Noble Energy 10-K 2014
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
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)
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
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):
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, 2013: $21.5 billion.
Number of shares of Common Stock outstanding as of December 31, 2013: 359,905,771.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2014 Annual Meeting of Stockholders to be held on April 22, 2014, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, are incorporated by reference into Part III.
TABLE OF CONTENTS
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.
Noble Energy, Inc. (Noble Energy, the Company, we or us) is a leading independent energy company engaged in worldwide oil and gas 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 and natural gas exploration and production while embracing our responsibility 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 natural gas liquids (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 substantial 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 2013, we spent over $3 billion in oil and gas exploration and development activities in the US, and approximately $1 billion in international locations.
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 the pursuit of material exploration opportunities which can be monetized on a competitive discovery-to-production cycle through effective major development project execution. During 2013, two major offshore development projects, Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, began production. Our ability to deliver major development projects on schedule and within budget has provided a competitive and financial advantage in the industry.
Onshore US assets provide a stable base of production along with high return, low risk development programs that deliver growth and accommodate flexible capital spending 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.
Our growth is supported by a strong balance sheet and liquidity levels. We strive to deliver competitive returns and a growing dividend. Our annual cash dividends have increased 67% in the last five years, from 33 cents per share in 2008 to 55 cents per share in 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 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 2009-2013.
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 2013. 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:
These projects are discussed in more detail in the sections below. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Major Development Project Inventory.
Proved Oil and Gas Reserves Proved reserves at December 31, 2013 were as follows:
Summary of 2013 Oil and Gas Reserves as of Fiscal-Year End
Based on Average 2013 Fiscal-Year Prices
Total proved reserves as of December 31, 2013 were approximately 1,406 MMBoe, a 19% increase from 2012. Our proved reserves are 55% US and 45% international. The proved reserves mix is 31% global liquids (crude oil and NGLs), 38% international natural gas, and 31% 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, and 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 numerous 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 2013, we advanced our exploration activities in the following new venture areas: onshore US in northeast Nevada, offshore Falkland Islands, offshore Nicaragua, and offshore Sierra Leone.
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 growing inventory of major development projects. In 2013, we commenced natural gas production from the Tamar field, offshore Israel, followed by the start up of Alen, a natural gas and condensate field, offshore Equatorial Guinea. Additionally, 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.
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 high-value and high-growth areas. The program has generated combined net proceeds of approximately $1.4 billion during the last two years, including $206 million during 2013. 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 2013, we sold onshore US crude oil and natural gas properties located in Kansas, Oklahoma, the Gulf Coast, New Mexico and Wyoming, and non-operated working interests in the North Sea.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources and Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Divestitures.
Asset Impairments During 2013, we recorded impairment charges of $86 million primarily related to our Mari-B field, offshore Israel, due to natural field decline, and certain non-core onshore US properties divested during the year or held for sale at December 31, 2013. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
We have been engaged in crude oil and natural gas exploration and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 58% of 2013 total consolidated sales volumes and 55% of total proved reserves at December 31, 2013. Approximately 57% of the proved reserves are natural gas and 43% are crude oil, condensate and NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows:
Wells drilled in 2013 and productive wells at December 31, 2013 for our US operating areas were as follows:
Locations of our onshore US operations as of December 31, 2013 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. It is our largest onshore US field (approximately 730,000 net acres), split between approximately 609,000 net acres in Colorado (approximately 96% operated working interest) and approximately 121,000 net acres in Wyoming (the majority non-operated). We have an extensive inventory of development drilling opportunities and plan to invest approximately 40% of our 2014 capital investment program in the DJ Basin.
The DJ Basin contributed an average of 95 MBoe/d of sales volumes, representing approximately 36% of total consolidated sales volumes in 2013, with approximately 63% being crude oil and NGLs, and represented approximately 32% of total proved reserves at December 31, 2013.
DJ Basin Acreage Exchange In October 2013, we closed an acreage exchange agreement with another operator related to our position in the DJ Basin. We exchanged approximately 50,000 net acres which consolidates our acreage position providing the opportunity to optimize drilling, production, and gathering activities and increase the number of extended-reach lateral wells in our development program. A short-term reduction in production of approximately 8 MBoe/d for fourth quarter 2013 related to the acreage exchange is anticipated to be quickly offset with operational efficiencies and cost savings. The transaction was accounted for at net book value, with no gain or loss recognized. We received $105 million in cash related to reimbursement of capital expenditures and other normal closing adjustments from the effective date of January 1, 2013, to closing date. See Item 8. Financial Statements and Supplementary Data – Note 3. Property Transactions.
2013 Activity Over the past year, we have focused our drilling and development activity on Integrated Development Plan (IDP) areas. This approach allows us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 60,000 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 and operations by reducing our land surface and water usage while enabling us to efficiently gather and process crude oil, natural gas, and water from a large surrounding area, and reducing truck traffic and our overall surface footprint. We sanctioned the Wells Ranch IDP in 2012, and brought online our first CPF at Wells Ranch during the fourth quarter of 2013. In 2013, we sanctioned the East Pony IDP in northern Colorado and expect to sanction additional IDPs over the next several years. In the second half of 2014, we will begin operation of the Keota plant, our second natural gas processing plant in northern Colorado, to support our East Pony IDP along with future IDPs in the area. This will enhance our ability to continue development in this part of the Basin.
Also during 2013, we spud a total of 295 development wells, of which 291 were horizontal wells in the Niobrara and Codell formations. We continue to evaluate impacts of changes in well spacing and pad design. The well numbers above include 34 extended-reach (over 5,000 feet) lateral wells. We also participated in approximately 170 non-operated development wells during 2013.
In conjunction with our IDP approach, infrastructure in the area continues to be built out. Several infrastructure projects will come online over the next year and will significantly improve our flow assurance and reduce truck traffic. In the fourth quarter of 2013, a new crude oil gathering pipeline began operations. The new pipeline allows us to move crude oil from the northern parts of the field to several oil processing facilities and transportation hubs, with additional access to end markets. Additionally, a new rail facility commenced operations during the fourth quarter of 2013 to further enhance the transportation of our crude oil out of the field.
Our 2013 DJ Basin development program resulted in additions to proved reserves of approximately 153 MMBoe, approximately 67% 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, including approximately 90,000 gross acres recently acquired to expand our acreage position in northwest West Virginia to further optimize the value of our existing acreage position. We operate the wet gas (natural gas containing more liquid hydrocarbons) development area while CONSOL operates the dry gas (natural gas containing less liquid hydrocarbons) development area.
The Marcellus Shale contributed an average of 139 MMcfe/d of sales volumes and represented approximately 9% of total consolidated sales volumes in 2013 and approximately 18% of total proved reserves at December 31, 2013.
During 2013, we and CONSOL drilled 71 wet gas wells and 46 dry gas wells and brought online 35 wet gas wells and 18 dry gas wells.
Utilizing an IDP concept, modeled after the DJ Basin, we have begun to realize cost efficiencies through longer lateral wells and increased production growth through applied learning, completion design and optimized well placement. The current identified IDP areas are Majorsville, Southwest Pennsylvania Area Dry, and Allegheny County Airport.
Majorsville is the first operated IDP area, which came online in 2013 and will be the IDP model for the Marcellus Shale. It is in the core operating area with water and marketing infrastructure in place to support further development.
Based on our 2014 joint development plan, we expect to invest approximately 20% of our 2014 capital investment program in the Marcellus Shale.
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. Based on acquired 3D seismic data over portions of the acreage, we began our exploratory drilling program with two exploratory wells drilled in 2013. We are currently evaluating the drilling results.
Other Non-Core Onshore Properties We also operate in the following onshore US areas: Rocky Mountains including Piceance Basin (western Colorado), Bowdoin field (north central Montana), Tri-State field (northeastern Colorado, northwestern Kansas and southwestern Nebraska) and Powder River Basin (north/central Wyoming); and Gulf Coast including the Haynesville field (East Texas and North Louisiana), Comanche Plains field (West Texas). Other non-core onshore properties accounted for 6% of total consolidated sales volumes in 2013 and 3% of total proved reserves at December 31, 2013. During 2013, we sold various non-core onshore properties and continue to evaluate the divestment opportunities associated with other non-core properties. See Acquisition and Divestiture Activities – Non-Core Divestiture Program above.
Deepwater Gulf of Mexico Locations of our operations in the deepwater Gulf of Mexico as of December 31, 2013 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 six producing fields, multiple ongoing development projects and a substantial inventory of exploration opportunities.
The deepwater Gulf of Mexico accounted for 7% of total consolidated sales volumes in 2013 and 2% of total proved reserves at December 31, 2013.
We currently hold leases on 121 deepwater Gulf of Mexico blocks, representing approximately 52,000 net developed acres and approximately 409,000 net undeveloped acres. We are the operator on approximately 68% of our leases. See also Developed and Undeveloped Acreage – Future Acreage Expirations, below. During 2013, we sanctioned two major development projects in the deepwater Gulf of Mexico, Gunflint and Big Bend. See details below.
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 20 identified prospects, which are a combination of both high impact subsalt prospects and smaller, high value tie-back opportunities. The prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options. To support the future exploration, appraisal, and development work, we have the ENSCO 8501 rig under contract through the third quarter of 2014. The Atwood Advantage drillship is currently mobilizing to the Gulf of Mexico. It will be used in the 2014 drilling plan which includes various exploration, appraisal and well completion activities.
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below.
Rio Grande (Mississippi Canyon Block 698, 699, 738 and 782) The Rio Grande area is a co-development opportunity for recent 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. In October 2013, we sanctioned the development plan for Big Bend utilizing a subsea
tieback to a third party host facility, with first production targeted for late 2015. We are currently evaluating possible integration of the Dantzler, potentially a 2014 sanctioned project, and Troubadour discoveries into our Rio Grande development plans.
Gunflint (Mississippi Canyon Block 948; 26% operated working interest) Gunflint is a 2008 crude oil discovery. During 2013, we completed drilling our second appraisal well and sanctioned the development plan for Gunflint utilizing a subsea tieback to an existing host facility. First production from Gunflint is targeted for 2016.
Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest), Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest) and Santiago (Mississippi Canyon Block 519; 23.25% operated working interest) The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. The Galapagos development began producing in 2012 and is connected to existing infrastructure through subsea tiebacks.
Other Offshore Properties
Raton (Mississippi Canyon Block 248; 67% operated working interest) is a 2006 natural gas discovery and has been producing since 2008. South Raton (Mississippi Canyon Block 292; 79% operated working interest) is a 2008 crude oil discovery and began producing in 2012. Both Raton and South Raton are currently shut-in due to mechanical issues. We are currently awaiting access to the third party processing platform to begin remediation efforts on the South Raton well.
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 recently acquired the Neptune Spar, a floating offshore production platform, which will 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, including one drilled in 2013.
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.
Other offshore properties are connected to existing infrastructure through subsea tiebacks.
Our international business focuses on offshore opportunities in a number of countries and provides diversity to our portfolio. Development projects in Equatorial Guinea and Israel have contributed substantially to our growth over the last decade.
During 2013, we successfully brought the Tamar project, offshore Israel, and Alen project, offshore Equatorial Guinea, to production as we continue to advance our major development projects. Additionally, significant exploration successes offshore West Africa, Israel and Cyprus have identified multiple major development projects that are expected to contribute to production growth in the future. We expect these large acreage positions in West Africa and the Eastern Mediterranean will provide further exploration opportunities.
International operations accounted for 42% of total consolidated sales volumes in 2013 and 45% of total proved reserves at December 31, 2013. International proved reserves are approximately 84% natural gas and 16% crude oil and condensate. Based on our current 2014 capital investment program, we expect to invest approximately 20% of our 2014 capital investment program in international locations.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of production sharing contracts (PSCs). In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Israel, Nicaragua, the Falkland Islands, the North Sea, 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, 2013 are shown on the map below:
Sales volumes and estimates of proved reserves for our international operating areas were as follows:
Wells drilled in 2013 and productive wells at December 31, 2013 in our international operating areas were as follows:
West Africa (Equatorial Guinea, Cameroon and Sierra Leone) West Africa is one of our core operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, as well as the YoYo mining concession and Tilapia PSC, offshore Cameroon, and two blocks offshore Sierra Leone. Equatorial Guinea, the only producing country in our West Africa segment, accounted for approximately 28% of 2013 total consolidated sales volumes and 15% of total proved reserves at December 31, 2013. We held approximately 118,000 net developed acres and 80,000 net undeveloped acres in Equatorial Guinea, 695,000 net undeveloped acres in Cameroon, and 414,000 net undeveloped acres in Sierra Leone at December 31, 2013.
Locations of our operations in West Africa as of December 31, 2013 are shown on the map below:
Alen Project Alen, our second major operated development project in West Africa, is a natural gas and condensate field primarily on Block O (45% operated working interest), offshore Equatorial Guinea. Alen began production in the second half of 2013, ahead of the original target start up date, and utilizes the Aseng FPSO for storage and offloading. Alen exited 2013 with production of 28 MBbl/d, and peak production of 30 to 35 MBbl/d is expected in 2014.
Aseng Project Aseng is a crude oil field on Block I (40% operated working interest), offshore Equatorial Guinea, which includes five horizontal wells flowing to the Aseng FPSO. Aseng started production in late 2011. The oil is stored on the Aseng FPSO until sold, while the natural gas and water are reinjected into the reservoir to maintain pressure and maximize oil recoveries.
The Aseng FPSO is designed to act as an 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. It is capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjection of up to 160 MMcf/d of natural gas. The Aseng FPSO has storage capacity of approximately 1.6 MMBbls of liquids. During 2013, Aseng maintained reliable and safe performance and averaged almost 99% production uptime.
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.
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. 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 with an anticipated completion date in 2016.
Other Block O & I Projects We are continuing our exploration and appraisal efforts offshore Equatorial Guinea. During the second half of 2013, we successfully drilled the Diega I-8 appraisal well, and we are targeting to sanction a development project in 2014, with first production targeted for 2016.
We continue to review the drilling results of the Carla O-7 and the Carla I-7 wells and evaluate regional development scenarios for the Carla discovery.
West Africa Gas Project We have a natural gas development team working with Equatorial Guinea's Ministry of Mines, Industry and Energy to evaluate several monetization options for natural gas in the region.
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.
Sierra Leone We participate in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million gross undeveloped acres. Under the terms of the award, Chevron (SL) Ltd. is the operator and we have a non-operated 30% working interest. During 2013, we acquired and began processing 766 square miles of 2D seismic information over portions of the acreage to assist with our 3D seismic plans.
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. We plan to explore for additional natural gas prospects as well as for crude oil, which may exist at greater depths in the basin.
Israel, the only producing country in our Eastern Mediterranean core area, accounted for 13% of 2013 total consolidated sales volumes and 30% of total proved reserves at December 31, 2013. Our leasehold position in the Eastern Mediterranean includes four leases and seven licenses offshore Israel and one license offshore Cyprus, and we are the operator of the properties at December 31, 2013. We held approximately 80,000 net developed acres and 326,000 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 596,000 net undeveloped acres adjacent to our Israel acreage.
Locations of our operations in the Eastern Mediterranean as of December 31, 2013 are shown below:
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 as a fuel in the future.
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, and, as discussed further below, we are considering multiple development options. The government of Israel recently finalized an export policy. See Regulations – Update on Israel's Natural Gas Policy, below.
Tamar Natural Gas Project Just over four years from discovery, the Tamar project began production in March 2013 and is now fully operational and delivering significant volumes of natural gas to Israel. 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 Ashdod onshore terminal (AOT). Tamar is a technical and commercial milestone that significantly contributes to our production growth. Production from Tamar averaged 153 MMcf/d, net, for the year with capable peak flow rates of approximately 1.0 Bcf/d gross to support seasonal high demand periods.
During 2013, we sanctioned the Tamar expansion project, which is estimated to grow our AOT capacity by 200 MMcf/d with operational start-up in the second half of 2015. Additionally, we are targeting the Tamar facility for further expansion up to 1.5 Bcf/d of capacity in 2016.
The Tamar partners have executed numerous gas sale and purchase agreements (GSPAs) for the initial and expanded capacity. See International Marketing Activities and Delivery Commitments, below.
Tamar Southwest During the second half of 2013, we drilled the successful Tamar Southwest natural gas exploratory well. Tamar Southwest, which was drilled to a total depth of 17,420 feet in 5,405 feet of water, is our eighth consecutive discovery in the Levant Basin. The field is located approximately eight miles southwest of the Tamar field. We operate Tamar Southwest with a 36% working interest, and we anticipate first production in 2015 utilizing Tamar infrastructure as part of our expansion project to meet domestic demand. Tamar Southwest will also provide flow rate assurance for our overall Tamar project.
Leviathan Natural Gas Project In December 2010, we announced a significant natural gas discovery at the Leviathan-1 well offshore Israel in the Levant Basin. The Leviathan field is the largest discovery in our history and was the world's largest offshore natural gas discovery in 2010. We own a 39.66% working interest in Leviathan. In 2013, the successful results from our recent Leviathan-4 appraisal well enhanced our understanding of the reservoir, and we continue our evaluation of multiple development concepts. Due to Leviathan's size, full field development is expected to require several development phases.
The Leviathan Phase 1 development concept is likely to serve both domestic demand and export. Domestic production could begin as early as 2017. We and our Leviathan partners recently signed a GSPA to sell approximately 170 Bcf of natural gas over a 20-year period to the Palestine Power Generation Company (PPGC). PPGC plans to build a power plant in the West Bank.
Multiple export options, including pipeline, onshore LNG, and floating LNG are under evaluation. Timing of project sanction depends on execution of natural gas sales contracts, determination of an onshore entry point and government approvals.
Woodside Agreement We and our Leviathan partners continue working with Woodside Energy Ltd. (Woodside) to reach a definitive agreement to sell portions of our working interests in the Leviathan licenses to Woodside. Such an agreement would be subject to customary government approvals. Noble expects to convey a 9.66% working interest, reducing our working interest in the Leviathan licenses to 30%. Noble would continue as upstream operator.
Cyprus During the second half of 2013, we drilled the successful Cyprus A-2 appraisal well on Block 12, offshore Cyprus. The A-2 well was drilled to a total depth of 18,865 feet in 5,575 feet of water and encountered approximately 120 feet of net natural gas pay within the targeted Miocene-aged sand intervals. We anticipate additional appraisal activities to further refine the ultimate recoverable resources and optimize field development planning. In addition to the appraisal well, we completed the acquisition phase of a 3D seismic study and are currently processing the results. We are the operator on Block 12 and hold a 70% working interest.
Leviathan-1 Deep (Mesozoic Oil Target) In January 2012, we returned to the Leviathan-1 well and began drilling toward two deeper intervals in order to evaluate them for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high pressures and the mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned objective, we are encouraged by the possibility of an active thermogenic (crude oil generating) hydrocarbon system at greater depths within the basin. We have integrated the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically for a potential test of the deep oil concept.
Mari-B, Pinnacles and Noa Fields The Mari-B field (47% operated working interest) was the first offshore natural gas production facility in Israel and has been producing since 2004. In order to help meet Israeli natural gas demand prior to the commencement of Tamar production, we completed the Noa (47% operated working interest) and Pinnacles (47% operated working interest) wells and tied them back to the Mari-B platform in 2012. During 2013, we ramped down production from these fields when Tamar commenced production.
Other Discoveries Offshore Israel We and our partners are working on a development plan for the Dalit field (36% operated working interest), a 2009 natural gas discovery. Development would include tie-in to the Tamar platform, and we have submitted a development plan to the Israeli government. In addition, we are reviewing alternatives for the development of the Karish (47.06% operated working interest), Dolphin (39.66% operated working interest) and Tanin 1 (47.06% operated working interest) natural gas discoveries. See Regulations – Update on Israel's Natural Gas Economy.
Our other international operations accounted for 1% of our total consolidated sales volumes for 2013 and less than 1% of total proved reserves at December 31, 2013.
Falkland Islands In August 2012, we entered into an agreement with Falkland Oil and Gas Limited (FOGL) to acquire an interest in FOGL's extensive license areas, consisting of approximately 10 million gross acres located south and east of the Falkland Islands. Under the agreement, we have farmed-in to the Northern and Southern Area Licenses for a 35% working interest.
In March 2013, we assumed operatorship of the Northern Area License from FOGL. In January 2014, we assumed operatorship of the Southern Area License, pending governmental approval. We continue to process recently acquired 3D seismic information for the Southern Area License and began acquisition of 3D seismic information for the Northern Area License in late 2013. The construction of our shore base facility is ongoing in preparation for our first operated exploratory well which we expect to drill in 2015.
During fourth quarter 2012, FOGL drilled the Scotia exploratory well, which reached its Cretaceous objective and encountered 40 feet of net pay. Although we did not see a substantial amount of the reservoir section, virtually all sandstones with significant porosity in and below the target area contained hydrocarbons. Integration of well results with the 3D seismic information we are acquiring will allow us to assess the economic viability of this prospect.
Nicaragua During the second half of 2013, we transferred a portion of our working interests in acreage offshore Nicaragua, pending government approval, to two new partners, reducing our working interest to 70%. Additionally, we drilled the Paraiso-1 exploratory well, the first deepwater well drilled offshore Nicaragua. The Paraiso-1 did not encounter commercial quantities of hydrocarbons. However, the information gathered from this well will be integrated into our regional geologic model to help us assess the remaining exploration potential over our nearly two million gross acre position offshore Nicaragua.
China We have been engaged in exploration and development activities in China since 1996 under the terms of a PSC, expiring in 2018. We have a 57% non-operated working interest in the Cheng Dao Xi field, which is located in the shallow water of the southern Bohai Bay.
We are currently negotiating for the sale of our China properties and expect the transaction to close during the first half of 2014. As of December 31, 2013, our China properties are included in assets held for sale in our consolidated balance sheet.
North Sea During 2013, we sold substantially all of the non-operated working interest properties located in the UK and Netherlands sectors of the North Sea. On a combined basis, the sales resulted in a $65 million gain based on net sales proceeds of $56 million for the fields, and we continue to market our remaining North Sea properties. The North Sea's fourth quarter production was 600 Boe/d.
As of December 31, 2013, all the properties remaining in our North Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued.
See Item 8. Financial Statements and Supplementary Financial Data – Note 3. Property Transactions.
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:
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 members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, new ventures, strategic planning, environmental analysis and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 33 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 2013 reserves estimates.
Third-Party Reserves Audit In each of the years 2013, 2012, and 2011, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2013 included a detailed review of nine of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 74% of US proved reserves and 98% of international proved reserves (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. The reserves audit for 2011 included a detailed review of 14 of our major fields and covered approximately 90% of total proved reserves.
In connection with the 2013 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, oil and 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, 2013, 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, 2013, on a quantity basis, the NSAI field estimates ranged from 21 MMBoe or 8% above to 15 MMBoe or 5% 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, 2013 were, in the aggregate, approximately 9 MMBoe, or 1%.
Proved Undeveloped Reserves (PUDs) As of December 31, 2013, our PUDs totaled 206 MMBbls of crude oil, condensate and NGLs and 2.1 Tcf of natural gas, for a total of 557 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, 2013:
The above fields represent 99% of total PUDs. The remaining 1% is associated with ongoing developments in various areas scheduled to be drilled in the next five years. 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:
Development Costs Costs incurred to advance the development of PUDs were approximately $1.0 billion in 2013, $1.8 billion in 2012, and $1.4 billion in 2011. A significant portion of costs incurred in 2013 related to the following development projects: horizontal Niobrara; Marcellus Shale; Alen; and Tamar, which were converted to proved developed reserves in 2013.
Estimated future development costs relating to the development of PUDs are projected to be approximately $3.2 billion in 2014, $2.1 billion in 2015, and $1.2 billion in 2016. 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 2018. PUDs associated with our Alba compression project are also expected to be converted to proved developed reserves prior to the end of 2018. Initial production from these PUDs is expected to begin during the years 2014 - 2018.
For more information see the following:
Other Reserves Information Since January 1, 2013, 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.
Sales Volumes, Price and Cost Data Sales volumes, price and cost data are as follows:
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, 2013, 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, 2013 was as follows:
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, 2013 was as follows:
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.
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.
Drilling Activity The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows: