APACHE CORP - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(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, 2004,
OR

[ ] 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 1-4300

APACHE CORPORATION
A DELAWARE CORPORATION IRS EMPLOYER NO. 41-0747868

ONE POST OAK CENTRAL
2000 POST OAK BOULEVARD, SUITE 100
HOUSTON, TEXAS 77056-4400
TELEPHONE NUMBER (713) 296-6000

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $0.625 par value

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. Yes [X] 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 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. [ ]

Indicate by check whether registrant is an accelerated filer (as defined in
Rule 12b-2 of the Act). [X]

Aggregate market value of the voting and non-voting common
equity held by non-affiliates of registrant as of June 30,
2004...................................................... $14,197,397,378
Number of shares of registrant's common stock outstanding as
of February 28, 2005...................................... 328,095,581

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of registrant's proxy statement relating to registrant's 2005
annual meeting of stockholders have been incorporated by reference into Part III
hereof.

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TABLE OF CONTENTS

DESCRIPTION

All defined terms under Rule 4-10(a) of Regulation S-X shall have their
statutorily prescribed meanings when used in this report. Quantities of natural
gas are expressed in this report in terms of thousand cubic feet (Mcf), million
cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is
quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions
of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil
equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural
gas liquids are compared with natural gas in terms of million cubic feet
equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil
is the energy equivalent of six Mcf of natural gas. Daily oil and gas production
is expressed in terms of barrels of oil per day (b/d) and thousands or millions
of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of
British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in
terms of one million British thermal units (MMBtu), which is approximately equal
to one Mcf. With respect to information relating to our working interest in
wells or acreage, "net" oil and gas wells or acreage is determined by
multiplying gross wells or acreage by our working interest therein. Unless
otherwise specified, all references to wells and acres are gross.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL

Apache Corporation, a Delaware corporation formed in 1954, is an
independent energy company that explores for, develops and produces natural gas,
crude oil and natural gas liquids. In North America, our exploration and
production interests are focused in the Gulf of Mexico, the Gulf Coast, the
Permian Basin, the Anadarko Basin and the Western Sedimentary Basin of Canada.
Outside of North America we have exploration and production interests offshore
and onshore Egypt, offshore Western Australia, offshore the United Kingdom in
the North Sea (North Sea), offshore The People's Republic of China (China), and
onshore Argentina. Our common stock, par value $0.625 per share, has been listed
on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange
(CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since January 2004.
In June 2004, we filed certifications of our compliance with the listing
standards of the NYSE and the NASDAQ, including our Chief Executive Officer's
certification of compliance with the NYSE standards. Through our website,
http://www.apachecorp.com, you can access electronic copies of the charters of
the committees of our Board of Directors, other documents related to Apache's
corporate governance, (including our Code of Business Conduct and Governance
Principles) and documents Apache files with the Securities and Exchange
Commission (SEC), including our annual reports on Form 10-K, quarterly reports
on Form 10-Q, and current reports on Form 8-K, as well as any amendments to
these reports. Included in our annual and quarterly reports are the
certifications of our chief executive officer and our chief financial officer
that are required by applicable laws and regulations. Access to these electronic
filings is available as soon as practicable after filing with the SEC. You may
also request printed copies of our committee charters or other governance
documents by writing to our corporate secretary at the address on the cover of
this report.

We hold interests in many of our U.S., Canadian, and other International
properties through operating subsidiaries, such as Apache Canada Ltd., DEK
Energy Company (DEKALB), Apache Energy Limited (AEL), Apache International,
Inc., and Apache Overseas, Inc. Properties referred to in this document may be
held by those subsidiaries. We treat all operations as one line of business.

Throughout this report, per share results and share amounts have been
adjusted for i) the 10 percent common stock dividend paid on January 21, 2002,
to our shareholders of record on December 31, 2001, ii) the five percent common
stock dividend paid on April 2, 2003, to our shareholders of record on March 12,
2003, and iii) the two-for-one stock split distributed on January 14, 2004, to
our shareholders of record on December 31, 2003. The stock dividends and stock
split reflect our board of directors' belief that we can reward our shareholders
while remaining focused on our primary objective of building Apache to last by
achieving profitable growth.

OUR GROWTH STRATEGY

Building on Apache's first 50 years in business, our mission remains the
same; to grow a significant and profitable company for the benefit of our
shareholders. However, over the years our strategy for achieving profitable
growth has evolved. Over the most recent decade Apache has been an active
acquirer of properties, following up each one with proactive exploitation
operations, including workovers, re-completions, and drilling, to increase
production and reserves, as well as efforts to reduce costs per unit produced
and enhance profitability. Also during the past decade, we added an
international exploration component to our strategy, which exposed our
shareholders to larger reserve targets and a greater ability to grow production
and reserves through drilling. This strategy starts with strong operating
capabilities in core areas where we obtain local expertise and, through active
operations, can make a difference. In each of our core producing areas, we have
built teams that have the technical knowledge, sense of urgency, and the desire
to wring more out of Apache's assets. Our local expertise also provides an
advantage in day-to-day operations and when acquisition opportunities arise in
core areas. After an extensive bottom-up/top-down planning process, each
operating area is given the autonomy necessary to make drilling and operating
decisions and to act quickly. To foster

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predictable and generally consistent results, a numbers-intensive management and
incentive system underscores high cash flow and rate-of-return targets. These
and other goals are measured monthly and reviewed with senior management
quarterly.

We take a portfolio approach to the areas in which we drill in an effort to
generate consistent, profitable growth. This approach provides diversity in
terms of hydrocarbon mix (oil and gas), reserve life, geological risk and
geographical location. In the U.S., our Gulf of Mexico operations generate
substantial production and cash flow and excellent rates of return; however,
with steep decline rates, offshore reserves are generally short lived and
difficult to replace through drilling alone. Our Central region brings the
balance of long-lived reserves and consistent drilling results. In general, the
United States is mature, offering smaller reserve targets but presently,
excellent prices and high margins. We seek to drill actively in the United
States, but not to the extent of pursuing growth at any cost. Our future growth
is more likely to be achieved in the U.S. through drilling and acquisitions,
rather than through drilling activity alone.

Our Canadian and other international operations provide a higher potential
to grow through drilling. Canada, Australia, Egypt and, in the last year, the
North Sea, all offer generally larger exploration reserve targets than those to
which we are exposed in the United States. Also, Apache's operations in Egypt
and Australia typically include large acreage positions with considerable
running room when compared to the U.S., where there are more companies competing
for acreage and drilling opportunities.

Once established in a core area, Apache takes an active approach to
drilling operations and supplements growth with occasional property
acquisitions. While the incremental production and reserves from acquisitions
are a key component in our evaluation of acquisitions, generally speaking, it is
the exploitation opportunities associated with property acquisitions where we
believe the greatest amount of value can be added and where the overall
rate-of-return can be impacted most. Over the last decade, Apache has invested a
little more than a dollar in drilling and exploitation operations for every
dollar invested in acquisitions. The objective is to increase reserves and
production on all properties, thereby lowering costs per unit, and increasing
overall profitability.

In the North Sea, for example, an active drilling and exploitation campaign
since acquiring the Forties Field in April 2003 enabled us to drive
fourth-quarter 2004 average daily production up to 61,680 barrels of oil from
40,950 barrels per day in the fourth quarter of 2003. This 50 percent increase
in production spread operating costs over a greater production base, driving
costs per unit down and profit margins up.

For 2005, we plan on another active year of drilling. Because we revise our
capital expenditure estimates frequently throughout the year based on industry
conditions and results to date, accurately projecting annual capital
expenditures is difficult at best. However, our preliminary estimate of 2005
capital expenditures is in excess of $2.5 billion. While we do not budget for
acquisitions because their timing is unpredictable, we continue to look for
acquisition properties where we believe we can add value and earn adequate rates
of return. Because we have maintained our financial flexibility (our year-end
ratio of debt-to-capitalization was 24 percent), we are in a good position to
take advantage of acquisition opportunities should they arise.

Apache has grown production 25 of the last 26 years and reserves for 19
consecutive years in varying industry environments. We are fortunate to have
evolved to the point where we believe we have the necessary ingredients to
continue growing over time through drilling, acquisition or both.

OPERATING HIGHLIGHTS

We currently have interests in seven countries: the United States, Canada,
Egypt, Australia, the United Kingdom, China, and Argentina. Our reportable
segments are the United States, Canada, Egypt, Australia, North Sea, and Other
International. In the U.S., our exploration and production activities are
divided into two regions: Gulf Coast and Central. At year-end, approximately 70
percent of our estimated proved reserves were located in North America. Outside
North America, our exploration and production activities are focused primarily
in Egypt, the North Sea, and Australia. Additionally, we have had production
from our interests in China for over a year, and have a small production
interest in Argentina.

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The following table sets out a brief comparative summary of certain key
2004 data for each area. More detailed information regarding the natural gas,
oil, and natural gas liquids (NGLs) production and average prices received in
our core geographic areas for 2004, 2003, and 2002 is available later in this
section under Production, Pricing and Lease Operating Cost Data with further
discussion and analysis in Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations in this Form 10-K. In addition,
for information concerning the amount of revenue, expenses, operating income
(loss) and total assets attributable to each of the reportable segments, see
Note 14, Supplemental Oil and Gas Disclosures (Unaudited), and Note 13, Business
Segment Information of Item 15 in this Form 10-K. For information regarding Oil
and Gas Capital Expenditures for each of the last three years, see Item 7,
Management's Discussion of Analysis of Financial Condition and Results of
Operations, "Capital Resources and Liquidity" in this Form 10-K.

THE FOLLOWING DISCUSSIONS INCLUDE REFERENCES TO OUR PLANS FOR 2005. THESE
ONLY REPRESENT INITIAL ESTIMATES AND COULD VARY SIGNIFICANTLY FROM ACTUAL
RESULTS. IN RECENT YEARS, THERE HAVE BEEN LARGE DIFFERENCES BETWEEN OUR CAPITAL
EXPENDITURE FORECASTS AND OUR ACTUAL ACTIVITY. DURING THE YEAR, WE ROUTINELY
ADJUST OUR LEVEL OF SPENDING BASED ON SUCCESS AND CHANGING INDUSTRY CONDITIONS.

UNITED STATES

Gulf Coast -- The Gulf Coast region comprises our interests in and along
the Gulf of Mexico, primarily in the areas in and offshore Louisiana and Texas.
Apache is the largest acreage holder and the second largest producer in Gulf
waters less than 1,200 feet deep. In 2004 and 2003, the Gulf Coast was our
leading region for both production volumes and revenues. This region performed
452 workover and recompletion operations during 2004 and completed 106 out of
133 total wells drilled. As of year-end 2004, Gulf Coast accounted for 21
percent of our estimated proved reserves. Although actual annual capital
expenditures may change considerably in 2005, we currently estimate spending
approximately $600 million to drill around 120 wells and to continue our
production enhancement and exploitation programs with a focus on properties
acquired from Anadarko Petroleum (Anadarko) in 2004 and BP p.l.c. (BP) and Shell
Exploration and Production Company (Shell) in 2003. See Note 2, Acquisitions and
Divestitures of Item 15 in this Form 10-K for detailed discussion of
acquisitions.

Central -- The Central Region includes assets in the Permian Basin of West
Texas and New Mexico, East Texas, and the Anadarko Basin of western Oklahoma,
where the Company got its start 50 years ago. At year-end 2004, the Central
region accounted for approximately 23 percent of our estimated proved reserves,

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the second largest in the Company. The Central Region's estimated proved
reserves increased 20 percent in 2004 through acquisitions, the most significant
being the Exxon Mobil Corporation (ExxonMobil) transaction, discussed later in
this section, and the most active drilling year in the region's history. During
2004, we participated in 283 wells, 268 of which were completed as productive.
Apache performed 367 workovers and recompletions in the region during the year.
Although actual annual capital expenditures may change considerably, in 2005, we
currently estimate spending approximately $300 million drilling 200-plus wells
spread among the newly acquired properties and our sizable acreage base in the
Anadarko Basin and to continue our production enhancement programs.

Marketing -- The Company began directly marketing its own U.S. natural gas
production in July 2003. Our objective is to reduce our dependence on middlemen
by taking control of our marketing activities in an effort to enhance the value
of our natural gas sales by diversifying our customer base and optimizing
transportation arrangements. The flexibility to transport our gas from the
wellhead has provided us access to new markets as our customers now include
Local Distribution Companies (LDCs), utilities, end-users, integrated majors and
to a lesser extent, marketers. We manage the sales risk associated with our
natural gas production fluctuations by selling a portion of our production into
the daily market. We manage our credit risk by selling to creditworthy
customers, monitoring our credit exposure daily and making adjustments as
needed. Prior to July 2003, Apache sold most of its U.S. natural gas production
to Cinergy Marketing and Trading, LLC (Cinergy), under a long-term gas purchase
agreement. The prices received for our gas production under this agreement were
based on a published index. See Note 12, Transactions with Related Parties and
Major Customers of Item 15 in this Form 10-K.

Several years ago, we locked in fixed prices on a portion of our U.S.
future natural gas production using long-term, fixed-price physical contracts.
These contracts, which represented approximately nine percent of our 2004
domestic natural gas production, will expire in 2005 through 2008. The contracts
provide protection to the Company's cash flows in the event of decreasing
natural gas prices. See Item 7a, Quantitative and Qualitative Disclosures about
Market Risk "Commodity Risk" in this Form 10-K.

In general, most of our gas is being sold on a monthly basis at either
monthly or daily market prices. In an effort to increase our sales to direct
users of natural gas and meet the needs of our customers, we also periodically
sell some of our gas under long-term contracts at prices that fluctuate with
market conditions. Our relationships with the LDCs and direct users of natural
gas continue to be an important focus of our marketing efforts.

We market our own U.S. crude oil to integrated majors, marketers and
refiners. Contracts are generally 30 days and renew automatically until
canceled. These oil contracts generally provide for sales at prices that change
with daily market conditions.

CANADA

Overview -- Our exploration and development activity in the Canadian region
is concentrated in the Provinces of Alberta, British Columbia, Saskatchewan and
the Northwest Territories. The region comprises 25 percent of our estimated
proved reserves, the largest in the Company. We hold over 4.8 million net acres
in Canada, the largest of the North American regions. Canada was our most active
drilling area in 2004, with Apache participating in 1,313 gross wells,
approximately 75 percent of which were shallow development wells. We completed
1,211 as producers and conducted 1,095 workover and recompletion projects.

Apache acquired four packages totaling 382,000 acres in a farmout from
ExxonMobil in the third quarter of 2004. Apache is planning to drill at least
250 wells over a two-year period which began in October 2004, with an
opportunity for further drilling in the third year. Apache earns its interest
section by section, and the Company is off to a fast start with 50 wells drilled
on this acreage in the fourth quarter of 2004 and a similar number estimated for
the first quarter of 2005. The new acreage fits well with Apache's asset
portfolio in Canada, which comprises large acreage plays with high working
interest ownership -- fields such as Hatton, Provost and Nevis. Apache is also
targeting those same areas for coalbed methane (CBM) and in the process has
emerged as the nation's largest producer of CBM. The North and South Grant Lands
in the ExxonMobil farmout provide additional CBM potential. Although actual
annual capital expenditures may change
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considerably with industry conditions and results, we currently estimate
spending approximately $600 million drilling around 1,000 wells, continuing our
exploration and exploitation program and developing our gas processing
infrastructure.

Marketing -- Our Canadian natural gas sales include sales to LDCs,
utilities, end-users, integrated majors, supply aggregators and marketers in the
United States and Canada. With the expansion of pipeline transport capacity out
of Canada in recent years, Canadian prices have become more closely correlated
with United States prices. To diversify our market exposure and optimize pricing
differences in the U.S. and Canada, we transport natural gas via our firm
transportation contracts to California, the Chicago area, and eastern Canada. We
currently have a limited number of longer term commitments to sell gas into
either the United States or eastern Canada, but the volumes are relatively small
and none of the terms extends beyond 2011. The prices we receive under these
contracts fluctuate monthly with market indices. The remainder, which represents
over 95 percent of our Canadian natural gas production, is sold on a monthly
basis at either monthly or daily market prices.

Our Canadian crude oil is primarily sold to refiners, integrated majors and
marketers. To increase the market value of our condensate and heavier crudes,
our condensate is either used or sold for blending purposes. All our NGLs are
sold to midstream companies. We sell our crude and NGLs on Canadian Postings
which are market reflective prices that depend on worldwide crude prices and are
adjusted for transportation and quality. In order to reach more purchasers and
diversify our market, we transport crude on 12 pipelines to the major trading
hubs within Alberta, Saskatchewan and Manitoba.

EGYPT

Overview -- In Egypt, our operations are generally conducted pursuant to
production sharing contracts under which contractor partners pay all operating
and capital expenditure costs for exploration and development. A percentage of
the production, usually up to 40 percent, is available to the contractor group
to recover operating and capital expenditure costs. In general, the balance of
the production is allocated between the contractor group and the Egyptian
General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is
the largest leaseholder and the most active driller in the Western Desert. Egypt
is the country with our largest single acreage position where as of December 31,
2004, we held over 8.5 million net acres in 14 concessions, including four
concessions in the Western Desert that were awarded in 2004 and are scheduled
for parliamentary approval in the first half of 2005. Development leases within
concessions generally have 25-year lives with extensions possible for additional
commercial discoveries, or on a negotiated basis. Apache is the largest producer
of liquid hydrocarbons and the second largest producer of natural gas in the
Western Desert. Egypt accounted for approximately 18 percent of Apache's
production revenues on 16 percent of total production for the year and accounted
for 12 percent of total estimated proved reserves at December 31, 2004. Apache
had an active drilling program in Egypt, completing 103 of 116 gross wells, for
a success rate of 88 percent. Although actual annual capital expenditures may
change considerably with industry conditions and success, we currently plan to
spend approximately $500 million in 2005 on approximately 130 exploration,
development and appraisal wells and installing and upgrading production
facilities.

Marketing -- Historically, we and our partners have sold our natural gas
production to EGPC pursuant to 25-year take-or-pay contracts. Pricing under
these contracts is based on the energy equivalent of 85 percent of Gulf of Suez
Blend crude oil. Beginning in 2000, EGPC introduced an alternative gas pricing
formula for certain quantities of gas purchased by them. This Industry Pricing
is a sliding scale based on Dated-Brent crude oil with a minimum of $1.50 per
MMbtu and a maximum of $2.65 per MMbtu upon reaching a Dated-Brent price of
$21.00 per barrel. We previously entered into new gas sales contracts containing
Industry Pricing at our Matruh, Ras Kanayes, Ras El Hekma, and Akik development
leases. In 2004, we entered into four new gas sales agreements containing
Industry Pricing. Those gas sales agreements relate to the Qasr, Imhotep, North
East Abu Gharadig and Atoun development leases. Additionally, in exchange for
extension of the Khalda Concession lease, a further amendment to the Khalda
Concession Agreement was executed in July 2004 whereby the old gas price formula
based on Gulf of Suez Blend, was preserved until 2013 for up to 100 MMcf/d
produced from the South Umbarka Concession and the Khalda, Khalda West, Salam
and Tarek

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development leases. Volumes above 100 MMcf/d from those areas are priced at
Industry Pricing. The Btu factor for our Egyptian gas generally ranges from
1,100 to 1,300 Btu per Mcf.

Production from our recently discovered Qasr field will be sold under the
terms of a 25-year Gas Sales Agreement with EGPC, signed April 22, 2004, and
covering up to 2.1 Tcf of natural gas. Principle terms include supplying up to
300 MMcf/d to the Egyptian market. Pricing under the Agreement will be according
to Industry Pricing described above.

Finally, a December 11, 2003, Memorandum of Understanding (MOU) for a Gas
Sales Agreement, Field Development Plan and Deepwater Development Lease for a
minimum of 2.7 Tcf of natural gas over 25 years from our deepwater interests in
the West Mediterranean Concession was extended to a current expiration date of
March 31, 2005, and is expected to be extended again. Reserve recognition and
proper scaling of the significant future development infrastructure (currently
estimated at over $800 million gross) are pending negotiation and completion of
the final sales agreement with EGPC and resolution in delays of certain payments
by EGPC.

In Egypt, oil from the Khalda Concession is generally sold directly into
the Egyptian oil pipeline grid. Oil from the Qarun Concession and other nearby
Western Desert blocks is delivered by pipeline to tanks at the Dashour tank farm
northeast of the Qarun Block. In Egypt, most of our oil production is presently
sold to EGPC on a spot basis at a "Western Desert" price (indexed to Brent Crude
Oil). In 2004, we exported our inaugural three cargoes (approximately 960,000
barrels) of Western Desert crude oil from the El Hamra terminal to refiners in
the Mediterranean. These export cargoes were sold at market prices comparable to
domestic sales to EGPC. Additional export sales from both the Khalda and Qarun
areas have continued in 2005.

Please refer to Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations "Critical Accounting Policies and Estimates,
Allowance for Doubtful Accounts" in this Form 10-K for a discussion of our
Egyptian receivables.

AUSTRALIA

Overview -- Our exploration activity in Australia is focused in the
offshore Carnarvon, Gippsland, and Perth Basins where Apache holds 5.3 million
net acres in 29 Exploration Permits, 10 Production Licenses, and five Retention
Leases. Production operations are concentrated in the Carnarvon Basin with 10
Production Licenses, nine of which are operated by Apache. In 2004, we produced
16.4 MMboe in Australia (10 percent of our total production) generating $458
million of production revenues. During the year we participated in drilling 31
wells; 22 exploration and nine development wells. Nine of the exploration wells
and seven of the development wells were productive for an overall 52 percent
success rate.

Australian region exploration successes included 2004 discoveries at
Stickle and Harrison in the Exmouth sub-basin. We also had a substantial
appraisal program with five productive wells. On the development side, three new
fields commenced production in 2004 including the Linda gas field in April, and
the Gudrun and Monet oil fields in February and June, respectively. Apache owns
a 68.5 percent working and revenue interest in all three developments.

First production from the John Brookes gas development is scheduled for the
third quarter of 2005 at an average projected rate of 60 MMcf of gas and 360
barrels of condensate per day net to Apache's 55 percent interest. Key factors
for continuing success in 2005 will be maintaining oil production, increasing
gas production to fulfill the requirements of two new gas contracts and
continued success in our exploration program. Although actual annual capital
expenditures may change considerably with industry conditions and success, we
currently estimate spending approximately $300 million for around 60
exploration, appraisal and development wells, and various new facilities and
facility upgrades in 2005.

Marketing -- In Australia during 2004, we agreed to terms on four new gas
sales contracts, increased our reserve commitment in two active contracts, and
formalized an agreement to increase 2005 daily rates into two other active
contracts. In aggregate, we committed an additional 130 Bcf of gas (gross) for
delivery. Under the largest new contract, we will supply more than 77 Bcf of gas
(gross) over a 10-year period commencing July
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2005. As of December 31, 2004, Apache had a total of 27 active gas contracts
with expiration dates ranging from 2005 to 2026.

Apache's net sales during 2005 are expected to climb with the initiation of
delivery into the Burrup Fertilizer contract at a net rate of 47 MMcf of gas per
day. Generally, natural gas is sold in Western Australia under long-term,
fixed-price contracts, many of which contain price escalation clauses based on
the Australian consumer price index. Apache realized an average price of US$1.65
per Mcf for gas sold in Australia in 2004.

We continue to export all of our crude oil production into the
international market at prices which fluctuate with world market conditions.

NORTH SEA

Overview -- In 2003, we established a new core area in the North Sea with
our acquisition of the Forties Field. First discovered in 1970, the Forties has
been one of the most productive fields in the North Sea. In 2004, the region
generated $472 million of production revenue, averaged 53,000 b/d of production
and accounted for nine percent of our year-end estimated proved reserves.
Although actual annual capital expenditures may change considerably with
industry conditions and success, we currently estimate spending approximately
$400 million on 20 wells and continuation of facility upgrades to increase the
overall efficiency of the platforms.

Marketing -- Concurrent with the acquisition of the North Sea properties,
the Company entered into a separate crude oil physical sales contract with BP.
The contract provided for BP to market all of the Company's equity crude oil
through December 31, 2004. A portion of the crude oil (25,000 b/d through
January 31, 2004 and 40,000 b/d for the remainder of the term) was sold at fixed
prices. The balance of the crude oil was sold at prevailing market prices.
Beginning in 2005, the Company entered into two new term contracts for the
physical sale of our crude at prevailing market prices, which fluctuate with
market conditions. In addition to receiving a higher value than Dated-Brent for
the Forties production, we also receive a premium for committing to a longer
term sales agreement.

OTHER INTERNATIONAL

We have exploration and production interests offshore China and in
Argentina. During 2003, we ceased operations in Poland.

In August 2003, first production came on stream from our interests in the
Zhao Dong block in Bohai Bay, China. We are the operator, with a 24.5 percent
interest, of the Zhao Dong Block pursuant to a production sharing contract
through 2023. Fourth quarter 2004 average net production of 9,000 barrels per
day was about 13 percent higher than the comparable prior-year period. In 2004,
our Chinese interests produced $91 million of production revenue from over 2.8
MMbbls of production. Since production began, our portion of the production has
been exported to international markets at prevailing market prices. Beginning in
March 2005, we will sell our equity crude oil into the domestic Chinese market,
pursuant to term contracts at market prices for oil imported into China.
Although actual capital expenditures may change considerably with industry
conditions and success, we currently estimate spending approximately $20 million
on new wells, recompletions and facility upgrades during 2005.

In 2001, we acquired exploration and production assets from Fletcher
Challenge and Anadarko in Argentina. After these transactions, we hold interests
in a small number of blocks in Argentina's Neuquen Basin. We are the operator
with a 100 percent interest in two blocks and hold smaller interests in three
non-operated blocks. For 2004, these interests represented under one percent of
our estimated proved reserves and generated small amounts of production and
revenue. All of our production is currently sold under term arrangements into
the domestic market under prevailing market prices which are subject to
regulatory caps. Our total net acreage position in Argentina is 321,000
developed acres at December 31, 2004. Although actual capital expenditures may
change considerably with industry conditions and success, we currently estimate
spending approximately $20 million to drill new wells in Argentina.

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SIGNIFICANT ACQUISITIONS

ACQUISITION FROM ANADARKO

On August 20, 2004, Apache signed a definitive agreement to acquire all of
Anadarko's Gulf of Mexico-Outer Continental Shelf properties (excluding certain
deepwater properties) for $537 million, subject to normal post-closing
adjustments, including preferential rights. The transaction was effective as of
October 1, 2004, and included interests in 74 fields covering 232 offshore
blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the
blocks were undeveloped at the time of the acquisition. Apache operates 49 of
the fields comprising approximately 70 percent of the production. Prior to
Apache's purchase from Anadarko, Morgan Stanley Capital Group, Inc. (Morgan
Stanley) paid Anadarko $646 million to acquire an overriding royalty interest in
these properties. For a complete discussion of this transaction, please refer to
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations, Results of Operations "Acquisitions and Divestitures" and Note 2,
Acquisitions and Divestitures of Item 15 in this Form 10-K.

ACQUISITION FROM EXXONMOBIL

During the third quarter of 2004, Apache entered into separate arrangements
with ExxonMobil that provided for property transfers and joint operating and
exploration activity across a broad range of prospective and mature properties
in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana
and the Gulf of Mexico-Outer Continental Shelf. Apache's participation included
cash payments of approximately $347 million, subject to normal post closing
adjustments. For a complete discussion of this transaction, please refer to Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations, "Results of Operations, Acquisitions and Divestitures" and Note 2,
Acquisitions and Divestitures of Item 15 in this Form 10-K.

DRILLING STATISTICS

Worldwide, in 2004, we participated in drilling 1,913 gross wells, with
1,735 (90.7 percent) completed as producers. We also performed over 1,836
workovers and recompletions during the year. Historically, our drilling
activities in the U.S. generally concentrate on exploitation and extension of
existing, producing fields rather than exploration. As a general matter, our
operations outside of the U.S. focus on a mix of exploration and exploitation
wells. In addition to our completed wells, at year-end several wells had not yet
reached completion: 21 in the U.S. (12.88 net); six in Canada (six net); 14 in
Egypt (12.98 net); one in Australia (0.6 net); and two in Argentina (two net).

8

The following table shows the results of the oil and gas wells drilled and
tested for each of the last three fiscal years:

PRODUCTIVE OIL AND GAS WELLS

The number of productive oil and gas wells, operated and non-operated, in
which we had an interest as of December 31, 2004, is set forth below:

9

PRODUCTION, PRICING AND LEASE OPERATING COST DATA

The following table describes, for each of the last three fiscal years,
oil, NGLs and gas production, average lease operating costs and average sales
prices for each of the countries where we have operations.

GROSS AND NET UNDEVELOPED AND DEVELOPED ACREAGE

The following table sets out our gross and net acreage position in each
country where we have operations.

Apache's operations in Poland ceased in 2003 and remaining acreage was
fully relinquished in early 2005.

10

ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS

As of December 31, 2004, Apache had total estimated proved reserves of 932
MMbbls of crude oil, condensate and NGLs and 6.0 Tcf of natural gas. Combined,
these total estimated proved reserves are equivalent to 1.94 billion barrels of
oil equivalent or 11.6 Tcf of natural gas. The company's estimated reserves grew
for the 19th consecutive year.

The Company's estimates of proved reserves and proved developed reserves as
of December 31, 2004, 2003, and 2002, changes in estimated proved reserves
during the last three years, and estimates of future net cash flows and
discounted future net cash flows from estimated proved reserves are contained in
Note 14, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this
Form 10-K. These estimated future net cash flows are based on prices on the last
day of the year and are calculated in accordance with Statement of Financial
Accounting Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing
Activities." Disclosure of this value and related reserves has been prepared in
accordance with SEC Regulation S-X Rule 4-10.

Proved oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and NGLs that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Reserve estimates
are considered proved if economical producibility is supported by either actual
production or conclusive formation tests. Estimated reserves that can be
produced economically through application of improved recovery techniques are
included in the "proved" classification when successful testing by a pilot
project or the operation of an active, improved recovery program in the
reservoir provides support for the engineering analysis on which the project or
program is based. Estimated proved developed oil and gas reserves can be
expected to be recovered through existing wells with existing equipment and
operating methods.

Apache emphasizes that its reported reserves are estimates which, by their
nature, are subject to revision. The estimates are made using available
geological and reservoir data, as well as production performance data. These
estimates are reviewed annually, and revised either upward or downward, as
warranted by additional performance data.

Apache's proved reserves are estimated at the property level and compiled
for reporting purposes by a centralized group of experienced reservoir engineers
who are independent of the operating groups. These engineers interact with
engineering and geoscience personnel in each of Apache's operating areas and
with accounting and marketing employees to obtain the necessary data for
projecting future production, costs, net revenues and ultimate recoverable
reserves. Reserves are reviewed internally with senior management and presented
to the board of directors in summary form on a quarterly basis. Annually, each
property is reviewed in detail by our centralized and operating region engineers
to insure forecasts of operating expenses, netback prices, production trends and
development timing are reasonable.

We engage Ryder Scott Company, L.P. Petroleum Consultants as independent
petroleum engineers, to review our estimates of proved hydrocarbon liquid and
gas reserves and provide an opinion letter on the reasonableness of Apache's
internal projections. During this review, they prepare independent projections
for each reviewed property and determine if the Company's estimates are within
engineering tolerance by geographical area. The independent reviews typically
cover a large percentage of major value fields, international properties and new
wells drilled during the year. During 2004, 2003, and 2002, their review covered
79, 78 and 68 percent of the Apache's estimated reserve value, respectively.

RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS

Our business activities and the value of our securities are subject to
significant hazards and risks, including those described below. If any of such
events should occur, our business, financial condition, liquidity and/or results
of operations could be materially harmed, and holders and purchasers of our
securities could lose part or all of their investments. Additional risks
relating to our securities may be included in the prospectuses for securities we
issue in the future.

11

OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES OF CRUDE OIL, NATURAL GAS
AND NATURAL GAS LIQUIDS, WHICH HAVE HISTORICALLY BEEN VERY VOLATILE

Our estimated proved reserves, revenues, profitability, operating cash
flows and future rate of growth are highly dependent on the prices of crude oil,
natural gas and NGLs, which are affected by numerous factors beyond our control.
Historically these prices have been very volatile. A significant downward trend
in commodity prices would have a material adverse effect on our revenues,
profitability and cash flow and could result in a reduction in the carrying
value of our oil and gas properties and the amounts of our estimated proved oil
and gas reserves.

OUR COMMODITY HEDGING MAY PREVENT US FROM BENEFITING FULLY FROM PRICE INCREASES
AND MAY EXPOSE US TO OTHER RISKS

To the extent that we engage in hedging activities to protect ourselves
from commodity price volatility, we may be prevented from realizing the benefits
of price increases above the levels of the hedges.

ACQUISITIONS OR DISCOVERIES OF ADDITIONAL RESERVES ARE NEEDED TO AVOID A
MATERIAL DECLINE IN RESERVES AND PRODUCTION

The rate of production from oil and gas properties generally declines as
reserves are depleted. Except to the extent that we acquire additional
properties containing estimated proved reserves, conduct successful exploration
and development activities or, through engineering studies, identify additional
behind-pipe zones, secondary recovery reserves or tertiary recovery reserves,
our estimated proved reserves will decline materially as reserves are produced.
Future oil and gas production is, therefore, highly dependent upon our level of
success in acquiring or finding additional reserves.

OUR DRILLING ACTIVITIES MAY NOT BE PRODUCTIVE

Drilling for oil and gas involves numerous risks, including the risk that
we will not encounter commercially productive oil or gas reservoirs. The costs
of drilling, completing and operating wells are often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors including, but not limited to:

- unexpected drilling conditions;

- pressure or irregularities in formations;

- equipment failures or accidents;

- fires, explosions, blow-outs and surface cratering;

- marine risks such as capsizing, collisions and hurricanes;

- other adverse weather conditions; and

- shortages or delays in the delivery of equipment.

Certain future drilling activities may not be successful and, if
unsuccessful, this failure could have an adverse effect on our future results of
operations and financial condition. While all drilling, whether developmental or
exploratory, involves these risks, exploratory drilling involves greater risks
of dry holes or failure to find commercial quantities of hydrocarbons.

RISKS ARISING FROM THE FAILURE TO FULLY IDENTIFY POTENTIAL PROBLEMS RELATED TO
ACQUIRED RESERVES OR TO PROPERLY ESTIMATE THOSE RESERVES

One of our primary growth strategies is the acquisition of oil and gas
properties. Although we perform a review of the acquired properties that we
believe is consistent with industry practices, such reviews are inherently
incomplete. It generally is not feasible to review in depth every individual
property involved in each acquisition. Ordinarily, we will focus our review
efforts on the higher-value properties and will sample the

12

remainder. However, even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken. Even when problems
are identified, we often assume certain environmental and other risks and
liabilities in connection with acquired properties. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs with respect to acquired
properties, and actual results may vary substantially from those assumed in the
estimates (see above). In addition, there can be no assurance that acquisitions
will not have an adverse effect upon our operating results, particularly during
the periods in which the operations of acquired businesses are being integrated
into our ongoing operations.

WE ARE SUBJECT TO DOMESTIC GOVERNMENTAL RISKS THAT MAY IMPACT OUR OPERATIONS

Our domestic operations have been, and at times in the future may be,
affected by political developments and by federal, state and local laws and
regulations such as restrictions on production, changes in taxes, royalties and
other amounts payable to governments or governmental agencies, price controls
and environmental protection laws and regulations.

GLOBAL POLITICAL AND ECONOMIC DEVELOPMENTS MAY IMPACT OUR OPERATIONS

Political and economic factors in international markets may have a material
adverse effect on our operations. On an equivalent-barrel basis, approximately
59 percent of our oil, NGLs and natural gas production in 2004 was outside the
United States, and approximately 56 percent of our estimated proved oil and gas
reserves at December 31, 2004 were located outside of the United States.

There are many risks associated with operations in international markets,
including changes in foreign governmental policies relating to crude oil, NGLs,
and natural gas pricing and taxation, other political, economic or diplomatic
developments, changing political conditions and international monetary
fluctuations. These risks include: political and economic instability or war;
the possibility that a foreign government may seize our property with or without
compensation; confiscatory taxation; legal proceedings and claims arising from
our foreign investments or operations; a foreign government attempting to
renegotiate or revoke existing contractual arrangements, or failing to extend or
renew such arrangements; fluctuating currency values and currency controls; and
constrained natural gas markets dependent on demand in a single or limited
geographical area.

On December 23, 2004, Apache entered into a twenty-year insurance contract
with the Overseas Private Investment Corporation (OPIC) which provides $300
million of political risk insurance for the Company's Egyptian operations. This
policy insures us against (1) non-payment by EGPC of arbitral awards covering
amounts owed Apache on past due invoices and (2) expropriation of exportable
petroleum when actions taken by the Government of Egypt prevent Apache from
exporting our share of production. See Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations, "Critical Accounting
Policies and Estimates, Allowance for Doubtful Accounts" in this Form 10-K for
additional discussion of our Egyptian receivables.

Actions of the United States government through tax and other legislation,
executive order and commercial restrictions can adversely affect our operating
profitability overseas, as well as in the U.S. Various agencies of the United
States and other governments have from time to time imposed restrictions which
have limited our ability to gain attractive opportunities or even operate in
various countries. These restrictions have in the past limited our foreign
opportunities and may continue to do so in the future.

COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS

We, as an owner or lessee and operator of oil and gas properties, are
subject to various federal, provincial, state, local and foreign country laws
and regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability on the lessee under an
13

oil and gas lease for the cost of pollution clean-up resulting from operations,
subject the lessee to liability for pollution damages, and require suspension or
cessation of operations in affected areas.

We have made and will continue to make expenditures in our efforts to
comply with these requirements, which we believe are necessary business costs in
the oil and gas industry. We have established policies for continuing compliance
with environmental laws and regulations, including regulations applicable to our
operations in all countries in which we do business. We also have established
operational procedures and training programs designed to minimize the
environmental impact of our field facilities. The costs incurred by these
policies and procedures are inextricably connected to normal operating expenses
such that we are unable to separate the expenses related to environmental
matters; however, we do not believe any such additional expenses are material to
our financial position or results of operations.

Apache manages its exposure to environmental liabilities on properties to
be acquired by identifying existing problems and assessing the potential
liability. The Company also conducts periodic reviews, on a company-wide basis,
to identify changes in its environmental risk profile. These reviews evaluate
whether there is a probable liability, its amount, and the likelihood that the
liability will be incurred. The amount of any potential liability is determined
by considering, among other matters, incremental direct costs of any likely
remediation and the proportionate cost of our employees who are expected to
devote a significant amount of time to any possible remediation effort. Our
general policy is to limit any reserve additions to incidents or sites that are
considered probable to result in an expected remediation cost exceeding
$100,000. In October 2003, Apache was issued a Findings of Violation and Order
for Compliance (an "Administrative Order") by the United States Environmental
Protection Agency (EPA), which cited certain paperwork administrative errors and
effluent violations reported by Apache during the period May 1, 1998 to June 30,
2003, as part of our offshore discharge permit monitoring. Apache signed a
Consent Agreement and Final Order (CAFO) to pay a monetary penalty of $21,000
and undertake a Supplemental Environmental Project (SEP) with an estimated cost
of $94,500. The SEP Project is underway and is expected to be completed by the
March 31, 2005, deadline imposed by the EPA. We are waiting for the EPA to set
the effective date of the CAFO and will pay the $21,000 penalty within 30 days
of that date.

We maintain insurance coverage, which we believe is customary in the
industry, although we are not fully insured against all environmental risks. As
of December 31, 2004, we had an accrued liability of $11 million for
environmental remediation. We have not incurred any material environmental
remediation costs in any of the periods presented and are not aware of any
future environmental remediation matters that would be material to our financial
position or results of operations.

Although environmental requirements have a substantial impact upon the
energy industry, generally these requirements do not appear to affect us any
differently, or to any greater or lesser extent, than other upstream companies
in the industry. We do not believe that compliance with federal, state, local or
foreign country provisions regulating the discharge of materials into the
environment, or otherwise relating to the protection of the environment, will
have a material adverse effect upon the capital expenditures, earnings or
competitive position of Apache or its subsidiaries; however, there is no
assurance that changes in or additions to laws or regulations regarding the
protection of the environment will not have such an impact.

INDUSTRY COMPETITION

Strong competition exists in all sectors of the oil and gas exploration and
production industry. We compete with major integrated and other independent oil
and gas companies for acquisition of oil and gas leases, properties and
reserves, equipment and labor required to explore, develop and operate those
properties and the marketing of oil and natural gas production. Higher recent
crude oil and natural gas prices have increased the costs of properties
available for acquisition and there are a greater number of companies with the
financial resources to pursue acquisition opportunities. Many of our competitors
have financial and other resources substantially larger than those we possess
and have established strategic long-term positions and maintain strong
governmental relationships in countries in which we may seek new entry. As a
consequence, we may be at a competitive disadvantage in bidding for drilling
rights. In addition, many of our larger competitors may have a competitive
advantage when responding to factors that affect demand for oil and

14

natural gas production, such as changing worldwide prices and levels of
production, the cost and availability of alternative fuels and the application
of government regulations. We also compete in attracting and retaining
personnel, including geologists, geo-physicists, engineers and other
specialists.

INSURANCE DOES NOT COVER ALL RISKS

Exploration for and production of oil and natural gas can be hazardous,
involving unforeseen occurrences such as blowouts, cratering, fires 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 or
the environment. We maintain insurance against certain losses or liabilities
arising from our operations in accordance with customary industry practices and
in amounts that management believes to be prudent; however, insurance is not
available to us against all operational risks.

INVESTORS IN OUR SECURITIES MAY ENCOUNTER DIFFICULTIES IN OBTAINING, OR MAY BE
UNABLE TO OBTAIN, RECOVERIES FROM ARTHUR ANDERSEN WITH RESPECT TO ITS AUDITS OF
OUR FINANCIAL STATEMENTS

On March 14, 2002, our previous independent public accountant, Arthur
Andersen LLP (Arthur Andersen), was indicted on federal obstruction of justice
charges arising from the federal government's investigation of Enron Corp. On
June 15, 2002, a jury returned with a guilty verdict against Arthur Andersen
following a trial. As a public company, we are required to file with the SEC
periodic financial statements audited or reviewed by an independent public
accountant. On March 29, 2002, we decided not to engage Arthur Andersen as our
independent auditors, and engaged Ernst & Young LLP (Ernst & Young) to serve as
our new independent auditors for 2002. Ernst & Young also served as our
independent public accountants in 2003 and 2004. However, included in this
annual report on Form 10-K are financial data and other information for 2001
that were audited by Arthur Andersen. Investors in our securities may encounter
difficulties in obtaining, or be unable to obtain, from Arthur Andersen with
respect to its audits of our financial statements, relief that may be available
to investors under the federal securities laws against auditing firms.

EMPLOYEES

On December 31, 2004, we had 2,642 employees. None of our employees are
subject to collective bargaining agreements.

OFFICES

Our principal executive offices are located at One Post Oak Central, 2000
Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2004, we
maintained regional exploration and/or production offices in Tulsa, Oklahoma;
Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia;
Aberdeen, Scotland; Beijing, China; and Buenos Aires, Argentina. Apache leases
all of its primary office space. The current lease on our principal executive
offices runs through December 31, 2013. For information regarding the Company's
obligations under its office leases, see the information appearing in the table
in Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, "Liquidity and Capital Resources" and Note 10,
Commitments and Contingencies, "Other Commitments and Contingencies, Operating
Leases and Other Commitments" of Item 15 in this Form 10-K.

TITLE TO INTERESTS

We believe that our title to the various interests set forth above is
satisfactory and consistent with the standards generally accepted in the oil and
gas industry, subject only to immaterial exceptions which do not detract
substantially from the value of the interests or materially interfere with their
use in our operations. The interests owned by us may be subject to one or more
royalty, overriding royalty and other outstanding interests customary in the
industry. The interests may additionally be subject to obligations or duties
under applicable laws, ordinances, rules, regulations and orders of arbitral or
governmental authorities. In addition, the interests may be subject to burdens
such as production payments, net profits interests, liens incident to operating
agreements and current taxes, development obligations under oil and gas leases
and other encumbrances,

15

easements and restrictions, none of which detract substantially from the value
of the interests or materially interfere with their use in our operations.

ITEM 3. LEGAL PROCEEDINGS

See the information set forth in Note 10, Commitments and Contingencies of
Item 15 and Items 1 and 2, Business and Properties, "Costs Incurred Related to
Environmental Matters" in this Form 10-K.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of our security holders during the most
recently ended fiscal quarter.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

During 2004, Apache common stock, par value $0.625 per share, was traded on
the New York and Chicago Stock exchanges, and the NASDAQ National Market under
the symbol APA. The table below provides certain information regarding our
common stock for 2004 and 2003. Prices were obtained from The New York Stock
Exchange, Inc. Composite Transactions Reporting System; however, the per share
prices and dividends shown in the following table have been adjusted to reflect
the two-for-one stock split, which is described below. Per share prices and
quarterly dividends shown below have been rounded to the indicated decimal
place.

The closing price per share of our common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for February 28,
2005, was $62.88. At February 28, 2005, there were 328,095,581 shares of our
common stock outstanding held by approximately 8,000 shareholders of record and
approximately 226,000 beneficial owners.

We have paid cash dividends on our common stock for 40 consecutive years
through December 31, 2004. When, and if, declared by our board of directors,
future dividend payments will depend upon our level of earnings, financial
requirements and other relevant factors.

In 1995, under our stockholder rights plan, each of our common stockholders
received a dividend of one "preferred stock purchase right" for each 2.310
outstanding shares of common stock (adjusted for subsequent stock dividends and
two-for-one stock split) that the stockholder owned. Unless the rights have been
previously redeemed, all shares of Apache common stock are issued with rights
and, the rights trade automatically with our shares of common stock. For a
description of the rights, please refer to Note 8, Capital Stock of Item 15 in
this Form 10-K.

On December 18, 2002, our board of directors declared a five percent
dividend on our shares of common stock payable in common stock on April 2, 2003
to shareholders of record on March 12, 2003. Pursuant to the terms of the
declared five percent stock dividend, we issued 15,736,496 shares (adjusted for
the 2003 stock split) of our common stock on April 2, 2003 to the holders of the
307,819,628 shares of common stock outstanding on March 12, 2003. No fractional
shares were issued in connection with the stock dividend and we made cash
payments totaling approximately $1,437,000 in lieu of fractional shares.

On January 22, 2003, in conjunction with the pending acquisition from BP,
the Company completed the public offering of 19.8 million shares (adjusted for
the stock split) of Apache common stock, including

16

2.6 million shares (adjusted for the stock split) for the underwriters'
over-allotment option, at $29.05 per share. Net proceeds after placement fees
totaled approximately $554 million. The proceeds were used to repay indebtedness
under our commercial paper program and money market lines of credit and to
invest in short-term treasury-only money market funds and treasury notes to hold
funds for the $1.3 billion acquisition from BP.

On September 11, 2003, our board of directors declared a two-for-one common
stock split which was distributed on January 14, 2004 to holders of record on
December 31, 2003. In connection with the stock split, the Company issued
166,254,667 shares.

Information concerning securities authorized for issuance under equity
compensation plans is set forth under the caption "Equity Compensation Plan
Information" in the proxy statement relating to the Company's 2005 annual
meeting of stockholders which is incorporated herein by reference.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and
its consolidated subsidiaries over the five-year period ended December 31, 2004,
which information has been derived from the Company's audited financial
statements. Our financial statements for the years 2000 and 2001 were audited by
Arthur Andersen. For a discussion of the risks relating to Arthur Andersen's
audit of our financial statements, please see discussion of issues related to
Arthur Andersen in Item 1 and 2, Business and Properties, "Risk Factors Related
to our Business and Operations" of this Form 10-K. This information should be
read in connection with, and is qualified in its entirety by, the more detailed
information in the Company's financial statements of Item 15 in this Form 10-K.

For a discussion of significant acquisitions, see Note 2 of Item 15 in this
Form 10-K.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

OVERVIEW

Apache Corporation is an independent energy company whose principle
business includes exploration, development and production of crude oil, natural
gas and natural gas liquids. The Company operates in five core countries which,
collectively, contained over 99 percent of the Company's 2004 year-end estimated
proved reserves and accounted for over 98 percent of the Company's 2004 oil and
gas production revenues. These principle operations are located in the United
States, Canada, Egypt, Australia and offshore the United

17

Kingdom in the North Sea. The Company's smaller non-core operations are
conducted offshore China and in Argentina.

Apache adheres to a portfolio approach to provide diversity in terms of
hydrocarbon mix (crude oil and natural gas), reserve life, geologic risk and
geographic location. Our growth strategy focuses on economic growth through
drilling, acquisitions, or a combination of both, depending on, among other
things, cost levels and availability of acquisition opportunities. As we pursue
growth, we continually monitor the capital resources available to us to meet our
future financial obligations and liquidity needs. These obligations and needs
are met with cash on hand, cash generated from our operations, unused committed
borrowing capacity under our global credit facility, and the capital markets.
The interest cost of debt and access to the equity markets are greatly
influenced by the Company's ability to maintain both a strong balance sheet and
generate ongoing operating cash flow. For these reasons, we strive to maintain a
manageable debt load that is properly balanced with equity, and our single-A
credit ratings. We are also cognizant of the costs to add reserves through
drilling and acquisitions as well as the costs necessary to produce such
reserves. Consequently, we closely monitor trends by operating area in drilling
costs and the price at which properties are available for purchase, so that we
may adjust our budgets accordingly and allocate funds to projects based on
potential rate of return. We review operating costs monthly by operating area,
on both an absolute dollar and per unit of production basis. We then compare
these results to our historical norms after factoring in the impact from
property acquisitions and changes in industry conditions in order to actively
manage individual cost elements as appropriate. Given the inherent volatility
and unpredictability of commodity prices and changing industry conditions, we
frequently revise our forecasts and adjust our budgets accordingly.

We entered 2004 with historically strong commodity prices which
strengthened further during the year. Average realized prices for crude oil and
natural gas increased 27 and seven percent, respectively, over 2003; a
reflection of higher worldwide commodity prices. In addition, oil and natural
gas production increased 13 and one percent, respectively, a result of
acquisitions and successful exploration and development drilling programs.
Increased production combined with high commodity prices drove the Company's
attainment of several operational and financial milestones as noted below.

- Our 2004 oil and gas production revenues totaled $5.3 billion, $1.1
billion higher than in 2003.

- We generated earnings of $1.7 billion, 49 percent above our prior-year
level. On a diluted share basis earnings rose $1.60 to $5.03 per diluted
share.

- Net cash provided by operating activities increased 19 percent from the
prior year to $3.2 billion.

- Production increased for 25 of the last 26 years.

- 2004 year-end estimated proved reserves grew 17 percent from 2003 to 1.94
billion barrels of oil equivalent, marking the 19th consecutive year of
reserve growth.

- Exploration, development and acquisition expenditures totaled $3.4
billion in 2004.

- Apache ended the year with debt at 24 percent of capitalization, down 2%
from year-end 2003.

- Fitch upgraded Apache's senior unsecured long-term debt rating from A- to
A and Moody's and Standard and Poor's continue to rate Apache's unsecured
long-term debt A3 and A-, respectively.

- The Company increased its common stock dividend from an annual rate of 24
cents per share to 32 cents per share.

The Company spent $1.1 billion on acquisitions in 2004, down $500 million
from 2003, as acquisition expenditures typically vary from year to year based on
the availability of opportunities that fit Apache's overall strategy. On the
exploration and development front, Apache spent $2.3 billion, 61 percent more
than last year, drilling a record number of wells. Significant highlights
resulting from the Company's acquisition, exploration and development programs
in each of our core areas follow.

18

U.S.:

- Apache entered into two separate Agreements with Exxon Mobil Corporation
(ExxonMobil) in the U.S. In West Texas and New Mexico we acquired
properties in 23 mature producing oil and gas fields for $318 million and
separately entered into a partnership to obtain additional interests in
the properties. Additionally, we entered into joint exploration
agreements to explore Apache's acreage in South Louisiana and the Gulf of
Mexico-Outer Continental Shelf. For additional details regarding these
agreements refer to the Acquisitions and Divestitures section of this
Item 7.

- Apache purchased interests in 74 fields covering 232 blocks and 104
platforms in the Gulf of Mexico from Anadarko Petroleum Corporation
(Anadarko) for $532 million. The properties were subject to a
pre-existing overriding royalty interest owned by Morgan Stanley Capital
Group, Inc. (Morgan Stanley). For additional details regarding this
transaction refer to the Acquisitions and Divestitures section of this
Item 7.

- The Company spent $755 million to drill over 400 wells on continued
exploitation of its U.S. properties, including those purchased from BP
p.l.c. (BP) and Shell Exploration and Production Company (Shell) in 2003
and the 2004 acquisitions noted above. The U.S. accounted for 41 percent
of our 2004 equivalent production and 44 percent of the Company's
estimated proved reserves at year-end 2004.

CANADA:

- The Company entered in to a farm-in agreement with ExxonMobil covering
approximately 380,000 gross acres of undeveloped properties in the
Western Canadian Province of Alberta, increasing our gross acreage to 6.5
million acres of prospective properties in Canada. By drilling at least
250 wells over a two-year period, which began in October 2004, Apache
will receive a one-year extension in which to earn additional sections.
Apache drilled 50 wells on this acreage in the fourth quarter of 2004.
For additional details regarding this transaction refer to the
Acquisitions and Divestitures section of this Item 7.

- The Company emerged as the largest producer of coalbed methane in Canada
with its drilling activities in the Nevis area. The North and South Grant
Lands in the ExxonMobil farmout provide additional coalbed methane
potential.

- Apache spent $757 million on exploration and development in Canada,
completing 1,211 of 1,313 wells for a success rate of 92 percent. Canada
accounted for approximately 18 percent of our equivalent production in
2004 and 25 percent of the Company's estimated proved reserves at
year-end 2004.

EGYPT:

- We continued to evaluate and develop the Qasr field, a July 2003
discovery, drilling several successful appraisal wells and one
development well, and commencing commercial production on a limited basis
in September 2004. The appraisal wells confirmed the overall
seismically-defined structure of the field and our original estimated
range of ultimately recoverable reserves. Following further development
of the field and construction of pipeline facilities, we currently expect
gross gas production of approximately 75 MMcf/d by third quarter 2005,
ramping up to approximately 150 MMcf/d and 5,000 barrels of condensate
per day around year-end 2005. The Qasr production will be sold under the
terms of a 25-year Gas Sales Agreement, signed April 22, 2004, with the
Egyptian General Petroleum Company (EGPC) covering up to 2.1 Tcf of
natural gas from the Qasr field. Principle terms include supplying up to
300 MMcf/d to the Egyptian market. The pricing terms under the agreement
are indexed to crude oil and include a minimum price of $1.50 per million
British thermal units (MMBtu) and a maximum price of $2.65 per MMBtu. The
Btu factor for our Egyptian gas generally ranges between 1,100 and 1,300
Btu per Mcf.

- On May 20, 2004, we announced the Sheiba 18-3 discovery. It is the first
commercial oil discovery in the eastern part of the Shell-operated North
East Abu Gharadig Concession in Egypt's Western Desert. We are continuing
to evaluate and explore this area.
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- On June 23, 2004, we announced the Ozoris-4 well which identified new
field pays in the Khalda Concession. The discovery of stratigraphically
trapped gas-condensate in Upper Safa sands in the Ozoris-4 opens up a
large new play in the Shushan Basin, north of the Qasr high and west of
the Khalda Ridge fields.

- On August 19, 2004, we announced two gas discoveries, the Imhoptep-1X on
the Khalda Offset Concession and the Mihos-1X well on the Matruh
Concession, that began flowing into the Tarek gas plant allowing it to
operate at full capacity of 100 MMcf/d.

AUSTRALIA:

- On January 6, 2004, we announced that the Thomas Bright-2 appraisal well
in the John Brookes field of the Carnarvon Basin offshore Western
Australia extended the boundary of the reservoir, thus increasing
estimated gross recoverable reserves. All of the 628 Bcf of estimated
proved reserves at John Brookes are dedicated to existing long-term
contracts (also see Item 1 and 2, Business and Properties, "Operating
Highlights -- Australia" in this Form 10-K for additional information on
Apache's gas contracts in Australia). We expect to complete facility
installation in mid-2005, with initial production commencing during the
third quarter 2005.

- On May 19, 2004, we announced the Stickle-1 well, our third wildcat
discovery in the Exmouth Sub-Basin of the Carnarvon Basin offshore
Western Australia. On July 13, 2004, we announced that our Ravensworth-2
appraisal well in the Exmouth Sub-Basin encountered an oil column 49 feet
higher than we expected, extending the area of the field considerably
farther north than we had mapped based on the July 2003 Ravensworth-1
well. Appraisal wells along with additional exploration drilling is
currently scheduled for 2005.

NORTH SEA:

- Our focus in the North Sea was two-pronged: invest capital to improve
field operating efficiency and undertake an active drilling program.
During 2004, we drilled 12 successful wells and invested over $150
million in capital expenditures to improve operating efficiency, boosting
fourth-quarter 2004 production to an average of 61,680 b/d, over 50
percent higher than the fourth quarter of 2003.

Our year-end 2004 estimated reserves were balanced, with a 48 percent oil
and 52 percent natural gas mix. This compares to 51 percent oil and 49 percent
natural gas at the end of 2003. Estimated proved undeveloped reserves
represented 32.7 percent of total estimated proved reserves for year-end 2004
compared to 28.5 percent at year-end 2003. The increase is primarily attributed
to appraisal drilling in the Qasr field, expansion of our infill shallow-gas
drilling programs in Canada, new gas contracts in Australia and a high
percentage of undeveloped reserves in the Anadarko acquisition.

Apache was challenged in 2004 by steadily increasing service and
acquisition costs resulting from increased demand with high commodity prices.
Service costs impacting both drilling and lease operating costs have grown
significantly over the past year; including rig rates, drill pipe costs,
chemical costs and the costs of power and fuel. The Company reviews these costs
for each core area on a routine basis and pursues alternatives in maintaining
efficient levels of costs and expenses. While we are encouraged by the current
outlook for 2005, we will continue to monitor costs and unless drilling costs
level out, we may act to reduce our drilling expenditures, as we did in 2001.
This is especially true in the U.S. where reserve targets continue to decrease
in size. Acquisition costs also increased, however Apache has developed
approaches to complete prudent asset acquisitions even when prices are high by
routinely hedging production from newly acquired assets in order to protect
acquisition economics in the critical early years. We believe we are well
positioned to pursue future acquisitions should the appropriate opportunities
arise. The Company also experienced unfavorable foreign exchange rate movements
in Canada, Australia and the U.K. in 2004 which impacted our lease operating and
drilling costs. Refer to the "Costs" section of this Item 7, Management
Discussion and Analysis of Financial Condition and Results of Operations, for
further discussion of items impacting costs in 2004.

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In July 2004, the Company signed an amendment agreement with the EGPC
which, among other things, extended the term of the Khalda, Khalda West and
Salam development leases through 2024. These development leases would have
expired in 2011, 2012 and 2010, respectively. We also received a five-year
extension on our Khalda Offset exploration acreage, with an option for an
additional three-year extension. As part of this agreement and in conjunction
with the Qasr 25-year Gas Sales Agreement discussed above, we agreed to re-price
natural gas volumes in excess of 100 MMcf/d produced from the Khalda Concession
development leases and future Khalda Offset development leases. Under the new
pricing formula, Apache will receive a price indexed to crude oil, with a
minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu. Pricing for the
first 100 MMcf/d remains subject to the original contract price, which is
indexed to oil pricing, but without a minimum or maximum. The pricing for this
first 100 MMcf/d continues until January 1, 2013, at which time all Khalda area
gas will be priced at the new pricing formula. For 2004, Apache's price averaged
$4.35 per Mcf, which was a blend of the old and new contracts.

As discussed in Note 1, Summary of Significant Accounting Policies and Note
8, Capital Stock of Item 15 in this Form 10-K, Apache's share price exceeded the
first threshold ($43.29) under its 2000 Share Appreciation Plan on April 28,
2004. As such, the Company will issue to substantially all employees
approximately 900,000 shares of its common stock, after minimum tax withholding
requirements, in three annual installments. The first installment was issued in
May 2004. The second and third installments will be issued in 2005 and 2006 to
employees remaining with the Company during those periods. Also, on October 26,
2004, Apache's share price exceeded the second threshold ($51.95) of the
Company's 2000 Share Appreciation Plan. Accordingly, Apache will issue
approximately 2.2 million additional shares of its common stock, after minimum
tax withholding requirements, in three equal installments. The first installment
was issued in November 2004. The second and third installments will be issued in
2005 and 2006 to employees remaining with the Company during those periods. In
February, 2005, the Company's Board of Directors voted to present to the
stockholders of the Company for approval a new plan that provides incentives for
employees to double the share price again, to $108, by the end of 2008, with an
interim goal to be achieved by the end of 2007. If the goals are achieved, the
shareholder value of the Company will grow by an additional $18 billion.

On January 14, 2004, we completed the two-for-one common stock split
approved by our board of directors in September 2003. Separately, on January 26,
2004, the NASDAQ Stock Market, Inc. approved Apache for trading on the NASDAQ
National Market (NASDAQ), an intention we first announced on January 12, 2004.
Our common stock is now listed on the NASDAQ as well as the New York Stock
Exchange and Chicago Stock Exchange.

RESULTS OF OPERATIONS

This section includes a discussion of our 2004 and 2003 results of
operations and provides insight into unique events and circumstances for each of
the Company's six reportable segments. Apache's geographic segments include the
United States, Canada, Egypt, Australia, the North Sea and Other International.
These segments are primarily in the business of crude oil and natural gas
exploration and production. Please refer to Note 13, Business Segment
Information of Item 15 in this Form 10-K for segment information.

ACQUISITIONS AND DIVESTITURES

ExxonMobil

During the third quarter of 2004, Apache entered into separate arrangements
with ExxonMobil that provided for property transfers and joint operating and
exploration activity across a broad range of prospective and mature properties
in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana
and on the Gulf of Mexico-Outer Continental Shelf. Apache's participation
included cash payments of approximately $347 million, subject to normal post
closing adjustments. The following summarizes these transactions:

ExxonMobil -- Western Canada In August 2004, Apache signed a farm-in
agreement with ExxonMobil covering approximately 380,000 gross acres of
undeveloped properties in the Western Canadian Province of Alberta. Under the
agreement, Apache has the right to earn acreage sections by drilling an initial
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well on each such section. By drilling at least 250 wells during the initial
two-year earning period under the agreement, Apache will receive a one-year
extension in which to earn additional sections. As to any sections earned by
Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35
percent of its working interest on leasehold acreage. Under certain
circumstances, ExxonMobil has the right to convert its retained 35 percent
working interest into a 12.5 percent overriding royalty. In addition, during the
terms of this agreement, Apache is required to carry ExxonMobil's retained
working interest with respect to certain drilling, capping, completion,
equipping and tie-in costs associated with wells drilled on leasehold acreage.

ExxonMobil -- West Texas and New Mexico In September 2004, Apache acquired
interests from ExxonMobil in 23 mature producing oil and gas fields in West
Texas and New Mexico for $318 million. Apache separately contributed
approximately $29 million into a partnership to obtain additional interests in
the properties. ExxonMobil will retain interests in the properties through the
partnership, including the right to receive, on certain fields, 60 percent of
the oil proceeds above $30 per barrel in 2004, $29 per barrel in 2005 and $28
per barrel during the period from 2006 thru 2009.

ExxonMobil -- Louisiana and Gulf of Mexico-Outer Continental Shelf Also in
September 2004, Apache and ExxonMobil entered into joint exploration agreements
to explore Apache's acreage in South Louisiana and the Gulf of Mexico-Outer
Continental Shelf. The agreements provide for an initial term of five years,
with the potential for an additional five years based on expenditures by
ExxonMobil. Pursuant to the agreement covering South Louisiana, Apache leased 50
percent of its interests below certain producing or productive formations in the
acreage to ExxonMobil, subject to retention of a 20 percent royalty interest.
Pursuant to the agreement covering the Gulf of Mexico-Outer Continental Shelf,
no assignments will be made until a prospect has been proposed and the initial
well has been drilled. Apache will retain all rights in each prospect above
certain producing or productive formations and further will retain a three
percent overriding royalty interest in any property assigned to ExxonMobil. See
Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for a
complete discussion of those transactions.

Anadarko

On August 20, 2004, Apache signed a definitive agreement to acquire all of
Anadarko Gulf of Mexico-Outer Continental Shelf properties (excluding certain
deepwater properties) for $537 million, subject to normal post-closing
adjustments, including preferential rights. The transaction was effective as of
October 1, 2004, and included interests in 74 fields covering 232 offshore
blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the
blocks were undeveloped at the time of the acquisition. Apache operates 49 of
the fields comprising approximately 70 percent of the production.

Prior to Apache's purchase from Anadarko, Morgan Stanley paid Anadarko $646
million to acquire an overriding royalty interest in these properties.
Anadarko's sale of an overriding royalty interest to Morgan Stanley is commonly
known in the industry as a volumetric production payment (VPP), the obligations
of which Apache assumed along with its subsequent purchase. Under the terms of
the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas
production (20 MMboe) over four years beginning in October 2004. The VPP
represents a non-operating interest in the properties that is free of all costs
of operations and production. Morgan Stanley is entitled to first production and
may receive up to 90 percent of the production from the assets encumbered by the
VPP in any given month to satisfy these deliverables. However, Morgan Stanley
has no right to look to other assets or production of Apache. The VPP is
scheduled to terminate on August 31, 2008, but may be extended if all scheduled
VPP volumes have not been delivered to Morgan Stanley and the properties are
still producing. The VPP includes restrictions on the Company's ability to sell
the properties subject to the VPP or resign as operator of VPP properties it
currently operates. Upon termination of the VPP, all rights, titles and
interests revert back to Apache. Apache does not record the reserves and
production volumes attributable to the VPP.

The strategic rationale for Apache buying these assets burdened by a
volumetric production payment is several fold. First, because Morgan Stanley
gets their production first and Apache receives the remainder, Morgan Stanley is
paying substantially more per boe, thereby significantly reducing Apache's cost
per unit. Second, although Morgan Stanley's priority call on production leaves
Apache with more risk, in exchange we

22

retain all the upside associated with finding more reserves on the acquired
properties than anticipated at the time of the acquisition. This is a
risk/reward scenario with which we are comfortable and that plays to our long
history of adding value to numerous acquired properties through proactive
operations. Third, our experience is that invariably we earn higher rates of
return from drilling and related activities than we do from acquisitions. Yet
acquisitions bring an inventory of drilling and exploitation opportunities.
Because Morgan Stanley paid Anadarko more than Apache for proved reserves, a
higher percentage of Apache's investment will be concentrated in the higher risk
but generally higher reward, future drilling activity. As a final note, Morgan
Stanley, while having less risk, is not risk free. In the event that the
properties purchased by Apache are insufficient to deliver the volumes sold to
Morgan Stanley, there is no recourse to any properties other than those acquired
from Anadarko. See the Capital Resources and Liquidity section of this item for
further discussion of VPPs.

The $537 million purchase price agreed to in the definitive agreement was
subsequently adjusted for the exercise of preferential rights by third parties
and other normal post-closing adjustments. After adjusting for these items,
Apache paid $532 million for the properties and recorded estimated proved
reserves of 60 MMboe, of which 50 percent is natural gas. In addition, an $84
million liability for the future cost to produce and deliver the VPP volumes was
recorded by the Company. This liability will be amortized as the volumes are
produced and delivered to Morgan Stanley. Apache also recorded abandonment
obligations for the properties of approximately $134 million and other
obligations assumed from Anadarko in the amount of $27 million. Apache allocated
$122 million of the purchase price to unproved property. The purchase price was
funded by borrowings under the Company's commercial paper program.

2003 Acquisitions

In 2003, we spent $1.6 billion on oil and gas acquisitions, adding 267
MMboe to our reserve base. The preponderance of our 2003 acquisition activity
was focused in the North Sea and Gulf of Mexico. In January 2003, we agreed to
purchase from BP the North Sea Forties Field offshore the United Kingdom and
properties in the Gulf of Mexico. The BP purchase, representing 72 percent of
our 2003 acquisition capital expenditures, established a new international core
area and augmented our Gulf of Mexico portfolio. In July 2003, we consummated a
deal with Shell adding additional oil and gas fields on the outer Continental
Shelf of the Gulf of Mexico. Apache recorded 27.4 MMboe of reserves from the
Shell acquisition, with interest in 26 fields and two onshore gas plants. The
balance of our 2003 activity involved smaller acquisitions in Australia and
North America.

In association with the BP acquisition, Apache agreed to sell all of the
production from the North Sea properties to BP for a two-year period ending
December 31, 2004 at a combination of fixed and market sensitive prices pursuant
to a contract entered into in connection with the North Sea purchase agreement.
To protect the acquisition economics on the Gulf of Mexico properties acquired
from BP we hedged prices on a substantial portion of the oil production for a
12-month period ending January 31, 2004, and a substantial portion of the gas
production for the first two years.

Prior to Apache's transaction with Shell, Morgan Stanley paid Shell $300
million to acquire an overriding royalty interest in a portion of the reserves
to be produced and delivered under a VPP agreement. Under the terms of the VPP
obligation which Apache assumed, Morgan Stanley is to receive a total of 11.4
MMboe of production from the properties over the period from August 2003 through
October 2007. Morgan Stanley is entitled to first production and may receive up
to 90 percent of the production from the assets encumbered by the VPP, but
Morgan Stanley may look only to the acquired properties for delivery of the
scheduled volumes. The VPP may be extended beyond October 2007 if all scheduled
VPP volumes have not been delivered to Morgan Stanley and the acquired
properties are still producing. The VPP is a non-operating interest free of all
costs associated with operations and production. As a result of this VPP
obligation, Apache recorded a $60 million liability for the future cost to
produce and deliver volumes subject to the VPP. This liability is being
amortized as the volumes are produced and delivered to Morgan Stanley. Apache
does not record the reserves and production volumes attributable to the VPP.

23

Our acquisitions help maintain diversity in terms of hydrocarbon product
(oil or gas), geologic risk and geographic location. As shown in Note 14,
Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K,
our North American 2004 and 2003 year-end reserves were 70 percent of total
reserves. Our 2004 North American average daily production as a percent of our
total production decreased to 59 percent from 64 percent in 2003. While the
U.S., a highly stable political environment, remains our largest producing core
area, Apache will continue to evaluate acquisition opportunities in existing
core areas and in new areas should they arise.

We routinely evaluate our property portfolio and divest those that are
marginal or no longer fit into our strategic growth program. We divested $4
million, $59 million and $7 million of properties during 2004, 2003 and 2002,
respectively.

REVENUES

Our revenues are sensitive to changes in prices received for our products.
A substantial portion of our production is sold at prevailing market prices,
which fluctuate in response to many factors that are outside of our control.
Given the current tightly balanced supply-demand market, small variations in
either supply or demand, or both, can have dramatic effects on prices we receive
for our oil and natural gas production. Political instability and availability
of alternative fuels could impact worldwide supply, while other economic factors
could impact demand.

Oil and Natural Gas Prices

While the market price received for crude oil and natural gas varies among
geographic areas, crude oil trades in a world-wide market, whereas natural gas,
which has a limited global transportation system, is subject to local supply and
demand conditions. Consequently, price movements for all types and grades of
crude oil generally move in the same direction, while natural gas price
movements generally follow local market conditions. However, throughout 2004 the
quality differential between prices we received for our North American sour
crude oil compared to the NYMEX index prices widened, with a substantial
increase in the fourth quarter of 2004. These quality differentials, which
impacted approximately 30 percent of our North American production, occurred
largely because OPEC produced more sour crude to satisfy rising world demand,
while worldwide sour crude refining capacity remained the same. This excess in
sour crude supply over the refining capacity created competition between the
producers driving a deeper discount for sour crude. In the fourth quarter, we
received an average of $41.00 per barrel for sour crude, approximately $5.00
less than we received for our sweet crude.

Apache primarily sells its natural gas into three markets:

1) North America, which has a common market and where production is
currently in short supply relative to demand creating a volatile pricing
environment;

2) Australia, which has a local market with limited demand and
infrastructure and generally long-term fixed prices; and

3) Egypt, which has a local market where the price received for our
production is indexed to a weighted-average Dated-Brent crude oil price,
a portion of which is subject to a minimum floor price and maximum
ceiling price.

The current outlook for 2005 indicates that the sour crude quality
differentials while narrowing somewhat, will remain above historical averages.
All of our North Sea production will trade at market prices, following
expiration on December 31, 2004, of a fixed-price contract on 40,000 b/d.

For specific marketing arrangements by segment, please refer to Item 1 and
2. Business and Properties of this Form 10-K.

24

Contributions to Oil and Natural Gas Revenues

As with production and reserves, a consequence of geographic
diversification is a shifting geographic mix of our oil revenues and natural gas
revenues. For the reasons discussed in the Oil and Natural Gas Price section
above, contributions to oil revenues and gas revenues should be viewed
separately.

The following table presents each segment's oil revenues and gas revenues
as a percentage of total oil revenues and gas revenues, respectively.

Crude Oil Contribution

In 2004, oil revenues from areas outside the U.S. rose slightly to 68
percent of consolidated oil revenues, up from 67 percent in 2003. Lack of
production growth reduced the U.S. overall contribution one percent to 32
percent of consolidated