UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
D.C. 20549




FORM 10-K/A




AMENDMENT
NO. 1




(Mark
One)




x
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE
              ACT
      OF 1934




For
the fiscal year ended December 31, 2007


or




o
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934




For
the transition period
from          to





Commission
file number: 001-07964





NOBLE
ENERGY, INC.


(Exact
name of registrant as specified in its charter)




Delaware
            
            73-0785597(State
      of incorporation)
            
            (I.R.S.
      employer identification number)100
      Glenborough Drive, Suite 100Houston,
      Texas
            
            77067(Address
      of principal executive offices)
            
            (Zip
      Code)




(281)
872-3100


(Registrant’s
telephone number, including area code)





Securities
registered pursuant to section 12(b) of the Act:




Title
      of each class
            
            Name
      of each exchange on which registeredCommon
      Stock, $3.33-1/3 par value
            
            New
      York Stock ExchangePreferred
      Stock Purchase Rights
            
            New
      York Stock Exchange




Securities
registered pursuant to section 12(g) of the Act:None


Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. x Yes o No




Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. o Yes x No




Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. x Yes o No




Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of the registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. x




Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
definitions of “accelerated filer”, “large accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):


Large
      accelerated filer x
            Accelerated
      filer o
            Non-accelerated
      filer o
            Smaller
      reporting company o(Do
      not check if a smaller reporting
company)




Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the
Act).oYes xNo




Aggregate
market value of Common Stock held by nonaffiliates as of June 29, 2007:
$10,563,558,607.


Number
of shares of Common Stock outstanding as of February 12, 2008:
171,835,490.




DOCUMENTS
INCORPORATED BY REFERENCE




Portions
of the Registrant’s definitive proxy statement for the 2008 Annual Meeting of
Stockholders held on April 22, 2008 are


incorporated
by reference into Part III. Such definitive
proxy statement was filed on March 21, 2008.










EXPLANATORY
NOTE





We
are filing this amendment to our annual report on Form 10-K for
theyear ended December 31, 2007, filed on February 27, 2008, to
reflect changes made in response to comments we received from the staff of
the Division of Corporation Finance of the Securities and Exchange Commission
("SEC") in connection with the staff’s review of our annual report. This
Amendment No. 1 on Form 10-K/A contains the complete text of Items 1 and 2, Item
1.A and Item 7, as amended. Unaffected Items have not been repeated in this
Amendment No. 1.





Changes
include the following:





·
              Expanded
      disclosure concerning both the general regulations as well as
      environmental regulations faced by us to specify the various regulatory
      bodies with which we interact and the specific laws and regulations to
      which we are subject, with several new paragraphs being added immediately
      after the original paragraph on "Government Regulation".  See
      Items 1 and 2. Business and Properties —GovernmentRegulation, pages
14-15.





·
              Revision
      of risk factors to focus on specific risks relating to us, with added
      disclosure to the risk factors on failure to fund continued capital
      expenditures; international operations; exploration, development and
      production; exploration and development drilling; acquisitions;
      governmental regulations; cost of drilling rigs; and competition. See Item
      1A. Risk Factors, pages
17-22.





·
              Additional
      disclosure concerning the 2006 Equatorial Guinea Hydrocarbons Law. See
      Item 7. Management’s Discussion and Analysis of Financial Condition and
      Results of Operations — Executive
      Overview, page 23.




No
attempt has been made in this Amendment No. 1 on Form 10-K/A to modify
or update the other disclosures presented in the Form 10-K. This Amendment
No. 1 on Form 10-K/A does not reflect events occurring after the
filing of the Form 10-K or modify or update those disclosures. Accordingly,
this Amendment No. 1 on Form 10-K/A should be read in conjunction with
the Form 10-K and our other filings with the SEC.





Currently
dated certifications from our Chief Executive Officer and Chief Financial
Officer as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002
are filed herewith.













TABLE
OF CONTENTS




Part IItems 1 and 2.
            Business and
    Properties.
            1Item 1A.
            Risk Factors.
            17Part IIItem 7.
            Management’s Discussion and Analysis
      of Financial Condition and Results of Operations.
            23Part IVItem 15.
            Exhibits, Financial Statements
      Schedules
            45
















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.







1





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




December
      31, 2007Proved
              
              
              Proved
              
              
              TotalDeveloped
              
              
              Undeveloped
              
              
              ProvedReserves
              
              
              Reserves
              
              
              ReservesUnited
      StatesNatural
      gas (Bcf)
              
              
              1,259
              
              
              
              581
              
              
              
              1,840Crude
      oil (MMBbls)
              
              
              129
              
              
              
              78
              
              
              
              207Total
      US (MMBoe)
              
              
              339
              
              
              
              175
              
              
              
              514InternationalNatural
      gas (Bcf)
              
              
              1,297
              
              
              
              170
              
              
              
              1,467Crude
      oil (MMBbls)
              
              
              100
              
              
              
              22
              
              
              
              122Total
      International (MMBoe)
              
              
              316
              
              
              
              50
              
              
              
              366WorldwideNatural
      gas (Bcf)
              
              
              2,556
              
              
              
              751
              
              
              
              3,307Crude
      oil (MMBbls)
              
              
              229
              
              
              
              100
              
              
              
              329Total
      Worldwide (MMBoe)
              
              
              655
              
              
              
              225
              
              
              
              880




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.







2






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.







3





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:




Year
      Ended December 31, 2007
              
              
              December
      31, 2007Sales
      Volumes
              
              
              Proved
      ReservesNatural
      Gas
              
              
              Crude
      Oil
              
              
              Total
              
              
              Natural
      Gas
              
              
              Crude
      Oil
              
              
              Total(MMcf)
              
              
              (MBbls)
              
              
              (MBoe)
              
              
              (Bcf)
              
              
              (MMBbls)
              
              
              (MMBoe)Northern
      RegionWattenberg
              
              
              59,670
              
              
              
              4,674
              
              
              
              14,619
              
              
              
              893
              
              
              
              109
              
              
              
              258Piceance
              
              
              7,797
              
              
              
              7
              
              
              
              1,307
              
              
              
              183
              
              
              
              -
              
              
              
              31Niobrara
              
              
              7,897
              
              
              
              -
              
              
              
              1,316
              
              
              
              98
              
              
              
              -
              
              
              
              16Other
              
              
              9,392
              
              
              
              53
              
              
              
              1,618
              
              
              
              139
              
              
              
              1
              
              
              
              24Total
              
              
              84,756
              
              
              
              4,734
              
              
              
              18,860
              
              
              
              1,313
              
              
              
              110
              
              
              
              329Southern
      RegionDeepwater
      Gulf of Mexico
              
              
              18,722
              
              
              
              5,847
              
              
              
              8,967
              
              
              
              79
              
              
              
              21
              
              
              
              34Mid-continent
              
              
              30,760
              
              
              
              3,340
              
              
              
              8,467
              
              
              
              341
              
              
              
              51
              
              
              
              108Gulf
      Coast onshore and other
              
              
              16,219
              
              
              
              1,530
              
              
              
              4,233
              
              
              
              107
              
              
              
              25
              
              
              
              43Total
              
              
              65,701
              
              
              
              10,717
              
              
              
              21,667
              
              
              
              527
              
              
              
              97
              
              
              
              185Total
      United States
              
              
              150,457
              
              
              
              15,451
              
              
              
              40,527
              
              
              
              1,840
              
              
              
              207
              
              
              
              514







4





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




Year
      EndedDecember
      31, 2007
              
              
              December
      31, 2007Gross
      Wells Drilled/
              
              
              GrossParticipated
      in
              
              
              Productive
      WellsNorthern
      RegionWattenberg
              
              
              508
              
              
              5,161Piceance
              
              
              55
              
              
              112Niobrara
              
              
              125
              
              
              744Other
              
              
              56
              
              
              1,239Total
              
              
              744
              
              
              7,256Southern
      RegionDeepwater
      Gulf of Mexico
              
              
              6
              
              
              13Mid-continent
              
              
              147
              
              
              3,981Gulf
      Coast onshore and other
              
              
              38
              
              
              457Total
              
              
              191
              
              
              4,451Total
      United States
              
              
              935
              
              
              11,707




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.







5







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.







6









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 continue 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.







7





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




Year
      Ended December 31, 2007
              
              
              December
      31, 2007Sales
      Volumes
              
              
              Proved
      ReservesNatural
      Gas
              
              
              Crude
      Oil
              
              
              Total
              
              
              Natural
      Gas
              
              
              Crude
      Oil
              
              
              Total(MMcf)
              
              
              (MBbls)
              
              
              (MBoe)
              
              
              (Bcf)
              
              
              (MMBbls)
              
              
              (MMBoe)InternationalWest
      Africa
              
              
              48,349
              
              
              
              5,500
              
              
              
              13,558
              
              
              
              941
              
              
              
              82
              
              
              
              239North
      Sea
              
              
              2,276
              
              
              
              4,564
              
              
              
              4,943
              
              
              
              19
              
              
              
              25
              
              
              
              28Israel
              
              
              40,449
              
              
              
              -
              
              
              
              6,742
              
              
              
              319
              
              
              
              -
              
              
              
              53Ecuador
              
              
              9,385
              
              
              
              -
              
              
              
              1,564
              
              
              
              188
              
              
              
              -
              
              
              
              31China
              
              
              -
              
              
              
              1,402
              
              
              
              1,402
              
              
              
              -
              
              
              
              8
              
              
              
              8Argentina
              
              
              -
              
              
              
              1,034
              
              
              
              1,034
              
              
              
              -
              
              
              
              7
              
              
              
              7Total
      consolidated
              
              
              100,459
              
              
              
              12,500
              
              
              
              29,243
              
              
              
              1,467
              
              
              
              122
              
              
              
              366Equity
      investees:Condensate
      (MBbls)
              
              
              -
              
              
              
              670
              
              
              
              670LPG
      (MBbls)
              
              
              -
              
              
              
              2,135
              
              
              
              2,135Total
              
              
              100,459
              
              
              
              15,305
              
              
              
              32,048Equity
      investee share ofmethanol
      sales (Kgal)
              
              
              
              
              
              
              
              
              
              
              160,540




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




Year
      EndedDecember
      31, 2007
              
              
              December
      31, 2007Gross
      Wells
              
              
              GrossDrilled/Participated
      in
              
              
              Productive
      WellsInternationalWest
      Africa
              
              
              7
              
              
              
              20North
      Sea
              
              
              2
              
              
              
              22Israel
              
              
              1
              
              
              
              8Ecuador
              
              
              -
              
              
              
              5China
              
              
              -
              
              
              
              16Argentina
              
              
              50
              
              
              
              732Total
      International
              
              
              60
              
              
              
              803




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.







8





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.




North Sea—Operations in the
North Sea (the Netherlands, Norway and the UK) comprise another core
international asset, and we have been conducting business there since 1996. We
have working interests in 23 licenses with working interests ranging from 7% to
100%. We are the operator of four blocks, covered by three
licenses.  The North Sea accounted for 17% of 2007 consolidated
international sales volumes and 8% of international proved reserves at
December 31, 2007. At December 31, 2007, we held 48,230 gross
developed acres and 836,625 gross undeveloped acres.




In
January 2007, production began at the non-operated Dumbarton development (30%
working interest) in Blocks 15/20a and 15/20b in the UK sector of the North Sea.
Dumbarton, a re-development of the Donan field, includes a subsea tie-back to
the GP III, a floating production, storage and offloading vessel in which we own
a 30% interest. We expect to continue the development of Dumbarton in 2008 with
phases 2a and 2b. In addition, we will participate in the development of the
Lochranza prospect, which will also consist of a subsea tie-back to the GP
III.




Exploration
efforts continued in 2007 as we and our partners successfully completed an
exploratory appraisal well on the Flyndre Block (22.5% working interest) in the
UK sector of the North Sea.  We also participated in a successful
exploration well at Selkirk in Block 22/22b P233 (30.5% working interest), also
in the UK sector of the North Sea.




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.




We
have been operating in the Mediterranean Sea, offshore Israel, since 1998, and
our 47% working interest in the Mari-B field is one of our core international
assets. The Mari-B field is the first offshore natural gas production facility
in the State of Israel. During 2007, we completed the Mari-B #7, which is
designed to produce twice what a normal
Mari-B well produces in Israel, or approximately 200 MMcfpd of natural gas. The
Mari-B#7 well has resulted in peak field deliverability of 600
MMcfpd.







9







Natural
gas sales began in 2004 and have been increasing steadily as Israel’s natural
gas infrastructure has developed. In 2007, our gas sales volumes increased 19%
over 2006 volumes and 67% over 2005 volumes. During 2007 we completed
construction of a permanent onshore receiving terminal in Ashdod for
distribution of natural gas from the Mari-B field to purchasers. Commissioning
of the terminal is expected in early 2008. We also began selling natural gas to
a desalinization plant and a paper mill in 2007. Additional natural gas sales in
2008 will depend on the timing of onshore pipeline construction and plant
conversion, which should allow the Israel Electric
Corporation Limitedpower plants at Gezer and Hagit to consume
gas.




Exploration
activities continue in Israel. We are in the process of securing a rig and
intend to drill one exploration well testing the Tamar prospect (33% working
interest), offshore northern Israel, in 2008.




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.







10





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




AverageSales
      Volumes(1)
              
              
              Average
      Sales Price
              
              
              Production
      CostNatural
      Gas
              
              
              Crude
      Oil
              
              
              Natural
      Gas
              
              
              Crude
      OilMMcf
              
              
              MBbls
              
              
              Per
      Mcf (2)
              
              
              Per
      Bbl (2)
              
              
              Per
      BOE(3)Year
      Ended December 31, 2007United
      States
              
              
              150,457
              
              
              
              15,451
              
              
              $
              7.51
              
              
              $
              53.22
              
              
              $
              8.49West
      Africa (4)
      (5)
              
              
              48,349
              
              
              
              5,500
              
              
              
              0.29
              
              
              
              71.27
              
              
              
              2.89North
      Sea
              
              
              2,276
              
              
              
              4,564
              
              
              
              6.54
              
              
              
              76.47
              
              
              
              9.81Israel
              
              
              40,449
              
              
              
              -
              
              
              
              2.79
              
              
              
              -
              
              
              
              1.14Other
      International (6)
              
              
              9,385
              
              
              
              2,436
              
              
              
              -
              
              
              
              53.69
              
              
              
              12.06Total
      Consolidated Operations
              
              
              250,916
              
              
              
              27,951
              
              
              
              5.26
              
              
              
              60.61
              
              
              
              6.99Equity
      Investee (7)
              
              
              -
              
              
              
              2,805
              
              
              
              -
              
              
              
              55.09Total
              
              
              250,916
              
              
              
              30,756
              
              
              $
              5.26
              
              
              $
              60.10Year
      Ended December 31, 2006United
      States
              
              
              164,875
              
              
              
              16,715
              
              
              $
              6.61
              
              
              $
              50.68
              
              
              $
              8.12West
      Africa (4)
      (5)
              
              
              16,579
              
              
              
              6,519
              
              
              
              0.37
              
              
              
              62.51
              
              
              
              2.86North
      Sea
              
              
              2,967
              
              
              
              1,357
              
              
              
              8.00
              
              
              
              67.43
              
              
              
              10.08Israel
              
              
              33,906
              
              
              
              -
              
              
              
              2.72
              
              
              
              -
              
              
              
              1.60Other
      International (6)
              
              
              9,041
              
              
              
              2,752
              
              
              
              0.96
              
              
              
              52.05
              
              
              
              9.74Total
      Consolidated Operations
              
              
              227,368
              
              
              
              27,343
              
              
              
              5.55
              
              
              
              54.47
              
              
              
              6.97Equity
      Investee (7)
              
              
              -
              
              
              
              2,931
              
              
              
              -
              
              
              
              45.83Total
              
              
              227,368
              
              
              
              30,274
              
              
              $
              5.55
              
              
              $
              53.64Year
      Ended December 31, 2005United
      States
              
              
              125,543
              
              
              
              9,468
              
              
              $
              7.43
              
              
              $
              46.67
              
              
              $
              7.39West
      Africa (4)
      (5)
              
              
              23,938
              
              
              
              6,492
              
              
              
              0.25
              
              
              
              42.51
              
              
              
              2.93North
      Sea
              
              
              3,394
              
              
              
              1,964
              
              
              
              5.93
              
              
              
              52.68
              
              
              
              7.54Israel
              
              
              24,228
              
              
              
              -
              
              
              
              2.68
              
              
              
              -
              
              
              
              2.11Other
      International (6)
              
              
              8,389
              
              
              
              2,866
              
              
              
              1.10
              
              
              
              42.37
              
              
              
              7.15Total
      Consolidated Operations
              
              
              185,492
              
              
              
              20,790
              
              
              
              5.78
              
              
              
              45.35
              
              
              
              6.06Equity
      Investee (7)
              
              
              -
              
              
              
              1,183
              
              
              
              -
              
              
              
              43.43Total
              
              
              185,492
              
              
              
              21,973
              
              
              $
              5.78
              
              
              $
              45.25





(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.





11







(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.


(6)
            Other
      International natural gas volumes include Ecuador and Argentina. Although
      Ecuador natural gas volumes are included in Other International
      production, they are excluded from average natural gas sales prices. We
      own 100% of the natural gas-to-power project in Ecuador and intercompany
      natural gas sales are eliminated. Natural gas production volumes
      associated with the gas-to-power project were 9,385 MMcf for 2007, 8,933
      MMcf for 2006 and 8,321 MMcf for 2005. Other International oil includes
      China and Argentina.


(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:




Crude
      Oil Wells
              
              
              Natural
      Gas Wells
              
              
              TotalGross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              NetUnited
      States - Onshore
              
              
              7,055
              
              
              
              5,997.8
              
              
              
              4,609
              
              
              
              3,134.5
              
              
              
              11,664
              
              
              
              9,132.3United
      States - Offshore
              
              
              28
              
              
              
              26.1
              
              
              
              15
              
              
              
              8.1
              
              
              
              43
              
              
              
              34.2West
      Africa
              
              
              1
              
              
              
              0.4
              
              
              
              19
              
              
              
              7.2
              
              
              
              20
              
              
              
              7.6North
      Sea
              
              
              15
              
              
              
              2.7
              
              
              
              7
              
              
              
              0.7
              
              
              
              22
              
              
              
              3.4Israel
              
              
              -
              
              
              
              -
              
              
              
              8
              
              
              
              3.8
              
              
              
              8
              
              
              
              3.8Ecuador
              
              
              -
              
              
              
              -
              
              
              
              5
              
              
              
              5.0
              
              
              
              5
              
              
              
              5.0China
              
              
              16
              
              
              
              9.1
              
              
              
              -
              
              
              
              -
              
              
              
              16
              
              
              
              9.1Argentina
              
              
              732
              
              
              
              95.4
              
              
              
              -
              
              
              
              -
              
              
              
              732
              
              
              
              95.4Total
              
              
              7,847
              
              
              
              6,131.5
              
              
              
              4,663
              
              
              
              3,159.3
              
              
              
              12,510
              
              
              
              9,290.8Multiple
      Completions
              
              
              8
              
              
              
              5.9
              
              
              
              14
              
              
              
              3.6
              
              
              
              22
              
              
              
              9.5




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.







12










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




Developed
      Acreage
              
              
              Undeveloped
      AcreageGross
              
              
              Net
              
              
              Gross
              
              
              NetUnited
      StatesOnshore
              
              
              1,308,823
              
              
              
              835,445
              
              
              
              1,234,858
              
              
              
              786,391Offshore
              
              
              147,945
              
              
              
              94,963
              
              
              
              485,258
              
              
              
              227,627Total
      United States
              
              
              1,456,768
              
              
              
              930,408
              
              
              
              1,720,116
              
              
              
              1,014,018Equatorial
      Guinea
              
              
              45,203
              
              
              
              15,727
              
              
              
              850,197
              
              
              
              379,026Cameroon
              
              
              -
              
              
              
              -
              
              
              
              1,125,000
              
              
              
              562,500North
      Sea (1)
              
              
              48,230
              
              
              
              5,671
              
              
              
              836,625
              
              
              
              339,151Israel
              
              
              123,552
              
              
              
              58,142
              
              
              
              1,183,479
              
              
              
              532,818China
              
              
              7,413
              
              
              
              4,225
              
              
              
              -
              
              
              
              -Ecuador
              
              
              12,355
              
              
              
              12,355
              
              
              
              851,771
              
              
              
              851,771Argentina
              
              
              113,325
              
              
              
              15,548
              
              
              
              -
              
              
              
              -Suriname
              
              
              -
              
              
              
              -
              
              
              
              7,740,328
              
              
              
              6,362,884Total
      International
              
              
              350,078
              
              
              
              111,668
              
              
              
              12,587,400
              
              
              
              9,028,150Total
      Worldwide(2)
              
              
              1,806,846
              
              
              
              1,042,076
              
              
              
              14,307,516
              
              
              
              10,042,168




(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:




Net
      Exploratory Wells
              
              
              Net
      Development WellsProductive
              
              
              Dry
              
              
              Total
              
              
              Productive
      (1)
              
              
              Dry
              
              
              TotalYear
      Ended December 31, 2007United
      States
              
              
              14.2
              
              
              
              4.5
              
              
              
              18.7
              
              
              
              757.6
              
              
              
              27.6
              
              
              
              785.2West
      Africa
              
              
              2.6
              
              
              
              0.5
              
              
              
              3.1
              
              
              
              -
              
              
              
              -
              
              
              
              -North
      Sea
              
              
              0.5
              
              
              
              -
              
              
              
              0.5
              
              
              
              -
              
              
              
              -
              
              
              
              -Israel
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              0.4
              
              
              
              -
              
              
              
              0.4Argentina
              
              
              -
              
              
              
              0.1
              
              
              
              0.1
              
              
              
              6.7
              
              
              
              -
              
              
              
              6.7Total
              
              
              17.3
              
              
              
              5.1
              
              
              
              22.4
              
              
              
              764.7
              
              
              
              27.6
              
              
              
              792.3Year
      Ended December 31, 2006United
      States
              
              
              6.3
              
              
              
              9.0
              
              
              
              15.3
              
              
              
              666.6
              
              
              
              5.5
              
              
              
              672.1West
      Africa
              
              
              -
              
              
              
              0.4
              
              
              
              0.4
              
              
              
              1.8
              
              
              
              -
              
              
              
              1.8North
      Sea
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1.1
              
              
              
              -
              
              
              
              1.1Argentina
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              7.6
              
              
              
              -
              
              
              
              7.6Total
              
              
              6.3
              
              
              
              9.4
              
              
              
              15.7
              
              
              
              677.1
              
              
              
              5.5
              
              
              
              682.6Year
      Ended December 31, 2005United
      States
              
              
              4.7
              
              
              
              10.7
              
              
              
              15.4
              
              
              
              488.1
              
              
              
              25.9
              
              
              
              514.0West
      Africa
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              0.3
              
              
              
              -
              
              
              
              0.3North
      Sea
              
              
              -
              
              
              
              0.2
              
              
              
              0.2
              
              
              
              -
              
              
              
              -
              
              
              
              -Argentina
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              7.7
              
              
              
              -
              
              
              
              7.7Total
              
              
              4.7
              
              
              
              10.9
              
              
              
              15.6
              
              
              
              496.1
              
              
              
              25.9
              
              
              
              522.0




(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.







13





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.




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 and the Minerals Management Service, 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
      Environmental Protection Agency 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 and the Occupational Safety and
      Health Act 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
      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 Securities and Exchange Commission, as
      well as the NYSE upon which shares of our common stock are
      traded.





Most
of the states within which we operate have separate agencies with authority to
regulate related operational and environmental matters.  An example of
such regulation on the operational side is 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.  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 US
Environmental Protection Agency, to regulate air emissions, water protection and
waste handling and disposal relating to our oil and gas exploration and
production.





14








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 Petroleum and Mines, the Equatorial Guinea Ministry of
Mines, Industry and Energy and the UK Department for Business, Enterprise and
Regulatory Reform.  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 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.







15









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.







16





Item 1A. Risk Factors.




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. 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 producing or natural gas producing
regions;


·
            the
      level of global crude oil and natural gas
  inventories;


·
            the
      price and level of foreign imports;


·
            the
      price and availability of alternative
fuels;


·
            the
      availability of pipeline capacity and
  infrastructure;


·
            the
      availability of crude oil transportation and refining
      capacity;


·
            weather
      conditions;


·
            electricity
      dispatch;


·
            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, ability to finance planned capital
      expenditures and results of
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
flow;


·
            reducing
      the carrying value of our crude oil and natural gas properties;
      or


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





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 many 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. Our reserve estimates are based on year-end commodity prices; therefore,
reserve 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;


·
            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 based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates.







17





Additionally,
because some of our reserve estimates are calculated using volumetric analysis,
those estimates are less reliable than the estimates based on a lengthy
production history. Volumetric analysis involves estimating the volume of a
reservoir based on the net feet of pay of the structure and an estimation of the
area covered by the structure. In addition, realization or recognition of proved
undeveloped reserves will depend on our development schedule and plans. A change
in future development plans for proved undeveloped reserves could cause the
discontinuation of the classification of these reserves as proved.




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




Ouracquisition, exploration, and development 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
program in West Africa. Historically, we have funded our capital expenditures
through a combination of cash flows from operations, our revolving bank credit
facility and debt and equity 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 revenue were to decrease as a result of lower crude
oil and natural gas prices or decreased production, and our access to capital
were limited, we would have a reduced ability to replace our reserves, resulting
in a decrease in production over time. If our cash flow from operations is not
sufficient to meet our obligations and fund our capital budget, we may not be
able to access debt, equity or other methods of financing 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.




A
recession or an economic slowdown could have a material adverse impact on our
financial position, results of operations and cash flows.




The
oil and gas industry is cyclical in nature and tends to reflect general economic
conditions. Currently, the US economy is slowing and may be headed toward a
recession. A recession may lead to significant fluctuations in demand and
pricing for our crude oil and natural gas production. If we were to continue
development of our property interests after a decline in the prices of crude oil
and natural gas had occurred, our profitability may be significantly affected by
decreased demand and lower commodity prices. In addition, our future access to
capital could be limited due to tightening credit markets.




Our
international operations may be adversely affected by economic and political
developments.




We
have significant international crude oil and natural gas operationscompared to companies we
consider to be our peers, with approximately 42% of our consolidated sales
volumes in 2007 coming from international operations. These operations may be
adversely affected by political and economic developments, including the
following:




·
            war,
      terrorist acts and civil disturbances, such as may occur in regions that
      encompass our operations in Ecuador, Israel and West
    Africa;


·
            loss
      of revenue, property and equipment as a result of actions taken by foreign
      crude oil and natural gas producing nations, such as expropriation or
      nationalization of assets and renegotiation, modification or nullification
      of existing contracts, such as may occur pursuant to the hydrocarbons law
      enacted in 2006 by the government of Equatorial
  Guinea;


·
            changes
      in taxation policies, such as the UK Finance Act of 2006, which increased
      the income tax rate on our UK operations effective January 1, 2006, and
      the China Petroleum Special Profits Tax enacted in 2006, which imposed an
      excise tax on crude oil produced in the
country;


·
            laws
      and policies of the US and foreign jurisdictions affecting foreign
      investment, taxation, trade and business
  conduct;


·
            foreign
      exchange restrictions;


·
            international
      monetary fluctuations and changes in the value of the US dollar, such as
      the decline of the US dollar against the pound sterling given that some of
      our North Sea development expenditures are paid in pound sterling;
      and


·
            other
      hazards arising out of foreign governmental sovereignty over areas in
      which we conduct operations.






18




Exploration,
development and production risks and natural disasters could result in liability
exposure or the loss of production and revenues.
  Ouroperations are subject
to hazards and risks inherent in the drilling, production and transportation of
crude oil and natural gas, including:
  ·
              pipeline
      ruptures and spills;


·
            fires;


·
            explosions,
      blowouts and cratering;


·
            formations
      with abnormal pressures;


·
            equipment
      malfunctions;


·
            hurricanes,
      which could affect our operations in areas such as the Gulf Coast and
      deepwater Gulf of Mexico, and cyclones, which could affect our operations
      offshore China; and


·
            other
      natural disasters.







Any
of these can result in loss of hydrocarbons, environmental pollution and other
damage to our properties or the properties of others.




Exploration
and development drilling may not result in commercially productive
reserves.




We
do not always encounter commercially productive reservoirs through our drilling
operations. The wells we drill or participate in may not be productive and we
may not recover all or any portion of our investment in those wells. The seismic
data and other technologies we use do not allow us to know conclusively prior to
drilling a well that crude oil or natural gas is present or may be produced
economically, and area well data and other data may be limited or less-developed
in some of the international areas in which we explore. The cost of drilling,
completing and operating a well is often uncertain, and cost factors can
adversely affect the economics of a project. Our efforts will be unprofitable if
we drill dry holes or wells that are productive but do not produce enough
reserves to return a profit after drilling, operating and other costs. Further,
our drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including:




·
            unexpected
      drilling conditions;


·
            title
      problems;


·
            pressure
      or other irregularities in
formations;


·
            equipment
      failures or accidents;


·
            adverse
      weather conditions;


·
            compliance
      with environmental and other governmental requirements;
  and


·
            increases
      in the cost of, or shortages or delays in the availability of, drilling
      rigs and equipment.





We
may be unable to make attractive acquisitions or integrate acquired businesses
and/or assets, and any inability to do so may disrupt 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 and
our purchase of U.S. Exploration.  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 of them or do so on commercially acceptable terms.
Additionally, if we acquire another business, we could have difficulty
integrating its operations, systems, management and other personnel and
technology with our own. These difficulties could 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 would be
realized.




We
are subject to various governmental regulations and environmental risks that may
cause us to incur substantial costs.




From
time to time, in varying degrees, political developments and federal and state
laws and regulations affect our operations. In particular, price controls, taxes
and other laws relating to the crude oil and natural gas industry, changes in
these laws and changes in administrative regulations have affected and in the
future could affect crude oil and natural gas production, operations and
economics. We cannot predict how agencies or courts will interpret existing laws
and regulations or the effect these adoptions and interpretations may have on
our business or financial condition.




Our
business is subject to laws and regulations promulgated by international,
federal, state and local authorities relating to the exploration for, and the
development, production and marketing of, crude oil and natural gas, as well as
safety matters. Legal requirements are frequently changed and subject to
interpretation and we are unable to predict the ultimate cost of compliance with
these requirements or their effect on our operations. We may be required to make
significant expenditures to comply with governmental laws and
regulations.







19





Our
operations are subject to complex international, federal, state and local
environmental laws and regulations including, for example, in the case of
federal laws, 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
and the Occupational Safety and Health Act. Environmental laws and regulations
change frequently and the implementation of new, or the modification of
existing, laws or regulations could negatively impact our operations. The
discharge of natural gas, crude oil, or other pollutants into the air, soil or
water may give rise to significant liabilities on our part to the government and
third parties and may require us to incur substantial costs of
remediation.




Potential
regulations regarding climate change could alter the way we conduct our
business.




As
awareness of climate change issues increases, governments around the world are
beginning to address the issue. This may result in new environmental regulations
that may unfavorably impact us, our suppliers, and our customers. The cost of
meeting these requirements may have an adverse impact on our financial
condition, results of operations and cash flows.




The
unavailability or high cost of drilling rigs, equipment, supplies, personnel and
other oil field services could adversely affect our ability to execute our
exploration and development plans on a timely basis and within our
budget.




Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies or qualified personnel. During these periods, the
costs of rigs, equipment and supplies are substantially greater and their
availability may be limited, particularly in areas of high activity and demand
in which we concentrate, such as the Rocky Mountains and deepwater Gulf of
Mexico, and in some international locations that typically have more limited
availability of equipment and personnel, such as Ecuador and Israel. As a result
of increasing levels of exploration and production in response to strong demand
for crude oil and natural gas, the demand for oilfield services and the costs of
these services have increased. Additionally, these services may not be available
on commercially reasonable terms.




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. 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 prudent. 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.




We
face significant competition and many of our competitors have resources in
excess of our available resources.




We
operate in the highly competitive areas of crude oil and natural gas
exploration, exploitation, acquisition and production. We face intense
competition from a large number of independent, technology-driven companies as
well as both major and other independent crude oil and natural gas companies in
a number of areas such as:




·
            seeking
      to acquire desirable producing properties or new leases for future
      exploration;


·
            marketing
      our crude oil and natural gas
production;


·
            seeking
      to acquire the equipment and expertise necessary to operate and develop
      properties; and


·
            attracting
      and retaining employees with certain
skills.





Many
of our competitors have financial and other resources substantially in excess of
those available to us. For example, in the deepwater Gulf of Mexico we compete
with major integrated crude oil and natural gas companies and in international
locations such as the North Sea we compete with major integrated crude oil and
natural gas companies as well as state-controlled multinational companies. This
highly competitive environment could have an adverse impact on our
business.







20





Our
level of indebtedness may limit our financial flexibility.




As
of December 31, 2007, we had long-term indebtedness of $1.9 billion
(excluding unamortized discount), with $1.2 billion drawn under our bank
credit facility. Our indebtedness represented 28% of our total book
capitalization at December 31, 2007.




Our
level of 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;


·
            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 acquisition, exploration and
development activities. A higher level of indebtedness increases the risk that
we may 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 manage our exposure to price risks in 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 four 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. In trying to manage our exposure to 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 future 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 any decline in crude oil or natural gas
prices.




Information
technology systems implementation issues could disrupt our internal operations,
increase our costs and adversely affect our financial results or our ability to
report our financial results.




We
are currently in the process of implementing a new Enterprise Resource Planning
software system to replace our various legacy systems. Our implementation is
based on a phased approach, the first phase of which was implemented fourth
quarter 2007. We expect to implement additional phases during 2008. As a part of
this effort, we are transitioning data and changing processes and this may be
more expensive, time consuming and resource intensive than planned. Any
disruptions that may occur in the implementation or operation of this system or
any future systems could increase our expenses and adversely affect our ability
to report in an accurate and timely manner our financial position, results of
operations and cash flows and to otherwise operate our business.







21





Provisions
in our Certificate of Incorporation and Delaware law may inhibit a takeover of
us.




Under
our Certificate of Incorporation, our Board of Directors is authorized to issue
shares of our common or preferred stock without approval of our stockholders.
Issuance of these shares could make it more difficult to acquire us without the
approval of our Board of Directors as more shares would have to be acquired to
gain control. In addition, Delaware law imposes restrictions on mergers and
other business combinations between us and any holder of 15% or more of our
outstanding common stock. These provisions may deter hostile takeover attempts
that could result in an acquisition of us that would have been financially
beneficial to our stockholders.




Disclosure
      Regarding Forward-Looking
Statements




This
annual report on Form 10-K and the documents incorporated by reference in
this report contain forward-looking statements within the meaning of the federal
securities laws. Forward-looking statements give our current expectations or
forecasts of future events. These forward-looking statements include, among
others, the following:




·
            our
      growth strategies;


·
            our
      ability to successfully and economically explore for and develop crude oil
      and natural gas resources;


·
            anticipated
      trends in our business;


·
            our
      future results of operations;


·
            our
      liquidity and ability to finance our acquisition, exploration and
      development activities;


·
            market
      conditions in the oil and gas
industry;


·
            our
      ability to make and integrate acquisitions;
and


·
            the
      impact of governmental regulation.





Forward-looking
statements are typically identified by use of terms such as “may,” “will,”
“expect,” “anticipate,” “estimate” and similar words, although some
forward-looking statements may be expressed differently. These forward-looking
statements are made based upon management’s current plans, expectations,
estimates, assumptions and beliefs concerning future events impacting us and
therefore involve a number of risks and uncertainties. We caution that
forward-looking statements are not guarantees and that actual results could
differ materially from those expressed or implied in the forward-looking
statements. You should consider carefully the statements under Item 1A. Risk
Factors and other sections of this report, which describe factors that could
cause our actual results to differ from those set forth in the forward-looking
statements.












22




PART II.


Item
      7.
            Management’s Discussion and Analysis of
      Financial Condition and Results of
  Operations.




We
are an independent energy company engaged in the acquisition, exploration,
development, production and marketing of crude oil and natural gas domestically
and internationally. We operate throughout major basins in the 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. We also conduct business
internationally, in China, Ecuador, the Mediterranean Sea, the North Sea, West
Africa (Equatorial Guinea and Cameroon) and in other areas.




Our
accompanying consolidated financial statements, including the notes thereto,
contain detailed information that should be referred to in conjunction with the
following discussion.




EXECUTIVE
      OVERVIEW




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 diversified between US and
international projects. The Patina Merger, purchase of U.S. Exploration and sale
of Gulf of Mexico shelf properties have allowed us to achieve a strategic
objective of enhancing our US asset portfolio. The result is a company with
assets and capabilities that include growing US basins coupled with a
significant portfolio of international properties. Our reserve base includes
both US and international sources at 58% US and 42% international. We are now a
larger, more diversified company with greater opportunities for both US and
international growth.




2007
was a strong year for us, both financially and operationally. Significant
financial results included the following:




·
            net
      income of $944 million, a 39% increase over 2006 net
      income;


·
            diluted
      earnings per share of $5.45, a 44% increase over
  2006;


·
            cash
      flow provided by operating activities of $2.0 billion, a 17% increase over
      2006; and


·
            completion
      of  a $500 million common stock repurchase program begun in
      2006.





Significant
operational highlights included the following:




·
            eight
      successful exploration wells drilled internationally, six offshore West
      Africa and two in the North Sea;


·
            deepwater
      Gulf of Mexico exploration success at Isabela (Mississippi Canyon Block
      562);


·
            commencement
      of production and continued ramp-up at the Dumbarton development and
      successful exploratory appraisal well drilled at the Flyndre prospect in
      the UK sector of the North Sea;


·
            completion
      of the Mari-B #7 well and record natural gas sales in
    Israel;


·
            continued
      success of development program in the US Wattenberg
      field;  and


·
            acquisition
      of approximately 290,000 net acres onshore US in the Piceance basin,
      Niobrara trend and New Albany Shale
areas.





Sale of 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.




Equatorial Guinea 2006 Hydrocarbons
Law—Effective November 2006, the government of Equatorial Guinea
enacted 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. The stated purpose of the
law is to modify the legal framework in order to deal with a variety of matters
that were not previously or adequately covered, with the law addressing areas
such as minimum participation of the state in contract areas, training and
social programs and the establishment of environmental programs.At
this time we are uncertain what economic impact this law will have on our
operations in Equatorial Guinea, as regulations contemplated by the law have not
been implemented and the application of certain of the law’s provisions is
unknown.







23





2008
OUTLOOK




We
expect crude oil and natural gas production to increase in 2008 compared to
2007. Factors which may impact our expected year-over-year increase in
production include:




·
            higher
      sales of natural gas from the Alba field in Equatorial Guinea;
      and


·
            growing
      production from the D-J and Piceance basins, where we are continuing
      active drilling programs;


offset
      by:


·
            natural
      field decline in the Gulf Coast
area.







Factors
which may impact our expected production profile include:




·
            potential
      hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast
      areas;


·
            potential
      winter storm-related volume curtailments in the Northern region of our US
      operations;


·
            potential
      pipeline and processing facility capacity constraints in the Rocky
      Mountain area of our US operations;


·
            infrastructure
      development in Israel;


·
            potential
      downtime at the methanol, LPG and/or LNG facilities in Equatorial
      Guinea;


·
            seasonal
      variations in rainfall in Ecuador that affect our natural gas-to-power
      project; and


·
            timing
      of capital expenditures, as discussed below, which are expected to result
      in near-term production.







2008 Budget—We have budgeted
capital expenditures of approximately $1.6 billion for 2008. Approximately24%of
the 2008 capital budget has been allocated to exploration opportunities and 76%
has been allocated to production, development and other projects. US spending is
budgeted for $1.2 billion, international expenditures are budgeted for$392
million and corporate expenditures are budgeted for $27million.
The 2008 budget does not include the impact of possible asset purchases. We
expect that the 2008 capital budget will be funded primarily from cash flows
from operations and borrowings under our revolving credit facility. We will
evaluate the level of capital spending throughout the year based on drilling
results, commodity prices, cash flows from operations and property acquisitions
and divestitures.




CRITICAL
      ACCOUNTING POLICIES AND ESTIMATES




The
preparation of the consolidated financial statements requires our management to
make a number of estimates and assumptions relating to the reported amounts of
assets and liabilities and the disclosures of contingent assets and liabilities
at the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the period. When alternatives exist among various
accounting methods, the choice of accounting method can have a significant
impact on reported amounts. The following is a discussion of the accounting
policies, estimates and judgments which management believes are most significant
in the application of generally accepted accounting principles used in the
preparation of the consolidated financial statements.




Purchase Price Allocation—As
a result of the Patina Merger in 2005 and the acquisition of U.S. Exploration in
2006, we acquired assets and assumed liabilities in transactions accounted for
as purchases. In connection with a purchase business combination, the acquiring
company must allocate the cost of the acquisition to assets acquired and
liabilities assumed based on fair values as of the acquisition date. Deferred
taxes must be recorded for any differences between the assigned values and tax
bases of assets and liabilities. Any excess of purchase price over amounts
assigned to assets and liabilities is recorded as goodwill. The amount of
goodwill recorded in any particular business combination can vary significantly
depending upon the value attributed to assets acquired and liabilities
assumed.




In
estimating the fair values of assets acquired and liabilities assumed we made
various assumptions. The most significant assumptions related to the estimated
fair values assigned to proved and unproved crude oil and natural gas
properties. To estimate the fair values of these properties, we prepared
estimates of crude oil and natural gas reserves. We estimated future prices to
apply to the estimated reserve quantities acquired, and estimated future
operating and development costs, to arrive at estimates of future net cash
flows. For estimated proved reserves, the future net cash flows were discounted
using a market-based weighted average cost of capital rate determined
appropriate at the time of the merger. The market-based weighted average cost of
capital rate was subjected to additional project-specific risking factors. To
compensate for the inherent risk of estimating and valuing unproved reserves,
the discounted future net cash flows of probable and possible reserves were
reduced by additional risk-weighting factors.







24





Estimated
deferred taxes were based on available information concerning the tax basis of
assets acquired and liabilities assumed and loss carryforwards at the merger
date, although such estimates may change in the future as additional information
becomes known.




While
the estimates of fair value for the assets acquired and liabilities assumed have
no effect on our cash flows, they can have an effect on the future results of
operations. Generally, higher fair values assigned to crude oil and natural gas
properties result in higher future depreciation, depletion and amortization
(“DD&A”) expense, which results in decreased future net earnings. Also, a
higher fair value assigned to crude oil and natural gas properties, based on
higher estimates of future crude oil and natural gas prices, could increase the
likelihood of impairment in the event of lower commodity prices or higher
operating or development costs than those originally used to determine fair
value. Impairment would have no effect on cash flows but would result in a
decrease in net income for the period in which the impairment is
recorded.




Goodwill—As of
December 31, 2007, the consolidated balance sheet included
$760 million of goodwill, all of which has been assigned to the US
reporting unit. Goodwill is not amortized to earnings but is tested, at least
annually, for impairment at the reporting unit level. We conduct the goodwill
impairment test as of December 31 of each year. Other events and changes in
circumstances may also require goodwill to be tested for impairment between
annual measurement dates. If the carrying value of goodwill is determined to be
impaired, the amount of goodwill is reduced and a corresponding charge is made
to earnings in the period in which the goodwill is determined to be
impaired.




The
impairment assessment requires management to make estimates regarding the fair
value of the reporting unit to which goodwill has been assigned. The fair value
of the US reporting unit was determined using a combination of the income
approach and the market approach. Under the income approach, the fair value of
the reporting unit is estimated based on the present value of expected future
cash flows. Under the market approach, the fair value is estimated based on
selected financial metrics.




The
income approach is dependent on a number of factors including estimates of
forecasted revenue and operating costs, proved reserves, as well as the success
of future exploration for and development of unproved reserves, appropriate
discount rates and other variables. Downward revisions of estimated reserve
quantities, increases in future cost estimates, divestiture of a significant
component of the reporting unit, or sustained decreases in natural gas or crude
oil prices could lead to an impairment of all or a portion of goodwill in future
periods. Under the market approach, we make certain judgments about the
selection of comparable companies, comparable recent company and asset
transactions and transaction premiums. Although we have based the fair value
estimate on assumptions we believe to be reasonable, those assumptions are
inherently unpredictable and uncertain and actual results could differ from the
estimate. In 2007, no goodwill impairment was recognized.




When
we dispose of a reporting unit or a portion of a reporting unit that constitutes
a business, we include goodwill associated with that business in the carrying
amount of the business in order to determine the gain or loss on disposal. The
amount of goodwill to be included in that carrying amount is based on the
relative fair value of the business to be disposed of and the portion of the
reporting unit that will be retained. During 2006, we allocated
$100 million of US reporting unit goodwill to the carrying amount of our
Gulf of Mexico shelf properties sold. The amount of goodwill allocated to the
carrying amount of a business can significantly impact the amount of gain or
loss recognized on the sale of that business.




Reserves—All of the reserve
data in this Form 10-K are estimates. Estimates of our crude oil and
natural gas reserves are prepared by our engineers in accordance with guidelines
established by the SEC. Reservoir engineering is a subjective process of
estimating underground accumulations of crude oil and natural gas. There are
numerous uncertainties inherent in estimating quantities of proved crude oil and
natural gas reserves. Uncertainties include the projection of future production
rates and the expected timing of development expenditures. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, reserve
estimates may be different from the quantities of crude oil and natural gas that
are ultimately recovered. Estimates of proved crude oil and natural gas reserves
significantly affect our DD&A expense. For example, if estimates of proved
reserves decline, the DD&A rate will increase, resulting in a decrease in
net income. A decline in estimates of proved reserves could also trigger an
impairment analysis to determine if the carrying amount of crude oil and natural
gas properties exceeds fair value and could result in an impairment charge,
which would reduce earnings. In addition, a decline in estimates of proved
reserves could trigger a goodwill impairment analysis.







25





Oil and Gas Properties—We
account for crude oil and natural gas properties under the successful efforts
method of accounting. The alternative method of accounting for crude oil and
natural gas properties is the full cost method. Under the successful efforts
method, costs to acquire mineral interests in crude oil and natural gas
properties, to drill and equip exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. Proved property
acquisition costs are amortized to operations by the unit-of-production method
on a property-by-property basis based on total proved crude oil and natural gas
reserves as estimated by our engineers. Costs to drill and equip exploratory
wells that find proved reserves and to drill and equip development wells are
also amortized to operations by the unit-of-production method on a
property-by-property basis. They are amortized based on proved developed crude
oil and natural gas reserves. Application of the successful efforts method
results in the expensing of certain costs including geological and geophysical
costs, exploratory dry holes and delay rentals, during the periods the costs are
incurred. Under the full cost method, these costs are capitalized as assets and
charged to earnings in future periods as a component of DD&A expense. In
addition, under the full cost method capitalized costs are accumulated in pools
on a country-by-country basis. DD&A is computed on a country-by-country
basis, and capitalized costs are limited on the same basis through the
application of a ceiling test. We believe the successful efforts method is the
most appropriate method to use in accounting for our crude oil and natural gas
properties as this method is better aligned with our business strategy. If we
had used the full cost method, our financial position and results of operations
could have been significantly different.




Exploratory Well Costs—In
accordance with the successful efforts method of accounting, the costs
associated with drilling an exploratory well may be capitalized temporarily, or
“suspended,” pending a determination of whether commercial quantities of crude
oil or natural gas have been discovered. We will carry the costs of an
exploratory well as an asset if the well found a sufficient quantity of reserves
to justify its completion as a producing well and as long as we are making
sufficient progress assessing the reserves and the economic and operating
viability of the project. For certain capital-intensive deepwater Gulf of Mexico
or international projects, it may take more than one year to evaluate the future
potential of the exploration well and make a determination of its economic
viability. Our ability to move forward on a project may be dependent on gaining
access to transportation or processing facilities or obtaining permits and
government or partner approval, the timing of which is beyond our control. In
such cases, exploratory well costs remain suspended as long as we are actively
pursuing access to necessary facilities and access to such permits and approvals
and believe they will be obtained. Management assesses the status of suspended
exploratory well costs on a quarterly basis. These costs may be charged to
exploration expense in future periods if we decide not to pursue additional
exploratory or development activities. At December 31, 2007, the
balance of property, plant and equipment included $249 million of suspended
exploratory well costs, $62 million of which had been capitalized for a
period greater than one year. The wells relating to these suspended costs
continue to be evaluated by various means including additional seismic work,
drilling additional wells, or evaluating the potential of the exploration wells.
For more information, see Item 8. Financial Statements and Supplementary
Data—Note 5—Capitalized Exploratory Well Costs.




Impairment of Proved Oil and Gas
Properties—We assess proved crude oil and natural gas properties for
possible impairment when events or circumstances indicate that the recorded
carrying value of the properties may not be recoverable. We recognize an
impairment loss as a result of a triggering event and when the estimated
undiscounted future cash flows from a property are less than the carrying value.
If impairment is indicated, the cash flows are discounted at a rate approximate
to our cost of capital and compared to the carrying value for determining the
amount of the impairment loss to record. Estimated future cash flows are based
on management’s expectations for the future and include estimates of crude oil
and natural gas reserves and future commodity prices and operating costs.
Downward revisions in estimates of reserve quantities or expectations of falling
commodity prices or rising operating costs could result in a reduction in
undiscounted future cash flows and could indicate property impairment. We
recorded approximately $4 million of impairments in 2007, primarily related
to adjustment of the carrying value of properties to their fair
values.




Impairment of Unproved Oil and Gas
Properties—We also perform periodic assessments of individually
significant unproved crude oil and natural gas properties for impairment. Cash
flows used in the impairment analysis are determined based upon management’s
estimates of natural gas and crude oil reserves, future commodity prices and
future costs to extract the reserves. Downward revisions in estimated reserve
quantities, reductions in commodity prices, or increases in estimated costs
could cause a reduction in the value of an unproved property and, therefore,
could also cause a reduction in the carrying amounts of the property. If
undiscounted future net cash flows are less than the carrying value of the
property, indicating impairment, the cash flows are discounted at a rate
approximate to our cost of capital and compared to the carrying value for
determining the amount of the impairment loss to record.







26





The
estimated prices used in the cash flow analysis are determined by management
based on forward price curves for the related commodities, adjusted for average
historical location and quality differentials. Estimates of cash flows related
to probable and possible reserves are reduced by additional risk-weighting
factors. Due to the volatility of natural gas and crude oil prices, these cash
flow estimates are inherently imprecise. Management’s assessment of the results
of exploration activities, availability of funds for future activities and the
current and projected political climate in areas in which we operate also impact
the amounts and timing of impairment provisions. During 2007, we recorded
impairments of significant unproved oil and gas properties totaling
approximately $3 million in exploration expense.




Asset Retirement
Obligation—Our asset retirement obligations (“ARO”) consist of estimated
costs of dismantlement, removal, site reclamation and similar activities
associated with our oil and gas properties. Statement of Financial Accounting
Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,”
requires that the discounted fair value of a liability for an ARO be recognized
in the period in which it is incurred with the associated asset retirement cost
capitalized as part of the carrying cost of the oil and gas asset. The
recognition of an ARO requires that management make numerous estimates,
assumptions and judgments regarding such factors as the existence of a legal
obligation for an ARO; estimated probabilities, amounts and timing of
settlements; the credit-adjusted risk-free rate to be used; and inflation rates.
In periods subsequent to initial measurement of the ARO, we must recognize
period-to-period changes in the liability resulting from the passage of time and
revisions to either the timing or the amount of the original estimate of
undiscounted cash flows. Increases in the ARO liability due to passage of time
impact net income as accretion expense. The related capitalized cost, including
revisions thereto, is charged to expense through DD&A. See Item 8. Financial
Statements and Supplementary Data—Note 6—Asset Retirement
Obligations.




Involuntary Conversions—When
an involuntary conversion occurs, such as the destruction of oil and gas
producing assets by a hurricane, a loss is accrued by a charge to income if the
amount of loss can be reasonably estimated. An asset relating to insurance
recovery is recognized only when realization of the claim for recovery of a loss
recognized in the financial statements is deemed probable. A gain (recovery of a
loss not yet recognized in the financial statements or an amount recovered in
excess of a loss recognized in the financial statements) is not recognized until
the insurance reimbursement has been received.




Management
must make a number of estimates and assumptions relating to these gain and loss
accruals. These include estimated costs of salvage, clean-up, restoration,
redevelopment or abandonment and estimated amounts of insurance recoveries. The
amount of an insurance recovery may be limited if total industry claims are in
excess of the insurance carrier’s ceiling limitation per event. A significant
amount of time may be necessary for an insurance carrier to review all related
claims for an event and determine the company-specific claim limitation on the
final recovery. In addition, we may continue to incur costs, submit claims and
receive reimbursements over a multi-year period.




The
estimates involved in this process can have significant effects on reported
amounts of net income. A decrease in the estimated amount of insurance
recoveries will result in an increase in the involuntary conversion loss, which
will result in a decrease in net income. An increase in estimated costs of
salvage, if not covered by insurance, will also result in an increase in the
involuntary conversion loss, which will result in a decrease in net income.
Unreimbursed losses will have a negative effect on our cash flows. During the
first half of 2007, several factors contributed to an increase in our estimated
cleanup costs for damage related to Hurricanes Ivan and
Katrina.  These factors included cost escalation due to weather delays
and an increase in effort for the design and construction of the deck lifting
barge and mooring system, as well as additional costs for the actual deck
lifting activities.  These increases caused the total project costs,
combined with net book value of the assets destroyed, to exceed certain
insurance coverage limitations.  As a result, we recorded $51 million
as a loss on involuntary conversion during 2007.  See Item 8.
Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast
Hurricanes.




Derivative Instruments and Hedging
Activities—We use various derivative instruments to minimize the impact
of commodity price fluctuations on forecasted sales of crude oil and natural gas
production. We also use derivative instruments in connection with purchases and
sales of third-party production to lock in profits or limit exposure to
commodity price risk. In addition, we have used derivative instruments in
connection with acquisitions and certain price-sensitive projects. Management
exercises significant judgment in determining types of instruments to be used,
production volumes to be hedged, prices at which to hedge and the
counterparties’ creditworthiness. We account for derivative instruments under
SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities, as amended”. For derivative instruments that qualify as cash flow
hedges, changes in fair value, to the extent the hedge is effective, are
recognized in accumulated other comprehensive income or loss (“AOCL”) until the
hedged







27





forecasted  transaction
is recognized in earnings. Therefore, prior to settlement of the derivative
instruments, changes in the fair market value of those derivative instruments
can cause significant increases or decreases in AOCL. For derivative instruments
that do not qualify as cash flow hedges, changes in fair value are reported in
current period net income and therefore can result in significant increases or
decreases in current period net income. All hedge ineffectiveness is recognized
in the current period in net income. Ineffectiveness is the amount of gains or
losses from derivative instruments which are not offset by corresponding and
opposite gains or losses on the expected future transaction. Regression analysis
is performed on initial assessment of the hedge and subsequently every quarter
thereafter in order to determine that the hedge instrument will be or has been
highly effective in offsetting gains or losses on the future transaction. As
discussed in Item 8. Financial Statements and Supplementary Data—Note 2—Summary
of Significant Accounting Policies, we voluntarily discontinued cash flow hedge
accounting for our commodity derivative instruments, effective January 1,
2008. Such a change did not affect our net assets or cash flows at December 31,
2007 and will not require adjustments to our previously reported financial
statements. However, the use of mark-to-market accounting for our commodity
derivatives will likely add volatility to our reported earnings. We
occassionally enter into forward contracts or swap agreements to hedge exposure to interest
rate risk. Changes in fair value of interest rate swaps or interest rate “locks”
used as cash flow hedges are reported in AOCL, to the extent the hedge is
effective, until the forecasted transaction occurs, at which time they are
recorded as adjustments to interest expense over the term of the related notes.
See Item 8. Financial Statements and Supplementary Data—Note 12—Derivatives and
Hedging Activities.




Income Tax Expense and Deferred Tax
Assets—We are subject to income and other taxes in numerous taxing
jurisdictions worldwide. For financial reporting purposes, we provide taxes at
rates applicable for the appropriate tax jurisdictions. Estimates of amounts of
income tax to be recorded involve interpretation of complex tax laws, assessment
of the effects of foreign taxes on domestic taxes, and estimates regarding the
timing and amounts of future repatriation of earnings from controlled foreign
corporations.




The
consolidated balance sheets include deferred tax assets. Deferred tax assets
arise when expenses are recognized in the financial statements before they are
recognized in the tax returns or when income items are recognized in the tax
return before they are recognized in the financial statements. Deferred tax
assets also arise when operating losses or tax credits are available to offset
tax payments due in future years. Ultimately, realization of a deferred tax
asset depends on the existence of sufficient taxable income within the future
periods to absorb future deductible temporary differences, loss carryforwards or
credits. In assessing the realizability of deferred tax assets, management must
consider whether it is more likely than not that some portion or all of the
deferred tax assets will not be realized. Management considers all available
evidence (both positive and negative) in determining whether a valuation
allowance is required. Such evidence includes the scheduled reversal of deferred
tax liabilities, projected future taxable income and tax planning strategies in
making this assessment, and judgment is required in considering the relative
weight of negative and positive evidence. We continue to monitor facts and
circumstances in the reassessment of the likelihood that operating loss
carryforwards, credits and other deferred tax assets will be utilized prior to
their expiration. As a result, we may determine, and we have determined in the
past, that a deferred tax asset valuation allowance should be established. Any
increases or decreases in a deferred tax asset valuation allowance would impact
net income through offsetting changes in income tax expense.




Allowance for Doubtful
Accounts—Weassess the
recoverability of all material trade and other receivables to determine their
collectibility on a quarterly basis. We accrue a reserve on a receivable when,
based on management’s judgment, it is probable that a receivable will not be
collected and the amount of such reserve may be reasonably estimated. In
determining the amount of the reserve, management must analyze the aging of
accounts receivable at the date of the consolidated financial statements and
assess collectibility based on historic results, current collection trends and
an evaluation of economic conditions. Over the last three years, we have
increased the allowance by approximately $40 million to cover potentially
uncollectible balances related to the Ecuador power operations. Certain entities
purchasing electricity in Ecuador have been slow to pay amounts due us. We are
pursuing various strategies to protect our interests including international
arbitration and litigation. However, if estimates are inaccurate, we may incur
gains or losses that could have a material effect on our results of
operations.




Benefit Plans—We sponsor a
qualified defined benefit pension plan, a non-qualified defined benefit pension
plan (“restoration plan”), and other postretirement benefit plans. The actuarial
determination of the projected benefit obligations and related benefit expense
requires that certain assumptions be made regarding such variables as expected
return on plan assets, discount rates, rates of future compensation increases,
estimated future employee turnoverrates and retirement dates, distribution election rates, mortality rates,
retiree utilization rates for health care services and health care cost trend
rates. The selection of assumptions requires considerable judgment concerning
future events and has a significant impact on the amount of the obligations
recorded in the consolidated balance sheets and on the amount of expense
included in the consolidated statements of operations.







28







We
base our determination of the asset return component of pension expense on a
market-related valuation of assets, which reduces year-to-year volatility. This
market-related valuation recognizes investment gains or losses over a five-year
period from the year in which they occur. Investment gains or losses for this
purpose are the difference between the expected return calculated using the
market-related value of assets and the actual return based on the fair value of
assets. Since the market-related value of assets recognizes gains or losses over
a five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of January 1, 2007, cumulative asset
gains of approximately $3 million remained to be recognized in the
calculation of the market-related value of assets.




In
selecting the assumption for expected long-term rate of return on assets, we
consider the average rate of earnings expected on the funds invested or to be
invested to provide for plan benefits included in the projected benefit
obligations. This includes considering the returns being earned by the plan
assets and the rates of return expected to be available for reinvestment. We
assume that the long-term asset mix will be consistent with the target asset
allocation of 70% equity and 30% fixed income, with a range of plus or minus 10%
acceptable degree of variation in asset allocation. A 1% decrease in the
expected return on plan assets assumption would have increased 2007 net periodic
benefit cost by approximately $1 million. The expected return assumption
used for 2007 was 8.25%.




In
selecting a discount rate, employers may look to rates of return on high quality
fixed-income investments available as of the year-end measurement date and
expected to be available during the period to maturity of the pension benefits.
In order to determine an appropriate December 31, 2007 discount rate, we
performed an analysis of the Citigroup Pension Discount Curve (the “CPDC”) for
each of our plans. The CPDC uses spot rates that represent the equivalent yield
on high quality, zero coupon bonds for specific maturities. We used these rates
to develop an equivalent single discount rate based on our plans’ expected
future benefit payment streams and duration of plan liabilities. A 1% increase
in the discount rate assumption would have decreased 2007 net periodic benefit
cost by $4 million and decreased the benefit obligation for the combined
plans by $17 million at December 31, 2007. A 1% decrease in the
discount rate assumption would have increased 2007 net periodic benefit cost by
$5 million and increased the benefit obligation for the combined plans by
$20 million at December 31, 2007. The assumed discount rate used to
determine net periodic benefit cost for 2007 was 5.75%. The assumed discount
rate used to determine the benefit obligations at December 31, 2007 was
6.5% for our defined benefit pension and restoration plans and 6.25% for our
medical and life plans.




Effective
January 1, 2008, the defined benefit pension plan and restoration plans were
amended in order to provide a lump sum option. Certain assumptions were made
regarding the percentage of active participants who would elect the lump sum
option upon future termination and the percentage of existing deferred vested
participants who would elect the lump sum option during 2008. In addition, the
amounts of lump sum payments are affected by mortality and interest rate
assumptions. The lump sum option increased the projected benefit obligation by
$5.5 million at December 31, 2007 and will increase 2008 net periodic benefit
cost by approximately $1 million.




We
adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88,
106 and 132(R), as of December 31, 2006. See Item 8. Financial Statements
and Supplementary Data—Note 11—Benefit Plans.




Recently Issued
Pronouncements—See Item 8. Financial Statements and Supplementary
Data—Note 16—Recently Issued Pronouncements.




LIQUIDITY
      AND CAPITAL RESOURCES




Overview




Our
primary cash needs are to fund capital expenditures related to the acquisition,
exploration and development of crude oil and natural gas properties, to repay
outstanding borrowings or to pay other contractual commitments and interest
payments on debt and to pay dividends. Our traditional sources of liquidity are
cash on hand, cash flows from operations and available borrowing capacity under
credit facilities. Funds may also be generated from occasional sales of
non-strategic crude oil and natural gas assets. We had $660 million in cash and
cash equivalents at December 31, 2007, compared with $153 million at December
31, 2006. Substantially all of this cash is located in our foreign
subsidiaries and would be subject to additional US income taxes if repatriated.
The cash is denominated in US dollars and is invested in highly liquid,
investment-grade securities with original maturities of three months or less at
the time of purchase. We currently intend to use our international cash to fund
international projects, including the development of West
Africa.







29







We
are monitoring the current conditions in the credit markets. We have reviewed
the creditworthiness of the banks and financial institutions with which we
maintain our investments as well as the securities underlying our investments.
Thus far, our liquidity and financial position have not been affected. We
believe that losses from nonperformance are unlikely to occur; however, we are
not able to predict sudden changes in creditworthiness.




Our
ratio of debt-to-book capital has decreased from 30% at December 31, 2006,
to 28% at December 31, 2007. We define our ratio of debt-to-book capital as
total debt (which includes both long-term debt, excluding unamortized discount,
and short-term borrowings) divided by the sum of total debt plus shareholders’
equity. Significant changes in our financial position causing a change in the
ratio of debt-to-book capital include:




·
            a
      $75 million increase in total debt from the balance at
      December 31, 2006;


·
            a
      $944 million increase in shareholders’ equity from current year net
      income;


·
            a
      $102 million decrease in shareholders’ equity due to repurchase of
      common stock; and


·
            a
      $144 million decrease in shareholders’ equity (effected by an
      increase in AOCL) primarily related to an increase in deferred hedging
      losses.




Cash
Flows




Summary
      cash flow information is as
follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)Total
      cash provided by (used in):Operating
      activities
              
              $
              2,016,573
              
              
              $
              1,730,306
              
              
              $
              1,239,878Investing
      activities
              
              
              (1,403,089
              )
              
              
              (1,098,339
              )
              
              
              (1,892,488
              )Financing
      activities
              
              
              (107,029
              )
              
              
              (588,880
              )
              
              
              583,137Increase
      (decrease) in cash and cash equivalents
              
              $
              506,455
              
              
              $
              43,087
              
              
              $
              (69,473
              )






Operating Activities—Net cash
provided by operating activities increased $286 million, or 17% during 2007 as
compared with 2006. The increase was due primarily to higher average realized
crude oil prices and higher average realized US natural gas prices. These
increases were partially offset by higher exploration expense and general and
administrative (“G&A”) expense. In addition, cash flows from operating
activities in 2007 included dividends from equity method investments, which
had been
classified as investing cash flows in 2006. See Results of Operations—Income
from Equity Method Investees.




Net
cash provided by operating activities increased $490 million, or 40%, during
2006 as compared with 2005. The increase was due primarily to higher sales
volumes and higher average realized crude oil prices, offset by lower average
realized US natural gas prices and increases in total production costs, G&A
expense and interest expense.




Investing Activities—The
primary use of cash in investing activities is for capital spending, which may
be offset by proceeds from property sales or dividends from equity method
investees. Net cash used in investing activities increased $305 million, or 28%
during 2007 as compared with 2006. The change was due primarily to a decrease in
divestiture activity in 2007 as compared with 2006, when we sold our Gulf of
Mexico shelf properties. In addition, investing cash inflows were reduced in
2007 because distributions received from equity method investees were included
in operating cash flows. See Results of Operations—Income from
Equity Method Investees.




Netcash
used in investing activities decreased $794 million, or 42% during 2006 as
compared with 2005. The decrease was due primarily to a decrease in acquisition
activity in 2006 as compared to the Patina Merger in 2005 and an increase in
divestiture activity in 2006, due to the
sale of our Gulf of Mexico shelf properties, which provided investing cash
inflows in 2006.




Financing
Activities—Net cash used in financing activities decreased $482 million
during 2007 as compared with 2006. The change was due to net increases in the
credit facility during 2007 as compared with payments being made to decrease
outstanding debt during 2006. In 2007 there was also a net decrease of $297
million in amounts used to repurchase common stock as compared with 2006. Cash
flows were provided by financing activities in 2005, as compared with 2006, and
totaled $583 million. In 2005, cash was provided by borrowings under the credit
facility and exercise of stock options, partially offset by dividend payments
and the repayment of debt acquired in the Patina Merger.







30







Acquisition,
      Capital and Other Exploration
Expenditures




Expenditure
information (on an accrual basis) is as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)Acquisition,
      Capital and Other Exploration ExpendituresLease
      acquisition of unproved property
              
              $
              145,326
              
              
              $
              53,652
              
              
              $
              16,793Exploration
      expenditures
              
              
              371,758
              
              
              
              203,035
              
              
              
              161,515Development
      expenditures
              
              
              1,185,385
              
              
              
              1,054,780
              
              
              
              662,585Corporate
      and other expenditures
              
              
              36,361
              
              
              
              35,069
              
              
              
              21,478Total
      consolidated capital expenditures
              
              
              1,738,830
              
              
              
              1,346,536
              
              
              
              862,371Our
      share of equity investee development costs
              
              
              516
              
              
              
              580
              
              
              
              27,639Total
              
              $
              1,739,346
              
              
              $
              1,347,116
              
              
              $
              890,010




Total
capital expenditures during 2007 increased $392 million, or 29%, as compared
with 2006. The increase was due to lease acquisition in the US, exploratory
activities in West Africa and the North Sea, and increased development activity
in the Northern region and Gulf of Mexico area of our US operations. Total
capital expenditures during 2006 increased $457 million, or 51%, as
compared with 2005. The increase was primarily due to development expenditures
in the US and the North Sea. Capital expenditures for 2005 included
$275 million of post-merger exploration and development-related
expenditures on Patina properties.




As
a result of the U.S. Exploration acquisition in 2006, we allocated $413 million
to proved properties and $131 million to unproved properties. As a result of the
Patina Merger in 2005, we allocated $2.6 billion to proved properties and $1.1
billion to unproved properties.




Insurance
      Recoveries




See
Item 8. Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast
Hurricanes.




Our
corporate insurance program provides up to $260 million property damage
coverage per loss event. However, our insurance carrier’s aggregation limit for
catastrophic windstorm events is $750 million. If an insured catastrophic loss
event occurs, we could still recover less than our stated limits should the
total aggregate losses realized by our carrier exceed its $750 million
aggregation limit applicable to any single loss event.




We
carry additional property damage and control of well coverage for our deepwater
Gulf of Mexico and remaining Gulf of Mexico shelf properties. This additional
insurance provides coverage only for claims in excess of $100 million, which
exceed the $260 million property damage coverage or where the $260 million
property damage coverage is reduced by application of the $750 million
aggregation limit. We carry business interruption insurance for certain
international locations. Effective June 2007, we no longer carry business
interruption insurance for our Gulf of Mexico operations.




Financing
      Activities




Long-Term Debt—Our long-term
debt totaled $1.9 billion (excluding unamortized discount) at
December 31, 2007. Maturities range from 2009 to 2097. Our principal
source of liquidity is an unsecured revolving credit facility (the “Credit
Facility”). In
November 2007, we extended the Credit Facility until December 9, 2012. The
commitment is $2.1 billion until December 9, 2011 at which time the commitment
reduces to $1.8 billion.The Credit Facility (i) provides for Credit
Facility fee rates that range from 5 basis points to 15 basis points per year
depending upon our credit rating, (ii) makes available short-term loans up
to an aggregate amount of $300 million and (iii) provides for interest
rates that are based upon the Eurodollar rate plus a margin that ranges from 20
basis points to 70 basis points depending upon our credit rating and utilization
of the Credit Facility.







31





The
Credit Facility contains customary representations and warranties and
affirmative and negative covenants. The Credit Facility requires that our total
debt to capitalization ratio (as defined in the credit agreement), expressed as
a percentage, not exceed 60% at any time. A violation of this covenant could
result in a default under the Credit Facility, which would permit the
participating banks to restrict our ability to access the Credit Facility and
require the immediate repayment of any outstanding advances under the Credit
Facility. At December 31, 2007, the total debt to capitalization ratio was
28%, calculated for this purpose as total debt divided by the sum of total debt
plus shareholders’ equity.




The
Credit Facility is with certain commercial lending institutions and is available
for general corporate purposes. At December 31, 2007, $1.2 billion in
borrowings were outstanding under the Credit Facility. The weighted average
interest rate applicable to borrowings under the Credit Facility at
December 31, 2007 was 5.28%.




We
also have $650 million of fixed-rate debt outstanding at December 31, 2007 with
a weighted average interest rate of 6.92%. Maturities range from 2014 to 2097.




Installment Payments Due—During
2007, we purchased working interests in oil and gas properties in the Piceance
basin of western Colorado for $75 million. After making an initial cash payment
of $25 million, we owe $50 million in the form of installment payments to the
seller. Installments of $25 million each are due on May 12, 2008 and May 11,
2009.  The amount due in 2008 is included in short-term borrowings and
the amount due in 2009 is included in long-term debt in the consolidated balance
sheets. Interest on the unpaid amounts is due quarterly. Interest accrues at a
LIBOR rate plus .30%.  The interest rate was 5.53% at December 31,
2007.




Short-Term Borrowings—Our
Credit Facility is supplemented by short-term borrowings under various
uncommitted credit lines used for working capital purposes. Uncommitted credit
lines may be offered by certain banks from time to time at rates negotiated at
the time of borrowing. Other than the installment payments discussed above,
there were no short-term borrowings outstanding at December 31,
2007.




Interest Rate Locks—We
occasionally enter into forward contracts or swap agreements to hedge exposure
to interest rate risk. As of December 31, 2007, we had entered into
two interest rate locks which are scheduled to expire third quarter 2008. See Item 8.
Financial Statements and Supplementary Data—Note 7—Debt.




Cash Interest Payments—We
made cash interest payments, net of capitalized interest, of $105 million
in 2007, $106 million in 2006 and $84 million in 2005.




Common Stock Repurchase
Program—During 2007 we completed a common stock repurchase program
authorized by our Board of Directors in 2006. We repurchased two million shares
of our common stock at an aggregate cost of $101 million in 2007 and
8.4 million shares of our common stock at an aggregate cost of
$399 million in 2006, resulting in a total of 10.4 million shares acquired
at an average price of $48.17 per share.




Dividends—We paid cash
dividends totaling 43.5 cents per common share in 2007, 27.5 cents per common
share in 2006 and 15 cents per common share in 2005. On January 22, 2008,
the Board of Directors declared a quarterly cash dividend of 12.0 cents per
common share, which was paid February 19, 2008 to shareholders of record on
February 4, 2008. The amount of future dividends will be determined on a
quarterly basis at the discretion of the Board of Directors and will depend on
earnings, financial condition, capital requirements and other
factors.




Exercise of Stock
Options—Proceeds from the exercise of stock options totaled $25 million
in 2007, $63 million in 2006 and $68 million in 2005. Proceeds
received from the exercise of stock options fluctuate primarily based on the
number of options exercised which is influenced by the price at which our common
stock trades on the NYSE in relation to the exercise price of the options
issued.




Off-Balance
      Sheet Arrangements




We
may enter into off-balance sheet arrangements and transactions that can give
rise to material off-balance sheet obligations. As of December 31, 2007,
the material off-balance sheet arrangements and transactions that we have
entered into included drilling service contracts, operating lease agreements,
undrawn letters of credit and derivative contracts. Other than the off-balance
sheet arrangements listed above, we have no transactions, arrangements or other
relationships with unconsolidated entities or other persons that are reasonably
likely to materially affect our liquidity or availability of or requirements for
capital resources. See Contractual Obligations below for more information
regarding off-balance sheet arrangements.







32





Contractual
Obligations




The
following table summarizes certain contractual obligations that are reflected in
the consolidated balance sheets and/or disclosed in the accompanying notes. See
Item 8. Financial Statements and Supplementary Data—Notes to Consolidated
Financial Statements.




Payments
      Due by Period2009
              
              
              2011
              
              
              2013Total
              
              
              2008
              
              
              and
      2010
              
              
              and
      2012
              
              
              and
      Beyond(in
      thousands)Long-term
      debt (excludes interest) (1)
              
              $
              1,880,000
              
              
              $
              25,000
              
              
              $
              25,000
              
              
              $
              1,180,000
              
              
              $
              650,000Drilling
      and equipment obligations (2)
      :United
      States drilling and equipment
              
              
              462,759
              
              
              
              181,337
              
              
              
              173,935
              
              
              
              107,487
              
              
              
              -International
      drilling and equipment
              
              
              68,170
              
              
              
              68,170
              
              
              
              -
              
              
              
              -
              
              
              
              -Purchase obligations (3)
              
              
              194,419
              
              
              
              194,419
              
              
              
              -
              
              
              
              -
              
              
              
              -Throughput
      agreement (4)
              
              
              95,000
              
              
              
              -
              
              
              
              38,000
              
              
              
              38,000
              
              
              
              19,000Operating
      lease obligations (5)
      :Office
      buildings and facilities
              
              
              52,894
              
              
              
              7,289
              
              
              
              14,495
              
              
              
              13,247
              
              
              
              17,863Oil
      and gas operations equipment
              
              
              12,074
              
              
              
              5,467
              
              
              
              6,607
              
              
              
              -
              
              
              
              -Other
      long-term liabilities (6):Asset
      retirement obligations (7)
              
              
              144,288
              
              
              
              13,332
              
              
              
              12,443
              
              
              
              13,034
              
              
              
              105,479Derivative
      instruments (8)
              
              
              603,133
              
              
              
              525,159
              
              
              
              77,974
              
              
              
              -
              
              
              
              -Total
      contractual obligations
              
              $
              3,512,737
              
              
              $
              1,020,173
              
              
              $
              348,454
              
              
              $
              1,351,768
              
              
              $
              792,342




(1)
            Based
      on the total debt balance outstanding at December 31, 2007, scheduled
      maturities and interest rates in effect at December 31, 2007, our cash
      payments for interest would be $109 million in 2008,
      $108 million in 2009, $107 million in 2010, $107 million in
      2011, $107 million in 2012 and $990 million for the remaining years for a
      total of $1.5 billion. See Item 8. Financial Statements and
      Supplementary Data—Note 7—Debt for additional information regarding our
      long-term debt obligations.


(2)
            Drilling
      and equipment obligations represent contractual agreements with third
      party service providers to procure drilling rigs and other related
      equipment for developmental and exploratory drilling
      facilities.  See Item 8. Financial Statements and Supplementary
      Data—Note 14—Commitments and Contingencies for additional information
      regarding our drilling and equipment
  obligations.


(3)
            Purchase
      obligations represent agreements to purchase goods or services that are
      enforceable, are legally binding and specify all significant terms,
      including fixed and minimum quantities to be purchased; fixed, minimum or
      variable price provisions; and the approximate timing of the transaction.
      See Item 8. Financial Statements and Supplementary Data—Note
      14—Commitments and Contingencies for additional information regarding our
      purchase obligations.


(4)
            In
      January 2007, we entered into a five-year throughput agreement. The
      transporting pipeline is expected to be completed and operational in
      2009.  See Item 8. Financial Statements and Supplementary
      Data—Note 14—Commitments and Contingencies for additional information
      regarding our throughput agreement.


(5)
            Operating
      lease obligations represent non-cancelable leases for office buildings and
      facilities and oil and gas operations equipment used in our daily
      operations. See Item 8. Financial Statements and Supplementary Data —Note
      14—Commitments and Contingencies for additional information regarding our
      operating lease obligations.


(6)
            The
      table does not include our deferred compensation liabilities of $225
      million and our accrued benefit costs of $51 million as specific payment
      dates are unknown. See Item 8. Financial Statements and Supplementary
      Data—Note 11—Benefit Plans for additional information on our deferred
      compensation liability and our accrued benefit
  costs.


(7)
            Asset
      retirement obligations are discounted. See Item 8. Financial Statements
      and Supplementary Data—Note 6—Asset Retirement Obligations for additional
      information on our asset retirement
obligations.


(8)
            See
      Item 8. Financial Statements and Supplementary Data—Note 12—Derivative
      Instruments and Hedging Activities for additional information on our
      derivative instrument obligations.







33





We
accrued approximately $12 million as of December 31, 2007, for an
insurance contingency due to our membership in Oil Insurance Limited (OIL). OIL
is a mutual insurance company which insures specific property, pollution
liability and other catastrophic risks. As part of our membership, we are
contractually committed to pay termination fees should we elect to withdraw from
OIL. We do not anticipate withdrawing from OIL; however, the potential
termination fee is calculated annually based on OIL’ s past losses and the
liability reflecting this potential charge has been accrued.




In
addition, in the ordinary course of business, we maintain letters of credit in
support of certain performance obligations of our subsidiaries. Outstanding
letters of credit totaled approximately $1 million at December 31,
2007.




Other




Contributions to Pension and Other
Postretirement Benefit Plans—We made contributions to the pension,
restoration and other postretirement benefit plans totaling $12 million
during 2007, $36 million during 2006, and $14 million during 2005. The
actual return on plan assets was $13 million in both 2007 and 2006. The
investment return has tended to follow market performance. In August 2006,
the Pension Protection Act of 2006 (the Act) was signed into law. Certain
provisions of this Act changed the calculation related to the maximum
contribution amount deductible for income tax purposes and require that pension
plans become fully funded over a seven-year period beginning in 2008. As a
result of previous contributions made to the pension plan, there are no required
contributions expected during 2008. We may, however, make additional
contributions to our pension plan. We expect to make contributions of
$4 million to the unfunded restoration and medical and life plans in 2008.
This amount is equal to the benefits expected to be paid by those
plans.




Income Taxes—We made cash
payments for income taxes, net of refunds, of $149 million during 2007,
$115 million during 2006 and $122 million during 2005.




Contingencies—During 2007, we
paid a total of $56 million to settle legal proceedings; these amounts had been
accrued previously. During 2006 and 2005, no significant payments were made to
settle any legal proceedings. We regularly analyze current information and
accrue for probable liabilities on the disposition of certain matters, as
necessary. Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability
has been incurred and the amount can be reasonably estimated.




RESULTS
      OF OPERATIONS




Net
      Income




Net
income for 2007 was $944 million, a 39% increase over 2006. Factors
contributing to the increase in net income from 2006 to 2007
included:




·
            a
      $332 million, or 11%, increase in total revenues, due primarily to
      higher average realized crude oil prices and higher average realized US
      natural gas prices and an increase in income from equity method
      investees;


·
            a  $395
      million decrease in loss on derivative instruments; and


offset
by:


·
            a
      $208 million decrease in gains from asset
sales;


·
            a
      $105 million increase in DD&A
expense;


·
            a
      $51 million loss on involuntary conversion expense;
  and


·
            a
      $51 million increase in oil and gas exploration
  expense.




Net
income for 2006 was $678 million, a 5% increase over 2005. Factors
contributing to the increase in net income from 2005 to 2006
included:




·
            a
      $753 million, or 34%, increase in total revenues, driven primarily by
      a full year of Patina operations and nine months of U.S. Exploration
      operations and higher average realized oil
  prices;


·
            an
      increase of $215 million in gains from asset sales;


offset
by:


·
            an
      increase in loss on derivative instruments of $360 million;
      and


·
            a
      $232 million increase in DD&A
expense.





34





Natural
      Gas Information




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)Natural
      gas sales
              
              $
              1,271,866
              
              
              $
              1,211,782
              
              
              $
              1,023,644




Average
daily natural gas sales volumes and average realized sales prices were as
follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005Mcfpd
              
              
              $/Mcf
              
              
              Mcfpd
              
              
              $/Mcf
              
              
              Mcfpd
              
              
              $/McfUnited
      States (1)
              
              
              412,212
              
              
              $
              7.51
              
              
              
              451,712
              
              
              $
              6.61
              
              
              
              343,953
              
              
              $
              7.43West
      Africa (2)
              
              
              132,464
              
              
              
              0.29
              
              
              
              45,422
              
              
              
              0.37
              
              
              
              65,581
              
              
              
              0.25North
      Sea
              
              
              6,235
              
              
              
              6.54
              
              
              
              8,130
              
              
              
              8.00
              
              
              
              9,299
              
              
              
              5.93Israel
              
              
              110,820
              
              
              
              2.79
              
              
              
              92,894
              
              
              
              2.72
              
              
              
              66,377
              
              
              
              2.68Ecuador
      (3)
              
              
              25,713
              
              
              
              -
              
              
              
              24,475
              
              
              
              -
              
              
              
              22,795
              
              
              
              -Other
      International
              
              
              -
              
              
              
              -
              
              
              
              294
              
              
              
              0.96
              
              
              
              190
              
              
              
              1.10Total
              
              
              687,444
              
              
              $
              5.26
              
              
              
              622,927
              
              
              $
              5.55
              
              
              
              508,195
              
              
              $
              5.78




(1)
            Reflects
      an increase of $1.12 per Mcf in 2007 and reductions of $0.25 per Mcf in
      2006 and $0.77 per Mcf in 2005 from hedging
  activities.


(2)
            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. The
      methanol and LPG plants are owned by affiliated entities accounted for
      under the equity method of accounting. The volumes sold by the LPG plant
      are included in the table below under crude oil information. Natural gas
      volumes include sales to an LNG facility of 78,090 Mcfpd 2007; there were
      no natural gas sales to the LNG facility before 2007. The natural gas sold
      to the LNG facility and methanol plant has a lower Btu content than the
      natural gas sold to the LPG plant. As a result of the natural gas
      volumes sold to the LNG plant in 2007, the average price received on an
      Mcf basis is lower. For 2007 and 2006, the price on an Mcf basis has been
      adjusted to reflect the Btu content on gas
  sales.


(3)
            The
      natural gas-to-power project in Ecuador is 100% owned by one of our
      subsidiaries, and intercompany natural gas sales are eliminated for
      accounting purposes. Electricity sales included in total revenues totaled
      $71 million in 2007, $72 million in 2006 and $74 million in
      2005.




2007 Compared with
2006—Natural gas sales increased a net $60 million, or 5%, during 2007 as
compared with 2006. The increase was affected by both volume and price changes.
In the US, natural gas sales increased $40 million from the previous year
despite lower sales volumes. Deepwater Gulf of Mexico volumes were slightly
higher than 2006, while development activity in the Piceance basin and a full
year of production from U.S. Exploration properties acquired in 2006 resulted in
increased production in the Northern region. However, the Gulf Coast onshore
area had lower production due to natural field decline, and there was a loss of
production due to the sale of our Gulf of Mexico shelf properties in 2006. The
Northern region also experienced a temporary decline in production due to third
party processing downtime and inclement weather. The net production decrease was
more than offset by a 14% increase in average realized natural gas
prices.







35





Internationally,
West Africa natural gas sales increased $8 million from the previous year.
Natural gas volumes were higher due to increased sales of natural gas from the
Alba field in Equatorial Guinea; however, the effect of higher production was
somewhat offset by lower average realized gas prices. In the North Sea, natural
gas production decreased 23% as compared with the prior year primarily due to
natural field decline. Lower production, combined with lower average realized
prices, resulted in a $9 million decrease in North Sea natural gas sales. In
Israel, natural gas sales increased $21 million due to record sales volumes.
There was a full year of sales to Israeli Electric Company’s Reading power plant
in Tel Aviv, as well as the start up of sales to a desalinization plant and a
paper mill.




2006 Compared with
2005—Natural gas sales increased a net $188 million, or 18%, during 2006
as compared with 2005. Again, the change was caused by both significant volume
and price changes. In the US natural gas sales increased by $157 million from
the previous year due to additional US production from Patina properties
acquired in 2005 and from U.S. Exploration properties acquired in May 2006. In
addition, there were increases in deepwater Gulf of Mexico production where
three new developments came on stream at Swordfish, Ticonderoga and Lorien.
However, increases due to higher gas sales volumes were partially offset by
lower average realized prices.




Internationally,
West Africa natural gas sales were flat year-to-year; however, there was a
decline in sales volumes due to the turnaround of the AMPCO methanol plant in
Equatorial Guinea. The turnaround lasted 57 days and was followed by reduced
production levels caused by 35 days of compressor repairs. The production
decline was completely offset by an increase in average realized natural gas
prices. In the North Sea, natural field decline resulted in reduced sales
volumes, but this reduction was more than offset by the increase in average
realized prices. Israel experienced a $4 million increase in natural gas sales
primarily due to increased demand from Israel Electric Corporation Limited, a
full year of sales to Bazan Oil Refinery and commencement of natural gas sales
to the Reading power plant in Tel Aviv, Israel.




Natural Gas Hedging
Activities—Natural gas sales are net of the effects of derivative
contracts that are accounted for as cash flow hedges and included an increase of
$169 million in 2007, and a reduction of $42 million in 2006 and $97 million in
2005 from hedging activities.  Natural gas sales in 2007 include a
$182 million non-cash increase related to hedge contracts that were redesignated
at the time of the Gulf of Mexico shelf property sale in 2006 and settled during
2007. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative
Instruments and Hedging Activities.




Crude
      Oil Information




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)Crude
      oil sales
              
              $
              1,694,233
              
              
              $
              1,489,459
              
              
              $
              942,778




Average
daily crude oil sales volumes and average realized sales prices were as
follows:
















36




Year
      Ended December 31,2007
              
              
              2006
              
              2005Production(1)
              
              Sales
              
              
              Production
      (1)
              
              Sales
              
              Sales
      (2)Bopd
              
              Bopd
              
              $/Bbl
              
              
              Bopd
              
              Bopd
              
              $/Bbl
              
              Bopd
              
              
              $/BblUnited
      States (3)
              
              42,332
              
              
              42,332
              
              $
              53.22
              
              
              
              45,798
              
              
              45,798
              
              $
              50.68
              
              
              25,941
              
              
              $
              46.67West
      Africa (4)
              
              15,523
              
              
              15,070
              
              
              71.27
              
              
              
              17,326
              
              
              17,860
              
              
              62.51
              
              
              17,786
              
              
              
              42.51North
      Sea
              
              12,813
              
              
              12,505
              
              
              76.47
              
              
              
              3,988
              
              
              3,717
              
              
              67.43
              
              
              5,380
              
              
              
              52.68Other
      International (5)
              
              6,806
              
              
              6,674
              
              
              53.69
              
              
              
              7,491
              
              
              7,540
              
              
              52.05
              
              
              7,851
              
              
              
              42.37Total
      Consolidated Operations
              
              77,474
              
              
              76,581
              
              
              60.61
              
              
              
              74,603
              
              
              74,915
              
              
              54.47
              
              
              56,958
              
              
              
              45.35Equity
      Investees(6)
              
              8,014
              
              
              7,684
              
              
              55.09
              
              
              
              7,531
              
              
              8,032
              
              
              45.83
              
              
              3,240
              
              
              
              43.43Total
              
              85,488
              
              
              84,265
              
              $
              60.10
              
              
              
              82,134
              
              
              82,947
              
              $
              53.64
              
              
              60,198
              
              
              $
              45.25


(1)
            The
      variance between production and sales volumes is attributable to the
      timing of liquid hydrocarbon tanker
liftings.


(2)
            Sales
      volumes equal production volumes in
2005.


(3)
            Reflects
      reductions of $13.68 per Bbl in 2007, $11.41 per Bbl in 2006 and $8.03 per
      Bbl in 2005 from hedging
activities.


(4)
            Reflects
      reductions of $2.19 per Bbl in 2007 and $9.93 per Bbl in 2005 from hedging
      activities. We did not hedge West Africa crude oil sales in
      2006.


(5)
            Other
      international includes China and
Argentina.


(6)
            Volumes
      represent sales of condensate and LPG from the Alba plant in Equatorial
      Guinea. LPG sales volumes totaled 5,848 Bopd in 2007, 6,294 Bopd in 2006
      and 2,328 Bopd in 2005.




2007 Compared with 2006—Crude
oil sales increased a net $205 million, or 14%, during 2007 as compared with
2006. The increase was affected by both volume and price changes. In the US,
crude oil sales declined by $25 million from the previous year. Deepwater Gulf
of Mexico volumes were lower due to well performance, third-party facility
restrictions and storm shut-in. The Gulf Coast onshore area had lower production
due to natural field decline, and there was a loss of production due to the sale
of our Gulf of Mexico shelf properties in 2006. Northern region production was
negatively impacted by severe winter weather in the Rocky Mountains during the
first and fourth quarters of 2007. However, development activity in the
Wattenberg field, as well as a full year of production from U.S. Exploration
properties acquired in 2006, resulted in increased production in our Northern
region, and the overall US volume decline was partially offset by higher average
realized prices.




Internationally,
West Africa crude oil sales declined by $15 million from the previous year.
Volumes declined due to increased downtime and lower condensate yields in
Equatorial Guinea, but the decline was offset by substantially higher average
realized crude oil prices. In January 2007, production began at the Dumbarton
development in the North Sea, and, as a result, crude oil production was more
than triple that of the prior year. North Sea crude oil sales increased $257
million over 2006 due to the increased volumes and, to a lesser extent, higher
average realized prices. Other international crude oil sales declined $12
million. China experienced lower volumes due to facility downtime and natural
field decline.




2006 Compared with 2005—Crude
oil sales increased a net $547 million, or 58%, during 2006 as compared with
2005. Again, the increase was caused by significant volume and price changes. In
the US crude oil sales increased by $405 million from the previous year due to
additional US production from Patina properties acquired in 2005 and from U.S.
Exploration properties acquired in May 2006. In addition, there were increases
in deepwater Gulf of Mexico production where three new developments came on
stream at Swordfish, Ticonderoga and Lorien.




Internationally,
higher average realized prices resulted in an increase of $132 million in West
Africa crude oil sales and contributed to most of the $22 million increase in
other international crude oil sales. The North Sea experienced a $12 million
decrease in crude oil sales. Natural field decline and timing of tanker liftings
resulted in lower sales volumes, the effect of which was mitigated by an
increase in average realized crude oil prices.




Crude Oil Hedging
Activities—Crude oil sales are net of the effects of derivative contracts
that are accounted for as cash flow hedges and included a reduction of $223
million in 2007, $191 million in 2006 and $140 million in 2005 from hedging
activities.  See Item 8. Financial Statements and Supplementary
Data—Note 12—Derivative Instruments and Hedging Activities.




Commodity
      Derivative Instruments and Hedging
Activities




We
use various derivative instruments in connection with anticipated crude oil and
natural gas sales to minimize the impact of product price fluctuations. Such
instruments include variable to fixed price swaps, costless collars and basis
swaps. Although these derivative instruments expose us to credit risk, we
monitor the creditworthiness of counterparties and believe that losses from
nonperformance are unlikely to occur. Hedging gains and losses related to crude
oil and natural gas production are recorded in oil and gas sales. See Item 7A.
Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk
and Item 8. Financial Statements and Supplementary Data—Note 12—Derivative
Instruments and Hedging Activities.







37





Income
from Equity Method Investees




We
own a 45% interest in AMPCO, which owns and operates a methanol plant and
related facilities and a 28% interest in Alba Plant, which owns and operates an
LPG processing plant. The plants and related facilities are located in
Equatorial Guinea. We account for investments in entities that we do not control
but over which we exert significant influence using the equity method of
accounting. Our share of operations of equity method investees was as
follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005Net
      income (in thousands):AMPCO
      and affiliates
              
              $
              82,877
              
              
              $
              38,024
              
              
              $
              56,896Alba
      Plant
              
              
              128,051
              
              
              
              101,338
              
              
              
              33,916Distributions/dividends
      (in thousands):AMPCO
      and affiliates
              
              
              96,483
              
              
              
              37,350
              
              
              
              59,625Alba
      Plant
              
              
              132,251
              
              
              
              155,158
              
              
              
              -Sales
      volumes (1):Methanol
      (Kgal)
              
              
              160,540
              
              
              
              109,942
              
              
              
              162,446Condensate
      (Bopd)
              
              
              1,836
              
              
              
              1,738
              
              
              
              912LPG
      (Bpd)
              
              
              5,848
              
              
              
              6,294
              
              
              
              2,328Production
      volumes (1):Condensate
      (Bopd)
              
              
              1,860
              
              
              
              1,730
              
              
              
              912LPG
      (Bpd)
              
              
              6,154
              
              
              
              5,801
              
              
              
              2,328Average
      realized prices:Methanol
      (per gallon)
              
              $
              1.09
              
              
              $
              0.90
              
              
              $
              0.77Condensate
      (per Bbl)
              
              
              74.87
              
              
              
              66.60
              
              
              
              55.76LPG
      (per Bbl)
              
              
              48.87
              
              
              
              40.10
              
              
              
              38.63





(1)
            The
      variance between production and sales volumes is attributable to the
      timing of liquid hydrocarbon tanker
liftings.




Net
income from AMPCO and affiliates increased substantially in 2007 relative to
2006 due to a 46% increase in methanol sales volumes and a 21% increase in
average realized methanol prices. The increase in methanol sales volumes was due
to a 57-day shutdown of methanol production for the plant turnaround that
occurred during May and June 2006 followed by 35 days of compressor
repairs.




Net
income from AMPCO and affiliates decreased 33% in 2006 relative to 2005 due to a
32% decrease in methanol sales volumes offset by a 17% increase in average
realized methanol prices. The decrease in methanol sales volumes was due to the
57-day shutdown of methanol production for the plant turnaround that occurred
during May and June 2006 followed by 35 days of compressor repairs. No such
shutdown or plant turnaround occurred during 2005.




Net
income from Alba Plant increased 26% in 2007 relative to 2006 due to a 22%
increase in average realized LPG prices and a 12% increase in average realized
condensate prices.




Net
income from Alba Plant increased substantially in 2006 relative to 2005 due to
an almost threefold increase in LPG sales volumes, an almost twofold increase in
condensate sales volumes and a 19% increase in average realized condensate
prices. The increases in LPG and condensate sales volumes reflected the
completion and ramp up to full production of the Phase 2B liquids expansion
project.




For
2007, $132 million received from Alba Plant was classified within operating cash
flows as a dividend from equity method investee as compared with 2006 in which
the distributions were classified within investing cash flows as a repayment of
a loan. The change in classification was the result of all outstanding loans
being repaid to us by Alba Plant in December 2006.







38





Costs
and Expenses




Production Costs—Production costs were as
follows:




United
              
              
              West
              
              
              North
              
              
              
              
              
              Other
      Int'l/Total
              
              
              States
              
              
              Africa
              
              
              Sea
              
              
              Israel
              
              
              Corporate
      (2)(in
      thousands)Year
      Ended December 31, 2007Oil
      and gas operating costs(1)
              
              $
              299,622
              
              
              $
              190,723
              
              
              $
              39,222
              
              
              $
              37,987
              
              
              $
              7,712
              
              
              $
              23,978Workover
      and repair expense
              
              
              22,830
              
              
              
              22,516
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              314Lease
      operating expense
              
              
              322,452
              
              
              
              213,239
              
              
              
              39,222
              
              
              
              37,987
              
              
              
              7,712
              
              
              
              24,292Production
      and ad valorem taxes
              
              
              113,547
              
              
              
              91,225
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              22,322Transportation
      expense
              
              
              51,699
              
              
              
              39,542
              
              
              
              -
              
              
              
              10,523
              
              
              
              -
              
              
              
              1,634Total
      production costs
              
              $
              487,698
              
              
              $
              344,006
              
              
              $
              39,222
              
              
              $
              48,510
              
              
              $
              7,712
              
              
              $
              48,248Year
      Ended December 31, 2006Oil
      and gas operating costs(1)
              
              $
              270,136
              
              
              $
              205,348
              
              
              $
              26,557
              
              
              $
              11,655
              
              
              $
              9,066
              
              
              $
              17,510Workover
      and repair expense
              
              
              46,951
              
              
              
              46,793
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              158Lease
      operating expense
              
              
              317,087
              
              
              
              252,141
              
              
              
              26,557
              
              
              
              11,655
              
              
              
              9,066
              
              
              
              17,668Production
      and ad valorem taxes
              
              
              108,979
              
              
              
              85,960
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              23,019Transportation
      expense
              
              
              28,542
              
              
              
              20,728
              
              
              
              -
              
              
              
              7,010
              
              
              
              -
              
              
              
              804Total
      production costs
              
              $
              454,608
              
              
              $
              358,829
              
              
              $
              26,557
              
              
              $
              18,665
              
              
              $
              9,066
              
              
              $
              41,491Year
      Ended December 31, 2005Oil
      and gas operating costs(1)
              
              $
              203,833
              
              
              $
              136,087
              
              
              $
              30,661
              
              
              $
              12,244
              
              
              $
              8,504
              
              
              $
              16,337Workover
      and repair expense
              
              
              14,027
              
              
              
              13,734
              
              
              
              -
              
              
              
              259
              
              
              
              -
              
              
              
              34Lease
      operating expense
              
              
              217,860
              
              
              
              149,821
              
              
              
              30,661
              
              
              
              12,503
              
              
              
              8,504
              
              
              
              16,371Production
      and ad valorem taxes
              
              
              78,703
              
              
              
              65,428
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              13,275Transportation
      expense
              
              
              16,764
              
              
              
              9,350
              
              
              
              -
              
              
              
              6,562
              
              
              
              -
              
              
              
              852Total
      production costs
              
              $
              313,327
              
              
              $
              224,599
              
              
              $
              30,661
              
              
              $
              19,065
              
              
              $
              8,504
              
              
              $
              30,498




(1)
            Oil
      and gas operating costs include labor, fuel, repairs, replacements,
      saltwater disposal and other related lifting
  costs.


(2)
            Other
      international includes Ecuador, China and
  Argentina.




Oil and gas
operating costs increased $29 million, or 11%, from 2006 to 2007.The
increase is primarily the result of expanded operations in Equatorial Guinea and
the North Sea.




Oil
and gas operating costs increased $66 million, or 33%, from 2005 to 2006
primarily as a result of our expanded operations. Three new deepwater Gulf of
Mexico development projects came online between December 2005 and
April 2006. Fiscal year 2006 represented a full year of Patina operations,
and we acquired U.S. Exploration in 2006. In addition, the high commodity price
environment resulted in higher service, contract labor and fuel costs. Insurance
costs were also higher in 2006 due in part to increased rates for property
damage coverage combined with the added costs of providing business interruption
coverage on deepwater Gulf of Mexico assets.




Workover and repair
expense decreased $24 million during 2007 as compared with 2006.The
decrease was primarily due to a reduction in hurricane-related repair expense,
which totaled $30 million in 2006 and $1 million in 2007.




Workover
and repair expense increased $33 million during 2006 as compared with 2005.
Expense for 2006 included $30 million ($0.45 per BOE) of hurricane-related
repair expense.







39





Production
and ad valorem tax expense increased $5 million, or 4%, during 2007 as compared
with 2006 and increased $30 million, or 38%, during 2006 as compared with
2005. The increase reflects additional production from U.S. Exploration and
Patina properties. These properties have proportionately more production subject
to such taxes.




Transportation
expense increased $23 million, or 81%, during 2007 as compared with 2006. The
increase was dueprimarily due to changes in the terms of certain sales
contracts for Northern region production and increased production in the North
Sea. Transportation expense increased $12 million, or 70%, during 2006 as
compared with 2005. The increase was primarily due to a full year of Patina
operations and U.S. Exploration.




Selected
expenses on a per BOE of sales volume basis were as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005Oil
      and gas operating  costs
              
              $
              4.29
              
              
              $
              4.14
              
              
              $
              3.94Workover
      and repair expense
              
              
              0.33
              
              
              
              0.72
              
              
              
              0.27Lease
      operating costs
              
              
              4.62
              
              
              
              4.86
              
              
              
              4.21Production
      and ad valorem taxes
              
              
              1.63
              
              
              
              1.67
              
              
              
              1.52Transportation
      expense
              
              
              0.74
              
              
              
              0.44
              
              
              
              0.33Total
      production costs (1)
      (2)
              
              $
              6.99
              
              
              $
              6.97
              
              
              $
              6.06





(1)
            Consolidated
      unit rates exclude sales volumes and costs attributable to equity method
      investees.




(2)
            Sales
      volumes include natural gas sales to an LNG facility in Equatorial Guinea
      that began late first quarter of 2007. The inclusion of these volumes
      reduced the unit rate by $0.51 per BOE for
2007.




The
unit rates of total production costs per BOE, converting gas to oil on the basis
of six Mcf per barrel, have been increasing year-over-year since 2005. The
increases are due to rising third-party costs, including insurance,
hurricane-related repair expense, and higher production taxes.







40





Oil and Gas Exploration
      Expense—Exploration expense was as
  follows:




United
              
              
              West
              
              
              North
              
              
              
              
              
              Other
      Int'l/Total
              
              
              States
              
              
              Africa
              
              
              Sea
              
              
              Israel
              
              
              Corporate
      (1)(in
      thousands)Year
      Ended December 31, 2007Dry
      hole expense
              
              $
              90,210
              
              
              
              49,473
              
              
              $
              40,399
              
              
              $
              5
              
              
              $
              -
              
              
              $
              333Unproved
      lease amortization
              
              
              16,013
              
              
              
              15,176
              
              
              
              -
              
              
              
              103
              
              
              
              -
              
              
              
              734Seismic
              
              
              64,856
              
              
              
              55,258
              
              
              
              939
              
              
              
              8,184
              
              
              
              691
              
              
              
              (216
              )Staff
      expense
              
              
              45,030
              
              
              
              11,900
              
              
              
              2,106
              
              
              
              8,318
              
              
              
              645
              
              
              
              22,061Other
              
              
              2,973
              
              
              
              2,423
              
              
              
              100
              
              
              
              340
              
              
              
              82
              
              
              
              28Total
      exploration expense
              
              $
              219,082
              
              
              $
              134,230
              
              
              $
              43,544
              
              
              $
              16,950
              
              
              $
              1,418
              
              
              $
              22,940Year
      Ended December 31, 2006Dry
      hole expense
              
              $
              70,325
              
              
              $
              66,150
              
              
              $
              46
              
              
              $
              4,129
              
              
              $
              -
              
              
              $
              -Unproved
      lease amortization
              
              
              18,836
              
              
              
              18,823
              
              
              
              -
              
              
              
              13
              
              
              
              -
              
              
              
              -Seismic
              
              
              37,676
              
              
              
              29,320
              
              
              
              4,204
              
              
              
              685
              
              
              
              3
              
              
              
              3,464Staff
      expense
              
              
              38,861
              
              
              
              12,710
              
              
              
              2,887
              
              
              
              4,816
              
              
              
              250
              
              
              
              18,198Other
              
              
              2,226
              
              
              
              1,083
              
              
              
              192
              
              
              
              879
              
              
              
              33
              
              
              
              39Total
      exploration expense
              
              $
              167,924
              
              
              $
              128,086
              
              
              $
              7,329
              
              
              $
              10,522
              
              
              $
              286
              
              
              $
              21,701Year
      Ended December 31, 2005Dry
      hole expense
              
              $
              98,015
              
              
              $
              95,678
              
              
              $
              1,403
              
              
              $
              932
              
              
              $
              2
              
              
              $
              -Unproved
      lease amortization
              
              
              17,855
              
              
              
              17,855
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Seismic
              
              
              21,761
              
              
              
              11,631
              
              
              
              316
              
              
              
              1,544
              
              
              
              -
              
              
              
              8,270Staff
      expense
              
              
              34,945
              
              
              
              16,255
              
              
              
              3,760
              
              
              
              2,690
              
              
              
              189
              
              
              
              12,051Other
              
              
              5,850
              
              
              
              4,974
              
              
              
              (16
              )
              
              
              819
              
              
              
              32
              
              
              
              41Total
      exploration expense
              
              $
              178,426
              
              
              $
              146,393
              
              
              $
              5,463
              
              
              $
              5,985
              
              
              $
              223
              
              
              $
              20,362




(1)
            Other
      international includes Ecuador, China, Argentina and
    Suriname.




Exploration
expense increased $51 million, or 30% during 2007 as compared with 2006. US dry
hole expense decreased $17 million due to a reduction in the number of dry holes
drilled during 2007. Dry hole expense increased $40 million in West Africa and
included amounts related to a dry exploratory well in Equatorial Guinea and
expense related to a secondary target of an exploration well in Cameroon in
which commercial hydrocarbons were not found. Seismic expense increased a net
$27 million during 2007 as compared with 2006, primarily due to increases in US
seismic expense incurred in support of the 2007 Central Gulf of Mexico Outer
Continental Shelf Sale. Staff expense increased a net $6 million primarily due
to new venture activity.




Exploration
expense decreased $11 million, or 6% during 2006 as compared with 2005. US
dry hole expense was $30 million less due to the reduction in the number of
dry holes drilled. US seismic expense increased $18 million due primarily
to the expansion of our deepwater Gulf of Mexico 3D seismic database. In
addition, other international staff expense increased $6 million due to new
venture activity.




Exploration
expense included stock-based compensation expense of $2 million in 2007 and $1
million in 2006.







41





Depreciation, Depletion and Amortization
Expense—DD&A expense was as
follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)United
      States
              
              $
              574,001
              
              
              $
              543,431
              
              
              $
              311,153West
      Africa
              
              
              25,315
              
              
              
              23,620
              
              
              
              27,121North
      Sea
              
              
              79,450
              
              
              
              8,123
              
              
              
              9,888Israel
              
              
              17,842
              
              
              
              13,947
              
              
              
              11,188Other
      international, corporate, and other
              
              
              31,373
              
              
              
              33,487
              
              
              
              31,194Total
      DD&A expense
              
              $
              727,981
              
              
              $
              622,608
              
              
              $
              390,544Unit
      rate of DD&A per BOE (1)
      (2)
              
              $
              10.43
              
              
              $
              9.54
              
              
              $
              7.55




(1)
            Consolidated
      unit rates exclude sales volumes and costs attributable to equity method
      investees.




(2)
            Sales
      volumes include natural gas sales to an LNG facility in Equatorial Guinea
      that began late first quarter of 2007. The inclusion of these volumes
      reduced the unit rate by $0.62 per BOE for
2007.




Total
DD&A expense has been increasing since 2005 primarily due to higher
production volumes. The increase in the unit rate for 2007 as compared with 2006
was primarily due to higher acquisition and development costs in the the US and
the Dumbarton North Sea development. The increase in the unit rate for 2006 as
compared with 2005 was primarily due to the change in the mix of our production
volumes, in particular, deepwater Gulf of Mexico production.




DD&A
expense includes abandoned assets cost of $5 million in 2007,
$1 million in 2006 and $11 million in 2005.




General and Administrative
      Expense—General and administrative (“G&A”) expense was as
      follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005General
      and administrative expense (in thousands)
              
              $
              206,378
              
              
              $
              164,541
              
              
              $
              100,125Unit
      rate per BOE(1)
      (2)
              
              $
              2.96
              
              
              $
              2.52
              
              
              $
              1.94




(1)
            Consolidated
      unit rates exclude sales volumes and costs attributable to equity method
      investees.




(2)
            Sales
      volumes include natural gas sales to an LNG facility in Equatorial Guinea
      that began late first quarter of 2007. The inclusion of these volumes
      reduced the unit rate by $0.21 per BOE for
2007.




G&A expense
increased $42 million, or 25%, during 2007 as compared with 2006due to
higher salaries and wages, including incentive compensation programs, resulting
from an increase in the number of employees and results exceeding targeted
performance goals. In addition, the effects of adoption of SFAS
No. 123(R), “Share-Based Payment” (“SFAS 123(R)”), combined with
additional equity-based awards, resulted in a $14 million increase in
stock-based compensation expense included in G&A during 2007. Stock-based
compensation expense included in G&A totaled $25 million in
2007.




G&A
expense increased $64 million, or 64% during 2006 as compared with 2005.
The increase was due to higher salaries and wages and the inclusion of a full
year of G&A expense related to Patina operations. Salaries and wages also
reflected wage inflation due to a tight labor market and expanded activity
across the industry driven by higher commodity prices. In addition, the effects
of adoption of SFAS 123(R), combined with additional equity-based awards,
resulted in a $7 million increase in stock-based compensation expense included
in G&A during 2006. Stock-based compensation expense included in G&A was
$11 million in 2006 as compared with $4 million in 2005.




G&A
includes actuarially-computed net periodic benefit cost related to pension and
other postretirement benefit plans of $17 million in 2007, $19 million in
2006 and $11 million in 2005.







42





Interest Expense and Capitalized Interest—Interest
expense and capitalized interest were as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)Interest
      expense, net
              
              $
              112,957
              
              
              $
              117,045
              
              
              $
              87,541Capitalized
      interest
              
              
              16,595
              
              
              
              12,515
              
              
              
              8,684




Interest
expense, net of capitalized interest, decreased in 2007 primarily due to a
declining rate of interest applicable to the Credit Facility from 5.69% at
December 31, 2006 to 5.28% at December 31, 2007. Interest expense, net of
capitalized interest, increased in 2006 due to additional borrowings related to
the Patina Merger and acquisition of U.S. Exploration and to increases in the
interest rate applicable to the Credit Facility from 4.82% at December 31,
2005 to 5.69% at December 31, 2006.




Interest
is capitalized on development projects using an interest rate equivalent to the
average rate paid on long-term debt. Capitalized interest is included in the
cost of oil and gas assets and amortized with other costs on a
unit-of-production basis. The majority of the capitalized interest related to
long lead-time projects in West Africa, the North Sea and deepwater Gulf of
Mexico in 2007; the North Sea and deepwater Gulf of Mexico in 2006; and
deepwater Gulf of Mexico and projects in West Africa in 2005.




Weoccasionally enter into forward contracts or swap agreements to hedge
exposure to interest rate risk. At December 31, 2007, AOCL included a
deferred loss of $4 million, net of tax, related to interest rate swaps. $3
million of this amount is being reclassified into earnings, at the rate of $0.8
million per year, as an adjustment to interest expense over the term of our 51⁄4%
senior notes due 2014. The remaining $1 million loss relates to interest rate
locks that will expire in third quarter 2008. See Item 8. Financial Statements
and Supplementary Data—Note 12—Derivative Instruments and Hedging
Activities.




(Gain) Loss on Derivative
Instruments—See Item 8. Financial Statements and Supplementary Data—Note
12—Derivative Instruments and Hedging Activities.




Gain
on Sale of Assets—See
Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures.




Loss on Involuntary
Conversion—See
Item 8. Financial Statements and Supplementary Data—Note 4—Effect of
Gulf Coast Hurricanes.




Electricity Sales—Ecuador Integrated
Power Project—Through our subsidiaries, EDC Ecuador Ltd. and MachalaPower
Cia. Ltda., we have a 100% ownership interest in an integrated natural
gas-to-power project. The project includes the Amistad natural gas field,
offshore Ecuador, which supplies fuel to the Machala power plant. Electricity
sales are included in other revenues and electricity generation expense is
included in other expense, net in the consolidated statements of
operations.




Operating
data is as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005Electricity
      sales (in thousands)
              
              $
              70,916
              
              
              $
              71,603
              
              
              $
              74,228Electricity
      generation expense (in thousands)
              
              
              56,552
              
              
              
              59,494
              
              
              
              53,137Operating
      income (in thousands)
              
              
              14,364
              
              
              
              12,109
              
              
              
              21,091Power
      generation (MW)
              
              
              911,830
              
              
              
              865,983
              
              
              
              799,160Average
      power price ($/Kwh)
              
              $
              0.078
              
              
              $
              0.083
              
              
              $
              0.093




The
volume of natural gas produced and electric power generated in Ecuador are
related to thermal electricity demand in Ecuador which typically declines at the
onset of the rainy season. When Ecuador has sufficient rainfall to allow
hydroelectric power producers to provide base load power, we provide electricity
only to meet peak demand. As seasonal rains subside, we experience increasing
demand for thermal electricity.







43





Electricity
generation expense includes net increases in the allowance for doubtful accounts
of $14 million in 2007, $15 million in 2006 and $11 million in 2005.
These increases have been made to cover potentially uncollectible balances
related to the Ecuador power operations. Certain entities purchasing electricity
in Ecuador have been slow to pay amounts due us. We are pursuing various
strategies to protect our interests including international arbitration and
litigation.




Gathering, Marketing and
Processing—We market a portion of our US natural gas production, as well
as certain third-party natural gas. We sell natural gas directly to end-users,
natural gas marketers, industrial users, interstate and intrastate pipelines,
power generators and local distribution companies. We also market certain
third-party crude oil. Gathering, marketing and processing (“GMP”) proceeds are
included in other revenues and GMP expenses are included in other expense, net
in the consolidated statements of operations. Gross margin from GMP activities
was as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005(in
      thousands)GMP
      proceeds
              
              $
              24,087
              
              
              $
              27,876
              
              
              $
              55,261GMP
      expenses
              
              
              17,539
              
              
              
              18,664
              
              
              
              28,067Gross
      margin
              
              $
              6,548
              
              
              $
              9,212
              
              
              $
              27,194




We
employ derivative instruments in connection with purchases and sales of
third-party production to lock in profits or limit exposure to commodity price
risk. Most of the purchases we make are on an index basis. However, purchasers
in the markets in which we sell often require fixed or NYMEX-related pricing. We
record gains and losses on these derivative instruments using mark-to-market
accounting. Gains (losses) were de minimis for 2007, 2006 and 2005. GMP proceeds
for 2005 includes a gain of $11 million for the sale of certain gas sales
and transportation contractual assets.




Deferred Compensation
Expense—In connection with the Patina Merger, we acquired the assets and
assumed the liabilities related to a deferred compensation plan. The assets of
the deferred compensation plan are held in a rabbi trust and include shares of
our common stock and mutual fund investments. At December 31, 2007, 45% of
the market value of the assets in the rabbi trust related to our common stock.
Deferred compensation expense totaled $34 million, $16 million and $15 million
for 2007, 2006, and 2005, respectively. See Item 8. Financial Statements and
Supplementary Data—Note 11—Benefit Plans.




Impairment of Operating
Assets—We recorded impairments of $4 million in 2007, $9 million in
2006 and $5 million in 2005, primarily related to downward reserve
revisions on proved US oil and gas properties and/or adjustment of the carrying
value of properties to their fair values. Impairment expense is included in
other expense, net in the consolidated statements of operations.




Income Taxes—The income
      tax provision was as follows:




Year
      Ended December 31,2007
              
              
              2006
              
              
              2005Income
      tax provision (in thousands)
              
              $
              423,697
              
              
              $
              417,789
              
              
              $
              322,940Effective
      rate
              
              
              31.0
              %
              
              
              38.1
              %
              
              
              33.3
              %




Several
factors resulted in a decrease in our effective tax rate for 2007. The major
factor was that, in 2006, $100 million of goodwill write-off associated
with the sale of the Gulf of Mexico shelf properties was not deductible, which
increased the rate for 2006. Other factors were an increase in deferred tax
assets arising from foreign tax credits, a decrease in the Chinese tax rate, and
the realization of additional income from equity method investees which is a
favorable permanent difference in calculating the income tax
expense.
  Our
effective tax rate increased significantly in 2006 from 2005 due to several
factors. The most significant factor was the nondeductible goodwill write-off of
$100 million related to the sale of the Gulf of Mexico shelf properties
discussed in the preceding paragraph. The rate was also impacted by decreases in
our US deferred tax assets arising from future foreign tax credits due to
changes in the limitation on our ability to claim foreign tax credits. In
addition, a change in UK tax law increased our UK tax expense in 2006.
Offsetting these increases was a reduction in the effective tax rate due to an
increase in earnings from equity method investees, which is a favorable
permanent difference in calculating income tax expense.
  The
2005 effective tax rate was impacted by our ability to claim a foreign tax
credit for the income taxes paid by foreign branch operations, as well as a
benefit realized on the repatriation of foreign earnings under the American Jobs
Creation Act of 2004.







44









PART IV




Item
      15.
            Exhibits, Financial Statements
      Schedules.


(a)       The
following documents are filed as a part of this report:




(3)
            Exhibits:
      The exhibits required to be filed by this Item 15 are set forth in
      the Index to Exhibits accompanying this
report.







45





SIGNATURES




Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.




NOBLE
      ENERGY, INC.(Registrant)Date:
      May 19, 2008
            By:
      /s/ Chris TongChris
      Tong,Senior
      Vice President, Chief Financial
Officer













46







INDEX
TO EXHIBITS







The
Index to Exhibits on pages 106 through 108 of the Annual Report on Form 10-K for
the fiscal year ended December 31, 2007 is amended by the addition of the
following exhibits:







Exhibit
              Number
            
            
            
            Exhibit12.1
            
            —
            
            Calculation
      of ratio of earnings to fixed charges, filed herewith.23.5
            
            —
            
            Consent
      of Netherland, Sewell & Associates, Inc., filed herewith.31.3
            
            —
            
            Certification
      of the Company’s Chief Executive Officer Pursuant to Section 302 of
      the Sarbanes-Oxley Act of 2002 (18 U.S.C.
    Section 7241).31.4
            
            —
            
            Certification
      of the Company’s Chief Financial Officer Pursuant to Section 302 of
      the Sarbanes-Oxley Act of 2002 (18 U.S.C.
    Section 7241).32.3
            
            —
            
            Certification
      of the Company’s Chief Executive Officer Pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002 (18 U.S.C.
    Section 1350).32.4
            
            —
            
            Certification
      of the Company’s Chief Financial Officer Pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002 (18 U.S.C.
    Section 1350).





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