Noble Energy (NBL)

 

·

Galapagos (deepwater Gulf of Mexico);

·

Aseng (offshore West Africa);

·

Tamar (offshore Israel);

·

Gunflint (deepwater Gulf of Mexico);

·

Belinda (offshore West Africa); and

·

Diega/Carmen (offshore West Africa).

 

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.

 

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Proved Oil and Gas Reserves    >Proved reserves estimates at December 31, 2009 were as follows:

 

Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices
		December 31, 2009
		Proved Reserves
		Crude Oil, Condensate & NGLs				Natural Gas				Total (1)
Reserves Category		(MMBbls)				(Bcf)				(MMBoe)
Proved Developed
United States			122				1,114				307
Equatorial Guinea			49				638				155
Israel			-				191				32
Other International			23				192				56
Total Proved Developed Reserves			194				2,135				550
Proved Undeveloped
United States			87				420				157
Equatorial Guinea			43				302				93
Israel			-				43				7
Other International			12				4				13
Total Proved Undeveloped Reserves			142				769				270
Total Proved Reserves			336				2,904				820

 

(1) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.

 

In December 2008, the Securities and Exchange Commission (SEC) announced that it had approved revisions to modernize its oil and gas company reserves reporting requirements. We adopted the new rules as of December 31, 2009.  See Proved Reserves Disclosures, below, for additional disclosures provided in accordance with the SEC’s rules for Modernization of Oil and Gas Reporting and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for definitions of proved oil and gas reserves, proved developed oil and gas reserves and proved undeveloped oil and gas reserves.

Crude Oil and Natural Gas Properties and Activities

 

We search for crude oil and natural gas properties, seek to acquire exploration rights in areas of interest and conduct exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which we have acquired exploration rights. 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 advantage and which we believe offer superior returns. We have had substantial exploration success in the deepwater Gulf of Mexico, West Africa and the Eastern Mediterranean resulting in a significant portfolio of major development projects. We have a numerous exploration opportunities remaining in these areas and are engaged in new venture activity in other international locations as well.

 

Appraisal, Development and Exploitation Activities>   We assess our exploration successes for potential development as demonstrated in our growing inventory of major projects.  In 2009, we sanctioned the Isabela and Aseng projects and are progressing toward sanctioning the Tamar, Belinda and Gunflint projects during 2010 and/or 2011.We support a significant portion of the capital needs of these major projects with our long-lived inventory of low-risk development and exploitation projects.  Low-risk development and exploitation projects, such as the Wattenberg field in our North America operations, also provide diversification and balance to our worldwide portfolio.

 

Acquisition and Divestiture Activities>     We maintain an ongoing portfolio optimization 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 divest non-core assets in order to optimize our property portfolio.

 

Pending Asset Acquisition In January 2010, we announced that we have entered into a definitive agreement to acquire substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for $494 million. We estimate total proved reserves to be 53 MMBoe, 45% of which are liquids and 80% are within the liquid-rich Wattenberg field, where our largest onshore US asset is located. The acquisition will add approximately 10 MBoepd, or 46 MMcf of natural gas and 2.5 MBbls of liquids to our daily production base, starting from the closing date, for 2010 and will provide significant growth potential. Included in the purchase are 340,000 total net acres, nearly 200,000 of which are located in the Greater Denver-Julesberg (DJ) Basin. The acquisition is expected to close late in the first quarter 2010 and is subject to customary closing conditions. See United States - Northern Region discussion below.

 

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Mid-continent Acquisition   In 2008, we acquired producing properties in western Oklahoma for $292 million. Properties acquired cover approximately 15,500 net acres. The total purchase price was allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.

 

Sale of Argentina Assets   In 2008, we closed on the sale of our producing property interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. The $24 million gain on sale was deferred until 2009 when approval was obtained from the Argentine government. Our crude oil reserves for Argentina totaled 7 MMBbls at December 31, 2007.

 

Sale of Gulf of Mexico Shelf Properties  In 2006, we sold all of our significant Gulf of Mexico shelf properties except for the Main Pass area, which required repairs related to hurricane damage at the time. As of the effective date of the sale, proved reserves for the Gulf of Mexico properties sold totaled approximately 7 MMBbls of crude oil and 110 Bcf of natural gas. The deepwater Gulf of Mexico remains a core area and is more aligned with our long-term business strategies.

 

U.S. Exploration Acquisition   In 2006, we acquired U.S. Exploration, a privately held corporation, for $412 million plus liabilities assumed. U.S. Exploration’s reserves and production were located primarily in Colorado’s Wattenberg field. This acquisition significantly expanded our operations in one of our core areas. Proved reserves of U.S. Exploration at the time of acquisition were approximately 234 Bcfe, of which 38% were proved developed and 55% natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were valued at $131 million. In addition, we recorded $34 million of goodwill. 

 

Patina Merger  In 2005, we acquired Patina through merger (Patina Merger) for a total purchase price of $4.9 billion. Patina’s long-lived crude oil and natural gas reserves provided a significant inventory of low-risk opportunities that balanced our portfolio. Patina’s proved reserves at the time of acquisition were estimated to be approximately 1.6 Tcfe, of which 72% were proved developed and 67% natural gas. Proved crude oil and natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. In addition, we recorded $875 million of goodwill.

 

United States

 

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. The Patina Merger and the acquisition of U.S. Exploration significantly increased the breadth of our onshore operations, especially in the Rocky Mountains and Mid-continent areas. These two acquisitions, along with other acquisitions of producing and non-producing properties, have provided us with a multi-year inventory of exploitation and development opportunities. We expect to close on a purchase of additional US Rocky Mountain assets in first quarter 2010, which will further increase our operations and project inventory in this area. In 2009, we were awarded 22 new leases in the deepwater Gulf of Mexico.

 

US operations accounted for 56% of our 2009 consolidated sales volumes and 56% of total proved reserves at December 31, 2009. Approximately 55% of the proved reserves are natural gas and 45% are crude oil, condensate and NGLs. Our onshore US portfolio at December 31, 2009 included 956,000 net developed acres and 1.3 million net undeveloped acres. We currently hold interests in 103 offshore blocks in the Gulf of Mexico.

 

Sales of production and estimates of proved reserves for our significant US operating areas were as follows:

 

		Year Ended December 31, 2009												December 31, 2009
		Sales Volumes												Proved Reserves
		Crude Oil & Condensate			Natural Gas			NGLs			Total			Crude Oil, Condensate & NGLs			Natural Gas			Total
		(MBpd)			(MMcfpd)			(MBpd)			(MBoepd)			(MMBbls)			(Bcf)			(MMBoe)
Northern Region
Wattenberg Field			15			150			6			46			129			819			266
Mid-continent Area			7			66			1			19			34			279			80
Other			-			95			-			16			1			290			49
Total			22			311			7			81			164			1,388			395
Southern Region
Deepwater Gulf of Mexico			10			49			3			21			26			47			34
Other			5			37			-			11			19			98			35
Total			15			86			3			32			45			145			69
Total United States			37			397			10			113			209			1,533			464

 

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Wells drilled in 2009 and productive wells at December 31, 2009 for our significant US operating areas were as follows:

 

		Year Ended December 31, 2009			December 31, 2009
		Gross Wells Drilled or Participated in			Gross Productive Wells
Northern Region
Wattenberg Field			424			6,285
Mid-Continent Area			31			3,920
Other			145			2,648
Total			600			12,853
Southern Region
Deepwater Gulf of Mexico			2			11
Other			32			1,180
Total			34			1,191
Total United States			634			14,044

 

 

Locations of our US onshore operations in the Wattenberg field, Mid-continent area and other significant areas are shown on the map below:

 

 

Northern Region >The Northern region consists of our operations in the Rocky Mountain area, which includes the DJ (Wattenberg field), Piceance, San Juan, and Wind River basins, as well as the Niobrara (Tri-State) and Bowdoin fields. The Rocky Mountain area is one of our core operating assets. The Northern region also includes the Mid-continent area, consisting of properties in the Texas Panhandle, Oklahoma and Kansas.

 

Wattenberg Field   The Wattenberg field (approximately 96% operated working interest), located in the DJ basin of north central Colorado, is our largest onshore US field and continues to grow. We acquired working interests in the Wattenberg field through the Patina Merger in 2005 and acquisition of U.S. Exploration in 2006. The Wattenberg field held 57% of our US proved reserves at December 31, 2009.

 

One of the most attractive features of the field is the presence of multiple productive formations, which include the Codell, Niobrara, and J-Sand formations, as well as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman formations. Drilling in the Wattenberg field is considered lower risk from the perspective of finding crude oil and natural gas reserves.

 

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Our current field activities are focused primarily on the improved recovery of reserves through drilling new wells or deepening within existing wellbores, recompleting the Codell formation within existing J-Sand wells, refracturing or trifracturing existing Codell wells and refracturing or recompleting the Niobrara formation within existing Codell wells. A refracture consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. A trifracture is effectively a refracture of a refracture. These projects and continued success with our production enhancement program, which includes well workovers, reactivations, and commingling of zones, allow us to increase production and add proved reserves to what is considered a mature field.

 

Due to economic conditions, our 2009 program decreased from 2008 levels. In 2009, we drilled or participated in 424 gross Wattenberg field development wells, with a 100% success rate. Three of these wells were horizontal wells targeting the Niobrara formation. We added approximately 36 MMBoe of proved reserves, approximately 49% of which were natural gas.  At year-end, we were running five drilling rigs and 17 completion units in the field.

 

We have experienced significant growth in production from the Wattenberg field, from an average of 33 MBoepd at year-end 2005 to approximately 45 MBoepd for fourth quarter 2009. Expansion of field boundaries has resulted in a large increase in our crude oil and NGL stream since year-end 2005. As a result, year-end 2009 production included approximately 20 MBpd of liquids. Sales of Wattenberg field production accounted for 41% of total US sales volumes in 2009.

 

The infrastructure in this area is improving and expanding. Oil transport alternatives improved in 2009 with the start up of a new interstate crude oil transportation pipeline system running from Weld County, Colorado, where the Wattenberg field is located, to Cushing, Oklahoma. The pipeline, in which we own a small equity interest, provides another option for the marketing of our crude oil. We have a five-year throughput agreement with the pipeline.

 

We continue to acquire acreage in the area and held interests in approximately 350,000 net acres at year-end 2009. We are planning an active capital program in 2010 and expect to increase the program from 2009 levels, drilling approximately 500 wells, with continued focus on new wells in the Codell/Niobrara formations. We will have the flexibility with short-term drilling rig contracts to decrease activity if economic conditions decline. Additionally, we have a substantial project inventory remaining and plan to continue steady refracture, trifracture, and recompletion programs in 2010.

 

As discussed under Acquisition and Divestiture Activities – Pending Asset Acquisition above, we expect to close on an acquisition of additional US Rocky Mountain assets late in the first quarter 2010. We have identified several thousand projects associated with the assets being acquired, including over 2,000 Codell/Niobrara drilling locations in Wattenberg. We plan to add two rigs to our Wattenberg program in 2010 as a result of the transaction. We expect this activity to grow net production, with a focus on increasing liquids contribution.

 

Mid-continent Area   The Mid-continent area includes properties in the Texas Panhandle, Oklahoma and Kansas. Significant areas of activity have been in the Cleveland Sandstone area of western Oklahoma (89% operated working interest). We drilled or participated in 31 development wells in 2009, 97% of which were successful.

 

In 2009, we continued drilling in the Cleveland Sandstone formation in western Oklahoma, on acreage we acquired in 2008. Cleveland Sandstone is a tight gas play characterized by low-permeability rock. We drilled 20 wells (included in the count above) using horizontal drilling techniques, all of which were successful, and recent wells have come on line with greater than 40% liquids production. We currently have one rig operating and expect to drill approximately the same number of wells in 2010 as we drilled in 2009.

 

Other Northern Region   Other Northern region areas of activity are as follows:

 

Piceance Basin – The Piceance basin in western Colorado (approximately 89% operated working interest) is a major North America natural gas basin and is characterized by low-porosity rock. The primary productive formation is the Mesaverde Williams Fork formation.  Multiple wells are drilled from individual drilling pads to reduce rig mobilization costs in mountainous terrain and to minimize environmental impact on the surface area.  Well spacing is approximately ten acres per well.

 

As in the Wattenberg field, Piceance basin drilling time per well has been reduced due to our increased use of improved drilling technology. In the Piceance basin, we are using new fit-for-purpose rigs which include design innovations and technology improvements that capture incremental time savings during all phases of the well drilling process, including moving between wells. Fit-for-purpose rigs can drill multiple wells from one location and are particularly useful in developing hydrocarbon reserves in tight-gas areas such as the Piceance basin.

 

In 2009, we drilled or participated in 48 development wells and one exploratory well, 100% of which were successful. Successful drilling activity in recent years has led to significant volume growth; production has grown from 2 MMcfepd in 2005 to 54 MMcfepd for fourth quarter 2009.

 

We have assembled a significant acreage position in the Piceance basin and currently hold interests in approximately 20,000 net acres providing a large inventory of future projects. At this time, we plan to operate a single-rig drilling program in 2010.

 

Tri-State Area (Niobrara) – Our operations in the Tri-State area (eastern Colorado, extending into Kansas and Nebraska) center primarily around the development of the Niobrara Trend (approximately 96% operated working interest). The Niobrara formation is an important shallow natural gas producer. Since 2006, we have expanded our acreage position to over 580,000 net acres.  We have a substantial future project inventory, including Niobrara infill and exploitation drilling along with gathering system and compressor station additions to develop reserves and deliver new production.  In 2009, we drilled or participated in 64 development wells, 100% of which were successful, and we plan to continue our Niobrara drilling program in 2010.

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Wind River Basin –  At Iron Horse in the Wind River Basin (88% operated working interest) located in central Wyoming, we drilled 18 development wells during 2009 with a 94% success rate.  We plan to continue our drilling program here during 2010 and expect to drill approximately 20 new wells.

 

Bowdoin and San Juan – We are also active in the Bowdoin field (approximately 63% operated working interest), located in north central Montana and the San Juan basin (approximately 82% operated working interest), located in northwestern New Mexico and southwestern Colorado. In 2009, activity was reduced in these areas as we focused most of our capital spending on the core development fields of Wattenberg, Piceance and western Oklahoma. We drilled or participated in a total of 13 development wells in the Bowdoin field and San Juan basin, 100% of which were successful, and one unsuccessful exploratory well.

 

Southern Region> The Southern region includes the deepwater Gulf of Mexico and onshore areas primarily in Texas and Louisiana.

 

Deepwater Gulf of Mexico   The deepwater Gulf of Mexico is one of our core areas and accounted for 19% of 2009 US sales volumes and 7% of US proved reserves at December 31, 2009. We currently hold leases on 103 deepwater Gulf of Mexico blocks, representing approximately 390,000 net acres. We operate approximately 86% of the leases. Locations of our deepwater Gulf of Mexico developments are shown on the map below:

 

 

 

 

We continue to expand our deepwater Gulf of Mexico operations primarily through an active exploration program, expansion of our 3-D seismic database, and lease acquisition. Our exploration activities have led to discoveries at Gunflint, a 2008 discovery which is our largest deepwater Gulf of Mexico discovery to date; Isabela; Redrock/Raton; and, most recently, Santa Cruz.

 

During 2009, we moved forward with development plans for some of our recent discoveries, as discussed below, and continued our exploratory program. We participated in Central Gulf of Mexico Lease Sale 208 and were awarded 22 new deepwater Gulf of Mexico blocks which will complement our growing inventory of exploration opportunities. We currently have an inventory of over 30 identified prospects, with a combination of both large stand-alone prospects as well as a number of smaller, tie-back opportunities.

 

Our exploration efforts continued during December 2009 as drilling began on two significant test wells at the Deep Blue prospect (Green Canyon Block 723; 33.75% operated working interest) and one at the Double Mountain prospect (Green Canyon Block 556; 30% non-operated working interest).

 

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Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below:

 

Gunflint (Mississippi Canyon Block 948; 37.5% operated working interest and Mississippi Canyon Block 949; 43.75% operated working interest)   We announced the Gunflint crude oil discovery, our largest deepwater Gulf of Mexico discovery to date, in October 2008. We have acquired additional seismic information and are preparing to drill one or two appraisal wells in 2010. We are the operator of the development.

 

Galapagos Development Project including Isabela (Mississippi Canyon Block 562, 33% non-operated working interest) and Santa Cruz (Mississippi Canyon Blocks 519/563, 23.25% operated working interest)  During third quarter 2009, we approved the Galapagos development project, which consists of our 2007 discovery, Isabela, and our 2009 discovery on adjacent acreage, Santa Cruz. The phased development plan includes completion of the Isabela and Santa Cruz wells during second and third quarter 2010, and then connecting them to nearby infrastructure via subsea tiebacks.   Initial production is expected in 2011.  During the first half of 2010, we also plan to drill the Santiago exploration well (23.25% operated working interest) which is a separate prospect in the same offshore block as Santa Cruz.  If the Santiago well is successful, it will be completed in 2010, with production expected in 2011.

 

Redrock/Raton (Mississippi Canyon Blocks 204, 248 and 292; 66.67 % working interest)   Redrock was a 2006 natural gas/condensate discovery and Raton was a 2006 natural gas discovery. The South Raton appraisal well was also drilled in 2006.  In 2007, we successfully sidetracked and completed the Raton discovery well and it was tied back and came on production in late 2008. In 2008, we drilled a successful sidetrack-appraisal well at South Raton and we currently expect it to be tied back to a host facility. Redrock is currently considered a co-development candidate to the completed sidetrack well at South Raton. We are the operator of Redrock/Raton.

 

Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% working interest)   Swordfish was a 2001 discovery and began producing in 2005. During 2009, a Swordfish gas well watered out. We sidetracked the well into an oil zone, and production began in January, 2010. The Swordfish project currently includes three producing wells connected to a third-party production facility through subea tiebacks. We are the operator of Swordfish.

 

Ticonderoga (Green Canyon block 768; 50% working interest)   Ticonderoga is a non-operated 2004 crude oil discovery and began producing in 2006. The project currently includes three producing wells connected to existing infrastructure through subea tiebacks. In September 2008, Ticonderoga was shut-in as a result of hurricane damage to third-party processing and pipeline facilities. It remained shut-in until August 2009 when it was returned to full production.

 

Onshore East Texas and North Louisiana   This is an emerging area for us. Recent acquisitions have increased our leasehold acreage to approximately 17,000 gross acres. Our 2009 drilling program targeted the Haynesville shale (approximately 60% working interest), and we completed our first horizontal East Texas Haynesville shale well with an initial thirty-day average production rate of over 11 MMcfpd, gross. We drilled a second exploration well in fourth quarter 2009 that was completed in late January 2010 and is being tested. We plan to drill approximately 10 to 11 Haynesville wells on our operated acreage in 2010 and participate in another seven to eight Haynesville wells operated by others.

 

International

 

International operations are significant to our business, accounting for 44% of consolidated sales volumes in 2009 and 44% of total proved reserves at December 31, 2009. International proved reserves are approximately 64% natural gas and 36% crude oil. Operations in Equatorial Guinea, Ecuador, China and Suriname are conducted in accordance with the terms of production sharing contracts. In Cameroon, we operate in accordance with the terms of a production sharing contract and a mining concession. Operations in the North Sea, Israel and other foreign locations are conducted in accordance with concession agreements or licenses.

 

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Sales of production and estimates of proved reserves for our significant international operating areas are as follows:

 

		Year Ended December 31, 2009																December 31, 2009
		Sales Volumes																Proved Reserves
		Crude Oil & Condensate				Natural Gas				NGL's				Total				Crude Oil, Condensate & NGLs				Natural Gas				Total
		(MBpd)				(MMcfpd)				(MBpd)				(MBoepd)				(MMBbls)				(Bcf)				(MMBoe)
International
Equatorial Guinea			14				239				-				54				92				940				248
Israel			-				114				-				19				-				234				39
Other			11				31				-				16				35				196				69
Total International			25				384				-				89				127				1,370				356
Equity Investee			2				-				6				8				-				-				-
Total			27				384				6				97				127				1,370				356
Equity Investee Share of Methanol Sales (MMgal)															145

 

 

Wells drilled in 2009 and productive wells at December 31, 2009 in our international operating areas were as follows:

 

		Year Ended December 31, 2009			December 31, 2009
		Gross Wells Drilled or Participated in			Gross Productive Wells
International
Equatorial Guinea			1			24
Israel			3			5
North Sea			6			30
Ecuador			-			3
China			1			16
Total International			11			78

 

Locations of our major international operations are shown on the map below:

 

West Africa (Equatorial Guinea and Cameroon) >  West Africa is one of our core operating areas. Crude oil and natural gas sales volumes accounted for 61% of 2009 consolidated international sales volumes and 70% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 53,000 net developed acres and 212,000 net undeveloped acres in Equatorial Guinea and 563,000 net undeveloped acres in Cameroon.

 

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Alba Field   We began investing in West Africa in the early 1990’s. Activities center around our 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, which is one of our most significant assets. Operations include the Alba field and related production and condensate facilities, a methanol plant, and an onshore LPG processing plant (both located on Bioko Island) where additional condensate is produced. The methanol plant is capable of producing up to 3,000 MTpd gross.

 

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 by the equity method. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest accounted for by the equity method. The methanol plant purchases natural gas from the Alba field under a contract that runs through 2026. AMPCO subsequently markets the produced methanol 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 and from the LPG plant under short-term contracts at market-based prices.

 

Blocks O and I, YoYo and Tilapia    During the past several years, we have conducted a successful exploration and appraisal drilling program in the Douala basin in West Africa, centering around Blocks O and I, offshore Equatorial Guinea, and the YoYo mining concession and Tilapia production sharing contract offshore Cameroon, where we have an interest in over 1.1 million gross acres. We are the operator in Cameroon (50% working interest) and the technical operator on Block O (45% working interest) and Block I (40% working interest).

 

Our first discovery occurred in October 2005, when we announced successful test results from the O-1 (Belinda) exploration well offshore Equatorial Guinea. In 2007, we drilled seven wells, resulting in three new discoveries and three successful appraisal wells. In 2008, we announced successful results from the I-5 Benita oil appraisal well on Block I; the Felicita, a condensate and natural gas discovery on Block O; and the Diega, a gas condensate and oil discovery on Block I.  In February 2009, we announced a successful oil discovery on Block O at the Carmen prospect.

 

In December 2008, we submitted a Plan of Development for the Aseng field (formerly known as Benita) to the government of Equatorial Guinea. On July 22, 2009, we announced that it had been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  

 

Initial development of the Aseng field will include multiple subsea wells flowing to a floating production, storage and offloading vessel (FPSO) where the production stream will be separated.  The oil will be stored on the FPSO until sold, while the natural gas and water will be reinjected into the reservoir to maintain pressure and maximize oil recoveries. The FPSO is designed with capacity to process 120 MBpd of liquids, including 80 MBpd of oil. In addition, the vessel will be capable of reinjecting 170 MMcfpd of natural gas. Storage on the vessel will be approximately 1.6 MMBbls of liquids. The vessel is designed to act as an oil production hub, and as a liquids storage and offloading hub with capabilities to support future subsea oil field developments, and capabilities to take on board, independently from the production train, stabilized condensate from gas condensate fields in the area. First production from the Aseng field is estimated to commence by mid-year 2012 at 50 MBpd of oil gross (16.5 MBpd net). The FPSO and subsea equipment contracts were awarded in 2009, and construction activities have begun on the FPSO. We have two rigs contracted to assist in field development. Drilling and completion activities have commenced. 

 

We have evaluated the potential for additional liquids and gas projects, and expect that the next development will be at the Belinda field. We are engaged in geologic and reservoir FEED (front end engineering design) work at Belinda, targeting liquid production from this gas condensate field.  We currently anticipate drilling subsea wells which will be tied to a production facility that would remove liquids and reinject gas for future use pending further development at Belinda.  The liquids would be transported to the FPSO at Aseng for storage and sales.  Belinda project sanction is currently scheduled to occur in 2010 with production beginning in 2013. We are also evaluating future oil projects at Diega and Carmen and currently scheduling first production for 2014.

 

In 2010, we expect to resume exploration activities offshore Equatorial Guinea and acquire a 3-D seismic survey over YoYo and portions of Tilapia in Cameroon.

 

Eastern Mediterranean (Israel and Cyprus>)   Another core operating area is located offshore Israel. Natural gas sales volumes in Israel accounted for 21% of 2009 consolidated international sales volumes and natural gas reserves accounted for 11% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 29,000 net developed acres and 796,000 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 17 licenses.  We are the operator of the properties. We also hold a license covering approximately 795,000 net undeveloped acres offshore Cyprus.

 

Mari-B Field    We have been operating in the Mediterranean Sea, offshore Israel, since 1998, and the Mari-B field (47% working interest) is one of our core international assets. The Mari-B field is the first offshore natural gas production facility in Israel and currently has a peak deliverability of approximately 500 MMcfpd from five wells. In 2008, we commissioned a permanent onshore receiving terminal in Ashdod for distribution of natural gas from the Mari-B field to purchasers. During 2009, we moved forward on a compression project that we expect will recover additional reserves and extend the field’s peak deliverability. We also began mobilizing equipment to drill two development wells planned in the first half of 2010. Together with the completion of the compression work, these new wells will provide substantial, additional near-term gas deliverability and serve as injection wells for natural gas storage in the future.

 

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Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Average sales volumes have risen from 48 MMcfpd in 2004 to a record high of 139 MMcfpd in 2008 and were 114 MMcfpd in 2009. The natural gas market in Israel continues to be robust. The Israel Electric Corporation Limited (IEC), our largest purchaser, has continued to convert power plants to use natural gas as fuel. In 2009, the IEC power plant at Hagit began consuming natural gas purchased from us and in December 2009 we initiated natural gas sales to a new customer, Israel Chemicals Ltd.

 

During third quarter 2009, we signed a new natural gas sales contract with our primary customer, IEC, under the terms of which they will purchase the majority of our remaining undedicated Mari-B field gas at prices expected to be significantly higher than what we have been receiving under the original contract. The actual price received is tied to a blend of liquids prices and a producer price index.  In addition, it was agreed that all sales from the Mari-B field going forward will be proportionately allocated between the two contracts regardless of the total volume sold.  This is a major change from the past arrangement wherein only “excess” volumes above a threshold level received premium prices. In addition, we have signed a letter of intent (LOI) with IEC, under which IEC expects to purchase natural gas to establish a strategic inventory reserve at Mari-B. The Mari-B partners would provide IEC with injection, storage and withdrawal capabilities for this inventory under a related service agreement.

 

Competing imports of natural gas from Egypt to Israel began in 2008. However, there is still opportunity for significant new sales in the future as the Israeli infrastructure and markets continue to expand.

 

Tamar and Dalit   During 2009, our exploratory program resulted in two significant discoveries. In January 2009, we announced a very significant natural gas discovery at the Tamar-1 well at the Tamar prospect (36% working interest), offshore northern Israel, and in February 2009, we announced a successful test of production flow rates at the location. Then in March 2009, we announced another natural gas discovery at the Dalit prospect (36% working interest) followed by a successful well test in April 2009.

 

We then drilled a Tamar appraisal well (Tamar-2), the results of which increased our estimate of the size of the reservoir and confirmed its high quality and extent. Tamar is the largest discovery in our history.

 

We are moving forward with Tamar development plans, and expect project sanction and recording of proved reserves in the first half of 2010, with first production projected for 2012.  

 

In fourth quarter 2009, we signed an LOI to sell natural gas from the Tamar field to Dalia Power Energies (Dalia). Dalia, a privately-owned electricity company, has a license to build a natural gas-fired power plant in Israel with operations planned to commence in 2013. According to terms of the LOI, we and our partners will deliver natural gas volumes of approximately 200 Bcf to Dalia under a 17-year supply agreement. Sales volumes under the LOI may be increased to 700 Bcf depending upon the final size of the power plant and extent of operations. We also signed an LOI to sell natural gas from the Tamar field to IEC. IEC expects to purchase at least 95 Bcf of natural gas per year with the potential to procure significantly higher quantities for a period of 15 years beginning at the startup of Tamar.

 

We continue to remain focused on the vast exploration potential remaining offshore Israel. The successes at Tamar and Dalit opened up a substantial new natural gas basin, the Levantine.  A 3-D seismic program is underway to collect additional data over several leads on our acreage in the Levantine. Based on results from the seismic program, we are planning to drill an exploratory well in the area in the second half of 2010.

 

Other

 

North Sea   We have been conducting business in the North Sea (the Netherlands and the UK) since 1996 and currently have working interests in 18 licenses with working interests ranging from 7% to 40%. We are the operator of one block.  The North Sea accounted for 8% of 2009 consolidated international sales volumes and 7% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 6,000 net developed acres and 44,000 net undeveloped acres.

 

Most of our production is from the non-operated Dumbarton field (30% working interest) in blocks 15/20a and 15/20b in the UK sector of the North Sea. We also produce 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 in which we own a 30% interest. Additional development (30% working interest) began in 2008, and two new wells were brought on line.  During 2009, our field optimization work continued.  Dumbarton now has eight horizontal producers and two water injection wells.

 

The Dumbarton field experienced a controlled shut-down in August 2009, due to a malfunctioning swivel on the FPSO. Production was deferred for essentially all of September and October.

 

We also participated in the development of the nearby Lochranza discovery in block 15/20a (30% working interest). During 2009, the first Lochranza horizontal well was completed and tied back to Dumbarton’s subsea facilities. Production began in fourth quarter 2009.  We expect a second horizontal well to be completed and come on line in the first quarter of 2010.

 

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We have also participated in the Flyndre project (22.5% working interest) and Selkirk project (30.5% working interest), both located in the UK sector of the North Sea. At Flyndre, we successfully completed an exploratory appraisal well in 2007.  We are currently working with the project operator and other partners to finalize the field development plan and relevant operating agreements. At Selkirk, we participated in the drilling of an appraisal well which was sidetracked to the original discovery well location, to ensure presence of effective reservoir, and suspended as a future producer. We are currently working with our partners on development options.

 

In 2009, we conducted a market test of our wholly-owned subsidiary Noble Energy (Europe) Limited, which holds our interests in the Netherlands and the UK, and received bids. However, we have not committed to a plan to sell these assets.

 

Ecuador   Operations in Ecuador accounted for 5% of 2009 consolidated international sales volumes and 8% of international proved reserves at December 31, 2009. The concession covers approximately 12,000 net developed acres and 849,000 net undeveloped acres.

 

We have been operating in Ecuador since 1996. We utilize natural gas from the Amistad field (in shallow water offshore Ecuador) to generate electricity through a 100%-owned natural gas-fired power plant, located near the city of Machala. The Machala power plant, which began operating in 2002, is a single cycle generator with a capacity of 130 MW from twin turbines. It is the only natural gas-fired commercial power generator in Ecuador and currently one of the lowest cost producers of thermal power in the country. The Machala power plant connects to the Amistad field via a 40-mile pipeline. In 2009, power generation totaled 902 GW hours.

 

See Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country's unsettled economic and political environment and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Conditions in Ecuador.

 

China     We have been engaged in exploration and development activities in China since 1996, with production beginning in 2003. We have a 57% working interest in the Cheng Dao Xi (CDX) field, which is located in the shallow water of the southern Bohai Bay. During fourth quarter 2009, we drilled one horizontal well from our existing platform at the CDX field and commenced drilling a second well.  The rig will initiate a program to pre-drill a number of production and injection wells designed to be connected to a second platform at the field.  This is part of the ongoing expansion project with plans to install the second platform and connect the additional wells in late 2010. China accounted for 5% of 2009 consolidated international sales volumes and 4% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 4,000 net developed acres and no undeveloped acres.

 

Additional International Locations   We hold approximately four million net undeveloped acres in other international locations including Suriname, Nicaragua, and India.

Proved Reserves Disclosures

 

Recent SEC Rule-Making Activity>   In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

 

·

Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

·

Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

·

Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

·

Reserves Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

·

Reserves Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process.  We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

·

Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.

·

Non-Traditional Resources – The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

 

We adopted the rules effective December 31, 2009.

 

Effect of Adoption    Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 27 MMBoe. Use of the old year-end prices rules would have resulted in an increase in proved reserves of approximately 34 MMBoe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 61 MMBoe. In addition to the new pricing methodology rules, the new proved undeveloped reserves rules, which limit PUDs to those scheduled to be drilled within the next five years, resulted in an additional reduction of proved reserves of approximately 18 MMBoe.

 

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Internal Controls Over Reserves Estimates >  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to our Corporate Reservoir Engineering group and requires that reserves estimates be made by the regional reservoir engineering staff and reviewed by the regional reservoir engineering supervisor.

 

Qualified petroleum engineers in our Houston, Denver and London 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 20 years of industry experience with positions of increasing responsibility in engineering and evaluations. The Vice President – Reserves reports directly to our Chief Executive Officer.

 

We engage a third-party petroleum consulting firm to audit a significant portion of our reserves.  See Third-Party Reserves Audit below.

 

Technologies Used in Reserves Estimation   >The SEC’s new 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 2009 reserves estimates.

 

Third-Party Reserves Audit>   In each of the years 2009, 2008 and 2007, we retained Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party reserves engineers, to perform reserves audits of proved reserves. The reserves audit for 2009 included a detailed review of 20 of our major international, deepwater Gulf of Mexico and US onshore fields, which covered approximately 78% of US proved reserves and 96% of international proved reserves (86% of total proved reserves). The reserves audit for 2008 included a detailed review of 18 of our major fields and covered approximately 86% of total proved reserves. The reserves audit for 2007 included a detailed review of 16 of our major fields and covered approximately 81% of total proved reserves.

 

In connection with the 2009 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 producing 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 the recently updated 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 conform to the guidelines 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)(2) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2009, based upon its evaluation. The NSAI opinion concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. NSAI’s report is attached as Exhibit 99.2 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 Board of Directors.  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. On a quantity basis, the NSAI field estimates ranged from one MMBoe above to 16 MMBoe below as compared with our estimates. On a percentage basis, the NSAI field estimates ranged from 9% above our estimates to 20% below our estimates. 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, 2009 were, in the aggregate, approximately 21 MMBoe, or 3%.

 

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Proved Undeveloped Reserves (PUDs) >  As of December 31, 2009, our PUDs totaled 142 MMBbls of crude oil and 769 Bcf of natural gas, for a total of 270 MMBoe.

 

PUD Locations     Approximately 70% of our PUDs at year-end 2009 were associated with our major development areas in the Wattenberg field (onshore US) and the Alba field (offshore Equatorial Guinea). An additional 17% of PUDs at year-end 2009 were associated with major development projects at the Aseng field (offshore Equatorial Guinea) and the Galapagos project (deepwater Gulf of Mexico). All of these projects will have PUDs convert from undeveloped to developed as these projects begin production and/or production facilities are expanded or upgraded.

 

Changes in PUDS    Changes in PUDs that occurred during the year were due to:

 

·

conversion of approximately 23 MMBoe PUDs into proved developed reserves;

·

reclassification of approximately 18 MMBoe PUDs that were not scheduled to be developed within five years from proved to probable reserves; and

·

negative revisions of approximately 23 MMBoe in PUDs due to changes in commodity prices.

 

The majority of the reserves reclassified from proved reserves to probable reserves were associated with the Wattenberg field, where we maintain an extensive multi-year development program.

 

Development Costs    Costs incurred relating to the development of PUDs were approximately $440 million in 2009, $528 million in 2008 and $390 million in 2007.

 

Estimated future development costs relating to the development of PUDs are projected to be approximately $900 million in 2010, $800 million in 2011, and $500 million in 2012.

 

Drilling Plans      All PUD drilling locations are scheduled to be drilled prior to the end of 2014.  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 2014.  Initial production from these PUDs is expected to begin between 2010 to 2015.

 

We have 7 MMBoe of PUDs associated with an international discovery that has been booked for longer than five years.  Development planning is proceeding on this project, and drilling is expected to begin in the next two years.  The only other PUDs that have been booked for longer than five years are associated with compression projects.  In those cases, the reserves are expected to be recovered from existing wells.

 

For more information see the following:

 

·

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves for a discussion of changes in proved reserves;

 

·

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves for further discussion of our reserves estimation process;

 

·

Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.

 

Other Reserves Information    Since January 1, 2009, 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.

 

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

 

		Sales Volumes									Average Sales Price									Production  Cost (1)
		Crude Oil MBpd			Natural Gas MMcfpd			NGLs MBpd			Crude Oil Per Bbl			Natural Gas Per Mcf			NGLs Per Bbl			Per BOE
Year Ended December 31, 2009
United States
Wattenberg Field			15			150			6		$	55.57		$	3.59		$	29.10		$	3.01
Other US			22			247			4			54.92			3.62			26.37			8.50
Total US (2)			37			397			10			55.19			3.61			27.96			6.26
Alba Field (Equatorial Guinea) (3)			14			239			-			55.94			0.27			-			2.30
Israel			-			114			-			-			3.47			-			1.36
North Sea			7			5			-			59.51			5.75			-			15.81
Ecuador			-			26			-			-			-			-			-
China			4			-			-			54.40			-			-			6.75
Total Consolidated Operations			62			781			10			55.76			2.54			27.96		$	5.05
Equity Investee (4)			2			-			6			59.51			-			36.03
Total			64			781			16		$	55.87		$	2.54		$	31.20
Year Ended December 31, 2008
United States
Wattenberg Field			15			146			5		$	71.41		$	7.39		$	52.19		$	3.12
Other US			25			249			4			78.02			8.55		$	47.51			7.91
Total US (2)			40			395			9			75.53			8.12		$	50.15			6.08
Alba Field (Equatorial Guinea) (3)			15			206			-			88.95			0.27			-			2.17
Israel			-			139			-			-			3.10			-			1.07
North Sea			10			5			-			100.56			10.54			-			12.63
Ecuador			-			22			-			-			-			-			-
China			4			-			-			82.66			-			-			7.03
Total Consolidated Operations			69			767			9			82.60			5.04			50.15		$	4.90
Equity Investee (4)			2			-			6			96.77			-			58.81
Total			71			767			15		$	82.96		$	5.04		$	53.45
Year Ended December 31, 2007
United States
Wattenberg Field			13			163			-		$	68.19		$	5.52		$	-		$	2.68
Other US			29			249			-			46.76			8.82			-			6.72
Total US (2)			42			412			-			53.22			7.51			-			5.26
Alba Field (Equatorial Guinea) (3)			15			132			-			71.27			0.29			-			2.89
Israel			-			111			-			-			2.79			-			1.14
North Sea			13			6			-			76.47			6.54			-			7.68
Ecuador			-			26			-			-			-			-			-
China			4									58.79									7.08
Argentina (5)			3			-			-			46.79			-			-			11.79
Total Consolidated Operations			77			687			-			60.61			5.26			-		$	4.62
Equity Investee (4)			2			-			6			74.87			-			48.87
Total			79			687			6		$	60.94		$	5.26		$	48.87

 

(1)	Average production cost includes oil and gas operating costs and workover and repair expense and excludes production and ad valorem taxes.

(2)

Average crude oil sales prices reflect reductions of $2.13 per Bbl (2009), $22.06 per Bbl (2008), and $13.68 per Bbl (2007) from hedging activities. Average natural gas sales prices reflect increases of $0.23 per Mcf (2008), and $1.12 per Mcf (2007) from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis.

(3)

Average crude oil sales prices reflect reductions of $5.57 per Bbl (2009), $7.59 per Bbl (2008), and $2.19 per Bbl (2007) from hedging activities. Natural gas is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. Sales to these plants are based on a BTU equivalent and then converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information.

(4)	Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.

(5)	We sold our Argentina assets in February 2008.

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Revenues from sales of crude oil and natural gas have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.

 

At December 31, 2009, our operated properties accounted for approximately 60% 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, 2009 was as follows:

 

		Crude Oil Wells							Natural Gas Wells							Total
		Gross				Net			Gross				Net			Gross			Net
United States
Northern Region			7,825				6,119.0			5,028				3,637.9			12,853			9,756.9
Southern Region			799				593.0			392				175.0			1,191			768.0
Equatorial Guinea			4				1.7			20				7.7			24			9.4
Israel			-				-			5				2.4			5			2.4
North Sea			22				4.7			8				1.0			30			5.7
Ecuador			-				-			3				3.0			3			3.0
China			15				8.6			1				0.6			16			9.2
Total			8,665				6,727.0			5,457				3,827.6			14,122			10,554.6

 

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, 2009 was as follows:

 

		Developed Acreage						Undeveloped Acreage
		Gross			Net			Gross			Net
(thousands)
United States
Onshore			1,625			956			1,603			1,262
Offshore			134			84			524			362
Total United States			1,759			1,040			2,127			1,624
International
Equatorial Guinea			140			53			523			212
Cameroon			-			-			1,125			563
Israel			62			29			1,790			796
North Sea (1)			50			6			229			44
Ecuador			12			12			849			849
China			7			4			-			-
Suriname			-			-			3,087			1,389
Nicaragua			-			-			1,977			1,977
Cyprus			-			-			1,136			795
India			-			-			694			347
Total International			271			104			11,410			6,972
Total (2)			2,030			1,144			13,537			8,596

 

(1)	The North Sea includes acreage in the UK and the Netherlands.

(2)

Approximately 687,000 gross acres (407,000 net acres) will expire in 2010; 1.4 million gross acres (975,000 net acres) will expire in 2011; and 172,000 gross acres (121,000 net acres) will expire in 2012 if production is not established or we take no other action to extend the terms of the leases or concessions.

 

Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well.

Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.

 

A gross acre is any leased acre in which a working interest is owned. A net acre is comprised of the total of the owned working interest(s) in a gross acre expressed in a fractional format.

 

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Drilling Activity> The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows:

 

		Net Exploratory Wells									Net Development Wells
		Productive			Dry			Total			Productive			Dry			Total			Total
Year Ended December 31, 2009
United States
Northern Region			2.5			1.0			3.5			516.9			1.0			517.9			521.4
Southern Region			1.6			0.6			2.2			15.4			1.0			16.4			18.6
Equatorial Guinea (1)			0.5			-			0.5			-			-			-			0.5
Israel (1)			1.1			-			1.1			-			-			-			1.1
North Sea			-			-			-			1.0			-			1.0			1.0
China			-			-			-			0.6			-			0.6			0.6
Total			5.7			1.6			7.3			533.9			2.0			535.9			543.2
Year Ended December 31, 2008
United States
Northern Region			1.0			-			1.0			837.2			42.0			879.2			880.2
Southern Region			14.6			2.0			16.6			30.9			2.0			32.9			49.5
Equatorial Guinea (1)			1.3			-			1.3			-			-			-			1.3
North Sea			-			0.4			0.4			0.6			0.3			0.9			1.3
Suriname			-			0.5			0.5			-			-			-			0.5
Total			16.9			2.9			19.8			868.7			44.3			913.0			932.8
Year Ended December 31, 2007
United States
Northern Region			13.9			1.9			15.8			738.0			24.5			762.5			778.3
Southern Region			0.3			2.6			2.9			19.6			3.1			22.7			25.6
Equatorial Guinea (1)			2.1			0.5			2.6			-			-			-			2.6
Cameroon (1)			0.5			-			0.5			-			-			-			0.5
Israel			-			-			-			0.4			-			0.4			0.4
North Sea			0.5			-			0.5			-			-			-			0.5
Argentina (2)			-			0.1			0.1			6.7			-			6.7			6.8
Total			17.3			5.1			22.4			764.7			27.6			792.3			814.7

 

(1)	Includes successful exploratory wells drilled but not yet producing.

(2)	We sold our assets in Argentina in February 2008.

 

A productive well is an exploratory, development or extension well that is not a dry well. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is part of a development project, which is defined as the means by which petroleum resources are brought to the status of economically producible. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

 

In addition to the wells drilled and completed in 2009 included in the table above, at December 31, 2009, we were in the process of drilling or completing 152 gross (113.2 net) wells in the Northern region of our US operations, two gross (0.7 net) onshore wells in the Southern region of our US operations, two gross (0.6 net) wells in the deepwater Gulf of Mexico, one gross (0.3 net) well in the North Sea, and one gross (0.6 net) well in China.

 

Marketing Activities We seek opportunities to enhance the value of our US natural gas production by marketing directly to end-users and aggregating natural gas to be sold to natural gas marketers and pipelines. We sell our natural gas production at both market-based and fixed prices. In 2009, approximately 28% of natural gas sales were made pursuant to long-term contracts under either fixed or market-based prices.

 

Crude oil, condensate and NGLs produced in the US and foreign locations are generally sold under short-term contracts at market-based prices adjusted for location and quality. In China, we sell crude oil into the local market under a long-term contract at market-based prices. In Israel, we sell natural gas under long-term contracts at negotiated prices. Crude oil and condensate are distributed through pipelines and by trucks or tankers to gatherers, transportation companies and refineries.

 

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Delivery Commitments   Some of our natural gas sales contracts specify the delivery of a fixed and determinable quantity of product. We have commitments to deliver approximately 220 Bcf of natural gas, net to our interest, to various customers in Israel through the year 2022. Approximately 90% of this amount will be delivered by 2015. We expect to fulfill the delivery commitments with proved developed and proved undeveloped reserves from the Mari-B and other nearby fields in Israel and we do not expect any shortfall. See International – Eastern Mediterranean (Israel and Cyprus).

 

Significant Purchaser Glencore Energy UK Ltd (Glencore) was the largest single non-affiliated purchaser of 2009 production and purchased our share of production from the Alba field in Equatorial Guinea under a short-term sales contract, subject to renewal.  Sales to Glencore accounted for 25% of 2009 crude oil sales, or 16% of 2009 total oil and gas sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2009. We believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.

 

Hedging Activities Commodity prices were volatile in 2009 and prices for crude oil and natural gas are affected by a variety of factors beyond our control. We have used derivative instruments, and expect to do so in the future, in order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas. For additional information, see Item 1A. Risk Factors – Hedging transactions may limit our potential gains and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note 6. Derivative Instruments and Hedging Activities.

 

Termination of Contracts   See Item 1A. Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country’s unsettled economic and political environment, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Current Conditions in Ecuador, and Item 8. Financial Statements and Supplementary Data – 3. Impairments.

 

Regulations

 

Government Regulation Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the international, federal, state and local levels. Crude oil and natural gas development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, transportation, prevention of waste and pollution and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Our ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases our costs of doing business and consequently affects our profitability. See Item 1A. Risk Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

 

Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil and natural gas include:

 

·

the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act have certain authority over our operations on federal lands, particularly in the Rocky Mountains and deepwater Gulf of Mexico;

·

the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration, which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Occupational Safety and Health Act and the recent Final Mandatory Reporting of Greenhouse Gases Rule have certain authority over environmental, health and safety matters affecting our operations as discussed below;

·

the Federal Energy Regulatory Commission, which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil and natural gas we produce onshore and from the deepwater Gulf of Mexico;

·

the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our US onshore and deepwater Gulf of Mexico operations; and

·

other federal agencies with certain authority over our business, such as the Internal Revenue Service and the SEC, as well as the NYSE upon which shares of our common stock are traded.

 

In January 2010, the BLM announced that it will be issuing a new draft oil and gas leasing policy that will require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process.  As the policy has not yet been released, we are not able to determine the impact these potential leasing policy changes may have on our business.

 

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Most of the states within which we operate have separate agencies with authority to regulate related operational and environmental matters.  Examples of such regulation on the operational side include the Greater Wattenberg Area Special Well Location Rule 318A, which was adopted by the Colorado Oil and Gas Conservation Commission to address oil and gas well drilling, production, commingling and spacing in the Wattenberg field, and the same Commission’s December 10, 2008 approval of a comprehensive update to statewide rules governing oil and gas operations in Colorado. These rules were reviewed by the Colorado legislature in its 2009 session and became effective in the second quarter of 2009, addressing areas such as public drinking water protection, monitoring and disclosure of chemicals used in drilling operations, erosion management and environment and wildlife protection. On the environmental side, Colorado Regulation Seven and requirements for storm water management plans were adopted by the Colorado Department of Environmental Quality, under delegation from the EPA, to regulate air emissions, water protection and waste handling and disposal relating to our oil and gas exploration and production.

 

Some of the counties and municipalities within which we operate have adopted regulations or ordinances that impose additional restrictions on our oil and gas exploration and production.  An example is Garfield County, Colorado, which provides local land and road use restrictions affecting our Piceance basin operations and requires us to post bonds to secure any restoration obligations.

 

Our international operations are subject to legal and regulatory oversight by energy-related ministries of our host countries, each having certain relevant energy or hydrocarbons laws.  Examples of these ministries include the Ecuador Ministry of Nonrenewable Natural Resources, the Equatorial Guinea Ministry of Mines, Industry and Energy, the Israel Ministry of National Infrastructures, and the UK Department of Energy and Climate Change.  An example of a law affecting our international operations is the UK Finance Act of 2006, which increased the income tax rate on our UK operations effective January 1, 2006.

 

Environmental Matters As a developer, owner and operator of crude oil and natural gas properties, we are subject to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. The EPA and various state agencies have limited the disposal options for hazardous and non-hazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. See Item 1A. Risk Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

 

Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

 

Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.

 

We have made and will continue to make expenditures in our efforts to comply with environmental requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.

 

Competition

 

The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling partnership programs. Many of our competitors are large, well established companies. Such companies may be able to pay more for seismic and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors – We face significant competition and many of our competitors have resources in excess of our available resources.

 

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Geographical Data

 

We have operations throughout the world and manage our operations by country. Information is grouped into five components that are all primarily in the business of crude oil, natural gas and NGL exploration, development and production: United States, West Africa, Eastern Mediterranean, North Sea, and Other International, Corporate and Marketing. See Item 8. Financial Statements and Supplementary Data – Note 15. Segment Information.

 

Employees

 

Our total number of employees increased from 1,571 at December 31, 2008 to 1,630 at December 31, 2009. The 2009 year-end employee count includes 154 foreign nationals working as employees in Ecuador, Israel, the UK, Equatorial Guinea and Cameroon. We regularly use independent contractors and consultants to perform various field and other services.

 

Offices

 

Our principal corporate office, including our offices for US and international operations, is located at 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain additional offices in Ardmore, Oklahoma and Denver, Colorado and in China, Cameroon, Ecuador, Equatorial Guinea, Israel and the UK.

 

Title to Properties

 

We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.

 

Available Information

 

Our website address is www.nobleenergyinc.com. Available on this website under “Investors – Investors Menu – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.

 

Also posted on our website, and available in print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee; Compensation, Benefits and Stock Option Committee; Corporate Governance and Nominating Committee; and Environment, Health and Safety Committee. Copies of the Code of Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.

 

Item 1A.  Risk Factors

 

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.

 

If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic environment intensifies many of these risks.

 

Future economic conditions in the US and key international markets may materially adversely impact our operating results.

 

The US and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest.  There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years.  In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.   Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

 

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Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.

 

Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2009 ranged from a high of $81.37 per barrel to a low of $33.98 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2009 ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. The markets and prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

 

·

worldwide and domestic supplies of crude oil and natural gas;

·

actions taken by foreign oil and gas producing nations;

·

political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;

·

the level of global crude oil and natural gas inventories;

·

the price and level of imported foreign crude oil and natural gas;

·

the price and availability of alternative fuels, including coal and biofuels;

·

the availability of pipeline capacity and infrastructure;

·

the availability of crude oil transportation and refining capacity;

·

weather conditions;

·

electricity generation;

·

domestic and foreign governmental regulations and taxes; and

·

the overall economic environment.

 

Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:

 

·

limiting our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;

·

reducing the amount of crude oil and natural gas that we can produce economically;

·

causing us to delay or postpone some of our capital projects;

·

reducing our revenues, operating income and cash flows; or

·

limiting our access to sources of capital, such as equity and long-term debt.

 

In addition, significant declines in the forward commodity price curves may result in the following:

 

·

a reduction in the carrying value of our crude oil and natural gas properties; or

·

a reduction in the carrying value of goodwill.

 

We recorded asset impairment charges during 2009. If commodity prices decline during 2010, there could be additional impairments of our oil and gas assets or other investments or an impairment of goodwill.

 

Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.

 

During 2009, credit markets recovered but remain vulnerable to unpredictable shocks should weaker than expected economic growth persist.  We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and our partners will need to seek financing in order to fund these or other activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.

 

Failure to fund continued capital expenditures could adversely affect our properties.

 

Our exploration, development, and acquisition activities require substantial capital expenditures especially in the case of our active drilling programs, such as the Wattenberg field, and our significant exploration and development programs in the deepwater Gulf of Mexico, West Africa and Israel. Significant capital investments on our inventory of major development projects will start next year and are estimated to be approximately $1 billion per year in 2010 and 2011.  First production from these projects is not expected until 2011 and thereafter. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt  issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to debt or capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access capital markets on an economic basis to meet these requirements. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.

 

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Indebtedness may limit our liquidity and financial flexibility.

 

As of December 31, 2009, we had long-term indebtedness of $2 billion (excluding unamortized discount), with $382 million drawn under our bank credit facility. Our indebtedness represented 25% of our total book capitalization at December 31, 2009.

 

Our indebtedness affects our operations in several ways, including the following:

 

·

a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

·

we may be at a competitive disadvantage as compared to similar companies that have less debt;

·

the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

·

additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

·

additional financing in the future is likely to have higher costs due to the negative impact of the credit market crisis which restricted access to the bond markets;

·

changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving credit facility; and

·

we may be more vulnerable to general adverse economic and industry conditions.

 

We may incur additional debt in order to fund our exploration, development and acquisition activities such as our pending acquisition of additional US Rocky Mountain assets. A higher level of indebtedness increases the risk that our liquidity may become impaired and we default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, crude oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.

 

Hedging transactions may limit our potential gains.

 

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.

 

Global commodity price fluctuation has been significant in 2009. Such volatility disrupts our ability to forecast and, as a result, we may become even more reliant on our hedging program.  In trying to manage our exposure to commodity price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our futures contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices.  We cannot assure that our hedging transactions will reduce the risk or minimize the effect of volatility in crude oil or natural gas prices.

 

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We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.

 

We are exposed to risk of financial loss from trade, joint venture, and other receivables.  We sell our crude oil, natural gas and NGLs to a variety of purchasers.   In addition, we are the operator on large joint venture development projects such as Aseng in Equatorial Guinea and Tamar in Israel. As operator of the joint ventures, we pay joint venture expenses and bill our nonoperating partners for their respective shares of joint venture costs. Some of our purchasers and joint venture partners are not as creditworthy as we are and may experience liquidity problems. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including our largest international crude oil purchaser; however, not all of our trade credit is protected through guarantees or credit support.  Nonperformance by a trade creditor or joint venture partner could result in significant financial losses.

 

We also monitor the creditworthiness of our counterparties on an ongoing basis. However, disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in financial market conditions or a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract.  To mitigate counterparty credit risk we conduct our hedging activities with a diverse group of major financial institutions.  We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

 

During periods of falling commodity prices, such as in late 2008 and first quarter 2009, our hedge receivable positions increase, which increases our counterparty exposure. If the creditworthiness of our counterparties, which are major financial institutions, deteriorates and results in their nonperformance, we could incur a significant loss.

 

We have over $1 billion in cash and cash equivalents invested in money market funds and short-term deposits with major financial institutions. During the first half of 2009, we shortened the duration of our bank deposits and held over 50% of our cash and cash equivalents in US Treasury securities. We maintained this investment posture well into the third quarter of 2009 before we started to reduce our US Treasury holdings in favor of reinvestment back into money market funds and time deposits with highly rated banks. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. However, we are unable to predict sudden changes in solvency of our financial institutions. In the event of a bank failure, we could incur a significant loss.

 

We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

 

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unfortuitous events such as blowouts, cratering, fire and explosion and loss of well control which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. Our international operations are also subject to political risk.

 

In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets. Although we believe the coverages and amounts of insurance carried are adequate, we may not have sufficient protection against some of the risks we face, because we chose not to insure certain risks, insurance is not available on commercially reasonable terms or actual losses exceed coverage limits. If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have an adverse impact on our financial condition, results of operations and cash flows.

 

Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and negative effects on our operating results.

 

We currently have an extensive inventory of major development projects, several of which will take years before first production, including the Aseng oil project, Tamar, Gunflint, and others.  Some of these projects, such as oil and gas projects in West Africa, have a great deal of complexity. This level of development will require significant effort from our management and technical personnel as well as place additional burden on our financial resources and internal financial controls. We may not be able to attract and retain personnel with the skills necessary to bring complicated projects to successful conclusions.

 

In addition, we will have increased dependency on third-party technology and service providers and other vendors for these complex projects.  Significant delays in delivery of essential items or performance of services, cost overruns, vendor insolvency, or other critical supply failure, could adversely affect development of our projects.

 

We may not be able to manage these and other risks effectively.

 

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We may be unable to make attractive acquisitions, integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing a disruption to our business.

 

One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current business, such as our Patina Merger in 2005, our purchase of U.S. Exploration in 2006 and the pending acquisition of additional US Rocky Mountain assets.  This may present greater risks for us than those faced by peer companies that do not consider acquisitions as a part of their business strategy. We cannot provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the acquisition due to capital market constraints, even if such capital is available on commercially acceptable terms. If we acquire another business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own, or could assume unidentified or unforeseeable liabilities, resulting in a loss of value.

 

We also engage in portfolio rationalization, such as the sale of our interest in Argentina in 2008, and the majority of our Gulf of Mexico shelf properties in 2006. These transactions can also result in changes in operations, systems, or management and other personnel.

 

Organizational modifications due to acquisitions, divestitures or portfolio rationalizations, or other strategic changes can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these difficulties could be overcome, we cannot provide assurance that the anticipated benefits of any acquisition, divestiture or other strategic change would be realized.

 

Estimates of crude oil and natural gas reserves are not precise.

 

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we adopted effective December 31, 2009, our reserves estimates are based on 12-month average prices; therefore, reserves quantities will change when actual prices increase or decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:

 

·

historical production from the area compared with production from other areas;

·

the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reserves reporting requirements;

·

assumptions concerning future crude oil and natural gas prices;

·

future operating costs;

·

severance and excise taxes;

·

development costs; and

·

workover and remedial costs.

 

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves ba