework also provided for the divestiture of the Karish and Tanin discoveries, and, in November 2015, we executed an agreement to divest our 47% interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields. The transaction closed in early 2016 for a total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs). No gain or loss was recognized.
Other Discoveries Offshore Israel   Our development plan for the Dalit field (36% 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. 
In July 2016, the Petroleum Commissioner of Israel deemed our Dolphin 1 (39.66% operated working interest) 2011 natural gas discovery to be non-commercial. As a result, we recorded exploration expense of $26 million in 2016 due to the expiration of our exploration license.
Asset Impairments During 2016 and 2015, we recorded impairment expense of $88 million and $ 36 million , respectively, related to offshore Israel properties. 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 a comprehensive regulatory natural gas framework by the Government of Israel. See Regulations – Israel Natural Gas Framework and Item 1A. Risk Factors Our Eastern Mediterranean natural gas marketing activities bear certain geopolitical, regulatory, economic and financial risks that could adversely impact our ability to monetize our Israel and Cyprus natural gas assets.
Cyprus 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 and received the remaining consideration, subject to post-close adjustments, in January 2017. The proceeds were applied to the field's basis with no gain or loss recognized. We will continue to operate with a 35% interest. As part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.
During 2015, we submitted a Declaration of Commerciality and in mid-2016, 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 Aphrodite field that, as currently planned, would deliver natural gas to potential customers in Cyprus and Egypt.
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 mining concession, offshore Cameroon, and one block offshore Gabon. In West Africa, our working 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 65 MBoe/d of sales volumes in 2016 and represented approximately 16% of total consolidated sales volumes. At December 31, 2016 , Equatorial Guinea represented approximately 9% of total proved reserves. We held approximately 118,000 net developed acres and 10,000 net undeveloped acres in Equatorial Guinea, 168,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres in Gabon at December 31, 2016 .

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Locations of our operations in Equatorial Guinea and Cameroon, as of December 31, 2016 are shown on the map below:
WESTAFRICAA01.JPG
Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest), offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng 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. In late 2016, the Aseng field reached several milestones including cumulative crude oil production of 80 MMBbls since coming online in 2011. We also completed the first major turnaround since production commenced. During 2016, the Aseng Field produced approximately 9 MBoe/d, net.
The Aseng FPSO is designed to act as a crude oil production hub, as well as 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 and safe performance, averaging over 99% production uptime.
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 8 MBoe/d, net, during 2016. In December 2016, Alen surpassed the 30 MMBbls cumulative gross production milestone. This accomplishment was achieved with a remarkable safety record of over 900 days without a recordable or lost time incident.
The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization below.
Alba Field    Alba is a natural gas and condensate field located offshore, Equatorial Guinea (35% non-operated working interest, 34% revenue interest), which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, an 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. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2016, the Alba field produced an average of 55 MBoe/d, net, reflecting 48 MBoe/d attributable to total sales volumes and 7 MBoe/d attributable to an equity investee.
During 2016, we along with the Alba field operator completed the Alba B3 compression project. Adding a compression platform to Alba is expected to extend the field life, and resulted in positive proved reserves revisions of 10 MMBoe at December 31, 2016.
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 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

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prevailing market prices. In the first half of 2016, we completed scheduled turnaround activities for both the AMPCO methanol plant and the Alba LPG plant.
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.
Other Block O & I Projects    In 2016, we analyzed, interpreted and evaluated acquired 3D seismic data across Blocks O and I. We determined that certain discoveries were impaired in the current forward outlook for crude oil prices and charged $468 million of capitalized exploratory well cost to exploration expense. We believe that the acreage attributable to the properties is currently subject to Blocks O and I PSCs which expire in 2036 and 2034, respectively.
Cameroon We have an interest in approximately 168,000 undeveloped acres offshore Cameroon in our YoYo mining concession (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, as well as to convert the YoYo mining concession to a PSC, which will provide a more robust framework directly related to oil and gas operational activities. We have completed reprocessing of 3D seismic data over our YoYo mining concession and are currently evaluating the data.
In 2016, we relinquished our acreage position in the Tilapia block (46.67% operated working interest), which covered an area of approximately 916,000 gross acres, to the Cameroon government and have exited this block. There was no significant impact to our 2016 financial results as dry hole costs relating to the Cheetah exploration well were expensed in 2015.
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) and 2008 Felicita discovery (Block O), offshore Equatorial Guinea, the YoYo discovery, offshore Cameroon, as well as natural gas from our Aseng and Alen fields.
A natural gas development team is working with both governments to evaluate natural gas monetization concepts at Bioko Island. Our current development concept provides for subsea tieback of Blocks I and O discoveries to the Alen platform. In third quarter 2016, a data exchange agreement for the 2007 Yolanda discovery (Block I) and 2007 YoYo discovery was executed between the governments of Equatorial Guinea and Cameroon. The execution of the agreement marks a significant milestone as a first step towards unitization of any cross border resources.
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 during second quarter 2016 and is currently being processed. Final product delivery is anticipated early 2017.
See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs .
Other International
Our other international operations contributed no sales volumes for 2016 and had no proved reserves at December 31, 2016 .
Offshore Falkland Islands In 2015, we experienced material operational issues with a drilling rig while drilling the Humpback well. The same drilling rig was scheduled to drill another prospect but due to significant safety and operational concerns, the drilling contract was terminated in first quarter 2016. As a result, we expensed $41 million of capitalized rig costs relating to pre-drill activities which is reflected in other operating expense, net, in the consolidated statements of operations.
We have been working closely with our partners and the Falkland Islands Government to evaluate a path forward for our Rhea prospect, located in the North Falkland Basin adjacent to a third party's 2010 Sea Lion discovery, and in 2016, we received a three-year extension for this license. We also held certain other licenses located in the South Falkland Basin and following completion of our geological assessment, we exited all licenses outside of PL-001, which contains the Rhea prospect, which resulted in $25 million undeveloped leasehold impairment expense in 2016.
An Argentine court has initiated a criminal investigation against Noble Energy and other oil and gas companies regarding their exploration activities offshore Falkland Islands.  The court has also issued a preservation order against the relevant companies to preserve assets in the event of any judgment. The investigation is premised on Argentina’s claim that the Falkland Islands are a part of its territory. Argentina does not recognize the United Kingdom’s sovereignty over the Falkland Islands or the Falkland Islanders rights to exploit their natural resources. The Falkland Islands are part of the United Kingdom’s overseas territories and are afforded full self-governance. Our concessions are with the Falkland Islands Government and we do not believe that Argentina has any authority over our operations in the Falkland Islands.

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Offshore Suriname   In October 2015, we acquired a non-operated 20% working interest in Block 54 offshore Suriname in the Atlantic Ocean via farm-in from Tullow Oil plc (Tullow). Tullow is the operator with a 30% interest. We have acquired and processed 3D seismic information and are currently interpreting data. We currently anticipate participating in drilling activities in late 2017.
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.
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.
The operator of the MacCulloch field has notified working interest owners that the scope and magnitude of decommissioning activities has been revised downward, resulting in a potential adjustment of the project timeline with lower field abandonment costs. As of December 31, 2016, we had a total asset retirement obligation of $85 million related to this remediation project. As the operator moves beyond the initial decommissioning phase, we will continue to monitor the status and costs of the project and will adjust our estimate accordingly.
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, environmental analysis 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 36 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 2016 reserves estimates.
Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be economically producible.
Third-Party Reserves Audit    In each of the years 2016 , 2015 , and 2014 , we retained NSAI to perform audits of proved reserves. The reserves audit for 2016 included a detailed review of nine of our major onshore US, deepwater Gulf of Mexico 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

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approximately 91% of total proved reserves. The reserves audit for 2014 included a detailed review of eight of our major fields and covered approximately 88% of total proved reserves.
In connection with the 2016 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 Regulation S-X Rule 4-10(a) 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, 2016 , 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, 2016 , on a quantity basis, the NSAI field estimates ranged from 3.1 MMBoe or 2% above to 6 MMBoe or 7% below 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, 2016 were, in the aggregate, approximately 27.9 MMBoe, or 2%.
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,
 
 
2016
 
2015
 
2014
(MMBoe)
 
 
 
 
 
 
Proved Reserves Beginning of Year
 
1,421

 
1,404

 
1,406

Revisions of Previous Estimates
 
64

 
(216
)
 
21

Extensions, Discoveries and Other Additions
 
179

 
100

 
120

Purchase of Minerals in Place
 
4

 
269

 

Sale of Minerals in Place
 
(77
)
 
(6
)
 
(33
)
Production
 
(154
)
 
(130
)
 
(110
)
Proved Reserves End of Year
 
1,437

 
1,421

 
1,404

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 included the following:
changes for the year ended December 31, 2016 include positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Permian Basin, 6 MMBoe for deepwater Gulf of Mexico, 5 MMBoe for other onshore US and 10 MMBoe for 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;
changes for the year ended December 31, 2015  include negative revisions of 307 MMBoe due to lower commodity prices, downward revisions of 9 MMBoe and 5 MMBoe for the DJ Basin and Eagle Ford Shale, respectively, primarily due to current drilling and development plans in the DJ Basin and expected reserve recovery from existing producing wells in the Eagle Ford Shale, and downward revisions of 3 MMBoe due to natural field decline from the Mari-B field,

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offshore Israel; offset by positive performance revisions of 81 MMBoe for the Marcellus Shale, 17 MMBoe for the Permian Basin and 10 MMBoe for Alba field; and
changes for the year ended December 31, 2014  included positive performance revisions of 18 MMBoe for the Marcellus Shale, 4 MMBoe for deepwater Gulf of Mexico, 4 MMBoe for Alba field, and 3 MMBoe for the Tamar field; offset by a downward revision of 8 MMBoe for the DJ Basin primarily due to planned reduction in pace of drilling activity due to lower commodity prices.
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 included the following:
changes for the year ended December 31, 2016 include increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Permian Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs;
changes for the year ended December 31, 2015 include increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs; and
changes for the year ended December 31, 2014 included increases of 48 MMBoe in the DJ Basin, 62 MMBoe in the Marcellus Shale, and 10 MMBoe deepwater Gulf of Mexico primarily attributable to sanction of the Dantzler development.
Approximately 75% of our 2017 capital program is allocated to onshore US, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale, and over 20% is allocated to offshore Israel. In turn, we expect that future reserves additions will primarily come from our development projects onshore US 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 and Other Exploration Expenditures .
Purchase of Minerals in Place   We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases included the following:
an increase of 4 MMBoe of NGL reserves primarily resulting from our Marcellus Shale acreage exchange in 2016; and
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Permian 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 included the following:
a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, divestment of 29 MMBoe in the Marcellus Shale driven by our asset exchange, and other smaller divestments in onshore US resulting in a reduction of 12 MMBoe in 2016;
the sale of onshore US assets in 2015; and
the sale of onshore US and China assets in 2014.
See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions, Divestitures and Merger .
Production   See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Revenues – Oil, Gas and NGL Sales 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, 2016 , our PUDs totaled 158 MMBbls of crude oil and condensate, 1.4 Tcf of natural gas, and 94 MMBbls of NGLs for a total of 486 MMBoe, or 34% of proved reserves. Changes in PUDs that occurred during the year are summarized below:
 
 
United
 States
 
Israel
 
Equatorial
Guinea
 
Total
(MMBoe)
 
 
 
 
 
 
 
 
Proved Undeveloped Reserves Beginning of Year
 
344

 
71

 
70

 
485

Revisions of Previous Estimates
 
32

 

 

 
32

Extensions, Discoveries and Other Additions
 
166

 

 

 
166

Purchase of Minerals in Place
 

 

 

 

Sale of Minerals in Place
 
(22
)
 
(7
)
 

 
(29
)
Conversion to Proved Developed
 
(98
)
 

 
(70
)
 
(168
)
Proved Undeveloped Reserves End of Year
 
422

 
64

 

 
486

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 32 MMBoe in the US for 2016 included:
53 MMBoe positive revisions primarily in the DJ Basin, Marcellus Shale and Permian Basin due to current drilling and development plans;
offset by:
negative revisions of 21 MMBoe due to lower commodity prices.
Extensions, discoveries and other additions include addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields. During 2016 , we recorded the following additions as a result of successful expansion of our extended reach lateral well programs:
76 MMBoe in the DJ Basin;
31 MMBoe in the Permian Basin;
19 MMBoe in the Eagle Ford Shale; and
40 MMBoe in the Marcellus Shale.
Conversion to proved developed reserves included the following transfers:
26 MMBoe in the DJ Basin;
1 MMBoe in the Permian;
25 MMBoe in the Eagle Ford Shale;
33 MMBoe in the Marcellus Shale;
13 MMBoe in deepwater Gulf of Mexico; and
70 MMBoe in the Alba Field, offshore Equatorial Guinea.
In 2016, we converted 98 MMBoe of our US PUDs, or 28% of our US PUDs 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, 2016 to be converted to proved developed reserves within five years of initial disclosure.
US PUDs Locations    As of December 31, 2016 , our US PUDs included:
199 MMBoe in the DJ Basin;
70 MMBoe in the Permian Basin;
92 MMBoe in the Eagle Ford Shale; and
61 MMBoe in the Marcellus 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, 2016 , we had approximately 81 MMBoe of proved undeveloped reserves associated with DUC well locations related to our onshore US operations, approximately 40% and 30% of which are in the Marcellus Shale and the Eagle Ford Shale, respectively, and the remainder are in the DJ Basin and Permian Basin.
International PUDs Locations As of December 31, 2016 , our international PUDs included 64 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields, including PUDs of 29 MMBoe related to the Tamar Southwest field, which is awaiting government approval of the development plan. We expect these PUDs to be converted to proved developed reserves within five years of initial disclosure.

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Development Costs    Costs incurred   to advance the development of PUDs were approximately $656 million in 2016 , $1.5 billion in 2015 , and $2.0 billion in 2014 . A significant portion of costs incurred in 2016 related to the DJ Basin, deepwater Gulf of Mexico and Marcellus Shale development projects.
Estimated future development costs relating to the development of PUDs are projected to be approximately $1.1 billion in 2017 , $0.9 billion in 2018 , and $0.8 billion in 2019 . 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. All PUD drilling locations are scheduled to be drilled prior to the end of 2021. Initial production from these PUDs is expected to begin during the years 2017 to 2021.
PUDs with Negative PV10 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. Although our PUD reserves meet the SEC definition, this prescribed calculation can result in some PUDs having negative present worth, meaning while we have positive cash flows, the rate of return is lower than 10%.
At December 31, 2016 , we had 133 well locations, primarily located in the DJ Basin and Marcellus Shale, with a negative present worth when discounted at 10% and based on SEC prices.
Although these PUD reserves had a negative present worth when discounted at 10%, they generated positive future net revenues.
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 these reserves within five years of initial disclosure. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2017 Capital Investment Program .
For more information see the following:
Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil, natural gas and NGL 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
 
Natural Gas
MMcf
 
NGLs
MBbl
 
Crude Oil &
Condensate
Per Bbl
 
Natural Gas
Per Mcf
 
NGLs Per
Bbl
 
Per BOE
Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
DJ Basin
 
20,342

 
82,431

 
7,651

 
$
40.85

 
$
2.80

 
$
14.66

 
$
3.43

Marcellus Shale
 
431

 
177,872

 
3,094

 
28.25

 
1.68

 
16.34

 
0.90

Other US
 
15,572

 
62,017

 
9,087

 
38.26

 
2.42

 
14.65

 
6.26

Total US
 
36,345

 
322,320

 
19,832

 
39.59

 
2.11

 
14.92

 
3.57

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 (2)
 
9,415

 
85,987

 

 
43.54

 
0.27

 

 
4.40

Total Consolidated Operations
 
45,900

 
511,115

 
19,832

 
40.39

 
2.42

 
14.92

 
$
3.59

Equity Investee (3)
 
629

 

 
1,993

 
45.44

 

 
26.30

 
N/M

Total
 
46,529

 
511,115

 
21,825

 
$
40.46

 
$
2.42

 
$
15.96

 
N/M

Year Ended December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
DJ Basin
 
20,909

 
85,369

 
6,910

 
$
44.37

 
$
2.53

 
$
14.21

 
$
5.51

Marcellus Shale
 
673

 
143,465

 
3,480

 
22.39

 
1.75

 
14.04

 
1.40

Other US
 
7,680

 
29,806

 
3,705

 
42.83

 
2.56

 
13.25

 
6.07

Total US
 
29,262

 
258,640

 
14,095

 
43.46

 
2.10

 
13.91

 
4.28

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 (2)
 
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

 
433,438

 
14,095

 
45.00

 
2.44

 
13.91

 
$
4.43

Equity Investee (3)
 
554

 

 
1,850

 
48.85

 

 
28.40

 
N/M

Total
 
41,441

 
433,438

 
15,945

 
$
45.05

 
$
2.44

 
$
15.59

 
N/M

Year Ended December 31, 2014
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
 

 
 

 
 

 
 

 
 

 
 

 
 

DJ Basin
 
18,209

 
75,039

 
6,072

 
$
87.86

 
$
4.11

 
$
34.51

 
$
6.00

Marcellus Shale
 
239

 
95,564

 
1,812

 
69.50

 
3.57

 
31.67

 
1.55

Other US
 
5,845

 
18,211

 
532

 
95.84

 
4.35

 
32.14

 
7.40

Total US
 
24,293

 
188,814

 
8,416

 
89.60

 
3.86

 
33.75

 
5.33

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
109

 
79,828

 

 
89.62

 
5.68

 

 
2.81

  Other Israel
 

 
4,539

 

 

 
3.52

 

 
N/M

  Total Israel
 
109

 
84,367

 

 
89.62

 
5.57

 

 
3.84

Equatorial Guinea (2)
 
12,191

 
88,833

 

 
94.61

 
0.27

 

 
5.44

China
 
788

 

 

 
103.74

 

 

 
8.53

United Kingdom
 
159

 
56

 

 
102.02

 
16.26

 

 
N/M

Total Consolidated Operations
 
37,540

 
362,070

 
8,416

 
91.58

 
3.38

 
33.75

 
$
5.31

Equity Investee (3)
 
605

 

 
1,934

 
96.53

 

 
62.89

 
N/M

Total
 
38,145

 
362,070

 
10,350

 
$
91.65

 
$
3.38

 
$
39.19

 
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)  
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.
(3)  
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
Revenues from sales of crude oil, natural gas and NGLs have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.
At December 31, 2016 , our operated properties accounted for the majority 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, 2016 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
3,974

 
3,628

 
3,821

 
3,501

 
7,795

 
7,129

Israel
 

 

 
8

 
3

 
8

 
3

Equatorial Guinea
 
5

 
2

 
21

 
8

 
26

 
10

Total
 
3,979

 
3,630

 
3,850

 
3,512

 
7,829

 
7,142

 
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) held at December 31, 2016 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore
 
902

 
768

 
694

 
430

Deepwater Gulf of Mexico
 
100

 
51

 
282

 
192

Total United States
 
1,002

 
819

 
976

 
622

International
 
 

 
 

 
 

 
 

Israel
 
185

 
78

 
284

 
116

Equatorial Guinea (1)
 
284

 
118

 
26

 
10

Suriname
 

 

 
2,095

 
419

Newfoundland
 

 

 
1,942

 
525

Gabon
 

 

 
671

 
403

Cyprus
 

 

 
95

 
33

Falkland Islands (2)
 

 

 
280

 
210

Cameroon
 

 

 
168

 
168

United Kingdom
 
2

 

 
4

 
1

Total International
 
471

 
196

 
5,565

 
1,885

Total
 
1,473

 
1,015

 
6,541

 
2,507

(1)  
Undeveloped acreage excludes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which expired in 2016. We are negotiating with the government of Equatorial Guinea to extend the lease.
(2)  
Following completion of our geological assessment in 2016, we exited all licenses in the Falklands Islands, outside of License PL-001, which contains the Rhea prospect, thereby reducing our acreage position by approximately 10 million, gross, and 3 million, net, acres.

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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Future Acreage Expirations    If production is not established or we take no other action to extend the terms of the leases, licenses, or concessions, undeveloped acreage will expire over the next three years as follows. No material quantities of PUD reserves were associated with the expiring acreage.
 
 
Year Ended December 31,
 
 
2017
 
2018
 
2019
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
 
 
 
 
Onshore US
 
156

 
103

 
143

 
41

 
113

 
73

Deepwater Gulf of Mexico
 
1

 
1

 
76

 
55

 
36

 
25

Falkland Islands
 

 

 

 

 
280

 
210

Suriname
 

 

 
2,095

 
419

 

 

Gabon
 

 

 
671

 
403

 

 

Total
 
157

 
104

 
2,985

 
918

 
429

 
308


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, 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

Falkland Islands
 

 
0.4

 
0.4

 

 

 

 
0.4

Cameroon
 

 
0.5

 
0.5

 

 

 

 
0.5

Total
 
1.5

 
4.9


6.4


212.8




212.8


219.2

Year Ended December 31, 2014
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
1.5

 
3.1

 
4.6

 
319.1

 
0.7

 
319.8

 
324.4

Total
 
1.5

 
3.1

 
4.6

 
319.1

 
0.7

 
319.8

 
324.4

 
In addition to the wells drilled and completed in 2016 included in the table above, wells that were in the process of drilling or completing at December 31, 2016 were as follows: 
 
 
Exploratory (1)
 
Development (2)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
5

 
4.0

 
142

 
128.9

 
147

 
132.9

Israel  
 
4

 
1.5

 
1

 
0.3

 
5

 
1.8

Equatorial Guinea
 
2

 
0.9

 

 

 
2

 
0.9

Cameroon
 
1

 
1.0

 

 

 
1

 
1.0

Cyprus
 
2

 
0.7

 

 

 
2

 
0.7

Total
 
14

 
8.1

 
143

 
129.2

 
157

 
137.3

(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.

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.
Oil Spill Response Preparedness    In the US, we maintain membership in Clean Gulf Associates (CGA), a nonprofit association of production and pipeline companies operating in the Gulf of Mexico, and Marine Spill Response Corporation, the largest, dedicated oil spill and emergency response organization in the US. For well capping and containment services we have contracted with HWCG, which has contracted with Helix Energy Solutions Group (HESG) for the provision of subsea intervention, containment, capture and shut-in capacity for deepwater Gulf of Mexico exploratory wells.

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Internationally, we maintain membership in Oil Spill Response Limited (OSRL), an industry-owned cooperative. We also maintain agreements internationally with National Response Corporation and PolyEco Group, which provide leased response equipment as well as supplemental oil spill response services. Additionally, in Equatorial Guinea, we are members of the Oil and Gas Operators Emergency Resource Allocation Group which shares equipment and resources in the event of a spill.
Domestic Marketing Activities    Crude oil, natural gas, condensate and NGLs produced onshore US and in the deepwater 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.
Certain onshore US areas in which we operate have had minimal infrastructure in place for the processing and transportation of our production. Company and third party infrastructure projects that came online in 2015 and 2016 have improved flow assurance. Future projects, such as near our Marcellus Shale assets in the Northeast, coming online in the next few years are expected to continue to enhance transportation of production to end markets.
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) under a long-term sales contract through 2018. 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. 
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 gath ering, processing and transportation contracts for some of our onshore US production, with remaining terms of one to 32 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 2016 , 2015 , and 2014 , we incurred expense of approximately  $58 million $33 million , and $16 million , respectively, related to volume deficiencies and/or unutilized commitments primarily in our onshore US 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. 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 Israel Electric Corporation (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 f or 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.

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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 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, 2016 , a total of approximately 5.7 Tcf, gross (1.847 Tcf, net), of natural gas remained to be delivered under the contracts. As of December 31, 2016 , we have recorded 2.0 Tcf, net, of proved na tural gas reserves, including proved developed reser ves of 1.6 Tcf, net, a nd PUD reserves of 384 Bcf, net, for offshore Israel. 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.
We are also engaged in marketing activities related to the Leviathan natural gas project. See Eastern Mediterranean (Israel and Cyprus), above.
Significant Purchasers    Glencore Energy and Shell Trading (US) (Shell) were the largest single purchasers of our 2016 production.
Glencore purchased our share of crude oil and condensate production from the Alba, Aseng and Alen fields in Equatorial Guinea. Sales to Glencore Energy accounted for 12% of 2016 total crude oil, natural gas and NGL sales, or 22% of 2016 crude oil sales.
Shell purchased crude oil and condensate domestically from the deepwater Gulf of Mexico, the DJ Basin and the Marcellus Shale. Sales to Shell accounted for 13% of our 2016 total crude oil, natural gas and NGL sales, or 24% of crude oil sales.
No other single purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2016 . 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 .

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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 National Infrastructures, Energy and Water Resources 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;
the Ministry of Energy, Commerce, Industry and Tourism which regulates our exploration and development activities offshore Cyprus; and
the Department of Mineral Resources which regulates our exploration activities offshore the Falkland Islands.
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 deepwater 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 (RCRA), 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 deepwater Gulf of Mexico; and
the Department of Transportation (DOT), which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater 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 As a developer, owner and operator of crude oil and natural gas properties, we are subject to various federal, state, local and foreign host country laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must 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. 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.
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.
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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 we have, to date, expended material amounts in connection with such activities or 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. In January 2017, for example, the FWS announced that it was listing the Rusty Patched Bumble Bee as endangered under the ESA. Conservation measures are currently not known but could have an impact on the timing of certain of our operations in the Marcellus Shale. Listing of the Lesser Prairie Chicken likewise could impact our operations in the Permian 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 that it has undertaken a new status review of the Lesser Prairie Chicken to determine whether listing is still warranted. That assessment is expected to be completed in the summer of 2017.
In May 2015, the US Environmental Protection Agency and the US Army Corps of Engineers jointly released a final rule that is meant to define more precisely which water bodies are and are not subject to the Clean Water Act (the Clean Water Rule). Among other things, the Clean Water Rule defines the intermittent, ephemeral, and man-altered streams to be protected and specifies when federal jurisdiction may be extended from a covered water to nearby waters. While the agencies have claimed that the new requirements are narrower than existing regulation, the Clean Water Rule has generated substantial controversy. Several court challenges have been filed, and in October 2015, the rule was stayed by the U.S. Court of Appeals for the Sixth Circuit, pending its review of legal challenges to the rule. To the extent that the Clean Water Rule requires more detailed studies of site conditions, or results in an expansion of federal jurisdiction over streams and wetlands, our costs may increase, especially with respect to spill prevention, storm water management, and wetlands permitting. We are continuing to monitor the challenges and to evaluate the impact of the new rule on our operations.
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. To date, those rules have had minimal impact on our business since the reduction of 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.
In March 2014, the previous US Administration released a Strategy to Reduce Methane Emissions that includes consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA released five draft white papers on methane emissions, volatile organic compound (VOC) emissions, and emission mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities, and natural gas production and transmission facilities. After issuing a proposed rule in 2015, the EPA issued a final rule in May 2016 that sets additional standards for methane and VOC emissions from new and modified oil and gas production sources. The new rule will require operators of oil and gas properties to monitor and repair leaks, capture gas from the completion of hydraulically fractured wells, limit emissions from new and modified pneumatic pumps, and limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and pneumatic controllers. An accompanying EPA rule

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will require oil and natural gas sites within one-quarter mile to be aggregated as a single source for purposes of air permitting, 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, in November 2016 the BLM issued final rules for reducing venting and flaring of methane gas on public lands. The previous US Administration's goal was to reduce methane emissions from the oil and gas industry by 40-45% by 2025 as compared to 2012 levels. Challenges to the new BLM rules have been filed in federal court. It also bears noting that substantially all of our onshore US 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. See Hydraulic Fracturing, below.
In 2014, by executive order, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force) for the purpose of recommending policies and legislation. The 21-member Task Force, which included a Noble Energy representative, concluded its activities on February 27, 2015. The Task Force sent nine recommendations to the Governor. The recommendations sought to balance land use issues among communities and oil and gas operators and allow reasonable access to private mineral rights. Three recommendations were approved by the legislature, and in January 2016 state regulators approved two rules addressing siting of large oil and gas operations in urban areas and coordination of drilling with local governments. We currently are evaluating the new rules.
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 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 18. Commitments and Contingencies .
Pennsylvania Pennsylvania's Act 13 of 2012 (Act 13) represented the first comprehensive legislation regarding the development of the Marcellus Shale in Pennsylvania. Act 13, among other things, enacted stronger environmental standards;

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established impact fees, which are set based on a multi-year fee schedule and the average sales price of natural gas; increased the notice distance for unconventional well permit applications from 1,000 feet to 3,000 feet; extended the setback distance for unconventional wells from 200 feet to 500 feet; and increased the distance and duration of presumed liability for water pollution to 2,500 feet from a well site and twelve months after well drilling, completion, stimulation or alteration. In addition, Act 13 imposed spill prevention requirements applicable to well site construction, wastewater transportation, and gathering lines.
Act 13 has been the subject of multiple challenges in the Pennsylvania courts. In 2013 for example, the Pennsylvania Supreme Court invalidated the portions of Act 13 providing for statewide zoning and state waivers of the setback requirements in Pennsylvania's Oil and Gas Act. In 2014, moreover, the Pennsylvania Commonwealth Court invalidated Act 13’s provisions allowing the state to review local drilling rules. These court decisions have the effect of giving local communities in Pennsylvania more authority to regulate oil and gas operations, which could make it more difficult to develop our Marcellus Shale acreage in some municipalities.
Furthermore, the state has finalized new rules for surface operations at oil and gas sites that, among other things, would increase public participation in the permitting process, increase mitigation obligations and require surveys for abandoned wells. On October 8, 2016, the Pennsylvania Department of Environmental Protection issued the final rule amending Pennsylvania Code Chapter 78a revising requirements for surface activities related to unconventional oil and gas operations. The final rule increases requirements for permitting, waste handling, water management and restoration, surface reclamation, and requirements related to abandoned and orphaned wells. In November 2016, a Pennsylvania state court issued an opinion requiring the enforcement of certain portions of the new rule while the court considers legal challenges to the rule brought by an industry group. These regulations may increase operating costs and cause delays. 
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 May 2013, the Texas Railroad Commission (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.
Other US Environmental Requirements In addition to the above, we will continue to monitor proposed and new legislation and regulations in all our operating jurisdictions to assess the potential impact on the Company. We continue to engage in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.
US Offshore Regulatory Developments 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. Although the final rule incorporates some of the changes recommended by the oil and gas industry, it imposes a number of new requirements relating to well design, well control, casing, cementing, real-time well monitoring and subsea containment. For example, the new rule requires double sets of shear rams on all deepwater blowout preventers (BOPs), periodic inspections of BOPs and outside audits of equipment, and real-time well monitoring requirements. The new rule will likely increase the costs associated with well design, drilling and completion operations, as well as ongoing monitoring costs for our wells in the Gulf of Mexico. The final rule went into effect on July 28, 2016.
On March 17, 2016, the BOEM proposed a new 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. The comment period for the proposed rule expired June 20, 2016.
Additionally, 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

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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 is extending the implementation timeline for six months in certain circumstances. 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.
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. We are currently evaluating the expansion alternatives and assessing any potential impact on our operations in the Gulf of Mexico.
See Item 1A. Risk Factors – We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
Israel's Natural Gas Policy and Antitrust Authority The Israel Natural Gas Framework, as adopted by the Government of Israel, provides clarity on numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters, which we will rely upon to support a final investment decision and proceed with the development of these resources while ensuring economic benefits to the state of Israel and its citizens. The Framework provides for the reduction of our ownership interest in Tamar to 25% by year-end 2021, while enabling the marketing of Leviathan natural gas to Israeli customers. In second quarter 2016, the Government of Israel adopted a new economic stability clause which does not remove the possibility of future adverse legislation but does provide for project economic stability in the event of certain future adverse actions.
Impact of Dodd-Frank Act Section 1504 On June 27, 2016, the SEC adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that will require resource extraction companies, such as us, to publicly file with the SEC 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 U.S. 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. Reporting and disclosure will be required annually beginning with the 2018 fiscal year.
Hydraulic Fracturing  
Concerns    The practice of hydraulic fracturing, especially the hydraulic fracturing processes associated with drilling in shale formations, is the subject of significant focus among some environmentalists and regulators. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment and, potentially, the general public health, have been raised at local, state and federal levels of government in the US and internationally. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of both water supply sources and disposal methods.
Our Operations   Hydraulic fracturing techniques have been used by the industry since 1947, and, currently, more than 90% of all crude oil and natural gas wells drilled in the US employ hydraulic fracturing. The process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into those aquifers. 
Where possible, we strive to procure non-hydrologic water (water that is not connected to a natural surface stream) for use in hydraulic fracturing; a large proportion of our water is from non-tributary sources, such as deep ground water. In the DJ Basin, we are in the process of securing additional water rights in support of our drilling program, and we engage in significant water recycling efforts in both the DJ Basin and Marcellus Shale. 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. 
Studies and Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are studying it and evaluating the need for further requirements. For example, in 2011, the US Secretary of Energy formed the Shale Gas Production Subcommittee (Subcommittee), a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee issued final recommendations in November 2011 that included better communications with the public, better air quality controls, protection of water supply and quality, disclosure of fracturing fluid

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composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas.  
In addition, the US Department of Energy's National Energy Technology Laboratory (NETL) is conducting a comprehensive assessment of the environmental effects of shale gas production at two industry-provided Marcellus Shale test sites in southwestern Pennsylvania. Goals include:
documentation of environmental changes that are coincident with shale gas production;
development of technology or management practices that mitigate any unintended environmental changes; and