10-K
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, 2015
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


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, 2015: $16.5 billion.
Number of shares of Common Stock outstanding as of December 31, 2015: 428,843,495.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2016 Annual Meeting of Stockholders to be held on April 26, 2016, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2015, are incorporated by reference into Part III.



Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

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



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Index to Financial Statements


PART I

Items 1. and 2. Business and Properties
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Item 1A. Risk Factors.
General
Noble Energy, Inc. (Noble Energy, the Company, we or us) is a leading independent energy company engaged in worldwide crude oil, natural gas and natural gas liquids (NGLs) exploration and production. 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 people and the communities where we operate.
We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified portfolio of assets with investment flexibility between onshore unconventional developments and offshore organic exploration leading to major development projects. Our asset portfolio is further diversified between short-term and long-term projects, domestic and international and a balanced production mix among crude oil, natural gas and NGLs. In addition, occasional strategic acquisitions of producing and non-producing properties, combined with the periodic divestment of non-core assets, have allowed us to pursue our objective of a well-diversified, growing portfolio.
In particular, our organization and business models are focused on achieving sustainable, high-return growth through effective major development project execution complemented by pursuit of exploration opportunities that can be monetized on competitive discovery-to-production cycle times. Our ability to deliver major development projects on schedule and within budget has provided a competitive and financial advantage in our industry. In addition, the majority of our assets are held by production, which provides for investment and financial flexibility.
Impact of Current Commodity Prices on our Business The upstream oil and gas business is cyclical and we are currently operating in a period of low commodity prices. Commodity prices began declining sharply during fourth quarter 2014, continued to decline throughout 2015, and have been trading at multi-year lows thus far in 2016, with crude oil prices in particular falling below $30.00 per barrel on several occasions. During 2015, low commodity prices resulted in a reduction of our revenues, profitability, cash flows and proved reserves, asset and goodwill impairments, and reductions in our stock price, causing us to execute certain organizational changes. Continued decline in commodity prices in 2016 may result in additional impairments and cause further reduction in revenues, profitability, cash flows and proved reserves. In response to the low commodity prices, we reduced our capital spending program approximately 40%, as compared with 2014. See Item 1A. Risk Factors We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our results of operations, our liquidity, and the price of our common stock and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments.
Operational Success Despite the negative financial impacts of the low commodity price environment, 2015 was a very successful year operationally. We directed our focus on the enhancement of onshore US completions, advancement of Eastern Mediterranean regional natural gas developments, development of our Gulf of Mexico crude oil discoveries and integration of two premier onshore US shale positions acquired through the Rosetta Merger, described below. Just as importantly, we achieved material reductions in capital and controllable unit costs, supporting project returns and margin improvements, and delivered year-over-year volume growth of almost 20% (or year-over-year organic volume growth of 10% excluding the addition of the Rosetta assets) resulting in record average sales volumes of 355 MBoe/d. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview and Results of Operations.
Positioning for the Future Throughout 2015 and into 2016, we have taken steps to sustain our business in the volatile and low commodity price environment that has evolved. We have adopted a comprehensive effort to spend within cash flow and manage the Company's balance sheet. To this end, we plan to defer certain activity to protect our liquidity position and have adopted a 2016 capital program more closely aligned with expected cash flow. In addition, our Board of Directors recently

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adjusted the quarterly dividend to 10 cents per common share, which represents a reduction of 8 cents, aligns the dividend yield with historical levels, and further enhances our liquidity. We also intend to reduce leverage in this environment and recently engaged in debt refinancing activities. The dividend reduction and debt refinancing are expected to provide approximately $200 million annually in support of balance sheet management efforts. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.
As we enter 2016, we believe we have positioned the Company for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. However, if the industry downturn continues for an extended period, or becomes more severe, we could experience additional material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and in response, we may consider further reductions in our capital program or dividends, asset sales or additional organizational changes. Our production and our stock price could decline further as a result of these potential developments. See Item 1A. Risk Factors We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our results of operations, our liquidity, and the price of our common stock.
Oil and Gas Assets Onshore US assets provide a stable base of production along with low production-risk development programs. Our DJ Basin and Marcellus Shale assets, in particular, along with our recently-acquired Eagle Ford Shale and Permian Basin assets, have delivered significant historical production growth. Onshore US assets accommodate a flexible capital investment program that can be adjusted in response to ongoing changes in the economic environment and have the potential to deliver improved returns as supply and demand factors re-balance in the long term. We continue to enhance project performance through technology and operational efficiency.
Our long cycle offshore development projects, while requiring multi-year capital investment, offer sustained production, and are once again expected to offer attractive financial returns and sustained cash flow as supply and demand factors re-balance in the long term.
We have operations in seven core areas:
 
These seven core areas provide:
l the DJ Basin (onshore US)
 
l almost all of our crude oil, natural gas and NGL production
l the Marcellus Shale (onshore US)
 
l continual investment opportunities in proved areas
l  Eagle Ford Shale (onshore US)
 
l exploration opportunities
l  Permian Basin (onshore US)
 
 
l the deepwater Gulf of Mexico (offshore US)
 
 
l offshore West Africa
 
 
l offshore Eastern Mediterranean
 
 
In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy and its subsidiaries. All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated.
Major Development Project Inventory   We continue to advance a number of major development projects, many of which have resulted from our exploration success. Each project will progress, as appropriate, through the various development phases including appraisal, front-end engineering and design, development drilling, construction and production. We currently have projects in all phases of the development cycle with some contributing production growth in 2015 including, for example, our onshore US projects and the deepwater Gulf of Mexico Rio Grande field, which started production in the fourth quarter.
Although these projects will require significant capital investments over a multi-year period, they typically offer long-life, sustained cash flows and attractive financial returns over the oil and gas business cycle. Our current major development projects resulting from exploration success and strategic acquisitions include the following:
Sanctioned(1) Projects
Unsanctioned Projects
 
 
 
 
·
DJ Basin (onshore US) (2)
·
Tamar Expansion (offshore Israel) (3)
·
Marcellus Shale (onshore US) (2)
·
Leviathan (offshore Israel) (3)
·
Eagle Ford Shale (onshore US) (2)
·
Cyprus (offshore Cyprus)
·
Permian Basin (onshore US) (2)
·
Diega and Carla (offshore Equatorial Guinea)
·
Gunflint (deepwater Gulf of Mexico)
.
Katmai (deepwater Gulf of Mexico)
·
Tamar Southwest (offshore Israel) (3) (4)
 
 
(1) 
Final investment decision has been made.

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(2) 
Represents multiple ongoing development projects.
(3) 
See Update on Israel Israel Natural Gas Framework, below.
(4) Regulatory approval for the project has been delayed. Currently we are in an appeals process with the Israeli Ministry of National Infrastructures, Energy and Water Resources.
These projects are discussed in more detail in the sections below. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Major Development Project Inventory.
Proved Oil and Gas Reserves    Proved reserves at December 31, 2015 were as follows:
 
 
December 31, 2015
 
 
Proved Reserves
 
 
Crude Oil and
Condensate
 
Natural Gas
 
NGLs
 
Total
Reserves Category
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe) (1)
Proved Developed
 
 
 
 
 
 
 
 
United States
 
137

 
1,813

 
101

 
540

Equatorial Guinea
 
34

 
247

 
5

 
81

Israel
 
3

 
1,879

 

 
315

Total Proved Developed Reserves
 
174

 
3,939

 
106

 
936

Proved Undeveloped
 
 

 
 

 
 

 
 

United States
 
119

 
898

 
75

 
344

Equatorial Guinea
 
14

 
287

 
8

 
70

Israel
 

 
425

 

 
71

Total Proved Undeveloped Reserves
 
133

 
1,610

 
83

 
485

Total Proved Reserves
 
307

 
5,549

 
189

 
1,421

(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. See Item 6. Selected Financial Data.
Our proved reserves totaled 1,421 MMBoe as of December 31, 2015 as compared with 1,404 MMBoe as of December 31, 2014. Changes included the following:
positive revisions of 91 MMBoe;
extensions and other additions of 100 MMBoe related to our onshore US horizontal drilling programs; and
additions of 269 MMBoe related to our acquisition of Eagle Ford Shale and Permian Basin assets;
offset by:
record production volumes of 130 MMBoe;
downward revisions of 307 MMBoe that were commodity price driven; and
reduction of 6 MMBoe as a result of asset sales.
Price Revisions Of the 307 MMBoe price revisions, 116 MMBoe relate to proved developed reserves and 191 MMBoe relate to proved undeveloped reserves. Unlike proved undeveloped reserves, which require capital investment associated with drilling and development activities, proved developed reserves that were subject to downward price revisions, would not require additional capital investment to access the reserves if the commodity price increases.
Our proved reserves are 62% US and 38% international, and the mix is 35% global liquids (crude oil and NGLs), 33% international natural gas and 32% 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.
Crude Oil and Natural 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. These activities include geophysical and geological evaluation, analysis of commercial, regulatory and political risk and exploratory drilling, where appropriate. Our properties consist primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. We also own natural gas processing plants and natural gas gathering systems and other crude oil and natural gas-related pipeline systems. These assets are primarily used in the processing and transportation of our crude oil, natural gas and NGL production.

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Exploration Activities   We primarily focus on organic growth from exploration and development drilling, concentrating on basins or plays where we have strategic competitive advantages, emanating 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 exploration success in the deepwater Gulf of Mexico, the Douala Basin offshore West Africa and the Levant Basin offshore Eastern Mediterranean, resulting in a portfolio of major development projects. We have exploration opportunities remaining in these areas and have also engaged in new venture activity.
Although our focus on exploration activities has historically created a sustainable exploration program, we significantly reduced our 2015 exploration budget due to the current commodity price environment. Our 2016 exploration budget is also reduced but provides flexibility to respond to commodity price changes.
In 2015, we conducted exploration activities in domestic and international locations including the deepwater Gulf of Mexico, offshore West Africa and offshore the Falkland Islands.
Appraisal, Development and Production Activities   Our discoveries and strategic acquisitions in recent years have provided us with numerous appraisal, development and production opportunities, as demonstrated in our inventory of major development projects.  Although our capital budget for these activities was reduced in 2015, we continued to make significant progress on our ongoing onshore US and other major development projects.
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 owning the assets. We may also periodically divest non-core, non-strategic assets.
Rosetta Merger On July 20, 2015, we completed the merger of Rosetta Resources Inc. (Rosetta) into a subsidiary of Noble Energy (Rosetta Merger). This merger adds two premier onshore US shale positions to our core operating areas: the Eagle Ford Shale and Permian Basin. Rosetta's liquids-rich asset base included approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin (45,000 net acres in the Delaware Basin and 9,000 net acres in the Midland Basin). We are continuing to improve drilling and well performance in these unconventional plays by applying best practices from our onshore business and by capitalizing on Noble Energy - Rosetta synergies. See Item 8. Financial Statements and Supplementary Data - Note 3. Mergers, Acquisitions and Divestitures.
Suriname Entry In October 2015, we acquired a non-operated 20% working interest in Block 54 offshore Suriname via farm-in from Tullow Oil plc. Tullow is the operator with a 30% interest. The initial phase of exploration on the block requires acquisition of a 3D seismic survey, which has been completed and is currently being processed. Evaluation of the seismic survey will determine if a commitment to a subsequent exploration phase to drill an exploration well is warranted.
Offshore Israel Assets In November 2015, we signed an agreement to divest our 47% working interest in the Alon A and Alon C offshore Israel licenses, which include the Karish and Tanin fields, to the Delek Group. The terms of the agreement simplify the ultimate sale to a third party by providing our partners with the exclusive right to conclude the full divestment of these assets. This agreement is an important step in fulfilling Noble Energy's obligations under the Natural Gas Framework. The transaction closed in January 2016 for a total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs). These fields were not included in our proved reserves estimates at December 31, 2015. See Update on Israel – Israel Natural Gas Framework below.
Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with BG Group plc (BG) for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery. In January 2016, we received proceeds of $125 million related to the farm-out agreement and expect to receive the remaining consideration of $40 million, subject to post-close adjustments, in 2017. We remain operator of Block 12 with a 35% interest.
Non-Core Divestiture Program During 2015, we continued our non-core asset divestiture program with the sale of certain smaller onshore US property packages resulting in net proceeds of $151 million. Divestitures of non-core properties allow us to allocate capital and other resources to areas with potential for higher value and growth. We continue to evaluate divestment opportunities of certain non-core, onshore properties located in the Rocky Mountain and Bowdoin (north central Montana) areas.
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. Mergers, Acquisitions and Divestitures.
Asset Impairments  We recorded $533 million in impairment charges for 2015, including $490 million in fourth quarter 2015. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.
Goodwill Impairment During fourth quarter 2015, we determined that our goodwill, which had arisen from previous mergers and been assigned to the US reporting unit, had been fully impaired and recorded impairment charges of $779 million. See Item 8. Financial Statements and Supplementary Data – Note 4. Goodwill.


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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 68% of 2015 total consolidated sales volumes and 62% of total proved reserves at December 31, 2015. Approximately 51% of the proved reserves in the US are natural gas, 29% are crude oil and condensate and 20% are NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows: 
 
 
Year Ended December 31, 2015
 
December 31, 2015
 
 
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
 
57

 
234

 
19

 
115

 
160

 
861

 
70

 
374

Marcellus Shale
 
2

 
393

 
10

 
77

 
2

 
1,253

 
20

 
231

Eagle Ford Shale
 
5

 
55

 
8

 
22

 
36

 
485

 
77

 
194

Deepwater Gulf of Mexico
 
13

 
11

 
1

 
15

 
28

 
38

 
2

 
36

Other Onshore US
 
4

 
15

 
1

 
8

 
30

 
74

 
7

 
49

Total
 
81

 
708

 
39

 
237

 
256

 
2,711

 
176

 
884

Wells drilled in 2015 and productive wells at December 31, 2015 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2015
 
December 31, 2015
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
DJ Basin
 
211

 
7,613

Marcellus Shale
 
89

 
509

Eagle Ford Shale
 
8

 
339

Permian Basin
 
13

 
205

Deepwater Gulf of Mexico
 
3

 
13

Other Onshore US
 
4

 
955

Total
 
328

 
9,634

(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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Our onshore US operations are located in proven basins with long-life production profiles. These assets include 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, 2015 are shown on the map below:
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. Our position in the core area covers approximately 396,000 net acres.
In 2015 and currently, we are focusing our drilling and development activity on Integrated Development Plan (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, drill a much higher percentage of extended reach lateral wells, and build our own centralized production facilities, gathering systems, and water infrastructure. With this approach, we construct multi-well horizontal drilling pads and centralized processing facilities (CPFs) to minimize surface use. The drilling pads and CPFs facilitate efficient execution of operations by reducing land surface and water usage while enabling us to efficiently gather and process crude oil, natural gas, NGLs and water from a large surrounding area, reducing truck traffic and our overall surface footprint. Additionally, our IDP approach has provided an opportunity to efficiently and economically support production growth by constructing and expanding our infrastructure across the DJ Basin.
2015 Activity In response to the current commodity price environment, we adopted a reduced and flexible 2015 capital program, responsive to changes in the commodity price environment. Due to continued low prices during 2015, we reduced our level of drilling activity in the basin. Operationally, we focused on reducing capital costs per unit and unit operating costs while increasing operating efficiencies to support project returns and margin improvements. Through material efficiency gains, midstream expansions and improved completion techniques, we were able to deliver higher production at lower capital and operating costs.
Despite a reduced drilling budget, we were able to expand our extended reach lateral well program to approximately 43% of wells drilled in 2015. During the year, we spud 171 horizontal wells, of which 72 were extended reach lateral wells, and 182 wells initiated production. We also participated in approximately 30 non-operated development wells during 2015.
In second quarter 2015, we began operation of the Keota plant, our second natural gas processing plant in northern Colorado, to support our East Pony IDP, providing additional capacity to support future development in this part of the basin.

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The DJ Basin contributed an average of 115 MBoe/d of sales volumes in 2015, an increase of 14% over 2014 volumes, and
representing approximately 33% of total consolidated sales volumes. DJ Basin sales volumes were approximately 50% crude oil and 17% NGLs.
Our 2015 DJ Basin development program resulted in net additions/revisions to proved reserves of approximately 71 MMBoe, approximately 74% of which are crude oil and NGLs. At December 31, 2015, proved reserves in the DJ Basin represented approximately 26% of our total proved reserves. See Proved Reserves Disclosures.
We exited 2015 with a three rig drilling program. However, commodity prices have continued to trade in a low range into 2016. We are engaged in a comprehensive effort to spend within cash flow and have again adopted a reduced and flexible capital spending program for 2016. The spending program provides flexibility to reassess activity levels in response to the commodity price environment that evolves during the remainder of 2016.
In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, 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 DJ Basin Non-Attainment Area. A Non-Attainment Area is any area that does not meet (or that contributes to ambient air quality in a nearby area that does not meet) the national primary or secondary ambient air quality standard for a pollutant. The Consent Decree was entered by the US District Court of Colorado on June 2, 2015. See Item 1.A. 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.
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.
We have a 50-50 joint development agreement with CONSOL Energy, Inc. (CONSOL) in approximately 700,000 gross acres in southwest Pennsylvania and northwest West Virginia. We operate the wet gas (natural gas containing more liquid hydrocarbons) development area in Majorsville, West Virginia and Southwest Pennsylvania, and Moundsville, Shirley and Oxford, West Virginia, while CONSOL primarily operates in the dry gas (natural gas containing less liquid hydrocarbons) development area. Our joint development agreement with CONSOL provides for a multi-year drilling and development plan. 
Utilizing an IDP concept, modeled after the DJ Basin, we have realized capital and operating cost efficiencies through multi-well pads, central facilities and efficient liquids infrastructure that enable us to minimize truck traffic, enhance completion design and optimize well placement. The current identified IDP areas are Majorsville, West Virginia, Southwest Pennsylvania Area Dry, and Allegheny County Airport, Pennsylvania. Majorsville, which came online in 2012 as the first operated IDP location, is in the core operating area with water and marketing infrastructure in place to support further development.
2015 Activity During 2015, the joint venture drilled a total of 89 wells. Noble drilled 41 of these wells with an average lateral length of 8,000 feet. The joint venture initiated production on 91 wells. During the year, we shifted our drilling activity away from the Marcellus Shale in response to low commodity prices, coupled with high basis differentials due to oversupply. However, operational performance remained strong, with volumes increasing 57% compared to 2014.
Currently, there are no operated or non-operated rigs running in the Marcellus Shale. For 2016, we and CONSOL have agreed to operate within cash flow and have agreed to a reduced development program for the year compared to the plan provided for under the multi-year drilling and development plan. This 2016 plan will focus on well completions and provides for fewer wells to be drilled than the number of wells that was provided for under the multi-year drilling and development plan, and a reduction of allocated capital to be invested in the Marcellus Shale core area. Our 2016 capital spending program provides flexibility to reassess activity levels in response to the commodity price environment, and other factors, that may evolve in this region during the remainder of the year.
The Marcellus Shale contributed an average of 462 MMcfe/d of sales volumes and represented approximately 22% of total consolidated sales volumes in 2015 and approximately 16% of total proved reserves at December 31, 2015. Our 2015 Marcellus Shale development program resulted in net additions/revisions to proved reserves of approximately 95 MMBoe, approximately 12% of which are crude oil and NGLs. See Proved Reserves Disclosures.
CONE Gathering We and CONSOL also operate CONE Gathering LLC (CONE Gathering), which constructs, owns and operates midstream infrastructure servicing our joint production, and is the general partner controlling interest in CONE Midstream Partners (CONE Midstream). CONE Midstream is a master limited partnership, formed in late 2014, in which we own a 32.1% interest accounted for using the equity method of accounting. During 2015, 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 on line. Continued focus on cost optimization yielded decreases in operating expense as compared with the prior year.  

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Eagle Ford Shale and Permian Basin On July 20, 2015, we completed the Rosetta Merger, adding the Eagle Ford Shale and Permian Basin to our core areas (approximately 104,000 net acres total). During 2015, we drilled ten operated wells to total depth, including nine Lower Eagle Ford wells and one Wolfcamp A well in the Permian Basin, with reduced drilling times versus prior performance. We commenced production on eight operated Lower Eagle Ford wells and have applied IDP learnings from other US onshore assets to realize cost efficiencies, enhance completion design and optimize well placement.
In 2015 and on a full year basis, these assets contributed an average of 26 MBoe/d of sales volumes, representing approximately 7% of total consolidated sales volumes, and were approximately 28% crude oil and 35% NGLs. These assets represented approximately 16% of total proved reserves at December 31, 2015.
We exited 2015 with two rigs operating, one in the Eagle Ford Shale and one in the Permian Basin. At the end of 2015, 55 wells were drilled but not complete. Commodity prices have continued to trade in a low range into 2016 and our 2016 capital spending program provides flexibility to reassess activity levels in response to the commodity price environment that evolves during the remainder of the year.
Other Non-Core Onshore Properties   We also operate in the following onshore US areas: Rocky Mountains and Bowdoin (north central Montana). Other non-core onshore properties accounted for 1% of total consolidated sales volumes in 2015 and approximately 1% of total proved reserves at December 31, 2015. During 2015, we sold various non-core onshore properties and continue to evaluate divestment opportunities. See Acquisition and Divestiture Activities – Non-Core Divestiture Program above.
Northeast Nevada After assessing its commercial viability in the current commodity price environment, we elected to discontinue our exploration effort in northeast Nevada. During fourth quarter 2015, we recorded exploration expense of $95 million in conjunction with this exit.

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Deepwater Gulf of Mexico   Locations of our operations in the deepwater Gulf of Mexico as of December 31, 2015 are shown on the map below:
Noble Energy was one of the first independent producers to explore in the Gulf of Mexico. We acquired our first offshore block in 1968, and our focus has been on high-impact opportunities with the potential to provide sustained production and cash flow.
We have several producing fields, ongoing development projects and a substantial inventory of exploration opportunities.
In 2015, we completed Big Bend and Dantzler (Rio Grande project) ahead of schedule representing approximately three and two years development time from discovery to production, respectively. Production commenced fourth quarter with a combined peak rate of 20 MBoe/d, net.
We currently hold leases on 104 deepwater Gulf of Mexico blocks, representing approximately 39,000 net developed acres and approximately 329,000 net undeveloped acres. We are the operator on approximately 70% of our leases. See also Developed and Undeveloped Acreage – Future Acreage Expirations, below.
The deepwater Gulf of Mexico accounted for 4% of total consolidated sales volumes in 2015 and 3% of total proved reserves at December 31, 2015.
Deepwater Gulf of Mexico Exploration Program   Our deepwater Gulf of Mexico operations resulted from lease acquisition, expansion of our 3D seismic database, and an active drilling program. We currently have 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.
Our 2015 exploration budget was substantially reduced due to the current commodity price environment and effort to keep spending within our cash flows. However, we continued to engage in various exploration activities including spudding the Silvergate exploratory well, described below.

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Our 2016 exploration budget has also been substantially reduced, but provides flexibility to respond to commodity price changes. We currently have capitalized undeveloped leasehold cost of approximately $247 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2016 - 2024 and 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 leasehold expense could be significant.
In addition, new regulations are being considered by various federal agencies overseeing certain of our activities in the Gulf of Mexico. The Bureau of Safety and Environmental Enforcement recently issued a proposed rule intended to update 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, while the Bureau of Ocean Energy Management is in the process of updating 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. These regulations, if ultimately adopted could, among other things, significantly increase the costs associated with our activities in the Gulf of Mexico and result in some of our undrilled leaseholds becoming uneconomic to drill.
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.
2015 Activity We have a multi-year contract for the Atwood Advantage drillship. We used the drillship in our 2015 drilling plan which included various exploration, development and well completion activities. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations.
Silvergate (Mississippi Canyon Block 339; 50% operated working interest) During fourth quarter 2015, we spud an exploratory well at the Silvergate prospect. The well is targeting the Middle Miocene objective with results expected in first quarter 2016.
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. We plan to conduct additional appraisal drilling activities in 2016 to test the remaining resource potential and further define potential development scenarios.
Ongoing Major Development Projects
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. We are in the process of completing topsides modifications and facilities upgrades. Development is on track, and we are targeting first production for mid-2016.
Offshore Producing Properties   
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. We expect to conduct workover activities at Isabela during 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 third-party Thunder Hawk platform. The Rio Grande development commenced production in October 2015 and contributed almost 3 MBoe/d of sales volumes in 2015 and currently produces approximately 20 MBoe/d.
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.
Asset Impairments During 2015 and 2014, we recorded impairment expense of $158 million and $350 million, respectively, related to deepwater Gulf of Mexico properties. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.

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International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in Equatorial Guinea and Israel contributed substantially to our growth over the last decade.
Previous exploration successes offshore West Africa, Israel and Cyprus have identified multiple major development projects that have the potential to contribute to production growth in the future. We drilled two exploratory wells in 2015, and our large acreage positions in West Africa and the Eastern Mediterranean could provide further exploration opportunities.
On the development side, during 2015, we completed the Tamar field compression project and advanced Eastern Mediterranean regional natural gas export opportunities. Our partners in the Alba field, offshore Equatorial Guinea, advanced the Alba field compression project.
International operations accounted for 32% of total consolidated sales volumes in 2015 and 38% of total proved reserves at December 31, 2015. International proved reserves are approximately 88% natural gas and 12% 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 PSC and 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.

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Locations of our international operations as of December 31, 2015 are shown on the map below:
Sales volumes and estimates of proved reserves for our international operating areas were as follows: 
 
 
Year Ended December 31, 2015
 
December 31, 2015
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equatorial Guinea
 
31

 
227

 

 
69

 
48

 
534

 
13

 
151

Israel
 

 
252

 

 
42

 
3

 
2,304

 

 
386

Total International
 
31

 
479

 

 
111

 
51

 
2,838

 
13

 
537

Equity Investee
 
2

 

 
5

 
7

 

 

 

 

Total
 
33

 
479

 
5

 
118

 
51

 
2,838

 
13

 
537

Equity Investee Share of Methanol Sales (MMgal)
 
117

 
 

 
 
 
 
 
 


Wells drilled in 2015 and productive wells at December 31, 2015 in our international operating areas were as follows:
 
 
Year Ended December 31, 2015
 
December 31, 2015
 
 
Gross Wells Drilled
or Participated in
 
Gross Productive
Wells
International
 
 
 
 
Equatorial Guinea
 
1

 
26

Cameroon
 
1

 

Israel
 

 
8

North Sea
 

 
1

Falkland Islands
 
1

 

Total International
 
3

 
35

West Africa (Equatorial Guinea, Cameroon and Gabon)   West Africa is one of our core operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo mining concession and Tilapia PSC, offshore Cameroon, and one block offshore Gabon. Equatorial Guinea, the only producing country in our West Africa segment, accounted for

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approximately 20% of 2015 total consolidated sales volumes and 11% of total proved reserves at December 31, 2015. We held approximately 118,000 net developed acres and 30,000 net undeveloped acres in Equatorial Guinea, 511,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres in Gabon at December 31, 2015. During second quarter 2015, we exited our position in Sierra Leone following processing of 2D seismic data.
Locations of our operations in Equatorial Guinea and Cameroon, as of December 31, 2015 are shown on the map below:
Aseng Field Aseng is a crude oil field on Block I (40% operated working interest), offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal 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. Aseng produced approximately 11 MBoe/d, net, during 2015.
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 almost 99% production uptime.
Alen Field   Alen is a natural gas and condensate field primarily on Block O (45% operated working 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 13 MBoe/d, net, during 2015.
Alba Field    We have a 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, 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. The Alba field produced approximately 45 MBoe/d, net, during 2015.
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

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LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest accounted for as an equity method investment. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest, also accounted for as an equity method investment. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices. Both the AMPCO methanol plant and the ALBA LPG plant are scheduled for turnaround activities during first quarter 2016.
During 2015, we participated in the drilling of one development well. The Alba compression project installation progressed and is expected to be completed in early second quarter 2016.
Other Block O & I Projects    We are currently processing the results of recently acquired 3D seismic data across Equatorial Guinea Blocks O and I which will aid in advancing other regional exploration and development opportunities, including the Diega/Carmen and Carla discoveries.
Asset Impairments During 2015, we recorded impairment expense of $339 million related to offshore Equatorial Guinea properties due to a decline in future crude oil prices. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.
Cameroon We have an interest in over one million gross undeveloped acres offshore Cameroon, which include the YoYo mining concession (50% operating working interest) and Tilapia PSC (46.67% operating working interest). Petronas holds the other 50% operating working interest in the YoYo mining concession and has given notice to us and the Cameroon government of their intention to exit the YoYo mining concession. Once the assignment process is finalized, we will hold 100% operating working interest in the YoYo mining concession. We have begun efforts to market this additional 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 and are negotiating with the Cameroon government to convert the YoYo mining concession to a PSC. We have completed reprocessing of 3D seismic data over our YoYo mining concession and are currently evaluating the data.
In 2015, we drilled the Cheetah exploration prospect on the Tilapia license (46.67% working interest), offshore Cameroon. The well encountered both crude oil and natural gas shows in multiple non-commercial reservoir sands and was plugged and abandoned. In 2015, we recorded dry hole costs of $33 million associated with this exploratory well. Results from the well are being integrated into our geologic modeling for the remaining exploration potential in the Tilapia license.
West Africa Natural Gas Project    The West Africa natural gas project includes the 2007 Yolanda discovery (Block I) and 2008 Felicita discovery (Block O), offshore Equatorial Guinea, the YoYo discovery, offshore Cameroon, and associated natural gas from Aseng and Alen, offshore Equatorial Guinea. A natural gas development team is working with each government to evaluate natural gas monetization options. In addition, we are working to finalize a data exchange agreement between the two countries as a first step towards unitization of any cross border resources.
Offshore Gabon We are the operator of Block F15 (60% working interest), an undeveloped, ultra-deep water area, covering approximately 671,000 gross acres. The exploration phase is underway and we are planning to conduct a 3D seismic survey in the first half of 2016.
See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs.
Eastern Mediterranean (Israel and Cyprus)    One of our core operating areas is the Eastern Mediterranean, where we have drilled 11 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, our only producing country in our Eastern Mediterranean core area, accounted for 12% of 2015 total consolidated sales volumes and 27% of total proved reserves at December 31, 2015. Our leasehold position in the Eastern Mediterranean at December 31, 2015, included eight leases and three licenses operated offshore Israel and one license operated offshore Cyprus. Eastern Mediterranean acreage includes the Alon A and Alon C licenses which were converted to the Karish and Tanin leases in 2015 and subsequently divested in January 2016.
At December 31, 2015, the Eastern Mediterranean position included approximately 80,000 net developed acres and 261,000 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 464,000 net undeveloped acres adjacent to our Israel acreage.

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Locations of our operations in the Eastern Mediterranean as of December 31, 2015 are shown below:
 
(1) In January 2016, we closed the sale of our Karish and Tanin natural gas discoveries.
Update on Israel Noble Energy and our partners have remained committed to providing natural gas to Israeli citizens for over a decade. During this time we have reliably and consistently delivered approximately 1.6 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
We are the first company to construct, operate and produce from a major natural gas development project offshore Israel. Our Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed the Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by historical industry standards for an offshore natural gas project of this magnitude and complexity.

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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 become a significant natural gas exporter. Multiple markets exist in the region, and Israel’s domestic demand is predicted to continue to grow over the next decade.
In addition to our natural gas discoveries, the Levant Basin has potential for large scale crude oil discoveries, which may exist at greater depths. We have conducted preliminary exploration activities and are working on potential well design and placement to assess the presence of crude oil in the basin.
Israel Natural Gas Framework We have been progressing plans to develop the Leviathan field and expand the currently producing Tamar field. Historically we have had to address certain fiscal, antitrust and other regulatory challenges in Israel. These challenges have been addressed with the enactment of a comprehensive regulatory natural gas framework (Natural Gas Framework) by the Government of Israel. The Natural Gas Framework provides clarity on numerous matters concerning resource development which we will rely upon to support a final investment decision and upon which we can develop our resources while ensuring economic benefits to the state of Israel and its citizens. Among other items, the Natural Gas Framework provides for the following:
the timely approval of asset development permits and plans and export permits;
benchmarking future domestic contract pricing for an interim period until market competition is established, whereby such contracts are indexed to existing domestic and export contracts;
resolution of antitrust and competition concerns, whereby we would divest Karish and Tanin within 14 months and reduce our ownership in Tamar to 25% within six years;
the de-linking of Tamar export timing from Leviathan, enabling Tamar expansion to move forward; and
support for investment and industry growth through stabilization assurance.
The Natural Gas Framework also enables marketing of Leviathan natural gas to Israeli customers for the first time. The development of Leviathan will substantially expand Noble Energy's 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 for the people of Israel. The implementation of the Natural Gas Framework is a significant milestone towards the completion of the natural gas sales agreements with purchasers in Jordan and Egypt and obtaining financing for the project. With the strong support for the Natural Gas Framework demonstrated by the Government of Israel, the quantity and quality of discovered natural gas resources, regional demand for natural gas and the significant associated economic benefit to the government, citizens of Israel and the region, we plan to move forward with completing natural gas sales agreements, securing project financing and finalizing development scenarios to prepare the Tamar expansion and Leviathan development projects for final investment decisions.
The Israel Supreme Court held two hearings in February 2016 to consider legal challenges to the Natural Gas Framework, including the Government of Israel’s enactment of Section 52 of the Restrictive Trade Practices Act and constitutional aspects of the stability undertakings. The Court requested a response whether the government will be willing to consider enacting legislation that will support the stability provisions of the Framework. We cannot predict what will be the response from the Government of Israel nor determine the outcome of these hearings.
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, to the Delek Group. The terms of the agreement simplify the ultimate sale to a third party by providing our partners with the exclusive right to conclude the full divestment of these assets. This agreement is an important step in fulfilling Noble Energy's obligations under the Natural Gas Framework. The transaction closed in January 2016 for a total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs).
As of December 31, 2015, our $2.1 billion investment in Israel includes: approximately $1.4 billion related to the currently-producing Tamar field; approximately $400 million related to the Leviathan natural gas discovery and suspended deep oil test; approximately $200 million related to the Tamar expansion project and previous discoveries which are awaiting sanction of development plans; and $67 million related to the Karish and Tanin discoveries, which were included in assets held for sale.
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, 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 to use natural gas. We expect that government requirements for emissions reductions could also drive incremental demand for natural gas in the future. 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 large regional demand. With the Tamar field already on line, and the Leviathan field appraised and flow tested, we are well positioned to supply natural gas to the region for many years.

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With the clarity provided by implementation of the Natural Gas Framework, we are continuing to negotiate contracts for natural gas sales to supply LNG plants in Egypt and the National Electric Power Company in Jordan through a regional pipeline system. We have natural gas sales and purchase agreements with Dolphinus Holdings for up to 250 MMbtu of interruptible natural gas sales to Egypt from current Tamar capacity. We also have a natural gas sales and purchase agreement in place for Tamar natural gas sales of 66 Bcf to the Jordan Bromine and Arab Potash companies in Jordan, with sales beginning at the end of 2016. In addition, we have signed a letter of intent with Dolphinus Holdings for up to 4 BCM (approximately, 140 Bcf) annually from Leviathan for the Egyptian market. See Israel Natural Gas Framework above 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.
Tamar Natural Gas Projects  (36% 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. Growth in power and industrial demand in Israel, coupled with almost 100% uptime, enabled us to set new records for sales from our Tamar field in August 2015 of more than 1.0 Bcf/d, gross. Net production from Tamar averaged 254 MMcfe/d for 2015.
During 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT).
Also during 2015, we continued to work with the Government of Israel to obtain regulatory approval of the development plan for our 2013 Tamar Southwest discovery (36% operated working interest), which is intended to utilize current Tamar infrastructure.
We have also engaged in the planning phase for the Tamar expansion project. The expansion development 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)  Due to Leviathan's size, full field development is expected to require several development phases, with an overall development plan expected to serve both domestic demand and export markets.
In 2016, we will focus on finalizing GSPAs with multiple domestic and regional customers for the first phase of Leviathan. The GSPAs will be subject to, among other conditions, the receipt of regulatory approvals.
We are currently evaluating various development scenarios. Along with our original FPSO design, an additional concept utilizes a fixed platform to ensure timely first production. This fixed platform option provides greater flexibility to match initial contracted volumes, while retaining the ability to be expanded for additional contracts.
Timing of a final investment decision will depend on receipt of necessary regulatory approvals, the success of our marketing activities and securing of project financing.
Other Discoveries Offshore Israel   We and our partners previously submitted a development plan for the Dalit field (36% operated working interest), a 2009 natural gas discovery. Development would include a tieback to the Tamar platform. We are using recent 3D seismic data to reevaluate the potential of the area, including the possible existence of hydrocarbons at deeper intervals. 
We have submitted a commerciality package for Dolphin (39.66% operated working interest), including a potential tieback to Leviathan. We are also designing a drilling plan specifically for a potential test of a Mesozoic deep oil concept (Leviathan-1 Deep) and working on potential well design and placement.
Asset Impairments During 2015 and 2014, we recorded impairment expense of $36 million and $14 million, respectively, related to offshore Israel properties. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.
Cyprus Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with BG for a portion of our interest in Block 12, which includes the Aphrodite natural gas discovery. The agreement was approved by the Government of Cyprus and completed in January 2016 whereby BG acquired a 35% interest in Block 12 for total cash consideration of $165 million, $125 million of which was received in January 2016 and the remainder of which will be paid in 2017. We will continue to operate with a 35% interest. Also, as part of the BG farm-out process, we negotiated a waiver of our remaining exploration well obligation.
During 2015, we submitted a Declaration of Commerciality and a 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 gas, will allow us and our partners to perform the necessary front-end engineering design (FEED) studies and progress the project to final investment decision.

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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.
See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs.
Other International
Our other international operations accounted for less than 1% of total consolidated sales volumes for 2015 and had no proved reserves at December 31, 2015.
Offshore Falkland Islands We drilled the Humpback exploration prospect (35% operated working interest), located in the South Falkland Basin in 2015. After evaluating results, we plugged and abandoned this exploratory well as we did not locate commercial quantities of hydrocarbons. As a result, we recorded dry hole costs of $140 million in 2015.
In 2015, we acquired the PL001 License in the North Falkland Basin, which covers an area of approximately 280,000 gross acres. We identified the Rhea prospect (75% operated working interest) as the initial target on the PL001 License. However, we experienced material operational issues with the drilling unit while drilling the Humpback well and the drilling contract was terminated on February 11, 2016. We remain confident in the potential of the Rhea prospect, which is located near the Sea Lion discovery in a proven petroleum system. We have been and will continue to work closely with our partners and the Falkland Islands Government to evaluate a path forward that includes retaining flexibility for the Rhea exploration well.
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.
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 is the operator with a 30% interest.  The initial phase of exploration on the block requires acquisition of a 3D seismic survey, which has been completed and is currently being processed.  Evaluation of the seismic survey will determine if a commitment to a subsequent exploration phase to drill an exploration well is warranted.
North Sea  The non-operated MacCulloch field is currently undergoing decommissioning activities.
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.
In addition, our Company-wide short-term incentive plan does not include quantitative targets for proved reserves additions.
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 35 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.

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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 2015 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 2015, 2014, and 2013, we retained NSAI to perform audits of proved reserves. The reserves audit for 2015 included a detailed review of nine of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 85.1% of US proved reserves and 99.9% of international proved reserves (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. The reserves audit for 2013 included a detailed review of nine of our major fields and covered approximately 85% of total proved reserves.
In connection with the 2015 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, 2015, 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, 2015, on a quantity basis, the NSAI field estimates ranged from 11 MMBoe or 5% above to 17 MMBoe or 6% 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, 2015 were, in the aggregate, approximately 23 MMBoe, or 2%.
Proved Undeveloped Reserves (PUDs)   As of December 31, 2015, our PUDs totaled 133 MMBbls of crude oil and condensate, 1.6 Tcf of natural gas, and 83 MMBbls of NGLs for a total of 485 MMBoe. Changes in PUDs that occurred during

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the year are summarized below:
 
 
United
 States
 
Equatorial
Guinea
 
Israel
 
Total
(MMBoe)
 
 
 
 
 
 
 
 
Proved Undeveloped Reserves Beginning of Year
 
390

 
59

 
74

 
523

Revisions of Previous Estimates
 
(177
)
 
2

 
(3
)
 
(178
)
Extensions, Discoveries and Other Additions
 
77

 

 

 
77

Purchase of Minerals in Place
 
143

 

 

 
143

Sale of Minerals in Place
 

 

 

 

Conversion (to) from Proved Developed
 
(89
)
 
9

 

 
(80
)
Proved Undeveloped Reserves End of Year
 
344

 
70

 
71

 
485

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. Negative revisions of 177 MMBoe in the US for 2015 included:
the transfer to unproved reserves of 183 MMBoe due to negative price revisions attributed to low commodity price outlook and negative revisions of 48 MMBoe due to reduced future development activity, primarily in the DJ Basin;
offset by:
54 MMBoe positive revisions primarily in the Marcellus Shale, Eagle Ford Shale and Permian Basin due to current drilling and development plans.
Extensions, discoveries and other additions include addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields. During 2015, we recorded additions of 68 MMBoe and 9 MMBoe in the DJ Basin and Marcellus Shale, respectively, as a result of successful expansion of our extended reach lateral well programs.
Purchases of minerals included 119 MMBoe and 24 MMBoe in the Eagle Ford Shale and Permian Basin, respectively, as a result of the Rosetta Merger.
Conversion to proved developed reserves primarily included the transfer of 39 MMBoe, 22 MMBoe, 17 MMBoe and 11 MMBoe from the Marcellus Shale, DJ Basin, Eagle Ford Shale and deepwater Gulf of Mexico, respectively. In 2015, we converted 89 MMBoe of US PUDs, or 23% of our 2014 US PUD 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 as of December 31, 2015 to be converted to proved developed reserves well within a five-year period.
US PUDs Locations  As of December 31, 2015, our US PUDs included:
147 MMBoe in the DJ Basin;
50 MMBoe in the Marcellus Shale;
102 MMBoe in the Eagle Ford Shale;
31 MMBoe in the Permian Basin; and
14 MMBoe in the deepwater Gulf of Mexico primarily associated with the Gunflint project.

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, 2015, we had approximately 98 MMBoe of proved undeveloped reserves associated with DUC well locations related to our onshore US operations, approximately one-half of which are in the Marcellus Shale, nearly one-third are in the Eagle Ford Shale and the remainder are in the DJ Basin and Permian Basin.
International PUDs Locations As of December 31, 2015, our international PUDs included:
70 MMBoe in the Alba field, offshore Equatorial Guinea, all of which have been recorded as PUDs for over five years and are attributable to a sanctioned compression project which is currently under construction and expected to come online mid-2016. These volumes, which will be recovered through existing wells, will be reclassified to proved developed at start-up, currently expected in second quarter 2016; and
71 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields, including PUDs of 32 MMBoe related to the Tamar Southwest field, which is awaiting government approval of the development plan.

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PUDs include no material amounts, except the Alba field PUDs of 70 MMBoe, which have remained undeveloped for five years or more since initial disclosure.
Development Costs    Costs incurred to advance the development of PUDs were approximately $1.5 billion in 2015, $2.0 billion in 2014, and $1.0 billion in 2013. A significant portion of costs incurred in 2015 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 $0.7 billion in 2016, $0.7 billion in 2017, and $0.8 billion in 2018. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. PUDs related to major development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans  All PUD drilling locations are scheduled to be drilled prior to the end of 2020. PUDs associated with the Alba field compression project are also expected to be converted to proved developed reserves prior to the end of 2016.  Initial production from these PUDs is expected to begin during the years 2016 - 2020.
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, 2015, we had 195 PUD well locations, primarily located in the DJ Basin and Permian Basin, with a negative present worth when discounted at 10% and based on SEC prices. Net quantities totaled 28 MMBbl of crude oil and condensate, 173 Bcf of natural gas, and 9 MMBbl of NGLs. These amounts represented approximately 19% of total PUD locations and approximately 14% of total PUD quantities at December 31, 2015.  
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. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2016 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, 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

 

 
1.40

Eagle Ford Shale
 
1,656

 
19,969

 
3,074

 
31.65

 
2.25

 
13.44

 
3.15

Other US
 
6,024

 
9,837

 
631

 
45.91

 
3.18

 
12.34

 
8.90

Total US
 
29,262

 
258,640

 
14,095

 
43.46

 
2.10

 
10.39

 
4.28

Equatorial Guinea (2)
 
11,416

 
82,729

 

 
48.85

 
0.27

 

 
5.22

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
121

 
91,884

 

 
46.91

 
5.34

 

 
2.04

  Other Israel
 

 
136

 

 

 
3.01

 

 

  Total Israel
 
121

 
92,020

 

 
46.91

 
5.34

 

 
3.15

United Kingdom
 
88

 
49

 

 
55.52

 
6.32

 

 
41.07

Total Consolidated Operations
 
40,887

 
433,438

 
14,095

 
45.00

 
2.44

 
10.39

 
$
4.43

Equity Investee (3)
 
554

 

 
1,850

 
48.85

 

 
28.40

 
 
Total Continuing Operations
 
41,441

 
433,438

 
15,945

 
$
45.05

 
$
2.44

 
$
12.48

 
 
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

 
23.77

 
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

 
32.04

 
5.33

Equatorial Guinea (2)
 
12,191

 
88,833

 

 
94.61

 
0.27

 

 
5.44

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
109

 
79,828

 

 
89.62

 
5.68

 

 
2.81

  Other Israel
 

 
4,539

 

 

 
3.52

 

 
22.11

  Total Israel
 
109

 
84,367

 

 
89.62

 
5.57

 

 
3.84

China
 
788

 

 

 
103.74

 

 

 
8.53

United Kingdom
 
159

 
56

 

 
102.02

 
16.26

 

 
88.17

Total Consolidated Operations
 
37,540

 
362,070

 
8,416

 
91.58

 
3.38

 
32.04

 
$
5.31

Equity Investee (3)
 
605

 

 
1,934

 
96.53

 

 
62.89

 
 
Total Continuing Operations
 
38,145

 
362,070

 
10,350

 
$
91.65

 
$
3.38

 
$
37.81

 
 
Year Ended December 31, 2013
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
 

 
 

 
 

 
 

 
 

 
 

 
 

DJ Basin
 
16,826

 
76,267

 
5,048

 
$
93.28

 
$
3.50

 
$
36.33

 
$
4.75

Marcellus Shale
 
45

 
50,645

 
351

 
79.62

 
3.67

 
30.92

 
2.54

Other US
 
6,133

 
33,796

 
635

 
105.56

 
3.44

 
31.73

 
12.08

Total US
 
23,004

 
160,708

 
6,034

 
96.53

 
3.54

 
35.53

 
6.03

Equatorial Guinea (2)
 
11,420

 
91,805

 

 
107.48

 
0.27

 

 
3.96

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
77

 
55,794

 

 
100.49

 
5.32

 

 
2.61

  Other Israel
 

 
20,483

 

 

 
4.22

 

 
6.78

  Total Israel
 
77

 
76,277

 

 
100.49

 
5.02

 

 
3.73

China
 
1,569

 

 

 
103.21

 

 

 
9.45

Total Consolidated Operations
 
36,070

 
328,790

 
6,034

 
100.29

 
2.97

 
35.53

 
$
5.35

Equity Investee (3)
 
635

 

 
2,084

 
105.37

 

 
68.12

 
 

Total Continuing Operations
 
36,705

 
328,790

 
8,118

 
$
100.38

 
$
2.97

 
$
43.90

 
 


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(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 expenses.
(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 of accounting.
(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, 2015, 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, 2015 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
5,580

 
5,222

 
4,054

 
2,816

 
9,634

 
8,038

Equatorial Guinea
 
5

 
2

 
21

 
8

 
26

 
10

Israel
 

 

 
8

 
3

 
8

 
3

United Kingdom
 

 

 
1

 

 
1

 

Total
 
5,585

 
5,224

 
4,084

 
2,827

 
9,669

 
8,051

 
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, 2015 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore
 
1,294

 
874

 
1,050

 
665

Deepwater Gulf of Mexico
 
100

 
39

 
488

 
329

Total United States
 
1,394

 
913

 
1,538

 
994

International
 
 

 
 

 
 

 
 

Equatorial Guinea
 
284

 
118

 
81

 
30

Falkland Islands
 

 

 
10,202

 
3,683

Cameroon
 

 

 
1,084

 
511

Israel (1)
 
185

 
80

 
605

 
261

Cyprus (2)
 

 

 
663

 
464

United Kingdom
 
6

 
1

 
14

 
2

Suriname
 

 

 
2,095

 
419

Gabon
 

 

 
671

 
403

Total International
 
475

 
199

 
15,415

 
5,773

Total
 
1,869

 
1,112

 
16,953

 
6,767

(1) 
Includes approximately 124,000 gross undeveloped acres and 58,000 net undeveloped acres attributable to our Karish and Tanin fields which were subsequently divested in January 2016.
(2) 
Our working interest for Cyprus undeveloped acreage decreased from 70% as of December 31, 2015, to 35% upon closing of the sale of a 35% interest in the Cyprus undeveloped acreage to BG Group during 2016.

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,
 
 
2016
 
2017
 
2018
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
 
 
 
 
Onshore US (1)
 
230

 
143

 
137

 
90

 
170

 
47

Deepwater Gulf of Mexico
 
47

 
23

 
7

 
7

 
133

 
91

Equatorial Guinea
 

 

 
55

 
19

 

 

Falkland Islands
 
280

 
210

 
3,587

 
1,255

 
6,335

 
2,217

Israel (2)
 
296

 
132

 

 

 

 

Cyprus (3)
 
568

 
397

 

 

 

 

Cameroon (4)
 
458

 
214

 

 

 

 

Suriname
 

 

 

 

 
2,095

 
419

Gabon
 

 

 

 

 
671

 
403

Total
 
1,879

 
1,119

 
3,786

 
1,371

 
9,404

 
3,177

(1) 
Approximately 25% of 2016 gross acreage is located in core areas where we currently expect to continue development activities and/or extend the lease terms.
(2) 
We currently intend to extend certain leases prior to expiration in accordance with license terms. Approximately 99,000 gross acres (47,000 net) will expire and not be extended.
(3) 
Will expire in accordance with the terms of the Exploitation License for the Aphrodite field.
(4) 
The acreage represents the Tilapia PSC. We extended the lease during 2015. However, the extension timeline varies and it is therefore unknown what percentage of acreage will be relinquished in 2016.

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, 2015
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 
1.5

 
4.0

 
5.5

 
212.5

 

 
212.5

 
218.0

Falkland Islands
 

 
0.4

 
0.4

 

 

 

 
0.4

Equatorial Guinea
 

 

 

 
0.3

 

 
0.3

 
0.3

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

Year Ended December 31, 2013
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
5.8

 

 
5.8

 
341.7

 
3.9

 
345.6

 
351.4

Equatorial Guinea
 

 

 

 

 

 

 

Israel
 
0.4

 

 
0.4

 

 

 

 
0.4

Nicaragua
 

 
0.7

 
0.7

 

 

 

 
0.7

China
 

 

 

 
1.7

 

 
1.7

 
1.7

Total
 
6.2

 
0.7

 
6.9

 
343.4

 
3.9

 
347.3

 
354.2

 

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In addition to the wells drilled and completed in 2015 included in the table above, wells that were in the process of drilling or completing at December 31, 2015 were as follows: 
 
 
Exploratory(1)
 
Development(2)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
2

 
1.0

 
192

 
113.2

 
194

 
114.2

Cameroon
 
1

 
0.5

 

 

 
1

 
0.5

Cyprus
 
2

 
1.4

 

 

 
2

 
1.4

Equatorial Guinea
 
9

 
4.2

 

 

 
9

 
4.2

Israel (3)
 
7

 
3.0

 

 

 
7

 
3.0

Total
 
21

 
10.1

 
192

 
113.2

 
213

 
123.3

(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.
(3) 
Includes the Karish and Tanin exploratory wells which have been classified as assets held for sale as of December 31, 2015 and were divested in January 2016.

See Item 8. Financial Statements and Supplementary Financial Data – Note 6. Capitalized Exploratory Well 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, who 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. The system, known as the Helix Fast Response System (HFRS), at full production capacity, is designed to contain well leaks up to 55 MBbl/d of oil and 95 MMcf/d of natural gas, at 10,000 pounds per square inch (psi) in water depths to 10,000 feet. Resources also include 15,000 psi-gauge and 10,000 psi-gauge intervention capping stacks designed to shut-in wells in water depths to 10,000 feet. We have entered into a separate utilization agreement with HESG which specifies the asset day rates should the HFRS system be deployed.
Internationally, we maintain membership in Oil Spill Response Limited (OSRL). OSRL is an industry owned cooperative which exists to ensure effective response to oil spills wherever they occur. OSRL is an industry leader in oil spill preparedness and response services. Three supplemental agreements have been executed with OSRL, two of which are focused on well capping and containment services. These agreements allow access to four capping stacks geographically distributed around the world. Resources include two 15,000 psi-gauge and two 10,000 psi-gauge intervention capping stacks designed to shut-in wells in water depths to 10,000 feet. The third supplemental agreement provides access to the Global Dispersant Stockpile, a globally distributed 5,000 cubic meter dispersant stockpile. We also maintain agreements internationally with National Response Corporation, which provides leased response equipment as well as 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 are 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 have improved flow assurance and future projects coming online in the northeast in the next few years are expected to continue to enhance transportation of Marcellus Shale 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 and an unaffiliated LNG 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 of accounting.
In Israel, we sell natural gas from the Tamar and Mari-B fields, and have agreements with multiple customers to sell natural gas under long-term contracts, ranging from 15 to 17 years. See Delivery Commitments, below. 

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Delivery and Firm Transportation Commitments   Some of our contracts specify the delivery or transportation of fixed and determinable quantities.
Domestic Contracts We have commitments to deliver approximately 437 Bcf of natural gas produced onshore US, primarily in the Marcellus Shale to customers under long-term sales contracts ranging from one to 25 years. We have also entered into various long-term gathering, processing and transportation contracts for some of our onshore US natural gas production. These contracts may commit us to deliver minimum volumes and require us to make payments for any shortfalls in delivering or transporting the minimum volumes under the commitments.
We may use long-term contracts such as these to provide flow assurance for production in over-supplied markets with limited infrastructure, such as the Marcellus Shale, to enable our production to reach higher priced out-of-basin markets. Contracts such as these support continued development of our Marcellus Shale core asset and position us to take advantage of future market growth.
As properties are undergoing development activities, we may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. During 2015, we incurred expense of approximately $33 million related to these commitments. We expect to continue to incur deficiency and/or unutilized costs in the near-term as development activities continue. Should commodity prices continue to decline or 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 significant payments in the event that these commitments are not otherwise offset.
Although long-term shortfalls are unknown, we continually seek to optimize any short-term under-utilized assets through capacity release and third-party arrangements. (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 producing fields 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 a 15 to 17 year period. Some of the contracts provide for 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 the eighth and eleventh years with limits on the increase/decrease from the contractual price.
Under the contracts, we and our partners have a financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and will be reflected as a reduction in sales price 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, 2015, a total of approximately 5.5 Tcf, gross (1.985 Tcf, net), of natural gas remained to be delivered under the contracts. As of December 31, 2015, we have recorded 2.3 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.9 Tcf, net, and PUD reserves of 425 Bcf, net, for offshore Israel. Based on current production levels, our available quantities of proved developed reserves are more than sufficient to meet near-term delivery commitments.
Significant Purchasers   Glencore Energy was the largest single non-affiliated purchaser of 2015 production and 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 18% of 2015 total crude oil, natural gas and NGL sales, or 30% of 2015 crude oil sales. Shell Trading (US) Company and Shell International Trading and Shipping Limited (collectively, Shell) purchased crude oil and condensate domestically from the deepwater Gulf of Mexico and the DJ Basin area and internationally from the North Sea. Sales to Shell accounted for 11% of 2015 total crude oil, natural gas and NGL sales, or 18% of crude oil sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2015. 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 continued to be volatile in 2015 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, natural gas and NGLs. As a result of hedging, a portion of near-term cash flow volatility is reduced, which allows us to plan our financial commitments and support our capital investment programs.
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. 

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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.
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, Industry and Energy 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;
the Department of Energy and Climate Change which regulates our activities in the UK sector of the North Sea; 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, 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

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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 designated as hazardous and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.
Under federal and state occupational safety and health laws, we must develop and maintain information about hazardous materials used, released, or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not believe that 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 April 2015, for example, the FWS announced that it was listing the northern long-eared bat as threatened under the ESA, which 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. In September 2015, a federal court invalidated the FWS’s listing of the Lesser Prairie Chicken as threatened because the FWS failed to give proper consideration to voluntary conservation measures; however, the government has asked the court to instead return the listing to the FWS for further consideration and indicated it would restore the Lesser Prairie Chicken to the list of endangered and threatened wildlife.
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 legislation has been introduced in Congress to require changes. 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

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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 Obama 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. Building on its white papers and the public input on those documents, the EPA issued a proposed rule in the summer of 2015 that would set additional standards for methane and VOC emissions from new and modified oil and gas production sources, including hydraulically fractured oil wells, and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. An accompanying EPA proposal would clarify when oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs. As another prong of the Administration's methane strategy, BLM is expected to propose standards for reducing venting and flaring on public lands. The Administration's goal is to reduce methane emissions from the oil and gas industry by 40-45% by 2025 as compared to 2012 levels. 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 Examples of such regulation on the operational side include the Greater Wattenberg Area Special Well Location Rule 318A (Rule 318A), which was adopted by the Colorado Oil and Gas Conservation Commission (COGCC) to address oil and gas well drilling, production, commingling and spacing in Wattenberg (located in the DJ Basin). The 2011 amendments to Rule 318A removed the limit on the number of wells which can produce from a particular formation, allowing wellbore spacing units and permitting wells to cross section lines. The amendments also addressed areas such as infill drilling, water sampling and waste management plans.
In February 2013, the 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 prohibited certain exploration and production activities, particularly use of hydraulic fracturing within their boundaries. See Hydraulic Fracturing, below.

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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 state regulators proposed two rules covering siting large oil and gas operations in urban areas and coordination of drilling with local governments. We currently are evaluating the proposals.
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; established impact fees, which are set based on a multi-year fee schedule and the average 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. These requirements may result in increased costs and lower rates of return for our Marcellus Shale development project.
In 2013, 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 been moving to finalize 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.
West Virginia In December 2011, the West Virginia legislature passed, and the governor signed, the Natural Gas Horizontal Well Control Act, which, among other things, provides for increased well permit fees, well location restrictions, development of well site safety and water management plans, and public notice requirements.
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. Concurrently, we are engaged 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 2015, the BSEE issued a proposed rule entitled “Oil and Gas and Sulphur Operations in the Outer Continental Shelf - Blowout Preventer Systems and Well Control,” which is intended to update standards for blowout prevention systems and other well controls for offshore oil and gas activities conducted in US federal waters, including the Gulf of Mexico. The proposed rule is significant in both the scope of its requirements and its potential impact. It would impose significant new requirements relating to well design, well control, casing, cementing, real-time well monitoring and subsea containment. It would also significantly revise provisions relating to drilling, workover, completion and decommissioning activities. If adopted as proposed, the new rule would likely increase the costs associated with well design, drilling and completion operations and may require the temporary shut-in of existing offshore wells in federal waters while work is done to bring them into compliance with the new rule, which could adversely impact our existing and planned operations in the Gulf of Mexico. Final rules are expected to be issued in 2016.
Additionally, the BOEM is in the process of updating 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. The proposed revisions are intended to enable the BOEM to better assess the risk management and financial capabilities of both operators and owners of oil and gas interests in the Outer Continental Shelf. As part of this effort, in September 2015, BOEM announced that it would be making changes to the agency’s guidance criteria for determining an entity’s

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financial ability to carry out decommissioning obligations on the Outer Continental Shelf. The revised regulatory framework that the BOEM ultimately adopts could, among other things, expand the classes of interested parties that are required to post financial assurances in favor of the BOEM (such as operating and/or non-operating interest owners previously exempt from posting such financial assurances, ORRI holders and secured lenders) and increase the amounts of the required coverage for offshore oil and gas operations, which could significantly increase the costs associated with our activities in the Gulf of Mexico. Final guidance is expected to be issued in 2016.
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 See Items 1. and 2. Business and Properties – Update on Israel.
Impact of Dodd-Frank Act Derivatives Regulation The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market. We have determined that we qualify as a ‘‘non-financial entity’’ for purposes of the end-user exception and satisfy the other requirements of the end-user exception. As a result, our hedging activity will not be subject to mandatory clearing. We do not expect to clear our swaps, and our swap transactions will not be subject to the margin requirements imposed by derivatives clearing organizations. In addition, Section 302(a) of the Terrorism Risk Insurance Program Reauthorization Act of 2015 excludes end users who are exempt from mandatory clearing, such as us, from any margin requirements imposed by rules ultimately adopted by the CFTC.
While we will not directly experience significant burdens from the changes in the regulation of swaps, some of our counterparties may. If so, this could result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business cannot be determined at this time.
Impact of Dodd-Frank Act Section 1504 Section 1504 of the Dodd-Frank Act requires disclosure of certain payments made by resource extraction companies to a foreign government or the US federal government for the commercial development of oil, natural gas or minerals. The Dodd-Frank Act mandates that the SEC promulgate rules to implement this disclosure requirement. On December 11, 2015, the SEC proposed resource extraction issuer payment disclosure rules that, if adopted, would require resource extraction companies, such as us, to publicly file information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas or minerals, and the type and total amount of payments made to each government.
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 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
development of monitoring technologies to (1) assess the impact of shale gas production on air quality and (2) determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic fracturing.
We are monitoring the results of the NETL study in order to assess any potential impact on our onshore US development programs.
Also in June 2015, the US EPA issued its draft “Assessment of the 17 Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources.” At a high level, the agency states, “[it] did not find evidence that hydraulic fracturing mechanisms have led to widespread, systemic impacts on drinking water resources in the United States.” The agency’s Science Advisory Board (SAB) recently commented however, that the agency’s conclusions do not clearly describe the systems of interest (e.g., groundwater, surface water) nor the definitions of “systemic,” “widespread,” or “impacts.” The SAB has also raised a concern that the agency’s conclusions do not reflect “the uncertainties and data limitations described in the body of the Report associated with such impacts.” The SAB has suggested the agency revise the major statements of findings in the Executive Summary and elsewhere in the draft Assessment Report to be more precise, and to clearly link these statements to evidence provided in the body of the draft Assessment Report. The SAB also recommends that the EPA discuss the significant data limitations and uncertainties, as documented in the body of the Report, when presenting the major findings. EPA has not yet responded to the SAB.
Also on the regulatory front, the US BLM issued proposed regulations in 2012 for hydraulic fracturing on federal lands, which were withdrawn and then reissued on May 16, 2013. The proposed rules would affect drilling operations on the 700 million acres of federally-owned minerals administered by the BLM, as well as 56 million acres of Native American-owned minerals. A final rule was released in March, 2015, and was immediately challenged in U.S. district court in Wyoming. The judge issued a preliminary injunction in September agreeing with claims that the BLM may lack statutory authority for the rule. The agency was ordered by the court to provide a complete administrative record, which it says it will comply with by January 2016. The agency has also asked the 10th Circuit Court of Appeals to overturn the lower court’s preliminary injunction, which is pending.
Apart from its air regulations for newly fractured natural gas wells (see Regulations), the EPA developed new guidelines under the Safe Drinking Water Act regarding the issuance of permits for the use of diesel fuel as a component in hydraulic fracturing activities. The guidance outlines for EPA permit writers, where EPA is the permitting authority, requirements for diesel fuels used for hydraulic fracturing of wells, technical recommendations for permitting those wells, and a description of diesel fuels subject to EPA underground injection control permitting. Beyond that, the agency has solicited public comment on information reporting and disclosure for hydraulic fracturing. The EPA also is planning to develop a rule addressing discharges of hydraulic fracturing wastewaters from oil and gas extraction facilities to public treatment works.
In June 2012, OSHA and the National Institute of Occupational Safety and Health (NIOSH) issued a joint hazard alert for workers who use silica (sand) in hydraulic fracturing activities. The following year saw the agency formally propose to lower the permissible exposure limit for airborne silica. OSHA also has prepared guidance identifying additional workplace hazards resulting from hydraulic fracturing and ways to reduce exposure to those hazards.
To date, hydraulic fracturing has been regulated primarily at the state level, and all of the states where our US core onshore operations are located (including Colorado, Texas, West Virginia, and Pennsylvania) have developed such requirements. See Regulations. In 2012, moreover, several local communities in Colorado became interested in increasing regulatory requirements on oil and gas development. The most notable situation occurred in the City of Longmont, Colorado in 2012 where voters chose to ban hydraulic fracturing activities within city limits.
In 2013, the municipalities of Broomfield, Fort Collins and Lafayette each passed similar ballot measures supporting restrictions or bans on the practice of hydraulic fracturing within their boundaries. Challenges were brought against each of these bans in state district court and industry has prevailed in Longmont and Fort Collins. The cities have appealed to the Colorado Supreme Court, which held oral arguments in December 2015, and is expected to rule on the legality of municipal bans sometime in the first half of 2016. The litigation in Broomfield is stayed pending resolution of the Supreme Court Appeal, and the City of Lafayette has dropped their ban. Another measure to ban hydraulic fracturing was on the ballot in the City of Loveland in northern Colorado in June of 2014, but the oil and gas industry worked with the community to defeat that initiative. Likewise, in January 2015, the Board of Trustees for the Town of Erie, Colorado voted not to impose a mora

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torium on new crude oil and natural gas wells. The large majority of our DJ Basin acreage is not located in the municipalities that have attempted to prevent oil and gas operations; therefore, we do not expect our operations to be materially impacted by these developments.
However, in the future, should additional statewide or local Colorado initiatives be undertaken to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations, our business could be impacted, resulting in delay or inability to develop oil and gas reserves, reducing our long-term reserves, production and cash flow growth, and potentially having a negative impact on our stock price. For example, a number of statewide ballot initiatives have been proposed for the upcoming 2016 election that would unreasonably restrict or limit crude oil and natural gas development in Colorado. The proposed measures call for a statewide ban on hydraulic fracturing, mandatory drilling setbacks ranging between 2,500 and 4,000 feet, and local and municipal control over regulation of the industry. These ballot initiatives are subject to titling and Colorado Supreme Court review and other qualifying requirements. The ultimate passage and implementation of any of these initiatives could have a negative impact on our business. In particular, a statewide ban on hydraulic fracturing or imposition of unreasonable drilling setbacks will likely delay or otherwise limit our drilling and development activities in certain parts of the DJ Basin. This could result in a reduction in our proved reserves and negatively impact our results of operations, cash flows, and stock price.
In addition to the above, we will continue to monitor proposed and new legislation and regulations in all operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged 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.
Public Disclosure   Several states have issued regulations requiring disclosure of certain information regarding the components used in the hydraulic-fracturing process. In 2011, for example, the RRC adopted the Hydraulic Fracturing Chemical Disclosure rule, which requires companies to disclose, on a public registry, chemical ingredients used to hydraulically fracture wells in Texas. The registry, FracFocus.org, is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council. In December 2011, the COGCC adopted hydraulic fracturing fluid ingredient regulations requiring disclosure of all chemicals and establishing ways to protect proprietary information. The regulations allow disclosure through the FracFocus web site. The State of Wyoming also requires disclosure of the types and amounts of chemicals. In 2012, through legislation known as Act 13, Pennsylvania established a requirement that operators submit information regarding hydraulic fracturing chemicals to FracFocus.org. Other states have proposed, or are considering, similar regulations which require specific disclosures by operators and/or outline requirements for construction and operation of wells and monitoring of well activity. We are currently providing disclosure information on FracFocus.org for all onshore US areas in which we operate. 
Additional Information  See: 
Undeveloped Oil and Gas Leases Oil and gas exploration is a lengthy process of obtaining data, evaluating, and de-risking prospects, and it takes time to develop resources in a responsible manner. The period of time from lease acquisition to discovery can take many years of ongoing effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the host government. It may take years for us to assemble sufficient acreage to cover the areal extent of a prospect that we wish to explore.
Once the acreage position is assembled, we obtain seismic data either through purchase of available data or by contracting for seismic services. Our exploration staff then begin a lengthy process of analyzing the seismic and other data in order to identify a potential optimal location for drilling an initial exploratory well. Once we decide to drill an exploratory well, we must obtain permits and contract a drilling rig with the specifications for the depth and well pressures which we expect to drill.
For example, in 2012, we entered the Falkland Islands through a farm-in agreement of the Northern and Southern Area Licenses with a 35% working interest in approximately 10 million gross acres. Later that year, we participated in an initial non-operated exploratory well, the Scotia well located in the Northern License, which was drilled and permanently plugged and abandoned after finding noncommercial amounts of hydrocarbons. In 2013 and 2014, we assumed operatorship and continued to acquire and process 3D seismic information for both licenses, which our exploration staff analyzed and used to plan an initial operated drilling program. We drilled the Humpback exploration prospect, located in the South Falkland Basin in 2015 but did not locate commercial quantities of hydrocarbons. In the North Falkland Basin, we identified the Rhea prospect (75% operated working interest) as the initial target. However, we experienced material operational issues with the drilling unit while drilling the Humpback well and the drilling contract was terminated on February 11, 2016. We remain confident in the potential of the Rhea prospect, which is located near the Sea Lion discovery in a proven petroleum system. We have been and will continue to

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work closely with our partners and the Falkland Islands Government to evaluate a path forward that includes retaining flexibility for the Rhea exploration well.
If there is a discovery, we may need to obtain additional data and/or drill appraisal wells in order to estimate the extent of the reservoir and the volume of resources that could potentially be recovered. Appraisal or development drilling requires additional time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies.
We strive to maintain an appropriate inventory of onshore and offshore exploration prospects suitable to our experience as an operator, financial resources, and current development timeline.
Competition 
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors. 
Geographical Data
We have operations throughout the world and manage our operations by region. Information is grouped into four components that are all primarily in the business of crude oil, natural gas and NGL exploration, development and production: United States, West Africa, Eastern Mediterranean, and Other International and Corporate. See Item 8. Financial Statements and Supplementary Data – Note 15. Segment Information
Employees 
As of December 31, 2015, we had 2,395 full-time employees. The 2015 year-end employee count includes 340 foreign nationals working as employees primarily in Israel, Cyprus, Equatorial Guinea and Cameroon. We regularly use independent contractors and consultants to perform various field and other services. 
Offices 
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional offices in Denver, Colorado; Greeley, Colorado; Canonsburg, Pennsylvania; Washington, D. C.; and in Cameroon, Equatorial Guinea, Israel, Cyprus, Mexico, Falkland Islands and the Netherlands. 
Title to Properties 
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under PSCs or exploration licenses.
Furthermore, while the majority of our assets are held by production, certain of our assets, such as our Eagle Ford Shale and Permian Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas and failure to meet these obligations may result in the loss of a lease.
Title Defects Subsequent to a lease or fee interest acquisition transaction, such as our Marcellus Shale acquisition in 2011, the buyer usually has a period of time in which to examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement, which may provide for arbitration between the buyer and seller. Curative efforts for remaining uncured defects related to the Marcellus Shale acreage are ongoing. Options to address uncured title defects include a reduction in the remaining amount of the CONSOL Carried Cost Obligation, an indemnity agreement, or the transfer of additional interests.
Conflicts with Surface Rights Mineral rights are property rights that include the right to use land surface that is reasonably necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently pending in several states. In several cases, owners of surface rights are suing various companies to prevent companies from using their land surface to drill horizontal wells to explore for or produce natural gas from neighboring mineral tracts. If a

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plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well pads and/or limit the length of horizontal wells drilled from a pad.
Risk Management
The oil and gas business is subject to many significant risks, including operational, strategic, financial and compliance/regulatory risks. We strive to maintain a proactive enterprise risk management (ERM) process to plan, organize, and control our activities in a manner which is intended to minimize the effects of risk on our capital, cash flows and earnings. ERM expands our process to include risks associated with accidental losses, as well as operational, strategic, financial, compliance/regulatory, and other risks.
Our ERM process is designed to operate in an annual cycle, integrated with our long range plans, and supportive of our capital structure planning. Elements include, among others, cash flow at risk analysis, credit risk management, a commodity hedging program to reduce the impacts of commodity price volatility, an insurance program to protect against disruptions in our cash flows, a robust global compliance program, and government and community relations initiatives. We benchmark our program against our peers and other global organizations. See Item 1A. Risk Factors for a discussion of specific risks we face in our business.
Available Information
Our website address is www.nobleenergyinc.com. Available on this website under “Investors – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.
Also posted on our website under “About Us – Corporate Governance”, and available in print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Environment, Health and Safety Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are also posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. 
If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks. 
We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our operations, our liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our business and pay dividends on our common stock depend highly upon the prices we receive for our crude oil, natural gas, and NGL production. Commodity prices are volatile. Crude oil prices, in particular, began to decline significantly in the fourth quarter 2014, declined further in 2015 and have continued to trade at a low level or decline further thus far in 2016.
High and low monthly daily average prices for crude oil and high and low contract expiration prices for natural gas for the last three years and into 2016 were as follows:

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Jan. 1 - Feb.12,
Year Ended December 31,
 
2016
2015
2014
2013
NYMEX
 
 
 
 
    Crude Oil - WTI (per Bbl) High (1)
$
31.78

$
59.83

$
105.15

$
110.53

    Crude Oil - WTI (per Bbl) Low (1)
29.71

37.33

59.29

86.68

    Natural Gas - HH (Per MMbtu) High
2.23

3.19

5.56

4.46

    Natural Gas - HH (Per MMbtu) Low
2.05

2.03

3.73

3.11

Brent
 
 
 
 
    Crude Oil - (per Bbl) High
32.80

64.32

111.76

118.90

    Crude Oil - (per Bbl) Low
31.93

38.21

62.91

97.69

(1) Average realized prices for our US NGL production, determined at two primary market centers (Conway and Mt. Belvieu) tend to track the volatility of NYMEX WTI and have also declined.
During 2015, low commodity prices had material negative impacts on our revenues, operating cash flows and profitability, caused us to reduce our capital investment program and led to reductions in the price of our common stock. An extended period of low, or lower, crude oil and natural gas prices could have further material adverse effects on our planned operations, level of capital expenditures and financial condition. In addition, we may not be able to achieve sufficient additional reductions in operating or capital costs or achieve additional drilling and/or operational efficiencies to offset all or a portion of a further decline in commodity prices.
If commodity prices continue to trade for an extended period at the lower levels reached thus far in 2016, or decline further, the following impacts could occur:
further significant reductions of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically, leading to shut-in or early abandonment of producing wells and increased capital requirements for abandonment operations;
certain properties in our portfolio becoming economically unviable;
additional impairments of proved or unproved properties;
loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;
use of cash flow to satisfy minimum take or pay obligations under throughput agreements if production is suspended;
further reduction, or suspension, of our 2016 capital investment program, or significant reductions in future capital investment programs, resulting in a reduced ability to develop our reserves;
delay, postponement or cancellation of some of our exploration or development projects;
inability to meet exploration commitments, leading to loss of leases or exploration rights;
divestments of properties to generate funds to meet cash flow or liquidity requirements;
limitations on our financial condition, liquidity,