PART I

 

Items 1 and 2.      Business and Properties .

 

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, see Item 1A. Risk Factors—Disclosure Regarding Forward-Looking Statements of this Form 10-K.

 

General

 

Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is a Delaware corporation, formed in 1969, that has been publicly traded on the New York Stock Exchange (“NYSE”) since 1980. We are an independent energy company that has been engaged in the acquisition, exploration, development, production and marketing of crude oil and natural gas since 1932. In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy and its subsidiaries. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which we have exploration rights. We operate throughout major basins in the United States (“US”) including Colorado’s Wattenberg field and Piceance basin, the Mid-continent area of western Oklahoma and the Texas Panhandle, the San Juan basin in New Mexico, the Gulf Coast and the deepwater Gulf of Mexico. In addition, we conduct business internationally in China, Ecuador, the Mediterranean Sea, the North Sea, West Africa (Equatorial Guinea and Cameroon) and in other areas.  

 

Strategy

 

We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flow through the development of a high quality portfolio of producing assets that is balanced between US and international projects. Strategic acquisitions (Patina Oil & Gas Corporation (“Patina”) in 2005 and U.S. Exploration Holdings, Inc. (“U.S. Exploration”) in 2006), along with additional capital investment have resulted in substantial growth in the last five years. Acquisitions and capital investment, combined with the sale of non-core assets, have allowed us to achieve a strategic objective of enhancing our US asset portfolio, resulting in a company with assets and capabilities that include growing US basins coupled with a significant portfolio of international properties. Crude oil and natural gas sales volumes have doubled since 2003. Our reserve base, which includes both US and international sources at 58% US and 42% international, has almost doubled in the same period. We are now a larger, more diversified company with greater opportunities for both US and international growth. See Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2003-2007.

 

Proved Reserves

 

As of December 31, 2007, we had estimated proved reserves of 3.3 Tcf of natural gas and 329 MMBbls of crude oil. On a combined basis, these proved reserves were equivalent to 880 MMBoe, an increase of 5% over the prior year. At December 31, 2007, 74% of reserves were proved developed reserves.

 

 

 

Proved reserves estimates at December 31, 2007 were as follows:

 

 

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Information (Unaudited) and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Reserves.

 

Engineers in our Houston, Denver and London offices prepare all reserve estimates for our different geographical regions. These reserve estimates are reviewed and approved by senior engineering staff and division management with final approval by the Director of Asset Development and certain members of senior management. During each of the years 2007, 2006 and 2005, we retained Netherland, Sewell & Associates, Inc. (“NSAI”), independent third-party reserve engineers, to perform reserve audits of proved reserves. A “reserve audit”, as we use the term, is a process involving an independent third-party engineering firm’s visits, collection of any and all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of reserve estimates. Our use of the term “reserve audit” is intended only to refer to the collective application of the procedures which NSAI was engaged to perform. The term “reserve audit” may be defined and used differently by other companies.

 

The reserve audit for 2007 included a detailed review of 16 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 71% of US proved reserves and 96% of international proved reserves (81% of total proved reserves). The reserve audit for 2006 included a detailed review of 14 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 80% of our total proved reserves. The reserve audit for 2005 included a detailed review of 11 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 72% of our total proved reserves.

 

In connection with the 2007 reserve 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 reserve quantities, future producing rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance. In the conduct of the reserve 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, 2007, based upon its evaluation. Its 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.

 

 

 

The fields that NSAI audits include our most significant fields and are chosen by senior engineering staff and division management with final approval by the Director of Asset Development and certain members of senior management. We usually include all deepwater Gulf of Mexico fields, all international fields that require reports by requirement of the host government, all fields that require sanctioning by our Board of Directors, and other major fields. No significant fields were excluded from the December 31, 2007 reserve audit.

 

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 21,966 MBoe above to 16,882 MBoe below as compared with our estimates. On a percentage basis, the NSAI field estimates ranged from 9% above our estimates to 42% 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%. At December 31, 2007, reserves differences, in the aggregate, were less than 13,200 MBoe, or 2%.

 

Since January 1, 2007, no crude oil or natural gas reserve 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 reserve and other information, with the EIA.

 

Acquisition and Divestiture Activities

 

We maintain an ongoing portfolio optimization program. 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.

 

In December 2007, we entered into an agreement to sell our interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008. Crude oil reserves for the Argentina properties totaled 7 MMBbls at December 31, 2007.

 

In 2006, we sold all of our Gulf of Mexico shelf properties except for the Main Pass area, which is undergoing redevelopment studies. 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. Deepwater Gulf of Mexico and Gulf Coast onshore areas remain core areas and are more aligned with our long-term business strategies. See Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.

 

In 2006,   we acquired U.S. Exploration, a privately held corporation, for $412 million plus liabilities assumed. U.S. Exploration’s reserves and production are located 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% of the reserves were proved developed and 55% of the reserves were natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were valued at $131 million. See Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.

 

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 provide 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% of the reserves were proved developed and 67% of the reserves were natural gas. Proved crude oil and natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. See Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.

 

 

 

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. We also own natural gas processing plants and natural gas gathering and other crude oil and natural gas related pipeline systems.

 

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 have significantly increased the breadth of our onshore operations, especially in the Rocky Mountain and Mid-continent areas. These two acquisitions have provided us with a multi-year inventory of exploitation and development opportunities. In 2007, we continued to expand our acreage position with the acquisition of approximately 290,000 net acres in the Piceance, Niobrara, and New Albany Shale areas. US operations accounted for 58% of our 2007 consolidated sales volumes and 58% of total proved reserves at December 31, 2007. Approximately 60% of the proved reserves are natural gas and 40% are crude oil. Our onshore US portfolio at December 31, 2007 included 1,308,823 gross developed acres and 1,234,858 gross undeveloped acres. We also hold interests in 97 offshore blocks in the Gulf of Mexico . In 2008, we plan to invest approximately $1.2 billion, or 74%, of budgeted capital in the US.

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

 

 

 

 

Additional information for our significant US operating areas is as follows:

 

 

Northern Region— The Northern region consists of our operations in the Rocky Mountain area, which includes the D-J (Wattenberg field), San Juan, Wind River, and Piceance basins, as well as the Niobrara, Bowdoin and Siberia Ridge fields. The addition of Patina and U.S. Exploration assets, particularly in the Wattenberg field, combined with our legacy operations in the Bowdoin field, the Niobrara trend, the Wind River basin and Piceance basin, have made the Rocky Mountains one of our core operating areas.  We are currently running 13 drilling rigs and 24 completion/workover units. We plan to invest approximately $744 million, or 62% of budgeted US capital in the Northern region during 2008.

 

Wattenberg Field— The Wattenberg field (approximately 97% operated working interest), our largest US asset, continues to grow production and reserves. In 2007, sales of production from this field accounted for 36% of total US sales volumes. Wattenberg field proved reserves accounted for 50% of US proved reserves at December 31, 2007.

 

We acquired working interests in the Wattenberg field through the Patina Merger in 2005 and acquisition of U.S. Exploration in 2006. Located in the D-J basin of north central Colorado, the Wattenberg field provides us with a substantial future project inventory. 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, with 99.8% of the wells drilled in 2007 encountering sufficient quantities of reserves to be completed as economic producers. In May 1998, the Colorado Oil and Gas Conservation Commission (“COGCC”) adopted the “Greater Wattenberg Area Special Well Location Rule 318A” which allows all formations in the Wattenberg field to be drilled, produced and commingled from any or all of ten “potential drilling locations” on a 320-acre parcel. A “commingled” well is one which produces crude oil from two or more formations or zones through a common string of casing and tubing. In December 2005, the COGCC amended Rule 318A providing for an effective well density of one well per 20 acres in a designated portion of the Greater Wattenberg Area to more effectively drain the reservoir. The amendment applies only to the Niobrara, Codell and J-Sand formations and became effective in March 2006.

 

We are currently running seven drilling rigs and 17 completion units in the Wattenberg field. Our current field activities are focused primarily on the development of J-Sand, Codell and Niobrara 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. During 2007, we drilled or participated in 508 development wells, with a 99.8% success rate, and added approximately 244 Bcfe of proved reserves in the Wattenberg field. Approximately 58% of these reserve  additions were natural gas. We also grew production from an average of 227 MMcfe per day for 2006 to 240 MMcfe per day for 2007. We plan to drill approximately 480 wells in 2008 (of which 337 will be combination Codell/Niobrara new drills).  We also plan to participate in 120 non-operated drilling projects in 2008.  We have a substantial project inventory remaining and plan to perform approximately 340 projects including refractures, trifractures, and recompletions during 2008.

 

 

 

Other Rocky Mountain areas include:

 

Niobrara Trend— The Niobrara trend (approximately 87% operated working interest) is located in eastern Colorado and extends into Kansas and Nebraska. During 2007, we expanded our acreage position with the acquisition of 160,000 net acres.  We are currently running two drilling rigs and three completion units.  During 2007, we drilled or participated in 125 wells with a 79% success rate, and our activity resulted in the addition of 19 Bcfe of proved reserves. We plan to drill 300 wells in 2008.

 

Piceance Basin— The Piceance basin in western Colorado (approximately 96% operated working interest) is another rapidly growing area for us. During 2007, we added 10,500 net acres to our position. We are currently running four drilling rigs and three completion units.  We drilled or participated in 55 development wells during 2007, 100% of which were successful, and our activity resulted in the addition of 83 Bcfe of proved reserves. We plan to drill over 100 wells during 2008.

 

Other— We are also active in the Bowdoin field (approximately 60% operated working interest), located in north central Montana; the San Juan basin (approximately 81% operated working interest), located in northwestern New Mexico and southwestern Colorado; and the Wind River basin (approximately 56% operated working interest), located in central Wyoming. During 2007 we drilled or participated in a total of 56 development wells in these areas, 100% of which were successful. We plan to drill approximately 60 wells and recomplete 190 wells during 2008.

 

Southern Region — The Southern region includes the Gulf Coast onshore, West and East Texas, Louisiana, and the deepwater Gulf of Mexico, as well as the Mid-continent area (the Texas Panhandle and parts of Oklahoma, Kansas, Arkansas, Illinois and Indiana). The Gulf Coast and deepwater Gulf of Mexico are core US operating areas.  During 2006, we sold all of our Gulf of Mexico shelf properties except for the Main Pass area. The sale of our shelf properties allows us to migrate future investments and growth from the Gulf of Mexico shelf to the deepwater Gulf of Mexico which we believe is an area of higher potential. We plan to invest approximately $460 million, or 38% of budgeted US capital, in the Southern region during 2008, with approximately 67% in the deepwater Gulf of Mexico, and the remainder to the Gulf Coast and the Mid-continent areas.

 

Deepwater Gulf of Mexico— Deepwater Gulf of Mexico accounted for 22% of 2007 US sales volumes and 7% of US proved reserves at December 31, 2007. During 2007, we continued to focus on the growth of our deepwater Gulf of Mexico business highlighted by a successful exploration discovery at Isabela and a successful sidetrack-appraisal well at our 2006 Raton discovery.  We also completed successful development drilling programs in our Ticonderoga and Swordfish fields. Deepwater Gulf of Mexico activity resulted in proved reserve additions of 12 MMBoe during 2007. Participation in the 2007 Central Gulf of Mexico Outer Continental Shelf Sale resulted in our being awarded eight new deepwater Gulf of Mexico leases totaling $50 million.

 

At year-end, development planning was underway for Isabela ( Mississippi Canyon Block 562, 33% working interest). We have also acquired an interest in adjacent acreage with additional exploration potential on Mississippi Canyon Blocks 519 and 563 (23.25% working interest).  We plan to drill a well on Block 519 (Santa Cruz Prospect) in 2008 pending rig availability.  In total there are three prospects on the combined leasehold that, conceptually, would be co-developed in a subsea tieback to an existing production facility.

 

Other 2007 exploration drilling included the Mississippi Canyon Block 568 #1 (Robusto Prospect, 20% working interest) and the East Breaks Block 465 #1 (Lost Ark South Prospect, 98.4% working interest), neither of which encountered hydrocarbons in commercial quantities.

 

During 2007 we saw an extremely active deepwater Gulf of Mexico development program. At our Raton project in Mississippi Canyon Block 248 (66.67% operated working interest), we successfully sidetracked and completed the 248 #1 discovery well drilled in 2006.  At year-end the project had moved into the development stage and is slated for subsea tieback and first production in the second quarter of 2008.

 

 

 

At our operated Swordfish project (85% working interest), we drilled and completed a sidetrack to Viosca Knoll Block 917 #1 well and began gas production from this well at year end.   At the Ticonderoga development in Green Canyon Block 768 (50% working interest, non-operated), the #3 and #1 ST4 wells were drilled and completed to extend and enhance production from the field.  Both are slated for first production in the first quarter of 2008.

 

At the Lost Ark project in East Breaks Blocks 421 and 464 (48.4% operated working interest), the 421 #1 well, which had reached the end of its productive life, was plugged and abandoned, and the 464 #1 well was completed and put on production to develop the remaining reserves at the field.

 

We are currently evaluating a possible sidetrack-appraisal well to be drilled at the Raton South oil discovery in Mississippi Canyon Block 292 during late 2008 (originally drilled in 2006). The Redrock natural gas/condensate discovery, also drilled in 2006, is currently considered a co-development candidate to a successful sidetrack-appraisal well at Raton South. Additional key exploration activity planned for 2008 includes a well at the Mississippi Canyon Block 948, Gunflint prospect, (50% working interest), in the second half of 2008.

 

Mid-continent— A significant area of activity in Mid-continent is the Granite Wash development, located in the Texas Panhandle. We drilled or participated in 53 development wells in 2007, 100% of which were successful. The potential for horizontal drilling is currently being evaluated.  Another significant area in Mid-continent is the ongoing Southern Oklahoma development. In 2007 we drilled or participated in 45 wells resulting in additional incremental production of 1,515 Boepd.

 

In addition, we contintue to selectively increase our acreage position in resource plays, including shale plays. We have accumulated over 179,000 acres in the New Albany Shale. During 2007, we drilled 16 New Albany Shale wells. Currently nine are producing and seven are in the progress of pipeline connection. The Paxton facility, which we operate, will serve the majority of wells in the Paxton field. We plan to have an active drilling program during 2008.

 

Other Mid-continent areas include parts of Texas, Oklahoma, Kansas, Illinois, Indiana, and Arkansas.  During 2007, we drilled or participated in a total of 33 wells. We plan to drill or participate in 60 wells in the Mid-continent area during 2008.

 

Gulf Coast Onshore — During late 2007, we began a six well program at Oliver Creek in Shelby County, Texas to develop the Travis Peak reservoir as well as test deeper Cotton Valley horizons. We have completed one Travis Peak well and are currently completing the second Travis Peak well.  The deeper Cotton Valley horizons are being tested in two additional wells currently being drilled or completed.  Two additional wells remain in the current six well program.  Additional drilling is planned for later in 2008.

 

International

 

International operations are significant to our business, accounting for 42% of consolidated sales volumes in 2007, and 42% of total proved reserves at December 31, 2007. International proved reserves are approximately 67% natural gas and 33% crude oil. Operations in Equatorial Guinea, Cameroon, Ecuador, China and Suriname are conducted in accordance with the terms of production sharing contracts. In 2008, we plan to invest approximately $392 million, or 24%, of budgeted capital in our international locations.

 

 

 

Additional information for our significant international operating areas is as follows:

 

 

Wells drilled in 2007 and productive wells at December 31, 2007 in our international operating areas were as follows:

 

 

West Africa (Equatorial Guinea and Cameroon) —Operations in West Africa accounted for 46% of 2007 consolidated international sales volumes and 65% of international proved reserves at December 31, 2007. At December 31, 2007, we held 45,203 gross developed acres and 850,197 gross undeveloped acres in Equatorial Guinea and 1,125,000 gross undeveloped acres in Cameroon.

 

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 (located on Bioko Island), and an onshore LPG processing plant where additional condensate is produced. The methanol plant was originally designed to produce commercial grade methanol at a rate of 2,500 MTpd gross. As a result of various upgrade efforts, the plant is now 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 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 northwestern Europe. We sell our share of condensate produced in the Alba field and from the LPG plant under short-term contracts at market-based prices.

 

 

 

Our exploration activities in West Africa center around Blocks O and I offshore Equatorial Guinea and the PH-77 license offshore the Republic of Cameroon. We are the technical operator on Blocks O and I (45% and 40% working interest, respectively) and the operator on the PH-77 license (50% working interest). We drilled seven wells in the area during 2007 resulting in three new discoveries and three successful appraisal wells:

 

Benita   – The I-1 well, testing the Benita prospect, resulted in a new gas-condensate discovery on Block I.

 

Benita appraisal – The I-2 appraisal well on Block I encountered crude oil. Testing has been deferred in order to secure an additional drilling rig that will be capable of further appraisal drilling downdip in the Benita oil column, which is in deeper water. It is expected that a rig will be available for drilling the additional Benita appraisal well in the first quarter of 2008.

 

Yolanda – The I-3 well, testing the Yolanda prospect, resulted in another new gas-condensate discovery on Block I.

 

I-4 – The I-4 well on Block I was a successful well on trend with the 2005 Belinda discovery on Block O.

 

Adriana – The O-2 exploration well (the Adriana Southwest prospect) on Block O offshore Equatorial Guinea did not contain commercial hydrocarbons. The well was plugged and abandoned.

 

Belinda appraisal   – The O-3 appraisal well on Block O successfully extended the Belinda discovery by establishing significant downdip resources.

 

YoYo – The YoYo-1 well resulted in a new gas-condensate discovery on the PH-77 license offshore the Republic of Cameroon. Additional appraisal work is necessary to verify the areal extent of the discovery. There was also a secondary target, in which commercial hydrocarbons were not found.

 

In 2008, we plan to have an active exploration and appraisal drilling program for both Blocks I and O as we assess our options to commercialize our discoveries in the region.

 

Effective November 2006, the government of Equatorial Guinea enacted a new hydrocarbons law (the “2006 Hydrocarbons Law”) governing petroleum operations in Equatorial Guinea. The governmental agency responsible for the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and conditions that are inconsistent with the new law. At this time we are uncertain what economic impact this law will have on our operations in Equatorial Guinea.

 

 

Mediterranean Sea (Israel) —Operations in Israel accounted for 23% of 2007 consolidated international sales volumes and 14% of international proved reserves at December 31, 2007. At December 31, 2007, we held 123,552 gross developed acres and 1,183,479 gross undeveloped acres located between 10 and 60 miles offshore Israel in water depths ranging from 700 feet to 5,500 feet. Our leasehold position in Israel includes one preliminary permit, two leases and three licenses, and we are the operator.

 

 

 

 

 

 

 

Ecuador —Operations in Ecuador accounted for 5% of 2007 consolidated international sales volumes and 8% of international proved reserves at December 31, 2007. The concession covers 12,355 gross developed acres and 851,771 gross undeveloped acres.

 

We have been operating in Ecuador since 1996. We are currently utilizing the natural gas from the Amistad field (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. During 2007, power generation totaled 911,830 MW hours.

 

Other International —Other international includes China, Argentina and Suriname.

 

We have been engaged in exploration and development activities in China since 1996 and production began in 2003. We are operator of the Cheng Dao Xi field (57% working interest), which is located in the shallow water of the southern Bohai Bay. During 2007, activities consisted primarily of workover projects. China accounted for 5% of 2007 consolidated international sales volumes and 2% of international proved reserves at December 31, 2007. At December 31, 2007, we held 7,413 gross developed acres and no undeveloped acres.

 

We continue to work with our Chinese partner (Shengli) to obtain governmental approval of the Supplemental Development Plan, designed to further develop the Cheng Dao Xi field through additional drilling and facilities construction.

 

Our producing properties in Argentina are located in southern Argentina in the El Tordillo field (13% working interest), which is characterized by secondary recovery crude oil production. During 2007, we participated in the drilling of 50 gross (6.7 net) development wells. Argentina accounted for 4% of 2007 consolidated international sales volumes and 2% of international proved reserves at December 31, 2007. At December 31, 2007, we held 113,325 gross developed acres and no undeveloped acres in Argentina.

 

In December 2007, we entered into an agreement to sell our interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008. Crude oil reserves for the Argentina properties totaled 7 MMBbls at December 31, 2007.

 

Suriname, a country located on the northern coast of South America, represents a new exploration area for us. We have entered into participation agreements on non-operated Block 30 (60% working interest) and on Block 32 (100% working interest), which combined cover approximately 7.7 million gross acres offshore. We expect to participate in the drilling of one well on the West Tapir prospect on Block 30 in 2008.

 

 

 

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

 

 

(1)

2007 volumes include the effect of crude oil sales less than volumes produced of 165 MBbls in Equatorial Guinea, 112 MBbls in the North Sea and 48 MBbls in other international. 2006 volumes include the effect of crude oil sales in excess of volumes produced of 195 MBbls in Equatorial Guinea, less than volumes produced of 99 MBbls in the North Sea, and in excess of volumes produced of 18 MBbls in other international. The variance between production from the field and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings. Sales volumes equal production volumes in 2005.

(2)

Average natural gas sales prices in the US reflect an increase of $1.12 per Mcf (2007), and reductions of $0.25 per Mcf (2006) and $0.77 per Mcf (2005) from hedging activities. Average crude oil sales prices for the US reflect reductions of $13.68 per Bbl (2007), $11.41 per Bbl (2006) and $8.03 per Bbl (2005) from hedging activities. Average crude oil sales prices for West Africa reflect reductions of $2.19 (2007) and $9.93 (2005) from hedging activities. We did not hedge West Africa crude oil sales in 2006.

(3)	Average production costs include oil and gas operating costs, workover and repair expense, production and ad valorem taxes, and transportation expense.

(4)

Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG facility. 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. For 2007 and 2006, the price on an Mcf basis has been adjusted to reflect the Btu content of gas sales.

 

(5)	Equatorial Guinea natural gas volumes include sales to the LNG facility of 78,090 Mcfpd for 2007.  There were no natural gas sales to the LNG facility before 2007.

(7)	Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were 2,135 MBbls in 2007, 2,297 MBbls in 2006 and 850 MBbls in 2005.

 

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

 

At December 31, 2007, our operated properties accounted for approximately 62% 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 as of December 31, 2007 is as follows:

 

 

Productive wells are producing wells and wells 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. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. One or more completions in the same borehole are counted as one well in this table.

 

Developed and Undeveloped Acreage — Developed and undeveloped acreage (including both leases and concessions) held at December 31, 2007 was as follows:

 

(1)	The North Sea includes acreage in the UK, the Netherlands and Norway. In 2008, we entered into an agreement, subject to regulatory approval, to sell our interest in the Norway acreage consisting of 411,065 gross (126,607 net) undeveloped acres.

(2)	If production is not established, approximately 731,079 gross acres (433,236 net acres) will expire during 2008, 424,734 gross acres (193,554 net acres) will expire during 2009, and 683,274 gross acres (367,949 net acres) will expire during 2010.

 

Developed acreage includes leases that contain wells capable of production. A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.

 

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

 

 

(1)	Does not include wells drilled but not yet completed.

 

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

 

An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the table above and as defined in the rules and regulations of the SEC, is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 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 the production of crude oil or natural gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

 

In addition to the wells drilled and completed during 2007 included in the table above, at December 31, 2007, we were drilling or completing 2 gross (1.0 net) development wells offshore US,  223 gross (192.3 net) development wells and 4 gross (3.3 net) exploratory wells onshore US and one gross (0.1 net) development well in Argentina.

 

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 also engage in the purchase and sale of third-party crude oil and natural gas production. Such third-party production may be purchased from non-operators who own working interests in our wells or from other producers’ properties in which we own no interest.

 

Natural gas produced in the US is sold predominately under short-term or long-term contracts at market-based prices. In Equatorial Guinea and Israel, we sell natural gas to end-users under long-term contracts at negotiated prices. During 2007, approximately 12% of natural gas sales were made pursuant to long-term contracts.

 

Crude oil and condensate produced in the US and foreign locations is 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. Crude oil and condensate are distributed through pipelines and by trucks or tankers to gatherers, transportation companies and refineries.

 

 

 

Significant Purchaser — Marathon Petroleum Supply Company (“Marathon”) was the largest single non-affiliated purchaser of 2007 production and purchased our share of condensate from the Alba field in Equatorial Guinea. Sales to Marathon accounted for 18% of 2007 crude oil sales, or 10% of 2007 total oil and gas sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2007. 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 remained volatile during 2007 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, to achieve a more predictable cash flow by reducing our exposure to commodity price fluctuations. For additional information, see Item 1A. Risk Factors— Hedging transactions may limit our potential gains , Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging Activities.

 

Regulations

 

Government Regulation — Exploration for, and production and sale 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, 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.

 

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 US Environmental Protection Agency 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 US Environmental Protection Agency, 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 upon our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact upon 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 and income 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 .

 

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 and natural gas acquisition, exploration, development and production: United States, West Africa, North Sea, Israel, and Other International, Corporate and Marketing. For more information, see Item 8. Financial Statements and Supplementary Data—Note 15—Segment Information.

 

Employees

 

Our total number of employees increased during the year from 1,243 at December 31, 2006 to 1,398 at December 31, 2007. The 2007 year-end employee count includes 181 foreign nationals working as employees in Ecuador, China, Israel, the UK, Equatorial Guinea, Cameroon and Suriname.

 

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, Suriname 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 are not so material as to detract substantially 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 “Investor Relations—Investor Relations 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 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.

 

 

 

In 2007, we submitted the annual certification of our Chief Executive Officer regarding compliance with the NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company Manual.