Annual Report (10-k)

PART I

Items 1. and 2. Business and Properties

In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy, Inc. and its subsidiaries (Noble Energy, the Company, we or us). All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated. For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary , located at the end of this report.

Noble Energy is an independent crude oil and natural gas exploration and production company with a diversified high-quality portfolio spanning three continents. Founded in 1932, Noble Energy is a Delaware corporation, incorporated in 1969, and has been publicly traded on the New York Stock Exchange (NYSE) since 1980. We have a unique history of growth, evolving from a regional crude oil and natural gas producer to a global exploration and production company included in the Standard & Poor's 500 (S&P 500).

Our purpose, Energizing the World, Bettering People's Lives ^® , reflects our commitment to find and deliver affordable energy through crude oil, natural gas and NGL exploration and production while living our commitment to contribute to the betterment of people's lives in the communities in which we operate. We strive to build trust through stakeholder engagement, act on our values, provide a safe work environment, respect our environment and care for our employees and the communities where we operate.

Our portfolio of assets is diversified through US and international projects and production mix among crude oil, natural gas, and NGLs. In particular, our business is focused on both US unconventional basins and certain global offshore conventional basins. In US onshore unconventional basins, we have demonstrated competence in applying geological, drilling, completion, and midstream design and operational expertise. In US onshore, we typically apply a major project development concept to an unconventional basin by utilizing an Integrated Development Plan (IDP) approach. In the global offshore, we have had notable exploration and major project successes over the past twelve years, which have led to production from numerous offshore major development projects which have provided long-lived cash flows to our business.

Approximately 70% of our 2018 capital program is allocated to US onshore development, primarily focused on liquids-rich opportunities in the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including initial development costs associated with the Leviathan project, represent more than 25% of the total. The remaining portion of our 2018 capital program is designated for exploration for lease acquisition, seismic and other

geological analysis in support of future exploration prospects for potential development post 2020, as well as other corporate activities.

In addition, the majority of our assets are held by production, which allows for further investment and financial flexibility. Occasional strategic acquisitions of producing or non-producing properties, combined with the periodic divestment of assets, have allowed us to pursue our objective of a well-positioned and diversified portfolio to maximize strategic value.

Oil and Gas Properties and Activities We search for crude oil and natural gas properties onshore and offshore, and seek to acquire exploration rights and conduct exploration activities in areas of interest. Our activities include geophysical and geological evaluation; analysis of commercial, regulatory and political risks; and exploratory and development drilling leading to production, where appropriate.

Our current portfolio consists primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. These properties contribute all of our crude oil, natural gas and NGL production, provide continual investment opportunities in proved areas, and offer further exploration opportunities. Our new venture areas provide frontier exploration opportunities, which may result in the establishment of new operational areas in the future. We also own or invest in midstream assets primarily used in the processing and transportation of our US onshore production. See Midstream - Properties and Activities , below.

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

Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer. Our reportable segments include: United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Newfoundland, Suriname, and other new ventures); and Midstream.

The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production, or E&P). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative cost are recorded at the corporate level. See Item 8. Financial Statements and Supplementary Data – Note 14. Segment Information .

Development Activities Our development projects have resulted from both exploration success as well as periodic strategic acquisitions. These projects provide opportunities for growth at attractive financial returns. Each project progresses, as appropriate, through the various development phases including appraisal, engineering and design, development drilling, construction and production. While development projects require significant capital investments, typically over a multi-year period, they are expected to offer sustained cash flows, while on production.

In US onshore, our low production-risk development programs are centered around IDPs and generate efficiencies for upstream and midstream development. IDPs are generally areas of highly contiguous acreage, typically held by production, that

accommodate drilling long lateral wells, and other operational synergies. The approach also benefits from the ability to accommodate a flexible capital investment program that can be varied in response to changes in the commodity price environment. We continue to enhance project performance in these areas through technology and operational efficiencies.

Offshore, we engage in long-cycle development projects, such as progressing the first phase of development at the Leviathan natural gas field, offshore Israel, the largest natural gas discovery in our history. Our development activities are discussed in more detail in the sections below.

Divestiture and Acquisition Activities We maintain an ongoing portfolio management program. Accordingly, we may periodically divest assets through asset or equity sales, exchanges or other transactions. During 2017 , we closed several transformative portfolio transactions, demonstrating our continued focus on enhancing profit margins and company returns. We generated cash of $2.1 billion from asset sales, including divestiture of the Marcellus Shale upstream assets, as well as other non-strategic US onshore assets. Periodically, we may also engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities that own the assets. For example, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) in 2017 and the merger (Rosetta Merger) of Rosetta Resources Inc (Rosetta) in 2015. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources , Item 8. Financial Statements and Supplementary Data - Note 3. Clayton Williams Energy Acquisition , and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger .

Exploration Activities   We primarily focus on organic growth from exploration and development drilling activities, concentrating on existing basins or plays where we believe we have strategic competitive advantages or in new basins with attractive geological potential and the opportunity for attractive financial returns. These advantages are derived from proprietary seismic data and operational expertise, which we believe will generate superior returns over the oil and gas business cycle. We have had substantial historic exploration success in the Gulf of Mexico, the Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major development projects. In 2017 , we performed limited exploration activities due to the commodity price environment.

Proved Oil and Gas Reserves    Proved reserves at December 31, 2017 were as follows:

		December 31, 2017
		Proved Reserves
		Crude Oil and Condensate			NGLs			Natural Gas			Total
Reserves Category		(MMBbls)			(MMBbls)			(Bcf)			(MMBoe) (1)
Proved Developed
United States		176			119			983			458
Israel		3			—			1,793			302
Equatorial Guinea		29			11			411			108
Total Proved Developed Reserves		208			130			3,187			868
Proved Undeveloped
United States		243			99			838			482
Israel		6			—			3,655			615
Total Proved Undeveloped Reserves		249			99			4,493			1,097
Total Proved Reserves		457			229			7,680			1,965

⁽¹⁾  Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs is significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.

Our proved reserves totaled 1,965 MMBoe as of December 31, 2017 as compared with 1,437 MMBoe as of December 31, 2016 . Changes included the following:

offset by:

Our proved reserves are 48% US and 52% international, and the commodity mix is 35% global liquids (crude oil and NGLs), 50% international natural gas and 15% US natural gas.

See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for further discussion of proved reserves.

Oil and Gas Exploration and Production - Properties and Activities

United States

We have been engaged in crude oil, natural gas and NGL exploration and development activities throughout US onshore since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 72% of 2017 total consolidated sales volumes and 48% of total proved reserves at December 31, 2017 . Approximately 45% of the proved reserves in the US is crude oil and condensate, 32% is natural gas and 23% is NGLs.

Sales volumes and proved reserves estimates for our US operating areas were as follows: 

⁽¹⁾ We divested our Marcellus Shale upstream assets in second quarter 2017.

Wells completed in 2017 and productive wells at December 31, 2017 for our US operating areas were as follows: 

US Onshore

Our US onshore operations are located in proven basins with long-life production profiles. These assets provide low production-risk drilling opportunities in liquids-rich areas that offer predictable and long-term production and cash flow growth at attractive financial returns. Locations of our US onshore operations as of December 31, 2017 are shown on the map below:

DJ Basin In 2017 , we focused our drilling and development activity in the Wells Ranch and East Pony areas that produce a high oil mix. The IDP concept allows us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 80,000 acres). Our IDP approach has provided an opportunity to efficiently and economically support production growth by leveraging infrastructure, such as gas, oil and water, including both fresh and produced water, assets.

2017 Activity Operationally, our focus on drilling longer laterals and obtaining better results from enhanced completions has led to stronger new well performance. Coupled with expansion of midstream infrastructure and execution of synergies as well as prudent management of costs, we are delivering enhanced profit margin returns. During the year, we completed 103 horizontal wells and 101 wells initiated production. We also participated in approximately 35 non-operated development wells during 2017 .

As part of ongoing portfolio management, we entered into an agreement to divest approximately 30,200 net acres, the majority of which were undeveloped, in the Greeley Crescent area of Weld County, Colorado for $608 million. We received proceeds of $568 million at closing and expect to receive the remaining proceeds in mid-2018. As part of the transaction, all of the acreage in the Greeley Crescent Bronco IDP remains subject to dedications to Noble Midstream Partners LP (Noble Midstream Partners) for crude oil gathering, and produced and fresh water services.

Since 2015, we have been working with the State of Colorado to improve emission control systems as required under a joint consent decree (Consent Decree). Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells, the majority of which are vertical, and associated tank batteries. Costs associated with these abandonment activities will be incurred over several years.

We exited 2017 with one drilling rig and intend to increase to two rigs in 2018. Our current 2018 development program contemplates expansion into the Mustang IDP area where we have a large, contiguous acreage position.

Delaware Basin Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams Energy Acquisition on April 24, 2017, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings. We also executed strategic leasing initiatives and entered into a bolt-on acquisition, for $295 million, which closed in January 2017, adding additional production near our producing properties and increasing our

contiguous acreage position in the Reeves County area. As of December 31, 2017, we held approximately 117,000 net acres in the Delaware Basin.

2017 Activity In 2017, we successfully integrated the Clayton Williams Energy assets and initiated execution of the Delaware Basin IDP with a focus on long laterals, pad drilling, multi-zone completions and infrastructure development. As demonstrated in the DJ Basin, our IDP approach provides an opportunity to more efficiently and economically develop our acreage.

We successfully transformed our 2017 development program's focus from a single well development approach to an IDP to capture the full resource potential for the Delaware Basin. This was achieved with eight pads that developed multiple zones within the Wolfcamp A formation zone, including two pads that successfully included the shallower 3rd Bone Springs zone. With successful wells in the deeper Wolfcamp zones, as well as expanded understanding of the resource potential and our IDP approach, we are well positioned to efficiently and economically develop our acreage over future years.

We began 2017 with three drilling rigs and exited the year with six drilling rigs. During the year, we completed 45 wells and commenced production on 44 wells, of which 23 were multi-zone pads. We also participated in approximately 30 non-operated development wells during 2017 . In addition, we added two central gathering facilities (CGFs).

For 2018 , we will continue asset development through long laterals, pad drilling, multi-zone development and an infrastructure build-out initiative that will include an additional three CGFs.

Eagle Ford Shale We hold approximately 35,000 net acres located in the highly prolific liquids-rich area of the play, including producing assets in Webb and Dimmit counties. Since acquiring these assets, we have continued to apply IDP learnings and enhancements to optimize development of these assets, including optimizing drilling and completion designs through testing varying clusters per stage, lateral lengths, and proppant quantities to increase investment efficiency. We have also focused on testing co-development of both the Upper and Lower Eagle Ford formation zones utilizing our IDP approach.

2017 Activity Our 2017 capital program was focused within Webb and Dimmit counties where we operated up to two drilling rigs, completed 47 horizontal wells and commenced production on 49 horizontal wells. All wells drilled during 2017 were on multi-well pads leveraging centralized infrastructure. We also sold certain assets located in Gonzales and DeWitt counties, where we had not engaged in drilling activities since the completion of the merger (Rosetta Merger) with Rosetta Resources Inc. (Rosetta) and received proceeds of $45 million.

We exited 2017 with a two rig drilling program. Our capital program in 2018 focuses on developing the Upper and Lower Eagle Ford formation zones within the Gates Ranch area.

Marcellus Shale   On June 28, 2017, we closed the sale of the Marcellus Shale upstream assets, receiving net proceeds of $1.0 billion and recorded a loss on sale of $2.38 billion . The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver production and cash flow growth.

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger .

Gulf of Mexico     Locations of our operations in the Gulf of Mexico as of December 31, 2017 are shown on the map below:

We have several producing fields and an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options.

We currently hold leases on approximately 63 deepwater blocks, representing approximately 52,000 net developed acres and approximately 171,000 net undeveloped acres. We are the operator on nearly 80% of our leases.

Subsequent Event On February 15, 2018, we announced the Company signed a definitive agreement to sell its assets in the Gulf of Mexico. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger .

2017 Activity Our activity in 2017 primarily focused on optimizing production and progressing our Katmai project. See Offshore Producing Properties and Update to Gulf of Mexico Major Projects, below.

During 2017, we completed our geological evaluation of certain leases and determined that several leases, representing $60 million of undeveloped leasehold cost, should be impaired and expensed.

We have remaining capitalized undeveloped leasehold cost of approximately $44 million related to prospects that have not yet been drilled. Leases representing over 60% of this cost are scheduled to expire over the years 2018 to 2020. In addition, some leases may become impaired if production is not established or should we not take action to extend the terms of the leases. As a result of our exploration activities, capitalized undeveloped leasehold costs could become impaired. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Potential for Future Impairments.

Offshore Producing Properties    

Gunflint (Mississippi Canyon Block 948; 31% operated working interest)  Gunflint is a 2008 crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar platform. Production commenced in July 2016 and the development contributed 7 MBoe/d of sales volumes in 2017.

Rio Grande Development including Big Bend (Mississippi Canyon Block 698; 54% operated working interest) and Dantzler (Mississippi Canyon Block 782; 45% operated working interest) The Rio Grande crude oil development project consists of a single producing well from Big Bend, a 2012 crude oil discovery, and two producing wells from Dantzler, a 2013 crude oil discovery, flowing to the Thunder Hawk platform for which we assumed operatorship in 2016. The Rio Grande development commenced production in October 2015 and contributed an average of 12 MBoe/d of sales volumes in 2017.

Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest), Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest) and Santiago (Mississippi Canyon Block

519; 23.25% operated working interest) The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. The Galapagos development began producing in 2012 and is connected to existing infrastructure through subsea tiebacks. A well stimulation commenced in the fourth quarter of 2017 to enhance recovery. The Galapagos project contributed an average of 4 MBoe/d of sales volumes in 2017.

Swordfish (Viosca Knoll Blocks 917; 961 and 962; 85% operated working interest)   Swordfish is a 2001 crude oil discovery and began producing in 2005. The Swordfish project currently includes two producing wells flowing to the Neptune Spar, our 100%-owned floating offshore production platform, and contributed an average of 3 MBoe/d of sales volumes in 2017. We currently plan to begin abandonment activities in 2019.

Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) Ticonderoga is a 2004 crude oil discovery and began producing in 2006. The project currently includes two producing wells, which contributed an average of 1 MBoe/d of sales volumes in 2017. These properties are connected to existing infrastructure through subsea tiebacks.

Update to Gulf of Mexico Major Projects

Katmai (Green Canyon Block 40; 50% operated working interest) During 2014, we announced successful final well results at the Katmai exploratory well. Katmai was drilled to a total depth of 27,900 feet in 2,100 feet of water. Wireline logging data indicated a total of 154 net feet of crude oil pay discovered in multiple reservoirs, including 117 net feet in Middle Miocene and 37 net feet in Lower Miocene reservoirs. In 2016 , we spud our Katmai 2 appraisal well (38% operated working interest), located in Green Canyon Block 39, and encountered high pressure in the untested fault block. In response, we temporarily abandoned the well and are assessing plans to complete appraisal as well as development scenarios for the Katmai project.

Troubadour (Mississippi Canyon Block 699; 60% operated working interest) Troubadour was a 2013 natural gas discovery. In 2017, we determined that the asset was impaired in the current forward outlook for natural gas prices and development scenarios, and charged $63 million to impairment of oil and gas properties and $5 million to undeveloped leasehold impairment expense.

Regulatory Environment Various federal agencies overseeing certain of our activities in the Gulf of Mexico have adopted new regulations and are considering others. See Regulations - US Offshore Regulatory Developments below, and Item 1A. Risk Factors .

International

Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash flow growth over the last decade. Previous exploration successes in these areas have also identified additional multiple major development projects that have the potential to contribute to long-term production and cash flow growth in the future.

During 2017 , we progressed development of offshore Israel assets by completing the Tamar 8 development well and commencing drilling activities for the Leviathan 5 development well. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by progressing multiple natural gas sales and purchase agreements (GSPAs). See Eastern Mediterranean (Israel and Cyprus) and West Africa (Equatorial Guinea, Cameroon and Gabon), below.

Operations in Equatorial Guinea, Cameroon, Gabon, Cyprus, and Suriname are conducted in accordance with the terms of Production Sharing Contracts (PSCs). Operations in Israel, Newfoundland (Canada) and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors .

Sales volumes and proved reserves estimates for our international operating areas were as follows:

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

Wells completed in 2017 and productive wells at December 31, 2017 in our international operating areas were as follows:

Eastern Mediterranean (Israel and Cyprus )   One of our operating areas is the Eastern Mediterranean, where we have identified the existence of substantial natural gas resources since we obtained our first exploration license offshore Israel in 1998.

Israel, the only producing country in our Eastern Mediterranean area, contributed an average of 272 MMcf/d of natural gas sales volumes in 2017, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field. With the addition of proved undeveloped reserves associated with Leviathan field development in 2017, Israel represented approximately 47% of total proved reserves at December 31, 2017 . Our leasehold position in the Eastern Mediterranean at December 31, 2017 , included four leases and three licenses operated offshore Israel. Offshore Cyprus, we operate under the terms of a PSC.

At December 31, 2017 , the Eastern Mediterranean position included approximately 78,000 net developed acres and 116,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. The license offshore Cyprus covers approximately 33,000 net undeveloped acres adjacent to our Israel acreage.

Locations of our operations in the Eastern Mediterranean as of December 31, 2017 are shown below:

Offshore Israel Noble Energy and our partners have delivered reliable and affordable natural gas to Israeli citizens for over a decade. During this time, we have delivered approximately 2.3 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.

We are the first company to construct, operate and produce from a major natural gas development project offshore Israel. Our Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed the Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry standards for an offshore natural gas project of this magnitude and complexity.

In 2010, we discovered the Leviathan field, our largest natural gas discovery to date. The quantity of discovered natural gas resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predicted to continue to grow over the next decade, primarily driven by increased use of natural gas over coal to fuel electric power generation. During 2017, growth in power, industrial and residential demand in Israel and first exports to Jordan, coupled with almost 100% asset uptime, enabled us to set a new sales volume record of 956 MMcfe/d, gross, from fields offshore Israel.

In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil discoveries at greater depths. We conducted preliminary exploration activities in 2012 and are analyzing the potential for future exploration.

Domestic Natural Gas Demand As the Israeli economy continues to grow, the demand for natural gas used primarily for electricity generation is also expected to grow. Demand for natural gas in the industrial sector, including refineries, chemical, desalination, cement and other plants, as well as residential uses, is also increasing. These sectors are gaining confidence that a long-term supply of affordable natural gas will be available and are now investing the capital necessary to convert facilities and infrastructure to use natural gas. In addition, government requirements for emissions reductions have also driven incremental demand for natural gas beginning in 2016. We have executed numerous GSPAs with domestic customers. See International Marketing Activities and Delivery and Firm Transportation Commitments , below.

Regional Demand and Exports The Eastern Mediterranean presents an opportunity to match our affordable, abundant supply of natural gas with a substantially undersupplied regional market, including customers in Jordan and Egypt. With the Tamar field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to supply natural gas to the region for many years.

Israel Natural Gas Projects  

Tamar Natural Gas Project (32.5% operated working interest) The Tamar project began production in March 2013 and has peak flow rates of approximately 1.1 Bcf/d, gross, to support seasonal high demand periods. In 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT) and in 2017, we completed and commenced production from the Tamar 8 development well. The Tamar 8 well increases supply reliability as domestic demand for natural gas continues to grow.

In 2017, we installed subsea equipment to allow for future tie-back of our 2013 Tamar Southwest discovery into the Tamar platform and other existing infrastructure. We continue to work with the Government of Israel to obtain regulatory approval of the development plan, which would help reinforce the reliability for the Tamar project and support increased customer demand.

We are also assessing the possibility for expansion of the Tamar project. The project would expand field deliverability from the current capacity level of approximately 1.2 Bcf/d to up to approximately 2.1 Bcf/d, a quantity that would allow for additional regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources as well as regulatory approvals from respective governments.

The Israel Natural Gas Framework (Framework) provides for reduction in our ownership interest in the Tamar and Dalit fields from 36% to 25% by year-end 2021. In 2016, we divested 3.5% of our interest in these respective fields, partially fulfilling this commitment required by the Framework. Further, on January 29, 2018, we signed a definitive agreement to divest a 7.5% working interest in these respective fields to Tamar Petroleum Ltd (TASE: TMRP). See Item 8. Financial Statements and Supplementary Data – Note. 4. Acquisitions, Divestitures and Merger .

Leviathan Natural Gas Project (39.66% operated working interest)    In early 2017, we announced project sanction of the Leviathan natural gas project and recorded initial proved reserves of 3.3 Tcf ( 551 MMBoe) associated with the first phase of development. The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station and the Israel Natural Gas Lines (INGL) pipeline network. We expect our share of development costs to total approximately $1.5 billion and to be funded from our share of cash flows from the Tamar asset and expected proceeds to be received from the sell-down of our ownership interest in Tamar as noted above. In addition, we have the ability to borrow under the Leviathan Term Loan Facility (defined below). As we progress the first phase of development, we have included volume capacity expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas demand.

During 2017, we commenced drilling and continued detailed design and engineering activities and fabrication of onshore facilities, topsides, jacket and subsea equipment. We will continue drilling activities and commence well completions in 2018 as we progress the project towards first gas sales by the end of 2019. As of December 31, 2017 , the project remained within budget and on schedule at approximately 35% complete, with all critical path equipment and major contracts secured.

The marketing and development of natural gas from this asset is intended to serve both domestic demand and regional export. We are actively engaged in natural gas marketing activities and have progressed multiple GSPAs totaling up to approximately 525 MMcf/d, gross (approximately 208 MMcf/d, net) of natural gas from the Leviathan field.

Our largest Leviathan GSPA, with the National Electric Power Company Ltd. (NEPCO) of Jordan, provides for sales of natural gas intended for consumption in power production facilities over a 15-year period. Sales to NEPCO are anticipated to commence at field startup. We continue to market natural gas from the Leviathan field toward realizing full utilization of the 1.2 Bcf/d of production capacity. See Israel Natural Gas Framework and Regulatory Environment, below.

Alon D License In August 2017, the Petroleum Commissioner of Israel granted us a 32-month extension of the Alon D license (47.059% operated working interest) to drill an exploration well. We are performing geologic and environmental studies necessary to progress the prospect to an investment decision.

Other Discoveries Offshore Israel    Our development plan for the Dalit field (32.5% operated working interest) , a 2009 natural gas discovery, was approved by the Government of Israel. Development includes a tieback to the Tamar platform. We are also analyzing 3D seismic data to evaluate the additional potential of the area, including the possible existence of hydrocarbons at deeper intervals. 

Asset Impairments No impairment expense was recorded during 2017. During 2016, we recorded impairment expense of $88 million related to certain Leviathan field development concepts which were not selected. During 2015, we recorded impairment expense of $36 million , primarily due to an increase in field abandonment costs. See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments .

Israel Natural Gas Framework and Regulatory Environment We are subject to certain fiscal, antitrust and other regulatory challenges in Israel. These challenges have been addressed with the enactment of the Framework by the Government of Israel.

See Regulations – Israel Regulatory Environment and Item 1A. Risk Factors – Our Eastern Mediterranean discoveries bear certain geopolitical, regulatory, financial and technical challenges that could adversely impact our ability to monetize these natural gas assets.

Cyprus Natural Gas Project (Offshore Cyprus) During fourth quarter 2015, we entered into a farm-out agreement with a partner for a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, for $171 million. We received initial proceeds of $131 million related to the farm-out agreement in 2016 and received the remaining consideration, subject to post-close adjustments, in January 2017. We continue to operate with a 35% interest. As part of the farm-out process, we negotiated a waiver of our remaining exploration well obligation.

In September 2017, we submitted an updated development plan to the Government of Cyprus. We continue to work with the Government of Cyprus to obtain approval of the development plan and the issuance of an Exploitation License for the Aphrodite field. Receiving an Exploitation License, in conjunction with securing markets for Aphrodite natural gas, will allow us and our partners to perform the necessary FEED studies and progress the project to final investment decision. In preparation for FEED, we and our partners are currently performing preliminary engineering and design (pre-FEED) for the potential development of the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. During 2017, we progressed capital project cost improvements and continued regional natural gas marketing efforts.

West Africa (Equatorial Guinea, Cameroon and Gabon)   West Africa is one of our operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC, offshore Cameroon, and one block offshore Gabon. In West Africa, our interests can be burdened by overriding royalty interests and/or other government interests. As such, our working interests may differ from our revenue interests. Equatorial Guinea is currently our only producing country in our West Africa segment and, excluding the impact of equity investees, Equatorial Guinea contributed an average of 57 MBoe/d of sales volumes in 2017 and represented approximately 15% of total consolidated sales volumes. At December 31, 2017 , Equatorial Guinea represented approximately 5% of total proved reserves. We held approximately 118,000 net developed acres and 30,000 net undeveloped acres in Equatorial Guinea, 168,000 net undeveloped acres in Cameroon, and 403,000 net undeveloped acres in Gabon at December 31, 2017 .

Locations of our upstream operations in Equatorial Guinea and Cameroon, as of December 31, 2017 are shown on the map below:

Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest) , offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold, and natural gas and water are reinjected into the reservoir to maintain pressure and maximize crude oil recoveries. During 2017 , the Aseng field produced approximately 7 MBoe/d, net.

The Aseng FPSO is designed to act as a crude oil production hub, as well as a liquids storage and offloading facility, with capabilities to support future subsea oil field developments in the area. It also has the ability to process and store condensate from natural gas condensate fields in the area, the first of which is Alen. Since it first came online, the Aseng field has maintained reliable performance, averaging over 99% production uptime and, as of December 31, 2017, has produced 89 MMBbls of cumulative gross crude oil production.

Alen Field    Alen is a natural gas and condensate field primarily on Block O (51% operated working interest, 45% revenue interest) , offshore Equatorial Guinea, which includes three production wells and three natural gas injection wells connected to a production platform that utilizes the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and produced approximately 4 MBoe/d, net, during 2017 . As of December 31, 2017, Alen has produced over 33 MMBbls of cumulative gross condensate production.

The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization, below.

In October 2017, we executed a unitization agreement on the Alen field with our partners and the Government of Equatorial Guinea. The agreement was between Block O and Block I interest owners. We expect the impact on our allocated future sales volumes to be de minimis.

Alba Field    Alba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest, 32% revenue interest) , which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, a liquefied petroleum gas (LPG) processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2017 , Alba field sales volumes totaled 54 MBoe/d, net, reflecting 46 MBoe/d attributable to total sales volumes and 8 MBoe/d attributable to an equity investee.

In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government of Equatorial Guinea. The agreement was between Alba Block and Block D interest owners. As a result of the unitization, our revenue interest going forward changed from 34% to 32%, and our non-operated working interest changed from 35% to 33%. As anticipated, our 2017 sales volumes from the Alba field were lower as a result of the unitization, and the impact on our proved reserves was de minimis. We expect the impact on our allocated future sales volumes to be de minimis.

We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated liquefied natural gas (LNG) plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices.

We account for both Alba Plant and AMPCO as equity method investments and present our share of income as a component of revenues. We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing operations in our West Africa operating area. Our Alba asset teams are fully engaged in operational and financial decisions and exert significant influence in the monetization of the Alba field and Alba Plant. We hold a voting position on AMPCO's leadership team through AMPCO's management committee, and our asset teams influence decisions regarding capital investments, budgets, turnarounds, maintenance and other project matters.

West Africa Natural Gas Monetization    We continue our efforts to monetize the significant natural gas resources represented by our discoveries offshore West Africa, including our 2007 Yolanda discovery (Block I), the YoYo discovery, offshore Cameroon, as well as natural gas from our Aseng and Alen fields.

As part of our monetization efforts, a natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, we believe these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial returns.

Cameroon We have an interest in approximately 168,000 undeveloped acres offshore Cameroon in our YoYo PSC (100% operated working interest) . The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options, which will provide a more robust framework directly related to oil and gas operational activities. In June 2017, we converted our mining concession license for the YoYo block into a PSC.

Offshore Gabon We are the operator of Block Doukou Dak (60% working interest) , an undeveloped, deepwater area, covering approximately 671,000 gross acres. Our exploration commitment includes an obligation for 3D seismic, which was acquired

and processed throughout 2016 and the first half of 2017. We received the final product mid-year 2017 and are currently evaluating the seismic data results.

See also Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs .

Other International

Other international operations include the following:

Offshore Newfoundland (Canada) In November 2016, we acquired a non-operated 25% working interest in exploration parcels (blocks) 3, 4 and 8, and a non-operated 40% working interest in exploration parcel (block) 10. BP Canada Energy Group ULC is the operator of the blocks. We have acquired 3D seismic data which will allow us to assess the economic viability of this exploration prospect.

Offshore Suriname   We hold a non-operated 20% working interest in Block 54 offshore Suriname in the Atlantic Ocean. In October 2017, our partner spud the Araku-1exploration well and subsequently plugged and abandoned the well. As a result, we recorded dry hole expense of $7 million and are currently analyzing the well results to update modeling of the basin and review further prospectivity. See Note 5. Asset Impairments .

Offshore Falkland Islands In 2016, following completion of our geological assessment, we exited all licenses, excluding the PL-001 which contains the Rhea prospect. The exit resulted in a $25 million undeveloped leasehold impairment expense. As of December 31, 2017, there is no remaining net book value associated with the assets.

North Sea   The non-operated MacCulloch field is currently undergoing decommissioning activities. Due to its size and location, field abandonment is a multi-year process, requiring several phases. Therefore, our share of estimated field abandonment costs, recorded as an asset retirement obligation, may change over time. For example, during 2017, the operator of the MacCulloch field notified working interest owners that the scope and magnitude of decommissioning activities has been revised downward, resulting in lower projected field abandonment costs. As such, we recorded a revision of $42 million in 2017 that decreased our estimated asset retirement obligation for the remediation project. The discounted obligation totaled 44 million at December 31, 2017. We will continue to monitor the status and costs of the project and will adjust our estimate accordingly.

Midstream – Properties and Activities

We continue to develop our Midstream business, which includes gathering, treating, and transportation assets as well as water-related infrastructure, including fresh water delivery and produced water disposal assets, that support our upstream operations. Our Midstream assets are strategically located with our exploration and production activities in the DJ and Delaware Basins. These assets also provide services to third party customers.

Our Midstream operations include those of Noble Midstream Partners, a publicly traded consolidated subsidiary and limited partnership that owns, operates, develops, and acquires a wide range of domestic midstream infrastructure assets. Noble Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized in a development company structure. At December 31, 2017, our ownership interest in Noble Midstream Partners consisted of a 45.5% limited partner interest, the entire non-economic general partner interest, and all of the incentive distribution rights. On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided access to capital markets to support funding of our US onshore midstream investment program.

The following diagram depicts our organizational structure as of December 31, 2017. Development companies identified in red and blue indicate the location of the assets as either in the DJ Basin or Delaware Basin, respectively.

Advantage Joint Venture In April 2017, Noble Midstream Partners, along with its partner, Plains Pipeline, L.P., formed the Advantage joint venture (Advantage Joint Venture) and subsequently completed the acquisition of Advantage Pipeline L.L.C. (Advantage Pipeline). Noble Midstream Partners serves as the operator of the Advantage Pipeline System, which includes a 70-mile crude oil pipeline (Advantage Delaware Basin Pipeline) in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150 MBbls per day of capacity (expandable to over 200 MBbls per day) and 490 MBbls of storage capacity. Noble Midstream Partners owns a 50% interest in the joint venture.

Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of Blanco River DevCo, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy. Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.

Black Diamond Gathering and Acquisition of Saddle Butte Pipeline In December 2017, Noble Midstream Partners and Greenfield Midstream, LLC (Greenfield Midstream) formed an entity, Black Diamond Gathering LLC (Black Diamond Gathering), to acquire Saddle Butte Rockies Midstream, LLC and affiliates (Saddle Butte). The acquisition includes a large-scale integrated crude oil gathering system in the DJ Basin, consisting of approximately 160 miles of pipeline in operation and 300 MBbls per day of delivery capacity. Saddle Butte has approximately 141,000, net dedicated acres from six customers under fixed fee arrangements.

The transaction closed on January 31, 2018, with Noble Midstream Partners funding $319.9 million of the total cash consideration of $638.5 million. Noble Midstream Partners received a 54.4% equity ownership and Greenfield Midstream will own the remaining 45.6% of Black Diamond Gathering. Noble Midstream Partners will operate the Saddle Butte system.

Marcellus Shale CONE Gathering Divestiture In late 2017 , we announced the signing of a definitive agreement to divest our 50% interest in CONE Gathering, LLC (CONE Gathering). CONE Gathering owns the general partner of CONE Midstream Partners LP (CONE Midstream). As of December 31, 2017, the net book value of the assets held by Noble Energy

was approximately $181 million. In January 2018, we closed the sale of CONE Gathering, receiving cash proceeds of $308 million. We now hold 21.7 million common units representing limited partner interests in CNX Midstream Partners LP (NYSE: CNXM). As of December 31, 2017, the net book value of the limited partner interests was approximately $70 million.

See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger and Item 8. Financial Statements and Supplementary Data – Note 7. Equity Method Investments .

Major Construction Projects Our activity in 2017 primarily focused on construction and development of midstream infrastructure assets, including:

In 2018, we expect to continue our midstream investment to focus on the DJ and Delaware Basins to meet the needs of our upstream operations.

Third Party Sales During 2017, we began providing crude oil and produced water gathering and fresh water delivery services to an unaffiliated third party in the Greeley Crescent IDP area of the DJ Basin.

Proved Reserves Disclosures

Internal Controls Over Reserves Estimates   Our policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the Securities and Exchange Commission (SEC) definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the following:

Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Senior Vice President – Corporate Development and certain other members of senior management.

Our Senior Vice President – Corporate Development oversees our corporate business development, strategic planning, and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 37 years of industry experience with positions of increasing responsibility in engineering, evaluations, and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our Chief Executive Officer.

Technologies Used in Reserves Estimation    The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates, including the material additions to the 2017 reserves estimates.

Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be economically producible.

Third-Party Reserves Audit     In each of the years 2017 , 2016 , and 2015 , we retained NSAI to perform audits of proved reserves. The reserves audit for 2017 included a detailed review of six of our major US onshore and international fields, which covered approximately 92% of US proved reserves and 99% of international proved reserves (95% of total proved reserves). The reserves audit for 2016 included a detailed review of nine of our major US onshore and international fields, which covered approximately 88% of US proved reserves and 99.9% of international proved reserves (92% of total proved reserves). The reserves audit for 2015 included a detailed review of nine of our major fields and covered approximately 91% of total proved reserves.

In connection with the 2017 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserves quantities, future production rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves categorization, using the definitions for proved reserves set forth in Rule 4-10(a) of Regulation S-X and subsequent SEC staff interpretations and guidance.

In the conduct of the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2017 , based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. For proved reserves at December 31, 2017 , on a quantity basis, the NSAI field estimates ranged from 18 MMBoe or 8% below to 9 MMBoe or 2% above as compared with our estimates on a field-by-field basis. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. Reserves differences at December 31, 2017 were, in the aggregate, approximately 17 MMBoe, or less than 1%.

Proved Reserves

We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. Changes in proved reserves were as follows:

		Year Ended December 31,
		2017			2016			2015
(MMBoe)
Proved Reserves Beginning of Year		1,437			1,421			1,404
Revisions of Previous Estimates		135			64			(216	)
Extensions, Discoveries and Other Additions		736			179			100
Purchase of Minerals in Place		57			4			269
Sale of Minerals in Place		(261	)		(77	)		(6	)
Production		(139	)		(154	)		(130	)
Proved Reserves End of Year		1,965			1,437			1,421

Revisions   Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, development costs or abandonment costs. Revisions primarily included the following:

Extensions, Discoveries and Other Additions   These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions primarily included the following:

Approximately 70% of our 2018 capital program is allocated to US onshore, primarily the DJ Basin, Delaware Basin and Eagle Ford Shale, and more than 25% is allocated to offshore Israel. In turn, we expect that future reserves additions will primarily come from our development projects in the US onshore and offshore Israel. Potential new discoveries resulting from our exploration programs in our operational areas as well as global new ventures programs could also lead to future reserve additions. In addition, we may also purchase proved properties in strategic acquisitions. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Acquisition, Capital Expenditures and Other Exploration Expenditures .

Purchase of Minerals in Place   We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. Purchases primarily included the following:

Sale of Minerals in Place    We maintain an ongoing portfolio management program through which we may periodically divest assets. Sales primarily included the following:

See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger .

Production   See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - E&P - Revenues and Critical Accounting Policies and Estimates – Reserves and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) .

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

		United  States			Israel			Total
(MMBoe)
Proved Undeveloped Reserves Beginning of Year		422			64			486
Revisions of Previous Estimates		26			—			26
Extensions, Discoveries and Other Additions		174			551			725
Purchase of Minerals in Place		36			—			36
Sale of Minerals in Place		(54	)		—			(54	)
Conversion to Proved Developed		(122	)		—			(122	)
Proved Undeveloped Reserves End of Year		482			615			1,097

Revisions of previous estimates include the transfer of PUDs to unproved reserve categories as a result of changes in development plans and/or the impact of changes in commodity prices, and the addition of new PUDs arising from current development plans. Positive revisions of 26 MMBoe in the US for 2017 included 7 MMBoe related to positive price revisions and 19 MMBoe related to enhancements of our horizontal drilling programs.

Extensions, discoveries and other additions include the addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields. During 2017 , we recorded the following additions as a result of successful expansion of our long lateral well programs in US onshore and recording of reserves for Leviathan:

Conversion to proved developed reserves included the following transfers:

US PUDs Locations In 2017 , we converted 122 MMBoe of our US PUDs, or 29% of our US PUDs beginning balance, to developed status. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and completion activity, we expect our US PUDs recorded as of December 31, 2017 to be converted to proved developed reserves within five years of initial disclosure.

As of December 31, 2017 , our US PUDs included:

Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required for completion, such as drilled but uncompleted (DUC) wells. As of December 31, 2017 , we had approximately 32 MMBoe of PUDs associated with DUC well locations related to our US onshore operations, approximately 75% of which are in the DJ Basin and the remainder are in the Delaware Basin and Eagle Ford Shale.

International PUDs Locations As of December 31, 2017 , our international PUDs included 615 MMBoe in Israel, of which 551 MMBoe relate to the Leviathan field, which is currently in the first phase of development. The Tamar field contains 35 MMBoe, and the Tamar Southwest field, which is awaiting government approval of the development plan, contains 29 MMBoe. Our Tamar Southwest PUDs of 29 MMBoe, or less than 5% of our international PUDs, are expected to remain undeveloped for five years or longer since initial disclosure in 2013. We have been working with the government of Israel for the approval of the development plan and have continued capital investment within this field, including laying subsea equipment in 2017 for future tie-in of field production into existing Tamar infrastructure. Other than the Tamar Southwest PUDs, we expect all of our international PUDs, including those associated with the initial phase of development at the Leviathan field, to be converted to proved developed reserves within five years of initial disclosure.

Development Costs    Costs incurred   to convert PUDs to proved developed reserves were approximately $1.2 billion in 2017 , $656 million in 2016 , and $1.5 billion in 2015 . Costs incurred in 2017 primarily related to the DJ Basin, Delaware Basin and Eagle Ford Shale development projects, as well as certain costs incurred for the development of the Tamar 8 well. In addition, we incurred approximately $416 million in 2017 to advance the development of the Leviathan PUDs which are expected to be converted to proved developed reserves in 2019.

Estimated future development costs relating to the development of all PUDs are projected to be approximately $1.7 billion in 2018 , $1.9 billion in 2019 , and $1.4 billion in 2020 . Estimated future development costs include capital spending on development projects and PUDs related to development projects will be reclassified to proved developed reserves when production commences.

Drilling Plans    Our long range development plans will result in the conversion of all PUDs to developed reserves within five years of their initial disclosure, with the exception of the previously mentioned Tamar Southwest PUDs. PUDs associated with the Tamar Southwest field are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated in our long range development plans, subject to local government approval. Initial production from all PUDs is expected to begin during the years 2018 to 2022 .

In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and SEC pricing rules. This prescribed calculation can result in some PUDs having negative present worth, meaning while these PUDs have positive cash flows, the rate of return is lower than 10%. As of December 31, 2017 , we had no PUDs with a negative present worth when discounted at 10%.

We consider the economic development of reserves based on our estimates of future pricing, future investments, production and other economic factors that are excluded from the SEC reserves requirements and are committed to developing PUDs within five years of initial disclosure. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2018 Capital Investment Program .

For more information see the following:

Index to Financial Statements

Sales Volumes, Price and Cost Data   Sales volumes, price and cost data are as follows: