Noble Energy 10-K 2012
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
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. x 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 x 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. x 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). x 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. x
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 x No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2011: $15.6 billion.
Number of shares of Common Stock outstanding as of January 13, 2012: 176,958,537.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2012 Annual Meeting of Stockholders to be held on April 24, 2012, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference into Part III.
TABLE OF CONTENTS
In this report, the following abbreviations are used:
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 – Disclosure Regarding Forward-Looking Statements of this Form 10-K.
Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Noble Energy is a Delaware corporation, formed in 1969, that has been publicly traded on the New York Stock Exchange (NYSE) since 1980. 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.
Our aim is to achieve growth in value and cash flow through exploration success and the development of a high-quality, diversified portfolio of assets that is balanced between US and international projects. Exploration success, along with additional 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, such as our entry into a new core area in 2011, the Marcellus Shale, and the Denver-Julesberg (DJ) Basin asset acquisition in 2010, combined with the periodic divestment of non-core assets, have allowed us to achieve our objective of a well-balanced and diversified asset portfolio.
Our portfolio is balanced between short-term and long-term projects, both onshore and offshore. The first of our major development projects, Aseng, offshore Equatorial Guinea, began commercial crude oil production in November 2011, coming online earlier than scheduled and 13% under budget. Onshore US assets provide a stable base of production and accommodate flexible capital spending programs that are responsive to ongoing changes in the economic environment. Our long-term development projects, while requiring multi-year capital investment, are expected to offer attractive financial returns and sustained production. Our portfolio offers a diverse production mix among crude oil, US natural gas, and international natural gas.
We have operations in five core areas:
These areas provide:
Our growth is supported by a strong balance sheet and sufficient liquidity levels. See Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2007-2011.
Major Development Project Inventory >We are moving forward on a number of major development projects, many of which have resulted from our exploration success. Each project will flow through the various development phases including appraisal drilling, front-end engineering and design, infrastructure build-out and exploitation. We currently have projects spanning all phases of the development cycle with some contributing production in 2011 and others with first production targets ranging from 2012 through 2016 and beyond. Although these projects will require significant capital investments over the next several years, they typically offer long-life, sustained cash flows after investment and attractive financial returns. Our major development projects resulting from exploration success and strategic acquisitions include the following:
Additionally, in December 2011, we announced our natural gas discovery well (A-1) in Block 12, offshore Cyprus.
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 estimates at December 31, 2011 were as follows:
Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices>
Estimated reserves at the end of 2011 were approximately 1.2 BBoe, an 11% increase from 2010. US reserves accounted for 47% of the total, and international reserves accounted for 53%. Our 2011 reserves mix is 31% global liquids, 42% international natural gas, and 27% 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 areas of interest. These activities include geophysical and geological evaluation 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 which 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, such as proprietary seismic data and operational expertise, and which we believe generate superior returns. We have had substantial exploration success onshore US and in the deepwater Gulf of Mexico, the Douala Basin offshore West Africa and the Levant Basin offshore Eastern Mediterranean, resulting in a significant portfolio of major development projects. We have numerous exploration opportunities remaining in these areas and are also engaged in new venture activity in the US and international locations.
Appraisal, Development and Exploitation Activities> Our exploration success and strategic acquisitions have provided us with numerous development opportunities, as demonstrated in our growing inventory of major development projects. In 2011, we commenced oil production from Aseng, the first of our major development projects, seven months ahead of the original schedule and 13% under budget. Additionally, we continued to make significant progress on our 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 in order to optimize our asset portfolio.
Entry into Marcellus Shale Joint Venture On September 30, 2011, we entered into an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) to jointly develop oil and gas assets in the Marcellus Shale areas of southwest Pennsylvania and northwest West Virginia. The Marcellus Shale Joint Venture strengthens and rebalances our portfolio, providing a new, material growth area, which we believe will contribute to future reserves, production, and cash flows. This transaction complements and further strengthens our US portfolio by adding a high-quality asset with substantial growth potential close to the US’s largest gas market, the Northeast US. It significantly increases our inventory of low risk, repeatable projects while exposing us to more US unconventional resources. The Marcellus Shale Joint Venture, combined with our other domestic projects in the DJ Basin and the deepwater Gulf of Mexico, provides balance to our rapidly expanding international programs.
Under the terms of the CONSOL agreement, we acquired 50% interests in approximately 628,000 net undeveloped acres, existing Marcellus Shale production and existing infrastructure for approximately $1.3 billion, including post-closing adjustments. Payments will be made in three annual installments, with the first installment made at closing on September 30, 2011. We will pay an additional $2.1 billion in the form of a carry of CONSOL’s drilling and completion costs. The carry, which we expect to extend over approximately eight years or more, is capped at $400 million annually and suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices. Initially, we will be the designated operator of the wet-gas areas (areas with more condensate or liquids) and CONSOL will be the designated operator of the dry-gas areas (areas with little or no condensate or liquids).
As a result of this transaction, we are now focusing on three core areas within the US: the DJ Basin, the Marcellus Shale, and the deepwater Gulf of Mexico. We are also considering the divestiture of certain non-core onshore US properties from our portfolio.
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 and Note 12. Long-Term Debt.
Exit from Ecuador In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. The Ecuadorian government had previously terminated our Block 3 PSC (100% working interest) on November 23, 2010, as we had not negotiated a service contract on Block 3 in accordance with the terms of a newly-enacted hydrocarbon law. The law aimed to change existing production sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010. We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets, onshore gas processing facilities, and Block 3 PSC and the assignment of the Machala Power electricity concession and its associated assets. Our net book value for the assets had been reduced due to previous impairment charges, resulting in a pre-tax gain of $25 million.
DJ Basin Asset Acquisition In March 2010, we acquired substantially all of the US Rocky Mountain oil and gas assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for a total purchase price of $498 million. The acquisition included properties located in the DJ Basin, one of our core operating areas. The acquisition added approximately 46 MMBoe of proved reserves at closing date, and approximately 10 MBoe/d to our daily production base, starting from the closing date, and provides significant growth potential. Included in the purchase were approximately 323,000 total net acres.
Onshore US Sale In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for cash proceeds of $552 million and recorded a gain of $110 million. The sale included approximately 32 MMBoe of proved reserves, at closing date, and approximately 5.7 MBoe/d of production.
Asset Impairments> During 2011, we recorded impairment charges of $759 million mainly related to our non-core onshore US assets. The majority of these impairment charges were triggered by the significant decline, approximately 17% over a five year future period, in natural gas prices in the fourth quarter of 2011. The US natural gas price environment continued to be volatile during 2011 as spot prices declined 32% from $4.41 per MMBtu at December 31, 2010 to $2.99 MMBtu at December 31, 2011. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 54% of our 2011 total consolidated sales volumes and 47% of total proved reserves at December 31, 2011. 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 2011 and productive wells at December 31, 2011 for our US operating areas were as follows:
Locations of our onshore US operations as of December 31, 2011 are shown on the map below:
DJ Basin / Wattenberg One of our core operating areas is the DJ Basin, where we have a significant acreage position of over 860,000 net acres. Included in the DJ Basin is Wattenberg (approximately 96% operated working interest), our largest onshore US asset, where we have a multi-year project inventory. In 2011, we continued to improve our operational performance while accelerating our drilling activities. During 2011 we had record sales volumes from our horizontal drilling program that began in 2010 and targets the Niobrara formation.
During 2011, we drilled a total of 639 successful development wells in historical Wattenberg, of which, 64 were drilled horizontally into the Niobrara formation. In 2011, we began constructing multi-well horizontal drilling pads and centralized production facilities to minimize our surface use and allow for more efficient execution and operations. We are currently evaluating the viability of 80-acre horizontal well spacing and extended reach horizontal lateral wells.
Wattenberg contributed 62 MBoe/d of sales volumes and represented approximately 29% of total consolidated sales volumes in 2011, with approximately 55% being liquids, and approximately 337 MMBoe or 28% of total proved reserves at December 31, 2011. Horizontal drilling in the Niobrara has significantly expanded the economic limits of this field. Of the net sales volumes from Wattenberg, approximately 8 MBoe/d came from a total of 85 producing wells in our horizontal Niobrara program. We also drilled eight horizontal wells in the Niobrara formation in northern Colorado.
Our 2011 Wattenberg drilling program resulted in additions to proved reserves of approximately 67 MMBoe, approximately 63% of which are liquids.
We have also started a horizontal drilling program on additional acreage in southeastern Wyoming and we are evaluating processing and transportation infrastructure needs as well as optimum well completion techniques.
At year-end, we were running eight vertical rigs, five horizontal rigs and 21 completion units in the DJ Basin. We expect to add three to four horizontal rigs and drill approximately 170 horizontal operated and 280 vertical operated wells in the DJ Basin in 2012. Within the next two years, we intend to double our annualized horizontal rig count and well completions.
Marcellus Shale In September of 2011, we entered into a new core operating area, the Marcellus Shale, through a joint venture with CONSOL. During the fourth quarter of 2011, the Marcellus Shale was producing approximately 74 MMcf/d, net to us, compared to net production of 50 MMcf/d at the end of the third quarter of 2011. This represents significant growth at a pace that is faster than we had originally modeled in our acquisition economics. At December 31, 2011, net proved gas reserves were approximately 542 Bcf.
At year-end CONSOL was operating five horizontal rigs and one completion unit on our joint acreage in the Marcellus Shale. In January 2012 we began operating our first horizontal rig in conjunction with the opening of our new field office in Canonsburg, Pennsylvania. CONSOL’s expertise in permitting, local water sourcing, transportation and processing will help facilitate our growth in operations. During the remainder of 2012, we expect to add approximately two horizontal rigs in the wet-gas area of the Marcellus Shale which complements our previous experience in the liquids-rich development in the DJ Basin. We have executed a multi-year development plan with CONSOL that steadily increases the rig count through 2016, and we estimate during 2012 the joint venture will operate six horizontal rigs.
Our joint development plan for 2012 projects that CONSOL will drill approximately 60 horizontal wells in the dry-gas areas of the Marcellus Shale and that we will drill approximately 39 horizontal wells focused in the wet-gas areas of the Marcellus Shale. Our dry-gas program delivers economically attractive returns even in low natural gas price environments due to strong production performance, competitive costs, and access to the US's largest gas market, the Northeast US.
Since the joint venture agreement was finalized on September 30, 2011, CONSOL has drilled a total of 23 successful development wells on our joint acreage. All of these wells were drilled horizontally. The significant portion of acreage that is currently held by production should allow for efficient development utilizing pad drilling. Pad drilling minimizes the permit and infrastructure requirements and surface use.
Hydraulic Fracturing We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs, including the DJ Basin, the Marcellus Shale, and the majority of our other onshore US operating areas. Hydraulic fracturing involves the injection of a mixture, comprised of water, sand and a small amount of chemicals, under pressure into rock formations to stimulate production of natural gas and/or oil from dense subsurface rock formations, including shale. The majority of our onshore US proved undeveloped reserves, which totaled 219 MMBoe at December 31, 2011, will require the use of hydraulic fracturing to produce commercial quantities of crude oil and natural gas. See Hydraulic Fracturing, below, for more discussion.
Other Onshore Properties We operate in the following additional onshore US areas: Rocky Mountains including Piceance Basin (Western Colorado), Iron Horse in the Wind River Basin (Central Wyoming), Bowdoin field (North Central Montana), Tri-State field (Northeastern Colorado, Northwestern Kansas and Southwestern Nebraska), San Juan Basin (Northwestern New Mexico), and Powder River Basin (North/Central Wyoming); Mid-Continent including the Shattuck field (Western Oklahoma), Granite Wash field (Texas Panhandle), and East Mid-Continent (Central Kansas); and Gulf Coast including the Haynesville field (East Texas and North Louisiana) and other properties in Texas and Louisiana. Other onshore properties accounted for 17% of total consolidated sales volumes in 2011 and 8% of total proved reserves at December 31, 2011. Although our future development focus is concentrated on our five core areas, we continue to produce and develop in these other areas. We drilled 168 development wells during 2011 and plan to drill approximately ten development wells during 2012 in these areas. Additionally, we continue to evaluate the divestment opportunities associated with certain non-core properties.
Deepwater Gulf of Mexico Locations of our deepwater Gulf of Mexico developments as of December 31, 2011 are shown on the map below:
The deepwater Gulf of Mexico is one of our core operating areas. Our focus is on high-impact opportunities with the potential to provide significant medium and long-term growth. We have four 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 2011 and 2% of total proved reserves at December 31, 2011. We currently hold leases on 102 deepwater Gulf of Mexico blocks, representing approximately 561,000 gross acres (403,000 net acres). Of our total gross acres, approximately 63,000 gross acres (33,000 net acres) have been developed. We are the operator on approximately 79% of the leases.
Deepwater Gulf of Mexico Exploration Program Our deepwater Gulf of Mexico operations resulted from lease acquisition, expansion of our 3-D seismic database, and an active drilling program. We currently have an inventory of 38 identified prospects, of which 23 are stand-alone, subsalt Miocene targets. The prospects are a combination of both large stand-alone prospects as well as a number of smaller, tie-back opportunities. Prospects in inventory are subject to an ongoing rigorous technical maturation process and may or may not emerge as drillable options. To support the future appraisal work in our exploration inventory, we have contracted an additional drilling rig on a shared basis in 2012 and 2013. We will have two separate four-month slots with the ENSCO 8505, which will share the Gulf of Mexico workload with our currently contracted drilling rig, the ENSCO 8501. Utilizing these drilling rigs, during 2012, we plan to drill approximately four wells, up to two of which we currently anticipate to be at our Gunflint discovery.
In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for BP Exploration & Production Inc., sank after a blowout and fire (Deepwater Horizon Incident). The resulting leak caused a significant oil spill. In May 2010, due to the Deepwater Horizon Incident, the Secretary of the Interior ceased issuing offshore drilling permits pursuant to a series of moratoria and all deepwater drilling activities in progress were suspended (Deepwater Moratorium). When the Deepwater Moratorium was announced, we were required to suspend drilling operations at Deep Blue and Santiago. In April 2011, we announced that we had received the first post-moratorium blowout preventer certification, completion permit and drilling permit to resume drilling at our Santiago exploration well. We also announced in December 2011 that we received a drilling permit to commence appraisal drilling at Gunflint.
Deep Blue During 2011 we resumed drilling efforts at Deep Blue (Green Canyon Block 723; 33.75% operated working interest), which was initially spud in 2009 and suspended due to the Deepwater Moratorium. In November 2011, we announced that we had finished the well and found additional hydrocarbons in high quality reservoirs. During first quarter of 2012, we will be completing additional analysis of the data from the side track well.
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below.
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. In 2009, we approved a phased development plan of the existing discoveries which includes completion of the wells and connection to the nearby Nakika production platform via subsea tieback. In May 2011, after receiving a permit to resume drilling, we announced that we had discovered commercial quantities of crude oil at Santiago, our third discovery at the Galapagos Development project. During the second quarter of 2011, we finished completion activities at Santiago. Installation of topside equipment at the host facility, and subsea tiebacks for Santa Cruz, Isabella, and Santiago are progressing. We currently expect production to commence in the second quarter of 2012.
Raton/South Raton (Mississippi Canyon Blocks 248 and 292) Raton (67% operated working interest) was a 2006 natural gas discovery and has been producing since 2008. South Raton (79% operated working interest) was a 2008 crude oil discovery. Work to tie South Raton back to a non-operated host facility at Viosca Knoll Block 900 is ongoing with initial production scheduled for first quarter 2012.
Gunflint (Mississippi Canyon Block 948; 26% operated working interest) Gunflint is a 2008 crude oil discovery, our largest deepwater Gulf of Mexico discovery to date. During 2011, a unitization agreement covering the Gunflint discovery was finalized. The agreement named us as the operator and added the northern half of Mississippi Canyon blocks 992 and 993 to the project area which already included blocks 904, 948, and 949. Also as part of the agreement, our working interest was revised to 26%. Our plans to drill two or three appraisal wells during 2011 were delayed by impacts of the Deepwater Moratorium. In October 2011, we received a drilling permit and in December 2011 we resumed drilling at Gunflint. Appraisal of Gunflint is necessary to narrow the resource range before final planning and sanctioning of a development project. We currently anticipate drilling up to three appraisal wells to fully evaluate the extent of the reservoir.
We are reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility. We are currently targeting 2016 for production start-up. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest) Swordfish was a 2001 discovery and began producing in 2005. The Swordfish project currently includes two producing wells connected to a third-party production facility through subsea tiebacks.
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 three producing wells connected to existing infrastructure through subsea tiebacks.
Lorien (Green Canyon Block 199; 60% operated working interest) Lorien was a 2003 crude oil discovery and began producing in 2006. The project currently includes one producing well connected to existing infrastructure through subea tiebacks.
Our international business focuses on offshore opportunities in multiple countries and provides balance and diversity to our portfolio. Development projects in Equatorial Guinea, Israel, the North Sea, and China have contributed substantially to our growth over the last decade.
Significant recent 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 have large acreage positions in West Africa, the Eastern Mediterranean, and a number of other locations that provide further exploration opportunities.
International operations accounted for 46% of total consolidated sales volumes in 2011 and 53% of total proved reserves at December 31, 2011. International proved reserves are approximately 80% natural gas and 20% crude oil and condensate. Operations in Equatorial Guinea, Cyprus, China and Senegal/Guinea-Bissau are conducted in accordance with the terms of PSCs. In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Israel, the North Sea, and other foreign locations are conducted in accordance with concession agreements, permits or licenses.
Locations of our international operations are shown on the map below:
Sales volumes and estimates of proved reserves for our international operating areas were as follows:
Wells drilled in 2011 and productive wells at December 31, 2011 in our international operating areas were as follows:
West Africa (Equatorial Guinea, Cameroon and Senegal/Guinea-Bissau) > West Africa is one of our core operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo mining concession and Tilapia PSC offshore Cameroon, as well as the AGC Profond Block offshore Senegal/Guinea-Bissau. Equatorial Guinea accounted for approximately 26% of 2011 total consolidated sales volumes and 20% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 119,000 net developed acres and 137,000 net undeveloped acres in Equatorial Guinea, 563,000 net undeveloped acres in Cameroon, and 729,000 net undeveloped acres in Senegal/Guinea-Bissau.
Locations of our operations in West Africa are shown on the map below:
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 metric tons per day gross. The LPG processing plant and the methanol plant are located on Bioko Island.
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 under the equity method. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest, also accounted for under the equity method. 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.
Significant development planning has occurred for an Alba field compression project, which is a natural progression for the operations of the field. We are evaluating certain features of project implementation and expect to grant final project approval in 2012.
Aseng Project Aseng is a crude oil development project on Block I (38% operated working interest) which includes five horizontal wells flowing to an FPSO (Aseng FPSO) where the production stream is separated. 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. We are the technical operator of the Aseng Project.
The Aseng FPSO is designed to act as an oil production hub, as well as liquids storage and offloading hub, with capabilities to support future subsea oil field developments in the area. It also has the ability to take on board stabilized condensate from gas condensate fields in the area. It is capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjecting 160 MMcf/d of natural gas. Storage is approximately 1.6 MMBbls of liquids.
During 2011, we concluded construction of the Aseng FPSO, which arrived on location in Equatorial Guinea and completed field installation in late 2011. We have executed an oil sale, purchase, and marketing agreement with Glencore Energy UK Ltd. for our share of Aseng production.
First production at Aseng commenced on November 6, 2011 and we completed three liftings totaling over 860 MBbl net in 2011. As of December 31, 2011, we had net oil production of approximately 19 MBbl/d.
Alen Project Alen, located primarily on Block O (45% operated working interest) offshore Equatorial Guinea, is our next West Africa development project. Initial field development will include three production wells and three subsea natural gas injection wells tied to a processing facility. Produced condensate will be separated and piped to the Aseng FPSO where it will be held until sold. Associated natural gas will be reinjected into the reservoir to maintain pressure and maximize liquids recovery. The Alen facilities are designed to process up to 440 MMcf/d of natural gas and 40 MBbl/d of condensate. We are the technical operator of the Alen Project.
During 2011, we began platform fabrication and commenced development drilling. First production at Alen is currently expected to commence by the fourth quarter of 2013 at 20 MBbl/d, net. Natural gas reinjection is estimated to be 390 MMcf/d during gas-recycling. The total gross development cost is estimated at $1.6 billion.
Other Block O & I Projects During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios. Additionally, in late 2011, we drilled the Carla well, a successful oil appraisal well in Block O, offshore Equatorial Guinea. We are evaluating drilling results from our Diega and Carla discovery wells, and reviewing development options and formulating a development plan for these areas.
West Africa Gas Project The Equatorial Guinea Ministry of Mines, Industry and Energy (MMIE) is considering the development of an integrated gas project (Integrated Project) which includes upstream gas projects, the required gas transportation system, and a second LNG train. Noble Energy, as Chair of the Integrated Project committee, is working with the MMIE and other Integrated Project stakeholders to determine the Integrated Project scope and schedule.
Cameroon We have an interest in over one million gross acres offshore Cameroon, which include the YoYo mining concession and Tilapia PSC. We are the operator (50% working interest) in Cameroon. Natural gas and condensate were discovered in 2007 when we drilled the YoYo -1 exploratory well. During 2011, the 3-D seismic data acquired in 2003 and 2010 over the YoYo and Tilapia blocks was reprocessed for further interpretation. Additionally, during 2011 we drilled an exploration well testing the Bwabe prospect in the Tilapia Block, offshore Cameroon, reached total depth during late 2011 and did not find commercial quantities of hydrocarbons. We are currently evaluating several prospects as a follow-up for our offshore Cameroon exploration program.
Senegal/Guinea-Bissau During 2011, we farmed into the AGC Profond block (30% non-operated working interest), which covers more than two million gross acres and includes a number of identified prospects. The joint venture drilled the Kora-1 exploration well during 2011. The well did not result in commercial quantities of hydrocarbons; however, there are a number of prospects in the area. We are working with our partners on future exploration plans and have the option to become the operator going forward.
Eastern Mediterranean (Israel and Cyprus>) Another core operating area is located in the Eastern Mediterranean. Israel accounted for 14% of 2011 total consolidated sales volumes and 31% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 80,000 net developed acres and 652,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. Our leasehold position in Israel includes four leases and 15 licenses, and we are the operator of the properties. We also hold a license covering approximately 596,000 net undeveloped acres offshore Cyprus adjacent to our Israel acreage.
Locations of our operations in the Eastern Mediterranean are shown below:
Mari-B Field The Mari-B field (47% operated working interest) was the first offshore natural gas production facility in Israel. Natural gas is delivered to a permanent onshore receiving terminal at Ashdod for distribution to purchasers. Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Our share of sales volumes rose from 48 MMcf/d in 2004 to 173 MMcf/d in 2011. In total, we have delivered over 319 Bcf of natural gas, net, to Israeli customers through December 31, 2011.
During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes delivered at very high rates to support Israel’s growing gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B to prudently manage the reservoir and preserve its deliverability for the peak demand months during the summer of 2012.
We are currently working closely with our Israeli customers to manage demand and operating the field so that it will produce until production commences at the Tamar field, which we expect to occur during the second quarter of 2013. At that time, we plan to transition the Mari-B reservoir to a natural gas storage facility. As a result of the accelerated depletion resulting from the high demand experienced as a result of Egyptian supply interruptions, we do not believe that the Mari-B field, alone, will be able to produce enough volumes to meet anticipated Israeli demand until production begins at Tamar. We are in the process of developing the Noa project and studying potential development of the Pinnacles project, both discussed below, to support near-term deliverability into the Israeli market. See also Delivery Commitments, below.
The Mari-B facility was designed to accommodate a certain amount of reservoir subsidence as the field depleted. As we near the end of the field’s producing life, the rate of subsidence could change, thereby increasing the risk of mechanical failure of individual wells and potentially decreasing the deliverability of the Mari-B field. See Item 1A. Risk Factors Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues.
Noa Project We are in the process of developing the Noa reserves (47% operated working interest) to support near-term deliverability to Israeli customers. The Noa project allows us to continue producing through the Mari-B platform at high rates, bringing another source of natural gas through our existing Mari-B facilities before Tamar begins producing. Two development wells have been drilled, engineering and design have been completed, and installation and fabrication are progressing on schedule. First production at Noa is expected in the third quarter of 2012.
Pinnacles Project We are also studying the potential development of Pinnacles, located near the Mari-B field, to help meet the Israeli natural gas demands. If partner approval is obtained and development occurs as expected, Pinnacles will begin producing in the third quarter of 2012.
Tamar Project We discovered the Tamar natural gas field (36% operated working interest) offshore Israel in the Levant Basin in 2009. Tamar is one of the world’s largest offshore conventional gas discoveries in recent years. In 2010, we sanctioned the development plan for Tamar and submitted the plan to the Israeli government for approval.
The initial phase of Tamar development will include five subsea wells. The natural gas produced at these wells will flow to a new offshore platform to be constructed near the existing Mari-B platform. The natural gas will then be delivered to an existing pipeline that connects the Mari-B field to the Ashdod onshore terminal. The development will allow for significant expansion as the Israeli natural gas market grows. We commenced field development drilling, platform jacket and deck fabrication, pipeline installation and onshore facility expansion during 2011, with first production expected by second quarter of 2013. The total first phase development cost of Tamar is estimated at $3.0 billion ($1.1 billion net).
The Israeli natural gas market continues to grow, and the Tamar partners are in the final stages of sales contract negotiations with the Israel Electric Corporation Limited (IEC) and are in active discussions with existing and new customers to sell natural gas from the Tamar field. See International Marketing Activities and Delivery Commitments below.
We are considering the implementation of a floating LNG (FLNG) project at Tamar and have begun conducting preliminary engineering design work. The economic viability of such a large project is dependent on the ability to export natural gas to the international market. We are working with the Israeli government to obtain support for the project.
Leviathan Project In December 2010, we announced a significant natural gas discovery at the Leviathan prospect (40% operated working interest) in the Levant Basin offshore Israel. The Leviathan field is the largest discovery in our history and was the world’s largest offshore natural gas discovery in 2010.
In early 2011, we drilled the Leviathan-2 appraisal well, which encountered wellbore issues resulting in our abandoning the well. The incident was a covered event under our well control insurance; therefore, we expect to recover most of the costs from insurance, subject to a deductible.
We resumed the natural gas appraisal drilling program in mid-2011 with the successful Leviathan-3 appraisal well. In January 2012, we resumed drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests, which have a low chance of success, are expected during the first half of 2012.
We have project and commercial teams in place and are in the process of considering our commercialization options for Leviathan. Due to the size of the field, economic viability depends on the ability to export via pipeline or LNG. Engineering design and planning work are currently underway for a potential first phase of development; however, we have not yet sanctioned a development project.
Although we will be able to incorporate our knowledge gained on the Aseng and Tamar projects to Leviathan, such a complex, costly project is not without financial or execution risk. See item 1A. Risk Factors – The magnitude of our offshore Eastern Mediterranean discoveries will present financial and technical challenges for us due to the large-scale development requirements.
Dalit Dalit (36% operated working interest) was our second 2009 natural gas discovery in the Levant Basin. We are currently working with our partners on a cost-effective development plan.
Dolphin 1 During the fourth quarter of 2011, we completed drilling the successful Dolphin 1 (39.66% operated working interest) exploration well in the Hanna license, southwest of the Tamar gas field and are evaluating results.
Cyprus During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. The well encountered approximately 310 feet of net natural gas pay in multiple high-quality Miocene sand intervals.
In 1974 the island of Cyprus was partitioned into two parts: the Republic of Cyprus with the majority of the south under its effective control, and the Turkish-controlled area in the north, which calls itself the Turkish Republic of Northern Cyprus. The United Nations recognizes the sovereignty of the Republic of Cyprus over the entire island. The Republic of Cyprus has been a member of the European Union since May 1, 2004. The Turkish government opposes the current exploratory activities being conducted by the Republic of Cyprus, claiming such activities will have a detrimental effect on reunification negotiations, and that any development projects should be deferred until the dispute over the political status of the island is resolved. While Turkey has voiced its opposition to the drilling operations, the European Union, Russia and the US have supported Cyprus' right to drill and our activities.
Other Exploration Activities
Tanin 1 During the fourth quarter of 2011, we spud the Tanin 1 (47.06% operated working interest) well in the Alon A block, offshore Israel. In February 2012, we announced a natural gas discovery at Tanin.
Israel During 2011, we completed the 3-D seismic survey that was started in 2010 for the Ruth, Ratio, and Alon licenses, offshore Israel.
Cyprus During 2011, we acquired approximately 1,544 square miles of 2-D seismic per our PSC work program.
See Item 1A. Risk Factors – Our international operations may be adversely affected by economic and political developments and Our operations may be adversely affected by civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.
North Sea We have been conducting business in the North Sea (the Netherlands and the United Kingdom (UK)) since 1996 and currently have interests in 14 licenses on 15 blocks with working interests ranging from 7% to 40%. We are the operator of one block.
Most of our production is from the Dumbarton and Lochranza fields (30% non-operated working interest) in blocks 15/20a and 15/20b in the UK sector of the North Sea. We also have production from the MacCulloch, Hanze, Cook and other fields.
The Dumbarton development, which began production in 2007, includes a subsea tie-back to the GP III, an FPSO (GP III FPSO) in which we own a 30% interest. Dumbarton has eight horizontal producing wells and two water injection wells. Two additional producing wells from the nearby Lochranza discovery are tied back to the Dumbarton facilities. During 2011, we began drilling a third Lochranza well and expect production to the Dumbarton facilities in early 2012.
We also participate in the Selkirk (30.5% non-operated working interest) project, located in the UK sector of the North Sea. We are currently working with our partners on development options.
The North Sea accounted for 4% of 2011 total consolidated sales volumes and 1% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 6,360 net developed acres and 29,130 net undeveloped acres. At December 31, 2011, we were running one horizontal rig and expect to drill one horizontal development well during 2012 at our Lochranza field.
China We have been engaged in exploration and development activities in China since 1996 under the terms of a 30-year PSC. We have a 57% non-operated working interest in the Cheng Dao Xi (CDX) field, which is located in the shallow water of the southern Bohai Bay. During 2011, we completed the commissioning of the newly installed B platform and commenced engineering and design of a third platform (C platform). In addition, we drilled and completed six development wells, five of which were production wells and one water injection well. The drilling results in 2011 gave us additional confidence going forward on the western side of the block.
China accounted for 2% of 2011 total consolidated sales volumes and 1% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 4,000 net developed acres and no undeveloped acres.
Other International Properties At December 31, 2011, we held undeveloped acreage offshore in other international locations including Nicaragua, India and France. During 2011, we acquired 3-D seismic for Nicaragua.
Proved Reserves Disclosures
Implementation of the Securities and Exchange Commission’s (SEC) Revisions to Oil and Gas Disclosures> Effective December 31, 2009, we implemented the SEC’s final rules related to the modernization of oil and gas reporting (SEC’s reserves rules). Although the SEC’s reserves rules allow probable and possible reserves to be disclosed separately, we have elected not to disclose probable and possible reserves in this report. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for a description of the most significant revisions to oil and gas reporting 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 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 Vice President – Strategic Planning, Environmental Analysis & Reserves (Vice President – Reserves) and certain members of senior management.
Our Vice President – Reserves is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Vice President – Reserves has a Bachelor of Science degree in Engineering and over 25 years of industry experience with positions of increasing responsibility in engineering and evaluations. The Vice President – Reserves reports directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation >The SEC’s reserves rules expanded the technologies that a company can use to establish reserves. The SEC now allows 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 2011 reserves estimates.
Third-Party Reserves Audit> In each of the years 2011, 2010, and 2009, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2011 included a detailed review of 14 of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 80% of US proved reserves and 98% of international proved reserves (90% of total proved reserves). The reserves audit for 2010 included a detailed review of 13 of our major fields and covered approximately 88% of total proved reserves. The reserves audit for 2009 included a detailed review of 20 of our major fields and covered approximately 86% of total proved reserves.
In connection with the 2011 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, 2011, 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 Vice President – Reserves 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 selection process results in the audit of each field representing more than 1% of total proved reserves. As a result, for each of the years 2009 – 2011, our ten largest fields at the current time were audited. The Aseng field was first audited in 2009, the Tamar and Alen fields were first audited in 2010 and the Marcellus Shale field was first audited in 2011, as no reserves had been recorded in prior years.
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, 2011, on a quantity basis, the NSAI field estimates ranged from 17 MMBoe or 19% above to 14 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, 2011 were, in the aggregate, approximately 18 MMBoe, or 2%.
Proved Undeveloped Reserves (PUDs) > As of December 31, 2011, our PUDs totaled 162 MMBbls of crude oil, condensate and NGLs and 3,257 Bcf of natural gas, for a total of 705 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, 2011:
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 $1.4 billion in 2011 (including $66 million non-cash costs related to an increase in our Aseng FPSO lease obligation), $1.1 billion in 2010 (including $266 million non-cash costs related to an increase in our Aseng FPSO lease obligation), and $440 million in 2009 (including $29 million non-cash costs related to an increase in our Aseng FPSO lease obligation). A significant portion of costs incurred in 2011 related to our major development projects horizontal Niobrara, Aseng, Marcellus Shale, Alen, Tamar and Galapagos, which will be converted to proved developed reserves in future years.
Estimated future development costs relating to the development of PUDs are projected to be approximately $2.4 billion in 2012, $1.3 billion in 2013, and $1.0 billion in 2014. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans All PUDs drilling locations are scheduled to be drilled prior to the end of 2016. PUDs associated with projects other than drilling (such as compression projects) are also expected to be converted to proved developed reserves prior to the end of 2016. Initial production from these PUDs is expected to begin during the years 2012 - 2016.
For more information see the following:
Other Reserves Information Since January 1, 2011, 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:
Average crude oil sales prices reflect a reduction of $5.57 per Bbl (2009) from hedging activities. This price reduction resulted from hedge losses that were previously deferred in accumulated other comprehensive loss (AOCL). All hedge losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.
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, 2011, our operated properties accounted for approximately 67% 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, 2011 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, 2011 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:
During 2011, the US Bureau of Safety and Environmental Enforcement (BSEE) granted one year extensions to the original terms of 26 of our deepwater Gulf of Mexico leases. To be eligible for an extension, each lease had to meet the following three criteria: no oil and gas production on the lease as of May 15, 2011, the lease includes water depths in excess of 500 feet, and the lease is scheduled to expire on or before December 31, 2015. The extensions were granted to allow more time to drill on offshore leases following the Deepwater Moratorium.
Drilling Activity >The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows: