10-K 1 nbl-20141231x10k.htm 10-K NBL-2014.12.31-10K
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, 2014
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, 2014: $28.0 billion.
Number of shares of Common Stock outstanding as of December 31, 2014: 362,126,299.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2015 Annual Meeting of Stockholders to be held on April 28, 2015, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2014, are incorporated by reference into Part III.




TABLE OF CONTENTS

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





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 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 embracing 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; US and international projects; and production mix among crude oil, natural gas and NGLs. Exploration success, along with development capital investment in the US and in international locations such as West Africa and the Eastern Mediterranean, has resulted in a visible lineup of major development projects which positions us for long-term future reserves, production and cash flow growth. Occasional strategic acquisitions of producing and non-producing properties, combined with the periodic divestment of non-core assets, have allowed us to achieve our objective of a well-diversified, growing portfolio. During 2014, we spent over $4.8 billion in oil and gas exploration and development activities.
Our portfolio is diversified between short-term and long-term projects, both onshore and offshore, domestic and international. Our organization and business model is focused on sustainable, high-return growth through effective major development project execution complimented by pursuit of exploration opportunities which can be monetized on a competitive discovery-to-production cycle. Our ability to deliver major development projects on schedule and within budget has provided a competitive and financial advantage in the industry.
However, the upstream oil and gas business is cyclical. During fourth quarter 2014, a significant decline in crude oil prices occurred which may result in deferral of some of our growth plans. We have taken steps to mitigate the impact on our business. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview, Operating Outlook and Liquidity and Capital Resources.
Onshore US assets provide a stable base of production along with high return, low risk development programs that deliver growth and accommodate a capital investment program that can be adjusted in response to ongoing changes in the economic environment. We continue to enhance project performance through technology and operational efficiency. Our long cycle offshore development projects, while requiring multi-year capital investment, are expected to offer attractive financial returns, and sustained production and cash flow.
We have operations in five core areas:
 
These five 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 visible growth from major development projects; and
l the deepwater Gulf of Mexico (offshore US);
 
l exploration opportunities.
l offshore West Africa; and
 
 
l offshore Eastern Mediterranean.
 
 

2


Our growth has been supported by a strong balance sheet and liquidity levels. We strive to deliver competitive returns and a growing dividend. Our annual cash dividends increased 89% in the last five years, from 36 cents per share in 2009 to 68 cents per share in 2014 (as adjusted for the 2 for 1 stock split during second quarter 2013). See Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities – Stock Performance Graph and Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2010-2014.
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 2014. Although these projects will require significant capital investments over the next several years, they typically offer long-life, sustained cash flows and attractive financial returns. 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)
·
Gunflint (deepwater Gulf of Mexico)
·
Cyprus (offshore Cyprus)
·
Big Bend (deepwater Gulf of Mexico)
·
Diega and Carla (offshore Equatorial Guinea)
·
Dantzler (deepwater Gulf of Mexico)
 
 
·
Tamar Compression (onshore Israel) (3)
 
 
·
Tamar Southwest (offshore Israel) (3) (4)
 
 
(1) 
Final investment decision has been made.
(2) 
Represents multiple ongoing development projects.
(3) 
See Update on Core Area – Israel, below.
(4) 
Regulatory approval for the project has been delayed. We recently petitioned the Israeli courts to expedite approval.
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.

3


Proved Oil and Gas Reserves    Proved reserves at December 31, 2014 were as follows:
 
Summary of 2014 Oil and Gas Reserves as of Fiscal-Year End
Based on Average 2014 Fiscal-Year Prices 
 
 
December 31, 2014
 
 
Proved Reserves
 
 
Crude Oil and
Condensate
 
Natural Gas
 
NGLs
 
Total
Reserves Category
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe) (1)
Proved Developed
 
 
 
 
 
 
 
 
United States
 
119

 
1,459

 
64

 
426

Equatorial Guinea
 
52

 
377

 
8

 
124

Israel
 
3

 
1,973

 

 
331

Total Proved Developed Reserves
 
174

 
3,809

 
72

 
881

Proved Undeveloped
 
 

 
 

 
 

 
 

United States
 
117

 
1,345

 
49

 
390

Equatorial Guinea
 
13

 
236

 
7

 
59

Israel
 

 
443

 

 
74

Total Proved Undeveloped Reserves
 
130

 
2,024

 
56

 
523

Total Proved Reserves
 
304

 
5,833

 
128

 
1,404

 
(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 natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil. See Item 6. Selected Financial Data.
Our total proved reserves of 1,404 MMBoe as of December 31, 2014 remained essentially the same as December 31, 2013, as record production volumes and reserves associated with divested assets were replaced by extensions, discoveries and other additions. Our proved reserves are 58% US and 42% international, and the mix is 31% global liquids (crude oil and NGLs), 36% international natural gas, and 33% US natural gas.
See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for further discussion of proved reserves.
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 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.
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. We have had substantial exploration success onshore US, in the deepwater Gulf of Mexico, the Douala Basin offshore West Africa and the Levant Basin offshore Eastern Mediterranean, resulting in our significant portfolio of major development projects. We have exploration opportunities remaining in these areas and are also engaged in new venture activity in both the US and international locations. Our focus on exploration activities has created a sustainable exploration program. During 2014, we conducted exploration activities in domestic and international locations such as northeast Nevada, deepwater Gulf of Mexico, offshore West Africa, offshore Eastern Mediterranean, and 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.  In 2014, 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.

4


IPO of Marcellus Shale Midstream Assets During third quarter 2014, our equity method accounted investee, CONE Gathering LLC (CONE Gathering), contributed a significant majority of its existing assets to a newly-formed master limited partnership, CONE Midstream Partners LP (CONE Midstream, CONE Midstream IPO). We own a 32.1% interest in CONE Midstream, which constructs, owns and operates natural gas midstream assets in support of our Marcellus Shale joint venture activities.
Atwater Valley Acquisition During second quarter 2014, we acquired working interests in 17 deepwater exploration leases in the Atwater Valley protraction area, deepwater Gulf of Mexico. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases.
Offshore Israel Assets In March 2014, we and our partners reached an agreement with the Israeli Antitrust Authority on various antitrust matters. As a result of the agreement, we agreed to divest the Tanin and Karish natural gas discoveries. We initiated an active program to locate a buyer and take other actions required to complete the plan to sell the assets. On December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the agreement to the Antitrust Tribunal for final approval. See Update on Core Area – Israel, below.
Gabon Entry During third quarter 2014, we signed a Production Sharing Contract (PSC) with the Government of Gabon covering Block F15, located 140 kilometers off the coast of Gabon and covering over 670,000 gross acres. Under the terms of the PSC, we will be the operator with a 60% working interest.
Non-Core Divestiture Program Our non-core divestiture program is designed to generate organizational and operational efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate capital and employee resources to higher-value and higher-growth areas. The program generated combined net proceeds of $2.4 billion during the last five years, including $321 million during 2014. In addition, we received a $204 million distribution of offering proceeds from the CONE Midstream IPO mentioned above. The proceeds from divestitures provide additional flexibility in the implementation of our international and deepwater Gulf of Mexico exploration and development programs and our horizontal drilling activities in the DJ Basin and Marcellus Shale. During 2014, we sold onshore US properties in the Piceance Basin, Tri-State and Powder River areas and our China assets.
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. Property Transactions.
Asset Impairments  We recorded $500 million in impairment charges for 2014, including $336 million in fourth quarter 2014. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
Update on Core Area – Israel Recent developments in the regulatory environment in Israel have had a significant impact on our future development plans. We plan to complete the Ashdod onshore terminal (AOT) compression project in the first half of 2015 and continue the sale of natural gas from the Tamar field to existing domestic customers. However, as discussed below, further investments in the expansion of Tamar, as well as the initial development of Leviathan, will be driven by achievement of regulatory certainty in Israel.
Potential for Future Growth and Development The quantity of discovered resources at Tamar and Leviathan have positioned Israel to meet domestic energy needs for years to come as well as become a significant natural gas exporter. Multiple regional markets are emerging and domestic demand can increase significantly in the future as existing coal burning facilities are either converted to natural gas or replaced by more efficient natural gas fired combined cycle power stations, and industrial and commercial applications are realized. In addition to producing natural gas to accommodate domestic and regional consumption, we believe our Eastern Mediterranean export projects would be well positioned to supply demand for natural gas beyond domestic and regional markets.
We are committed to the prudent and efficient development of both Tamar and Leviathan. We have engaged in engineering design and planning work for a potential first phase of development at Leviathan as well as follow-on developments at Tamar. Potential Leviathan development scenarios have included options that would require multi-billion dollar investments and span a number of years from project sanction to first production.
We have worked with the Israeli government to obtain support for the Leviathan development project, a complex, costly project with numerous political, financial and execution risks. We have also supported the efforts of our Leviathan partners to obtain appropriate financing for their share of development costs, and we have sought other arrangements with experienced industry participants to ensure the required technical support for the execution of the project.
On December 2, 2012, we and our existing partners announced that we had agreed in principle on a proposal to sell a working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). During 2013, we continued discussions with Woodside and, in February 2014, we signed a non-binding memorandum of understanding (MOU) for the sale of an interest in Leviathan to Woodside. However, in May 2014, we announced that negotiations between the parties had terminated. One factor contributing to Woodside's withdrawal was their inability to reach agreement with the Israeli government on various export tax issues.

5


Despite the withdrawal of Woodside, we moved forward with development plans for Leviathan Phase 1 and adopted a design utilizing a 1.6 Bcf/d floating production, storage and offloading vessel (FPSO). Technical design work for Leviathan Phase I became well advanced, and in 2014, we submitted the Phase 1 Plan of Development to the Ministry of National Infrastructures, Energy and Water Resources. We also engaged in marketing efforts and negotiated regional natural gas sales agreements with third parties to various degrees of maturity. However, regulatory uncertainty has delayed the consummation of non-binding Letters of Intent (LOIs) or natural gas sales and purchase agreements (GSPAs) and some of these agreements have expired. Therefore, our specific development plan may no longer be feasible; future development plans will require a technical design concept appropriate for the natural gas sales volumes ultimately contracted.
Increasingly Uncertain Regulatory Environment in Israel We have cooperated with the Israeli government on all significant matters relating to our exploration and development plans for offshore Israel. However, the regulatory environment in Israel has become increasingly challenging and uncertain. Laws, regulations and guidelines have been modified, sometimes with retroactive impacts, and as a result the investment climate has become unpredictable. Timing of approval for development plans has been delayed, and consequently our ability to make significant, long-term investment decisions has become increasingly difficult.
For example:
Changes in Tax Law   In March 2011, the Israeli government enacted the Oil Profits Taxation Law, 2011 (Petroleum Profits Law), which imposed additional income tax on crude oil and natural gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs.  
On March 26, 2014, the Ministry of Finance issued a memorandum indicating its intent to amend the Petroleum Profits Law to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas. Among other things, this action had a detrimental effect on our ability to reach commercial terms with Woodside, leading to a termination of the MOU.  
Natural Gas Policy In September 2012, the Interministerial Committee to Examine Government Policy Regarding the Natural Gas Industry in Israel (the Interministerial Committee) issued final recommendations regarding a government policy for developing Israel’s natural gas economy. The recommendations included, among others, material restrictions on our ability to monetize our natural gas discoveries. The recommendations approved by the Israeli government included further limitations on exports of natural gas than were recommended by said committee. See Regulations – Israel’s Natural Gas Policy, below.
Israel Antitrust Authority The Israeli Antitrust Commissioner (Commissioner) has intervened regarding the terms used in long-term contracts with certain natural gas customers; contended that the original acquisition agreement for the Leviathan acreage is an illegal restrictive arrangement; and, most recently, reversed a decision to submit a previously-agreed consent decree on certain antitrust matters (Consent Decree) to the Israeli Antitrust Tribunal for approval. Acting in good faith upon the Consent Decree, we consented to divest our Tanin and Karish natural gas discoveries and have been in discussions with potential purchasers. We believed that the Consent Decree matter had been resolved some time ago and had received recent assurances from the Antitrust Authority that approval was forthcoming. However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition. See Regulations – Israel Antitrust Authority, below.
Delay in Development Plan Approval We have worked with the Israeli government for some time to obtain regulatory approval for the Tamar Southwest development plan, and recently petitioned the Israeli courts to expedite the needed approvals.
Pricing Disputes The Public Utility Authority (PUA) has amended its own pricing formulas to impact pricing of natural gas in the Israeli market. These actions created pricing disputes between natural gas sellers and buyers. In addition, there have been threats of price controls.
Maritime Zones Law Bill The Israeli government has advanced a Maritime Zones Law bill that may adversely impact the ability to conduct oil and gas exploration and production activities in our offshore leases and licenses.
Changes in fiscal regimes and tax policies have material, long-term impacts on our business strategy, making it difficult to formulate and execute capital investment programs. The implementation of new, or modification of existing, laws or regulations, delays in approvals, and increasing tax costs disrupt our business plans and adversely impact our operations. In addition to the loss of a potential strategic partner for the Leviathan development, we have been delayed in negotiating project financing arrangements due to the uncertainty of the project. Furthermore, delay of the Tamar Southwest development could have a negative impact on our ability to achieve long-term reliability and redundancy for the overall Tamar project.

6


Stable fiscal and regulatory regimes are imperative. However, the upcoming March 2015 general elections in Israel are likely to delay resolution of all pending issues until a new government is in place. We may be unable to move forward with our major development projects without the following:
Approval of final GSPAs with off-takers, to support financing arrangements;
Clear, economically viable tax rulings, including export tax rulings;
Export approval with reasonable export allocations;
Approvals of Plans of Development;
Acceptable resolution of Leviathan and other pending matters with the Israeli Antitrust Authority;
Timely permitting;
Prompt decisions regarding pipeline onshore landing sites;
Stability clauses and protection from changes in laws and regulations;
Stable fiscal and contract terms that allow for financial returns that are appropriate to support long-term investment by a global exploration and production company; and
Other relevant regulatory terms essential to offshore crude oil and natural gas exploration and production.
The resolution of the above items, and greater certainty with respect to Israeli fiscal and regulatory matters, is required. See also Item 1A. Risk Factors.
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 61% of 2014 total consolidated sales volumes and 58% of total proved reserves at December 31, 2014. Approximately 57% of the proved reserves in the US are natural gas, 29% are crude oil and condensate and 14% are NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows: 
 
 
Year Ended December 31, 2014
 
December 31, 2014
 
 
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
 
50

 
206

 
17

 
101

 
198

 
1,051

 
78

 
451

Marcellus Shale
 
1

 
262

 
5

 
49

 
4

 
1,668

 
32

 
314

Deepwater Gulf of Mexico
 
15

 
14

 
1

 
18

 
32

 
43

 
3

 
42

Other Onshore US
 
1

 
36

 

 
8

 
2

 
42

 

 
9

Total
 
67

 
518

 
23

 
176

 
236

 
2,804

 
113

 
816

Wells drilled in 2014 and productive wells at December 31, 2014 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2014
 
December 31, 2014
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
DJ Basin
 
468

 
8,598

Marcellus Shale
 
179

 
441

Deepwater Gulf of Mexico
 
4

 
13

Other Onshore US
 

 
934

Total
 
651

 
9,986

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

7


 Locations of our onshore US operations as of December 31, 2014 are shown on the map below:


DJ Basin With the advent of horizontal drilling technology, the DJ Basin is now recognized by many industry analysts as a premier US crude oil resource play and is a key driver of our production and cash flow growth. Our position in the core area extends over 600,000 net acres.
The DJ Basin contributed an average of 101 MBoe/d of sales volumes, representing approximately 35% of total consolidated sales volumes in 2014, with approximately 66% being crude oil and NGLs, and represented approximately 32% of total proved reserves at December 31, 2014.
2014 Activity Over the past year, we focused our drilling and development activity on Integrated Development Plan (IDP) areas, allowing us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 80,000 acres). With this approach, we construct multi-well horizontal drilling pads and centralized processing facilities (CPFs) to minimize our surface use. The drilling pads and CPFs facilitate efficient execution of operations by reducing our 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 our production growth by constructing and expanding our infrastructure across the DJ Basin. In the first half of 2015, we will begin operation of the Keota plant, our second natural gas processing plant in northern Colorado, to support our East Pony IDP, which will provide additional capacity to support continued development in this part of the basin.
During 2014, we remained focused on horizontal drilling activity with continued growth from new wells brought online and expanded infrastructure. We accelerated our extended reach lateral well program to approximately 32% of our wells drilled in 2014. During the year, we spud 303 horizontal wells, of which 96 were extended reach lateral wells, and 310 wells initiated production. We also participated in approximately 160 non-operated development wells during 2014. We are currently running a four rig program.
Our 2014 DJ Basin development program resulted in net additions/revisions to proved reserves of approximately 39 MMBoe, approximately 62% of which are crude oil and NGLs.
Marcellus Shale The Marcellus Shale represents our second onshore US core area. 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.

8


We operate the wet gas (natural gas containing more liquid hydrocarbons) development area in Moundsville, Shirley and Oxford, West Virginia, while CONSOL operates the dry gas (natural gas containing less liquid hydrocarbons) development area. During 2014, the joint venture drilled 179 wells. Noble drilled 91 wells with an average lateral length per operated well of 8,000 feet, which is more than 1,000 feet longer than the previous year average and 3,000 feet longer than the 2012 average. The joint venture initiated production on 129 wells.
Currently, two operated drilling rigs are running in the wet gas area and four non-operated rigs are running in the dry gas area. We and our partner continue to have discussions on the level of joint venture investment in 2015.
Utilizing an IDP concept, modeled after the DJ Basin, we have begun to realize cost efficiencies through multi-well pads, central facilities and efficient liquids infrastructure that enables 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 2013 as the first operated IDP location, is in the core operating area with water and marketing infrastructure in place to support further development.
We and CONSOL also operate CONE Gathering, which constructs, owns and operates midstream infrastructure servicing our joint production, and is the general partner controlling interest in CONE Midstream. See Midstream IPO, below.
The Marcellus Shale contributed an average of 296 MMcfe/d of sales volumes and represented approximately 17% of total consolidated sales volumes in 2014 and approximately 22% of total proved reserves at December 31, 2014. Our 2014 Marcellus Shale development program resulted in net additions/revisions to proved reserves of approximately 79 MMBoe, approximately 17% of which are crude oil and NGLs.
Midstream IPO On September 24, 2014, CONE Gathering contributed a significant majority of its existing assets to a newly formed master limited partnership, CONE Midstream, concurrently with an initial public offering of limited partner units. As a result of the transaction, we own a 32.1% interest in CONE Midstream, which we account for using the equity method of accounting. We received a $204 million distribution of offering proceeds from CONE Gathering.
Northeast Nevada Exploration Prospect   We have an active global new venture process focused on identifying additional exploration opportunities with reasonable entry cost, significant running room and the potential to become a new core area. In the onshore US, this effort has captured a 370,000 net acre position (66% fee acreage and remainder federal acreage) in northeast Nevada, prospective for crude oil exploration, which we identified through basin scale reconnaissance and innovative geoscience concepts. We are currently analyzing results from our first four exploratory vertical wells and may conduct additional production tests.
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 3% of total consolidated sales volumes in 2014 and approximately 1% of total proved reserves at December 31, 2014. During 2014, we sold various non-core onshore properties and continue to evaluate divestment opportunities. We are in the process of divesting certain of our properties located in the DJ Basin, outside of our core DJ Basin operating area. See Acquisition and Divestiture Activities – Non-Core Divestiture Program above.
During 2014, we recorded impairments of certain non-core onshore US properties. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.

9


Deepwater Gulf of Mexico   Locations of our operations in the deepwater Gulf of Mexico as of December 31, 2014 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 today the deepwater Gulf of Mexico is one of our five core operating areas. Our focus is on high-impact opportunities with the potential to provide significant medium- and long-term growth.
We have several producing fields, ongoing development projects and a substantial inventory of exploration opportunities. We currently hold leases on 143 deepwater Gulf of Mexico blocks, representing approximately 59,000 net developed acres and approximately 465,000 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 6% of total consolidated sales volumes in 2014 and 3% of total proved reserves at December 31, 2014.
2014 Impairment Expense
During 2014, we recorded impairment expense of $350 million, $325 million during fourth quarter 2014, related to deepwater Gulf of Mexico properties. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
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, high value tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options.
The Atwood Advantage drillship mobilized to the Gulf of Mexico and was used in the 2014 drilling plan which included various exploration, appraisal and well completion activities.
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. Additional exploration and appraisal drilling will be required to test the remaining resource potential.

10


Atwater Valley During 2014, we acquired working interests in 17 deepwater exploration leases in the Atwater Valley protraction area, providing further opportunities to expand our exploration portfolio. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases. In third quarter 2014, we participated with a 50% non-operated working interest in the Bright prospect, which was drilled on Atwater Valley Block 362 to a total depth of 13,500 feet. The exploratory well reached the targeted Upper and Middle Miocene objectives and was subsequently plugged and abandoned as it did not encounter hydrocarbons.
Madison (Mississippi Canyon 479; 60% operated working interest) During fourth quarter 2014, we drilled an exploratory well at the Madison prospect. The well was drilled to a total depth of 16,859 feet, reaching the targeted Upper and Middle Miocene objectives, but did not encounter commercial quantities of hydrocarbons. The well has been plugged and abandoned.
Ongoing Major Development Projects
Rio Grande (Mississippi Canyon Block 698, 699, 738 and 782) The Rio Grande area represents several exploration successes in the deepwater Gulf of Mexico. Big Bend (54% operated working interest) is a 2012 crude oil discovery, Troubadour (60% operated working interest) is a 2013 natural gas discovery, and Dantzler (45% operated working interest) is a 2013 crude oil discovery.
A co-development project is underway for the Big Bend and Dantzler crude oil discoveries. During 2014, we signed a production handling agreement for tie back to the Thunder Hawk semi-submersible production facility. We expect to continue development of these projects during 2015. First production for Big Bend is targeted for fourth quarter 2015, and first production for Dantzler is targeted for first quarter 2016.
During 2014, we announced final well results at the Dantzler-2 appraisal well, which encountered 122 net feet of crude oil pay in two high-quality Miocene reservoirs. The well was drilled to a total depth of 18,210 feet in 6,600 feet of water.
We are currently evaluating a number of development options for Troubadour including subsea tieback to existing infrastructure.
Gunflint (Mississippi Canyon Block 948; 26% operated working interest) Gunflint is a 2008 crude oil discovery. We expect to continue development of this project in 2015. Development is on track utilizing a two-well subsea tieback to the Gulfstar 1 spar platform, and topsides equipment fabrication is underway for planned 2015 installation. 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.
Raton (Mississippi Canyon Block 248; 67% operated working interest) is a 2006 natural gas discovery and has been producing since 2008. Raton is currently shut in waiting on completion of third party platform maintenance.
South Raton (Mississippi Canyon Block 292; 79% operated working interest) is a 2008 crude oil discovery and began producing in 2012. During 2013, South Raton development in the deepwater Gulf of Mexico was shut-in due to mechanical issues. During 2014, the well was brought back online and, as part of our remediation plan, granted a 180 day Suspension of Operations (SOO) by the Bureau of Safety and Environmental Enforcement (BSEE) to conduct remediation activities. During 2014, we recorded an impairment of South Raton.
Swordfish (Viosca Knoll Blocks 917; 961 and 962; 85% operated working interest) is a 2001 crude oil discovery and began producing in 2005. The Swordfish project currently includes two producing wells. We acquired the Neptune Spar, a floating offshore production platform, to process our remaining Swordfish production.
Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) is a 2004 crude oil discovery and began producing in 2006. The project currently includes four producing wells. 
Lorien (Green Canyon Block 199; 60% operated working interest) is a 2003 crude oil discovery and began producing in 2006. The project currently includes one producing well.
These properties are connected to existing infrastructure through subsea tiebacks.
International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in Equatorial Guinea and Israel have contributed substantially to our growth over the last decade.

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During 2014, we continued to advance our major development projects, including the Tamar field compression project and the Leviathan development project. 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. Large acreage positions in West Africa and the Eastern Mediterranean could provide further exploration opportunities.
International operations accounted for 39% of total consolidated sales volumes in 2014 and 42% of total proved reserves at December 31, 2014. International proved reserves are approximately 86% natural gas and 14% crude oil and condensate.
Operations in Cyprus, Equatorial Guinea, Gabon, and Sierra Leone are conducted in accordance with the terms of 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.
Locations of our international operations as of December 31, 2014 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, 2014
 
December 31, 2014
 
 
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
 
33

 
243

 

 
74

 
65

 
613

 
15

 
183

Israel
 

 
231

 

 
39

 
3

 
2,416

 

 
405

China (1)
 
2

 

 

 
2

 

 

 

 

Total International
 
35

 
474

 


 
115

 
68

 
3,029

 
15

 
588

Equity Investee
 
2

 

 
5

 
7

 

 

 

 

Total
 
37

 
474

 
5

 
122

 
68

 
3,029

 
15

 
588

Equity Investee Share of Methanol Sales (MMgal)
 
130

 
 

 
 
 
 
 
 

(1) On June 30, 2014, we closed the sale of our China assets.


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There were no international wells drilled in 2014. Productive wells at December 31, 2014 in our international operating areas were as follows:
 
 
December 31, 2014
 
 
Gross Productive
Wells
International
 
 
Equatorial Guinea
 
25

Israel
 
8

North Sea
 
6

Total International
 
39

West Africa (Equatorial Guinea, Cameroon, Sierra Leone 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, two blocks offshore Sierra Leone, and one block offshore Gabon. Equatorial Guinea, the only producing country in our West Africa segment, accounted for approximately 25% of 2014 total consolidated sales volumes and 13% of total proved reserves at December 31, 2014. We held approximately 118,000 net developed acres and 30,000 net undeveloped acres in Equatorial Guinea, 695,000 net undeveloped acres in Cameroon, 414,000 net undeveloped acres in Sierra Leone and 403,000 net undeveloped acres in Gabon at December 31, 2014.
Locations of our operations in Equatorial Guinea and Cameroon, as of December 31, 2014 are shown on the map below:

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Aseng Project 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 13 MBoe/d, net, during 2014.
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 Project   Alen, is a natural gas and condensate field primarily on Block O (45% operated working interest), offshore Equatorial Guinea, which includes three horizontal wells connected to a production platform that utilizes the Aseng FPSO for storage and offloading. Alen has been producing since 2013. During 2014, we completed the 1P sidetrack well to enhance production efficiencies. Alen produced approximately 11 MBoe/d, net, during 2014.
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 50 MBoe/d, net, during 2014.
We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated LNG plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest 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. The methanol plant is scheduled for turnaround activities in 2015. Alba Plant sells its LPG products and condensate at our marine terminal at prevailing market prices. We sell our share of condensate produced in the Alba field under short-term contracts at market-based prices.
The execution phase of the Alba field B3 compression project began in early 2013. We expect to continue working on this project during 2015, with an anticipated completion date mid-2016.
Other Block O & I Projects    During 2014 we acquired 3D seismic data across Blocks O and I and are currently processing the results which will aid in efficiently producing the Aseng and Alen fields as well as potentially advancing other regional exploration and development opportunities, including Diega (Block I), Carla (Block O), and Carmen (Block O).
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 (66.67% operating 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. We are reprocessing 3D seismic data over our YoYo mining concession and plan to drill the Cheetah exploration prospect in the second half of 2015.
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, and the YoYo discovery, offshore Cameroon. 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.
Sierra Leone We participate in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million gross undeveloped acres, in which we have a non-operated 30% working interest. We are currently evaluating recently reprocessed seismic data over the blocks.
Gabon During 2014, we expanded our exploration portfolio by signing a PSC with the Government of Gabon. We are the operator of Block F15 (60% working interest), an undeveloped, ultra-deep water area, covering over 670,000 gross acres. The PSC includes a four-year seismic commitment and an option for exploration drilling. The exploration phase is underway and we are currently conducting an environmental impact assessment and considering options for shooting and acquiring 3D seismic data.
See also Item 8. Financial Statements and Supplementary Data – Note 5. Capitalized Exploratory Well Costs.
Eastern Mediterranean (Israel and Cyprus)    The Eastern Mediterranean is one of our core operating areas, where we have had eight consecutive natural gas discoveries in recent years. See Update on Core Area – Israel, above.

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Israel, the only producing country in our Eastern Mediterranean core area, accounted for 13% of 2014 total consolidated sales volumes and 29% of total proved reserves at December 31, 2014. Our leasehold position in the Eastern Mediterranean includes six leases and five licenses operated offshore Israel and one license operated offshore Cyprus. We hold approximately 80,000 net developed acres and 296,000 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.
Locations of our operations in the Eastern Mediterranean as of December 31, 2014 are shown below:
 

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Domestic Natural Gas Demand As the Israeli economy continues to grow, so does the demand for natural gas, used primarily for electricity generation. 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 GSPAs with domestic customers. See International Marketing Activities and Delivery Commitments, below.
Natural Gas Export As discussed below, we have made significant natural gas discoveries in the Eastern Mediterranean. We expect that these discoveries can be used to satisfy growing domestic demand as well as provide significant export potential. Eastern Mediterranean export projects would be well positioned to supply growing regional and global natural gas demand.
During 2014, we entered into LOIs for the export of natural gas to Egypt and Jordan.We also entered into a natural gas sales and purchase agreement with the Palestine Power Generation Company, Arab Potash Company and Jordan Bromine Company. We negotiated the LOIs to various degrees of maturity, some to full maturity. However, the emerging regulatory uncertainty has delayed the consummation of LOIs or GSPAs for regional natural gas sales. In the meantime, we continue to maintain active discussions with our potential customers in an effort to maintain our ability to eventually conclude negotiations and execute GSPAs. See Regulations – Israel's Natural Gas Policy, below.
Tamar Natural Gas Projects   Just over four years from discovery, the Tamar project began production in March 2013 with capable peak flow rates of approximately 1.1 Bcf/d, gross, to support seasonal high demand periods. The natural gas flows from the Tamar field through the world's longest subsea tieback, more than 90 miles to the Tamar platform, and then to the AOT. Tamar is a technical and commercial milestone that contributes significantly to our production profile. Production from Tamar averaged 219 MMcf/d, net, for 2014.
During 2014, we advanced the Tamar compression project, which will expand field production capacity by adding compression at the AOT. Compression is targeted to increase deliverability to a peak of 1.2 Bcf/d, gross, beginning in mid-2015.
Also during 2014, we continued to work with the Israeli government 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. Timely development of Tamar Southwest is important to achieve long-term reliability and redundancy for our overall Tamar project. Although the development project was sanctioned in 2013, continuing delays in securing regulatory approvals have placed the project at risk of delay. We recently petitioned the Israeli courts to expedite the needed approvals.
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  The 2010 Leviathan discovery (39.66% operated working interest) is the largest discovery in our history. Due to Leviathan's size, full field development is expected to require several development phases. During 2014, the Leviathan licenses were converted to Development and Production Leases and we submitted the Plan of Development to the Ministry of National Infrastructures, Energy and Water Resources. The development plan is expected to serve both domestic demand and export.
Timing of project sanction, which we have been targeting for 2015, depends on final resolution of antitrust and other regulatory matters, as well as execution of GSPAs, which will be subject to, among other conditions, the receipt of regulatory approvals. Project financing will also be required. We are engaged with the governments of the US, Israel, Jordan and Egypt on this project.
We have been working towards sanction of Leviathan Phase I based on the agreement we and our partners reached with the Israeli Antitrust Authority on various antitrust matters earlier in 2014. However, on December 23, 2014, we and our partners were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was resolved some time ago and we had received recent assurances from the Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition. See Update on Core Area – Israel, above.
Karish and Tanin We have been working towards a sale of the Karish and Tanin discoveries based on the agreement we and our partners reached with the Israeli Antitrust Authority on various antitrust matters earlier in 2014. However, the reversal of the Antitrust Authority of its decision to submit the Consent Decree to the Antitrust Tribunal for final approval has had a negative impact on our ability to close a sale of these discoveries. See Update on Core Area – Israel, above.
Other Discoveries Offshore Israel   We and our partners submitted a development plan for the Dalit field (36% operated working interest), a 2009 natural gas discovery. Development would include a tie-in 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. 

16


We are reviewing development scenarios 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.
Future Investment Further investments in the expansion of Tamar, as well as the initial development of Leviathan, will be driven by achievement of regulatory certainty in Israel. See Update on Core Area – Israel, above.
Cyprus Project (Offshore Cyprus)  In May 2014, our application for renewal of the PSC for two additional years was approved. We are currently evaluating development scenarios for Block 12 (70% operated working interest) and plan to submit a plan of development to the Cypriot government in 2015. There is also potential for a farm-out arrangement of our working interest.
See also Item 8. Financial Statements and Supplementary Data – Note 5. Capitalized Exploratory Well Costs.
Other International
Our other international operations accounted for 1% of total consolidated sales volumes for 2014 and less than 1% of total proved reserves at December 31, 2014.
Falkland Islands We currently operate the Northern and Southern Area licenses with a 35% working interest in approximately 10 million gross acres located south and east of the Falkland Islands. We continue to acquire and process 3D seismic information for both licenses and anticipate exploratory drilling operations to begin in mid-2015.
In third quarter 2014, based on the results of seismic interpretation conducted on the Scotia exploratory well which was drilled in 2012, we concluded that the Scotia prospect was not economically viable and recorded dry hole cost.
China In June 2014, we sold our China assets. See Item 8. Financial Statements and Supplementary Financial Data – Note 3. Property Transactions.
Nicaragua After evaluation of the Paraiso exploratory well results and the regional geology in the Tyra and Isabel blocks, we notified the Nicaraguan government of our intention to relinquish both concessions in the first half of 2015.
North Sea In 2012 and 2013, we sold the working interests in many of our non-operated North Sea properties. During 2014, the remaining unsold non-operated properties were transferred from assets held for sale as we were not able to locate a buyer. The decommissioning of our remaining North Sea portfolio is planned to begin in mid-2015. During 2014, we recorded an impairment of the MacCulloch field. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
Proved Reserves Disclosures
Internal Controls Over Reserves Estimates   Our policies 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.

17


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 2014 reserves estimates.
Based on reasonable certainty of reservoir continuity of the Niobrara and Marcellus Shale formations, 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 2014, 2013, and 2012, we retained NSAI to perform audits of proved reserves. The reserves audit for 2014 included a detailed review of eight of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 79.8% of US proved reserves and 99.4% of international proved reserves (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. The reserves audit for 2012 included a detailed review of eight of our major fields and covered approximately 93% of total proved reserves.
In connection with the 2014 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, 2014, 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.
The fields audited by NSAI are chosen in accordance with Company guidelines and result in the audit of a minimum of 80% of our total proved reserves. The fields are chosen by the Senior Vice President – Corporate Development and are reviewed by senior management and the Audit Committee of our Board of Directors. Our practice is to select fields for audit based on size. This process results in the audit of fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis.
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, 2014, on a quantity basis, the NSAI field estimates ranged from 27 MMBoe or 9% above to 13 MMBoe or 4% 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, 2014 were, in the aggregate, approximately 16 MMBoe, or 1%.
Proved Undeveloped Reserves (PUDs)   As of December 31, 2014, our PUDs totaled 130 MMBbls of crude oil and condensate, 2.0 Tcf of natural gas, and 56 MMbbls of NGLs for a total of 523 MMBoe.
PUDs Locations     We have several significant ongoing development projects which are in various stages of completion. PUDs are located as follows at December 31, 2014:
183 MMBoe in the DJ Basin. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves within a five-year period;

18


179 MMBoe in the Marcellus Shale. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves within a five-year period;
28 MMBoe in the deepwater Gulf of Mexico;
59 MMBoe in the Alba field, offshore Equatorial Guinea, 57 MMBoe 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 2016; and
74 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields. PUDS of 32 MMBoe relate to the Tamar Southwest field, which is awaiting government approval of the development plan.
The above fields represent almost 100% of total PUDs. PUDs include no material amounts, except the Alba field PUDs, which have remained undeveloped for five years or more since initial disclosure.
Changes in PUDs    Changes in PUDs that occurred during the year were due to:
 
 
United
 States
 
Equatorial
Guinea
 
Israel
 
China
 
Total
(MMBoe)
 
 
 
 
 
 
 
 
 
 
Proved Undeveloped Reserves Beginning of Year
 
425

 
58

 
72

 
2

 
557

Revisions of Previous Estimates
 
(14
)
 
1

 
2

 

 
(11
)
Extensions, Discoveries and Other Additions
 
95

 

 

 

 
95

Purchase of Minerals in Place
 

 

 

 

 

Sale of Minerals in Place
 
(1
)
 

 

 
(2
)
 
(3
)
Conversion to Proved Developed
 
(115
)
 

 

 

 
(115
)
Proved Undeveloped Reserves End of Year
 
390

 
59

 
74

 

 
523

United States
downward revisions of 14 MMBoe, primarily due to planned reduction in pace of DJ Basin drilling activity due to lower commodity price outlook;
additions of 26 MMBoe in the DJ Basin horizontal drilling program; 59 MMBoe in the Marcellus Shale horizontal drilling program; and 10 MMBoe in the Gulf of Mexico; and
conversion of 115 MMBoe into proved developed reserves attributable to ongoing development in the DJ Basin (24% of year end 2013 PUD volumes converted) and Marcellus Shale (34% of year end 2013 PUD volumes converted).
Equatorial Guinea
positive revisions of 1 MMBoe due to performance revisions for the Alba field.
Israel
positive revisions of 2 MMBoe due to performance revisions for the Tamar field.
China
sales of 2 MMBoe due to the sale of our China assets in June 2014.
Development Costs    Costs incurred to advance the development of PUDs were approximately $2.0 billion in 2014, $1.0 billion in 2013, and $1.8 billion in 2012. A significant portion of costs incurred in 2014 related to the DJ Basin and Marcellus Shale development projects.
Estimated future development costs relating to the development of PUDs are projected to be approximately $2.2 billion in 2015, $1.8 billion in 2016, and $1.7 billion in 2017. 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 2019.  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 2015 - 2019.
PUDs with Negative PV10 At December 31, 2014, we had 75 PUD well locations with negative present worth discounted at 10% based on constant prices and costs in our Marcellus Shale core area. Net quantities totaled 0.2 MMBbl of crude oil and condensate, 177 Bcf of natural gas, and 2.2 MMBbl of NGLs.  These locations represented approximately 6% of both total PUD locations and total PUD quantities at December 31, 2014.  Although these reserves had a negative present worth 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

19


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 – 2015 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.
Other Reserves Information    Since January 1, 2014, no crude oil or natural gas reserves information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (EIA) of the US Department of Energy. We file Form 23, including reserves and other information, with the EIA.


20


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, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
DJ Basin
 
18,209

 
75,039

 
6,072

 
$
87.86

 
$
4.11

 
$
34.51

 
$
6.30

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

 
5.50

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

 
$
5.42

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

 
$
4.92

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

 
6.13

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

 
$
5.40

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

 
 
Year Ended December 31, 2012
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
 

 
 

 
 

 
 

 
 

 
 

 
 

DJ Basin
 
11,647

 
70,959

 
4,625

 
$
89.41

 
$
2.67

 
$
35.50

 
$
4.45

Other US
 
6,401

 
89,308

 
1,365

 
104.30

 
2.57

 
34.92

 
8.00

Total US
 
18,048

 
160,267

 
5,990

 
94.69

 
2.61

 
35.36

 
6.04

Equatorial Guinea
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alba Field (2)
 
4,439

 
86,162

 

 
107.08

 
0.27

 

 
2.79

Aseng Field
 
7,544

 

 

 
111.93

 

 

 
4.88

Total Equatorial Guinea
 
11,983

 
86,162

 

 
110.14

 
0.27

 

 
3.39

Mari-B Field (Israel)
 

 
36,806

 

 

 
4.85

 

 
3.23

China
 
1,540

 

 

 
114.54

 

 

 
10.33

Total Consolidated Operations
 
31,571

 
283,235

 
5,990

 
101.52

 
2.19

 
35.36

 
$
5.09

Equity Investee (3)
 
648

 

 
2,108

 
104.56

 

 
69.14

 
 

Total Continuing Operations
 
32,219

 
283,235

 
8,098

 
$
101.58

 
$
2.19

 
$
44.15

 
 

(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.

21


(2) 
Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. Sales to these plants are based on a Btu equivalent and then converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information.
(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, 2014, 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, 2014 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
6,532

 
5,808.9

 
3,454

 
2,726.2

 
9,986

 
8,535.1

Equatorial Guinea
 
5

 
2.0

 
20

 
7.6

 
25

 
9.6

Israel
 

 

 
8

 
3.2

 
8

 
3.2

North Sea
 
5

 
0.7

 
1

 
0.2

 
6

 
0.9

Total
 
6,542

 
5,811.6

 
3,483

 
2,737.2

 
10,025

 
8,548.8

 
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, 2014 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore
 
1,249

 
833

 
1,200

 
735

Offshore
 
115

 
59

 
691

 
465

Total United States
 
1,364

 
892

 
1,891

 
1,200

International
 
 

 
 

 
 

 
 

Equatorial Guinea
 
284

 
118

 
81

 
30

Falkland Islands
 

 

 
9,921

 
3,473

Cameroon
 

 

 
1,084

 
695

Israel
 
185

 
80

 
679

 
296

Cyprus
 

 

 
663

 
464

North Sea
 
6

 
1

 
14

 
2

Sierra Leone
 

 

 
1,380

 
414

Nicaragua (1)
 

 

 
1,931

 
1,545

Gabon
 

 

 
671

 
403

Total International
 
475

 
199

 
16,424

 
7,322

Total
 
1,839

 
1,091

 
18,315

 
8,522

 (1) Represents acreage we expect to relinquish to the Nicaraguan government in the first half of 2015.
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,
 
 
2015
 
2016
 
2017
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
 
 
 
 
Onshore US (1)
 
294

 
140

 
253

 
196

 
87

 
57

Deepwater Gulf of Mexico
 
53

 
42

 
127

 
72

 
19

 
9

Equatorial Guinea
 
55

 
19

 

 

 

 

Israel (2)
 
395

 
178

 
99

 
47

 

 

Cyprus (2)
 

 

 
663

 
464

 

 

Cameroon (3)
 
916

 
611

 

 

 

 

Sierra Leone (2)
 
1,380

 
414

 

 

 

 

Nicaragua (4)
 
1,931

 
1,545

 

 

 

 

Total
 
5,024

 
2,949

 
1,142

 
779

 
106

 
66

(1) 
Represents acreage that will expire if no further action is taken to extend. Approximately 91% of the acreage is located in core areas where we currently expect to continue development activities and/or extend the lease terms.
(2) 
Represents acreage that will expire if no further action is taken to extend. We currently intend to extend the leases prior to expiration in accordance with license terms. See also Regulations Israel Natural Gas Policy and Israel Antitrust Authority, below.
(3) 
Represents acreage that will expire if no further action is taken to extend. The acreage represents the Tilapia PSC. We intend to formally request an extension of the lease during first quarter 2015; however, the extension timeline could vary and it is therefore unknown what percentage of acreage will be relinquished in 2015.
(4) 
Represents acreage that we expect to relinquish to the Nicaraguan government in the first half of 2015.

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, 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

Year Ended December 31, 2012
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
8.1

 
2.3

 
10.4

 
457.5

 

 
457.5

 
467.9

Equatorial Guinea
 

 

 

 
2.3

 

 
2.3

 
2.3

Cameroon
 

 
0.5

 
0.5

 

 

 

 
0.5

Israel
 

 

 

 
3.2

 

 
3.2

 
3.2

China
 

 

 

 
1.7

 

 
1.7

 
1.7

Total
 
8.1

 
2.8

 
10.9

 
464.7

 

 
464.7

 
475.6

 

23


In addition to the wells drilled and completed in 2014 included in the table above, wells that were in the process of drilling or completing at December 31, 2014 were as follows: 
 
 
Exploratory(1)
 
Development(2)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
9

 
7.8

 
250

 
117.4

 
259

 
125.2

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
 
28

 
16.9

 
250

 
117.4

 
278

 
134.3


(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 Tanin and Karish exploratory wells which have been classified as assets held for sale as of December 31, 2014.

See Item 8. Financial Statements and Supplementary Financial Data – Note 5. 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 Helix Well Containment group, 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 placed 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 2014 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 with a remaining term through May 2015. 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. 

24


Our North Sea crude oil production is transported by tanker and sold on the spot market. In China, prior to the sale of our China assets, we sold crude oil into the local market through pipelines under a long-term contract at market-based prices.
Delivery Commitments   Some of our natural gas sales contracts specify the delivery of fixed and determinable quantities.
Domestic Natural Gas Sales We may use long-term sales agreements to provide flow assurance for production in over-supplied markets with limited infrastructure or to enable our production to reach higher priced out-of-basin markets. We have commitments to deliver approximately 350 Bcf of natural gas produced onshore US, primarily in the Marcellus Shale, to customers under long-term contracts ranging from one to 14 years.
Israel Natural Gas Sales and Purchase Agreements (GSPA) 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, 2014, a total of approximately 6.0 Tcf, gross (2.2 Tcf, net), of natural gas remained to be delivered under the contracts. As of December 31, 2014, we have recorded 2.4 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.9 Tcf, net, and PUD reserves of 443 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 2014 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 22% of 2014 total crude oil, natural gas and NGL sales, or 32% of 2014 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 10% of 2014 total crude oil, natural gas and NGL sales, or 15% of crude oil sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil, natural gas and NGL sales in 2014. 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 were volatile in 2014 and prices for crude oil and natural gas are affected by a variety of factors beyond our control. We use derivative instruments to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas. As a result of hedging, a portion of near-term cash flow volatility is reduced, 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 7. Derivative Instruments and Hedging Activities
Regulations 
Exploration for, and production and marketing of, crude oil, natural gas and NGLs are extensively regulated at the federal, state, and local levels in the US, and internationally. Crude oil, natural gas and NGL development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, transportation, prevention of waste and pollution, and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion over time and frequently impose more stringent requirements on crude oil and natural gas companies.
Our ability to economically produce and sell crude oil, natural gas and NGLs is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules, regulations and orders that require extensive efforts to ensure compliance, that impose incremental costs to comply, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil, natural gas and NGL production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors.

25


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 exploration and development activities in the UK sector of the North Sea;
the Petroleum Directorate which regulates our exploration activities offshore Sierra Leone; 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 and US National Marine Fisheries Service, which under the Endangered Species Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines, and roads;
the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the deepwater Gulf of Mexico; and
the Department of Transportation (DOT), which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater Gulf of Mexico operations.
Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In addition, we are governed by the rules and regulations of the NYSE, upon which shares of our common stock are traded.
Among the laws affecting our operations are the following:
Environmental Matters As a developer, owner, and operator of crude oil and natural gas properties, we are subject to various federal, state, local, and foreign host country laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating, and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production wastes, water and air pollution control procedures, facility siting and construction, prevention of and responses to leaks and spills, and the remediation of petroleum-product contamination. Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us, or by prior owners or operators, in accordance with current laws, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups. The EPA and various state agencies have limited the disposal options for hazardous and non-hazardous wastes and may continue to do so. The owner and operator of a site, and persons that treated, disposed of, or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from the definition of hazardous waste may in

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the future be designated as hazardous and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. See Item 1A. Risk Factors.
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 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. 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.
On May 17, 2010, the BLM issued a revised oil and gas leasing policy for federal lands that requires, among other things, a more detailed environmental review prior to leasing crude oil and natural gas rights, increased public engagement in the development of master leasing and development plans prior to leasing any area where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. 
In 2009, the EPA launched a program that requires many suppliers of hydrocarbon fuels or industrial chemicals, manufacturers of vehicles and engines, and other facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to report their annual GHG emissions. In November 2010, the EPA issued final regulations requiring such annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production and offshore platforms (Subpart W). The first annual reports under Subpart W were due in 2012 for 2011 emissions. Substantially all of our onshore US properties are subject to the Subpart W reporting requirements. Information in such reports could form the basis of future GHG regulations.
On August 16, 2012, 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. These regulations require technologies and processes that, while reducing emissions, will enable companies to collect additional natural gas that can be sold. The EPA's final standards also address emissions from storage tanks and other equipment. The final rules establish a phase-in period that is intended to ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology. Until January 2015, for example, owners and operators of natural gas wells must either flare their emissions or use emissions reduction technology called “green completions,” technologies that are already widely deployed at wells. In 2015, all newly fractured natural gas wells will be required to use green completions. The EPA's final rules are expected to have minimal impact on our business. The reduction of GHG emissions already was one of our priorities and we have been working to improve our methods to reduce GHGs through operational and business practices.  For example, we use green completions on a number of our wells to comply with Colorado Oil and Gas Conservation Commission (COGCC) rules.  Additionally 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 has announced that it intends to issue a proposed rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. As another prong of the strategy, BLM is expected to propose standards in 2015 for reducing venting and flaring

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on public lands. The EPA and BLM actions are part of a series of steps by the Obama Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.
Also, the EPA has proposed to strengthen the National Ambient Air Quality Standard for ozone. Adoption of a stricter standard for ozone eventually would result in increased control requirements for sources of volatile organic compounds such as our operations.
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 COGCC to address oil and gas well drilling, production, commingling and spacing in Wattenberg (located in the DJ Basin). On August 9, 2011, the COGCC approved amendments to Rule 318A. The amendments, which became effective on October 1, 2011, remove 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 address areas such as infill drilling, water sampling and waste management plans.
In February 2013, the COGCC approved new setback rules for crude oil and natural gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC 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 new 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 new 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 expanded outreach and communication efforts by an operator.
The COGCC also approved two new rules making Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Those new 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 rule 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. On the air side, 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 would 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.
During 2014, moreover, we actively worked to avoid statewide ballot initiatives that could have resulted in other significant limitations on crude oil and natural gas development in Colorado. On August 4, 2014, an agreement was reached with proponents of adverse ballot initiatives whereby they agreed to withdraw them and support the creation of a Task Force on State and Local Regulation of Oil and Gas Operations (Task Force). By executive order, Colorado Governor Hickenlooper created the 21-member Task Force for the purpose of recommending policies and legislation by February 27, 2015. The Task Force is focused on how to reasonably and effectively balance land use issues in a way that minimizes conflicts while protecting communities and allowing reasonable access to private mineral rights. A Noble Energy representative is a member of the Task Force.
Nevada In Nevada, state regulators recently promulgated rules to govern hydraulic fracturing and crude oil and natural gas development. We have actively participated in that process and do not believe it will have a material impact on our activities.
Pennsylvania On February 14, 2012, Governor Tom Corbett of Pennsylvania signed into law what is known as Act 13 of 2012 (Act 13). Act 13 represents the first comprehensive legislation regarding the development of the Marcellus Shale in Pennsylvania. Act 13, among other things, enacted stronger environmental standards and established impact fees, which in 2012 equaled $50,000 for each horizontal Marcellus Shale well. Act 13 also increased the notice distance of unconventional well permit applications from 1,000 feet to 3,000 feet, and extended the setback distance for unconventional wells from 200 feet to 500 feet. The statute also 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

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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 March 2012, seven municipalities filed suit against Act 13's statewide zoning provisions, claiming that Act 13 violated the state constitution. On July 26, 2012, the Pennsylvania Commonwealth Court declared the statewide zoning provisions in Act 13 unconstitutional, null, void and unenforceable. The Court also struck down the provision of the law that required the Pennsylvania Department of Environmental Protection to grant waivers to the setback requirements in Pennsylvania's Oil and Gas Act. This decision was appealed to the Pennsylvania Supreme Court, which upheld the lower court's decision. In response to another challenge, in 2014 the 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.
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.
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 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.
Israel's Natural Gas Policy In 2011, the Interministerial Committee was charged with the task of proposing a government policy for developing the natural gas economy. Objectives included providing a framework for substantial resource exports, designating a certain percentage of production from each field for domestic natural gas demand, and maintaining competition in the different sectors of the local economy.
In September 2012, the Committee issued its final recommendations which included, among others: a provision that permitted the export of natural gas as long as the quantity allowed for exports from all reservoirs does not exceed specified quantities, which amount may be reassessed; a provision that required regulatory approval for export, with export licenses eligible for periods up to 25 years; and a recommendation that steps should be taken to increase competition in the natural gas market.
On June 23, 2013, the Israeli government approved the main recommendations of the Committee with certain amendments, including an additional limitation on the exports allowed from the Tamar field (50% of uncontracted quantities).
On March 26, 2014, the Ministry of Finance issued a memorandum indicating its intent to amend the Petroleum Profits Law to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas. We are currently evaluating the recommendation and proposed amendments and have submitted comments and suggestions to the Ministry.
General elections in Israel have been scheduled for March 17, 2015, and we anticipate a delay in achieving regulatory certainty until a new government is in place.
See also Update on Core Area – Israel, above. 
Israel Antitrust Authority The Israeli Antitrust Commissioner (Commissioner) has been actively engaged to encourage competition in developing Israel's natural gas resources. Among other actions, the Commissioner has ruled that all domestic natural gas sales contracts are subject to review and approval of the Antitrust Authority and has intervened regarding the terms used in long-term contracts with certain natural gas customers.
The Commissioner also initiated a hearing process to evaluate a contention that allegedly the original acquisition agreement for the Leviathan acreage is a restrictive arrangement. The Commissioner publicly expressed concerns regarding ownership concentration in exploration blocks and development projects and its potential impacts on a competitive domestic natural gas market.
We have been engaged in discussions with the Antitrust Authority's review of these, and other matters, and in March 2014, we and our partners reached an agreement with the Antitrust Authority on various matters. The Consent Decree, which was subject to final approval by the Antitrust Tribunal, granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. Also as a result of the Consent Decree, we agreed to divest our Tanin and Karish natural gas discoveries. However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval.
This is a matter that we believed was resolved some time ago and we had received assurances from the Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition.
Final resolution of this item, as well as other regulatory matters, is required before we proceed with additional exploration or development in Israel. If necessary, we expect to vigorously defend our rights relating to our assets.
See also Update on Core Area – Israel, above. 

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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. The Dodd-Frank Act mandates that the Commodities Futures Trading Commission (CFTC) adopt rules and regulations implementing the derivatives market provisions of the Dodd-Frank Act, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for uncleared swaps and other derivatives transactions. Although there is an exception from swap clearing and trade execution requirements for commercial end-users that meet certain conditions (commonly referred to as the “end-user exception”), certain market participants, including most if not all of our counterparties, will be required to clear many of their swap transactions with entities that do not satisfy the end-user exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a bilateral basis.
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. Although the Dodd-Frank Act’s margin requirements, and CFTC proposed rules, would have applied to end users, recent legislation has relieved end users of this requirement. In particular, 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 August 22, 2012, the SEC adopted Rule 13q-1 under the Exchange Act, which would have required 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. That rule, however, was vacated by the District Court for the District of Columbia on the grounds that (i) the SEC misread the statute to require public filing of the information and (ii) the SEC erred in denying an exemption where foreign law prohibits disclosure of payments. The SEC declined to appeal the court’s decision and, instead, is expected to promulgate a revised rule that is responsive to the court’s holdings. We expect that the new rule proposal will be subject to a process of public notice and comment, which generally takes several months to complete, and will not become effective until after the publication of a final revised rule.
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. 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

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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.
The EPA is also currently studying the potential impacts of hydraulic fracturing on drinking water resources. Results are expected to be released in a draft for public and peer review in 2015.
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.
As drafted, the rules would require companies to:
disclose chemicals they inject by using an online database, with an exception for chemicals deemed to be trade secrets;
verify that wells are drilled properly so that toxic fluids do not contaminate groundwater; and
submit plans for managing drilling wastewater in lined pits or storage tanks.
BLM’s final requirements may be different. Because oil and gas drilling and development activities, including hydraulic fracturing practices, are already regulated at the state level, compliance with federal hydraulic fracturing regulations may result in additional costs and reporting burdens. The final rules are expected to be published in 2015.
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, 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 the Colorado 2013 general election, the municipalities of Boulder, Broomfield, Fort Collins and Lafayette each passed similar ballot measures supporting restrictions or bans on the practice of hydraulic fracturing within their boundaries. To date, court challenges to several of these ordinances have been successful. 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 moratorium 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

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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.
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.
In Nevada, where we are identifying additional exploration opportunities, state regulators recently promulgated rules to govern hydraulic fracturing and crude oil and natural gas development. We have actively participated in that process and do not believe it will have a material impact on our activities. New state regulations governing hydraulic fracturing practices have been adopted. Noble Energy actively participated in the public process which led to the creation of the statute and regulations.
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 Texas Railroad Commission (RRC) adopted the Hydraulic Fracturing Chemical Disclosure rule, which requires companies to disclose, on a public registry, chemical ingredients used to hydraulically fracture wells. 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 2009 we began acquiring our 370,000 fairly contiguous acreage position in northeast Nevada. It took over two years to assemble adequate acreage to warrant data collection. Once the acreage position had been established, we conducted extensive 3D seismic surveys and obtained other data, which our exploration staff analyzed and used to plan an initial drilling program. During 2013, we initiated an exploratory vertical well pilot program. Drilling locations were driven by analysis of the 3D seismic surveys. We must integrate data, such as core samples and well logs obtained from the drilling process, with our seismic and other data to determine if we have discovered hydrocarbons. In northeast Nevada, we are analyzing results from our exploratory wells drilled during 2014.
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

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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 14. Segment Information
Employees 
Our total number of employees increased 8%, from 2,527 at December 31, 2013 to 2,735 at December 31, 2014, in support of our major development and exploration projects. The 2014 year-end employee count includes 285 foreign nationals working as employees in Israel, Cyprus, Equatorial Guinea, Cameroon, Nicaragua, and the UK. 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 Houston, Texas; Ardmore, Oklahoma; Denver, Colorado; Greeley, Colorado; Canonsburg, Pennsylvania; Washington, D. C.; and in Cameroon, Equatorial Guinea, Israel, Cyprus, Mexico, Nicaragua, Falkland Islands, China 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.
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 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 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.

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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, 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. 
Crude oil, natural gas, and NGL prices are volatile and a reduction in these prices could adversely affect our results of operations, our liquidity, and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil, natural gas, and NGL production. Historically, the markets for crude oil, natural gas, and NGLs have been volatile and are likely to continue to be volatile in the future. High and low monthly daily average prices for crude oil and high and low contract expiration prices for natural gas during 2014 were as follows:
 
 
Daily Average Settlement Price for Prompt Month Contracts
 
 
High
 
Low
Year Ended December 31, 2014
 
 
 
 
NYMEX
 
 
 
 
   Crude Oil - WTI (Per Bbl)  (1)
 
$
105.15

 
$
59.29

   Natural Gas - HH (Per MMBtu)
 
5.56

 
3.73

Brent
 
 
 
 
   Crude Oil (Per Bbl)
 
111.76

 
62.91

(1) Prices for our US NGL production are determined at two primary market centers, Conway and Mt. Belvieu. For the year ended December 31, 2014, US average realized NGL prices tended to track the volatility of NYMEX WTI.
During fourth quarter 2014, a significant decline in crude oil prices occurred. As a result, we experienced decreases in crude oil revenues and recorded asset impairment charges due to commodity price declines. If crude oil prices continue to decline, further operating asset impairment or a goodwill impairment could occur, and our profitability will likely be negatively affected. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
Markets and prices for crude oil, natural gas and NGLs depend on factors beyond our control, factors including, among others:
economic factors impacting global gross domestic product growth rates;
global demand for crude oil, natural gas and NGLs;
global factors impacting supply quantities of crude oil, natural gas and NGLs, in particular, US crude oil and NGL supply growth resulting from shale oil development;
Organization of Petroleum-Exporting Countries (OPEC) spare capacity relative to global crude oil supply and crude oil pricing strategies;
the extent to which US shale producers become swing producers, yielding additional non-OPEC crude oil supply;
further application of horizontal drilling techniques which could increase production and significantly impact both domestic and global supplies of crude oil, natural gas, and NGLs;
our ability to develop natural gas in shale or crude oil in tight formations relatively inexpensively which could increase the supply of natural gas or crude oil;

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developments in the global LNG market, including potential exports from the US;
actions taken by foreign hydrocarbon-producing nations;
political conditions and events (including instability or armed conflict) in hydrocarbon-producing regions;
the existence of government imposed price and/or product subsidies;
the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels;
the long-term impact on the crude oil market of the use of natural gas as an alternative fuel for road transportation;
the availability of pipeline capacity and infrastructure;
the availability of crude oil transportation and refining capacity;
weather conditions;
demand for electricity as well as natural gas used as fuel for electricity generation;
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on crude oil demand as a transportation fuel;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Declines in commodity prices or inadequate transportation and storage of our product may have the following effects on our business:
reduction of our revenues, profit margins, operating income and cash flows;
curtailment or shut-in of our production due to lack of transportation or storage capacity;
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically;
certain properties in our portfolio becoming economically unviable;
delay or postponement of some of our capital projects;
further reduction of our 2015 capital investment program, or significant reductions in future capital investment programs, resulting in a reduced ability to develop our reserves;
limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
limitations on our access to sources of capital, such as equity and debt; and
declines in our stock price.
In addition, lower commodity prices, including declines in the commodity forward price curves, may result in the following:
asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment;
additional counterparty credit risk exposure on commodity hedges; and
reduction in the carrying value of goodwill.
Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, and limitations on our growth with negative impact on our operating results, liquidity and financial position.
We currently have an inventory of major development projects in various stages of development. We have expanded our horizontal drilling programs in the DJ Basin and Marcellus Shale and are currently moving forward on the Gunflint, Big Bend and Dantzler development projects. In addition, we have invested significantly in the potential development of Leviathan Phase 1. Cyprus, Carla and Diega discoveries are being appraised and, as such, are not yet sanctioned. It will take several years before first production is achieved on some of these projects.
Offshore projects often entail significant technical and other complexities including subsea tiebacks to an FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. Additionally, we are considering multiple future integrated development plans, which provide significant facilities and operating efficiencies, for our horizontal Niobrara and Marcellus Shale development projects.
This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. In addition, we depend on third-party technology and service providers and other supply chain participants for these complex projects. We may not be able to fully execute these projects due to:
the current low commodity price environment;
lack of government approval for projects, including Israeli government approval for Leviathan Phase 1 development;
inability to attract and/or retain a sufficient quantity of personnel with the skills required to bring these complex projects to production on schedule and on budget;
significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure which could adversely affect project development;
civil disturbances, anti-development activities, legal challenges or other potential interruptions which could prevent access; and

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drilling hazards or accidents or natural disasters.
We may not be able to compensate for, or fully mitigate, these risks.
See also Items 1 and 2. Business and Properties – Update on Core Area – Israel. 
Our international operations may be adversely affected by economic and political developments.
We have significant international operations, with approximately 40% of our 2014 total consolidated sales volumes coming from international areas. We are also conducting exploration activities in these and other international areas. Our operations may be adversely affected by political and economic developments, including the following:
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;
disruptions caused by territorial or boundary disputes in certain international regions;
changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident, a large oil spill occurring in the Gulf of Mexico in 2010, or other incidents that have occurred;
laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;
foreign exchange restrictions;
international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Certain of these risks could be intensified by large crude oil or natural gas discoveries in areas where we are currently conducting offshore exploration activities, such as the Gulf of Mexico or Falkland Islands. Large discoveries, such as ours in the Levant Basin, may have impacts on global natural gas supplies.
Such political and economic developments as mentioned above could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
See also Items 1. and 2. Business and Properties – Update on Core Area – Israel. 
Our operations may be adversely affected by changes in the fiscal regimes and related government policies and regulations in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access along with government participation in oil and gas projects, royalties and taxes. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government financial take from developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in the fiscal regimes of these countries could have a significant impact on our operations and financial performance. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws or the effect such interpretations could have on our business.
Currently, many governments globally are seeking additional revenue sources, including, potentially, increases in government financial take from oil and gas projects. In developing nations, governments may seek additional revenues to support infrastructure and economic development and for social spending. In many nations of the Organisation for Economic Cooperation and Development (OECD), governments are facing significant budget deficits and growing national debt levels, as well as pressure from financial markets to address structural spending imbalances.
The OECD itself is in the process of issuing guidance on Base Erosion and Profit Shifting (BEPS), an initiative which aims to standardize and modernize global tax policy. Adoption of BEPS by foreign jurisdictions in which we operate could result in changes to tax policies, including transfer pricing policies. To the extent such changes are retroactive, currently producing projects could become uneconomic, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges.
In the US, certain measures have been proposed that would alter current tax expense on oil and gas companies, for example: the repeal of percentage depletion for oil and natural gas properties; the deferral of expensing intangible drilling and development costs (IDC); the inability to expense costs of certain domestic production activities; and a lengthening of the amortization period for certain geological and geophysical expenditures. It is likely that some of these proposals to increase tax expense on

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the oil and gas industry will continue to be reviewed by the US Congress in future years. The enactment of some or all of these proposals could have a significant negative impact on our capital investment, production and growth.
Changes in fiscal regimes have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations in the following ways, among others:
restrict resource access or investment in lease holdings;
reduce exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
have a negative impact on the ability of us and/or our partners to obtain financing;
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow;
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
adversely affect the price of our common stock.
See also Items 1. and 2. Business and Properties – Update on Core Area – Israel. 
Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.
Violent acts resulting in loss of life, destruction of property, environmental damage and pollution occur around the world. Many incidents are driven by civil, ethnic, religious or economic strife. In addition, the number of incidents attributed to various terrorist or extremist organizations have increased significantly. We operate in regions of the world that have experienced such incidents or are in close proximity to areas where violence has occurred.
We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results, among others: