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.
19

- 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.

20

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
21

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 oil revenues. Canada's contribution also declined one
percent to 12 percent on lower relative production growth. Egypt's share rose
one percent to 24 percent as it saw both price gains and production growth. The
North Sea's contribution increased three percent on both an increase in average
daily production and a full year of revenues versus nine months in 2003.
Australia's contribution fell three percent on lower production.

In 2003, oil revenues from areas outside the U.S. rose to 67 percent of
consolidated oil revenues, up from 65 percent in 2002. The increase is directly
related to the acquisition of the North Sea properties and, to a much lesser
extent, initial production from China. The percentage contribution from all
other areas fell, reflecting the impact of revenues from the North Sea and
China.

Natural Gas Contribution

A significant portion of the Company's natural gas revenues comes from our
North American operations. In 2004, 87 percent of Apache's natural gas revenues
came from North America of which 58 percent was from the U.S. and 29 percent was
from Canada. The U.S. contribution decreased four percent from 2003, primarily
because of production declines, the impact Hurricane Ivan had on U.S. Gulf of
Mexico revenues, and the additional revenues generated by Canada and Egypt. Our
U.S. Gulf Coast region, which contributed 69 percent of Apache's U.S. 2004
production, down two percent from 2003, is characterized by reservoirs which
demonstrate high initial production rates followed by steep declines when
compared to most other U.S. producing areas. Canada's contribution was up two
percent from 2003 resulting from three percent production growth and higher
price gains relative to other areas. Egypt's contribution to total gas revenues
increased to 10 percent from eight percent in 2003, on 21 percent production
growth. Australia's contribution to 2004 natural gas revenues remained the same
as 2003 at three percent.

In 2003, 89 percent of Apache's natural gas revenues came from North
America, 62 percent from the U.S. and 27 percent from Canada. The U.S.
contribution rose 11 percent from 2002, primarily because of the properties
acquired from BP and Shell in 2003, and properties acquired in South Louisiana
in December 2002. Canada's contribution was down two percent from 2002 primarily
because of the production growth in the U.S. Egypt's contribution to total gas
revenues declined to eight percent from 15 percent in 2002. Egypt's total
25

natural gas revenues were relatively flat year-over-year, as higher natural gas
prices were offset by lower net production. Australia's contribution to 2003
natural gas revenues declined to three percent from five percent in 2002.

The table below presents oil and gas production revenues, production and
average prices received from sales of natural gas, oil and natural gas liquids.

Natural Gas Revenues

Our 2004 natural gas revenues increased $171 million with a $.30 per Mcf
increase in our average natural gas price realizations generating an additional
$133 million of revenues. Higher production added the remaining $38 million.
While all of our operating segments reported an increase in natural gas price
realizations, most of the additional revenues attributable to price came from
the U.S. and Canada. The additional revenues attributable to production were
primarily generated in Egypt, where natural gas production increased 21 percent,
reflecting the success of our drilling program. Canada and Australia also
contributed to the increase in production revenues with production growth of
three percent and six percent, respectively. Canada's increase is from new wells
while Australia's increase was driven by higher customer demand and new
contractual sales. Partially offsetting these additional production revenues was
a three percent decrease in U.S. production. The lower U.S. production was
focused in the Gulf Coast region and is related to the impact of Hurricane Ivan
and natural decline in mature fields.

Consolidated natural gas revenues increased $916 million in 2003,
consistent with a $1.74 per Mcf increase in the average price realized for
natural gas and a 13 percent increase in production. The price increase
generated $686 million of revenues while production growth added another $230
million. U.S. production increased 32 percent, reflecting the impact from the
2003 BP and Shell acquisitions and the December 2002 South Louisiana
acquisition. Offsetting the U.S. production growth were lower production in
Egypt, Australia, and Canada, down seven percent, six percent, and three
percent, respectively. The decline in Egypt related to gas production
curtailment imposed by EGPC and scheduled plant shutdowns, while Australia
experienced lower customer demand.

Apache uses a variety of strategies to manage its exposure to fluctuations
in natural gas prices, including fixed-price physical contracts and derivatives.
Although a majority of our worldwide sales contracts are indexed to prevailing
market prices, approximately nine percent of our 2004 and 2003 domestic natural
gas production was subject to long-term, fixed-price physical contracts. The
long-term, fixed-price physical contracts apply to a small portion of our U.S.
future natural gas production and provide a measure of protection to the Company
in the event of decreasing natural gas prices. These contracts negatively
impacted our 2004 and 2003 realized prices by $.10 per Mcf and $.08 per Mcf,
respectively. Additionally, substantially all of our natural gas production sold
in Australia is subject to long-term fixed-price supply contracts. These
contracts are periodically adjusted for changes in Australia's consumer price
index and are also impacted by

27

changes in the value of the Australian dollar relative to the U.S. dollar. In
2004, we saw an increase in our realized prices primarily because of the
stronger Australian dollar.

Approximately 16 percent of our worldwide natural gas production was
subject to financial derivative hedging for 2004 and 2003. Refer to Note 3,
Hedging and Derivative Instruments of Item 15 in this Form 10-K for a summary of
current derivative positions and terms. We also amortized unrealized gains and
losses from derivative positions closed in October and November 2001, which had
no impact on 2004 average realized prices. The following table shows the impact
on average prices for these financial derivatives:

Crude Oil Revenues

Our 2004 consolidated oil revenues increased $905 million with a $7.48 per
barrel increase in our average realized oil price generating an additional $561
million of revenues. A 13 percent growth in production added the remaining $344
million. The increase in production came from the North Sea, China and Egypt.
North Sea production is up 23,576 b/d, with 53 percent of the increase
reflecting additional production from new wells and operational enhancements.
The balance of the North Sea increase results from reporting a full year of
production in 2004 versus nine-months in 2003. A portion of the North Sea
revenue was tied to an average $23.38 per barrel fixed-price sales contract
entered into in at the time of the BP acquisition. This two-year contract
expired at the end of 2004. See Note 2, Acquisitions and Divestitures of Item 15
in this Form 10-K for a discussion of the terms of this contract. Production in
China, which commenced in July 2003, added 4,792 b/d on exploration and
production activity and a full year of production. Egypt's production is up
4,632 b/d on exploration and production activity. These production increases
were partially offset by lower production in the U.S. and Australia, down 1,532
b/d and 5,415 b/d, respectively. The U.S. decline is related to Hurricane Ivan,
downtime, and natural decline in mature fields. Australia's decrease was driven
by natural decline.

Consolidated oil revenues increased $698 million in 2003 with a 34 percent
increase in oil production generating an additional $531 million of revenues.
The average crude oil realized price increased $2.98 per barrel, adding the
remaining $167 million of oil revenues. Revenues from properties acquired in the
North Sea accounted for over half of the oil revenue increase attributable to
production. U.S. production increased 31 percent, primarily from the Gulf of
Mexico BP properties and to a lesser extent from properties acquired from Shell
and in South Louisiana in December 2002. Initial production from China and a
nine percent increase in production from Egypt also contributed to the revenue
gains.

Apache also manages its exposure to fluctuations in crude oil prices using
financial derivatives. Approximately four percent and 22 percent of our
worldwide crude oil production was subject to financial derivative hedging for
2004 and 2003, respectively. Please refer to Note 3, Hedging and Derivature of
Item 15 in this Form 10-K for a summary of current derivative positions and
terms. We also continued to amortize unrealized gains and losses over the
original production life of derivative positions closed in October and November
2001, which had no impact on 2004 average realized prices. The following table
shows the impact on prices of these financial derivatives:

28

COSTS

The tables below present a comparison of our costs on an absolute dollar
basis and an equivalent unit of production (boe) basis. Our discussion may
reference either expenses on a boe basis or expenses on an absolute dollar
basis, or both, depending on their relevance.

Depreciation, Depletion and Amortization

Apache's Depreciation, Depletion and Amortization (DD&A) of oil and gas
properties is calculated using the Units of Production Method (UOP). The UOP
calculation in simplest terms multiplies the percentage of estimated proved
reserves produced each quarter times the costs of those reserves. The result is
to recognize expense at the same pace that the reservoirs are actually
depleting. The costs in the UOP calculation include both the net capitalized
amounts on the balance sheet, and the estimated future costs to access and
develop reserves needing additional facilities, equipment or downhole work in
order to produce. Under the full-cost method of accounting, the DD&A calculation
is prepared separately for each country in which Apache operates. Absolute DD&A
determines the expense reported each period, while the cost per unit of
production (DD&A rate) provides insight into the overall costs of the company's
reserves growth. Current costs incurred to drill or acquire additional reserves
that are higher than the historical cost level raises the overall DD&A rate.
Conversely, if reserves are added in the current period at a rate per unit less
than existing levels, they average down the company's DD&A rate. Changes from
period to period in absolute DD&A expense are determined by production levels,
the mix of production (high cost country versus a low cost country) and the
impact of recent spending (higher or lower DD&A rates).

Full-cost DD&A expense of $1.1 billion, increased $146 million compared to
2003. Approximately 59 percent of the increase in absolute costs was related to
higher production levels, mainly in the North Sea, Egypt and China. The balance
was primarily attributable to higher drilling costs, as our 2004 DD&A rate
increased $.42 to $7.01 per boe. The increase in per unit costs is primarily
attributable to our North American operations where high commodity prices have
led to increased demand for drilling services and thus higher drilling costs.
Additionally, high commodity prices have increased the costs of properties
available for acquisition and therefore, the cost of properties we acquired in
2004 were higher than our historical cost. A full year's production from China,
which carries the second highest DD&A rate in the Company, also contributed to
the increase in the worldwide rate. These increases were partially offset by a
decrease in the DD&A rate in Egypt from a successful exploration and development
program which added significant reserves through drilling at lower costs.

Our 2003 full-cost DD&A expense of $1 billion increased $220 million
compared to 2002. The majority of the increase in absolute costs was related to
production increases following our acquisitions from BP and Shell in the Gulf of
Mexico and from BP in the North Sea and first production in China. On a per unit
basis, our DD&A rate in 2003 increased $.30 to $6.59 from $6.29 in 2002. The
increase was driven by higher drilling

29

costs in Australia, Egypt and the U.S. and higher acquisition costs in the U.S.
In addition, China and the North Sea contributed to the increase in per unit
rates, with production reported for the first time in 2003 at higher DD&A rates
than other regions.

Depreciation of other assets increased $3 million in 2004, in line with our
overall growth.

Impairments

We assess all of our unproved properties for possible impairment on a
quarterly basis based on geological trend analysis, dry holes or relinquishment
of acreage. When an impairment occurs, costs associated with these properties
are generally transferred to our proved property base where they become subject
to amortization. Impairments in international areas without proved reserves are
charged to earnings upon determination that impairment has occurred. In 2002, we
impaired $20 million in Poland ($12 million after-tax). In 2003, we impaired the
final $13 million ($8 million after-tax) of unproved property costs in Poland.

Goodwill became subject to a periodic fair-value-based impairment
assessment in 2002. Goodwill totaled $189 million on December 31, 2004 and no
impairment was recorded in either 2004 or 2003. For further discussion, see Note
1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K.

Lease Operating Costs

Lease operating costs (LOE) are generally comprised of several components;
direct operating costs, repair and maintenance costs, workover costs and ad
valorem tax costs. LOE is driven in part by the type of commodity produced, the
level of workover activity and the geographical location of the properties. Oil
is inherently more expensive to produce than natural gas. Workovers continue to
be an important part of our strategy enabling us to exploit our existing reserve
base by accelerating production and taking advantage of high commodity prices.
Repair and maintenance costs are higher on offshore properties and in areas with
remote plants and facilities. Commodity prices and exchange rates also impact
LOE. Historically, electricity, fuel and other service costs have risen in high
commodity price environments, leading to an increase in industry-wide LOE.
Rising per unit operating costs remained a challenge in 2004, especially in
North America. The Company reviews production costs in each of its core areas on
a monthly basis and pursues alternatives in maintaining efficient levels of
costs. Fluctuations in exchange rates also impact the Company's LOE in Canada,
Australia and the North Sea. The dollar has generally weakened against these
currencies, particularly in 2004, increasing the impact of foreign exchange
rates on the Company's per unit costs in these countries. The following
discussion will focus on per unit operating costs as this is the most
informative method of analyzing LOE trends. Acquisitions increase absolute LOE
costs, but they do not necessarily increase per unit costs or lower margins.

On a per unit/boe produced basis, 2004 LOE increased $.68 to $5.27 per boe.
The increase was primarily attributable to an increase in industry-wide service
costs in North America with higher commodity prices (see discussion in preceding
paragraph), the increase in currency exchange rates in Canada, North Sea and
Australia, and higher expense resulting from our incentive programs, primarily
stock-based programs which we began expensing in 2003. Per unit costs were also
negatively impacted by the combined impact of lost production and additional
costs related to Hurricane Ivan in the Gulf of Mexico and higher repair and
maintenance costs in Australia. These increases offset the impact of a $2.75
decline in the unit cost in the North Sea, where our investments to increase
production and lower operating costs over the long-term are beginning to pay
off.

During 2003, the Company LOE per boe increased $.92 to $4.59, with all of
the increase occurring outside the U.S. Half of the increase was attributable to
our acquisition of the North Sea Forties field, which is located offshore,
produces oil and carries a higher unit rate than our other core areas. Upon
taking over operations, we performed multiple platform turnarounds and repair
and maintenance projects aimed at increasing production efficiency and lowering
operating costs over the long-term. The remainder of the increase was related to
an increase in currency exchange rates, the impact of higher commodity prices in
Canada, more workover activity in Egypt and higher repair and maintenance costs
in Australia. The LOE rate

30

in the U.S. declined as the impact from the additional absolute costs associated
with the acquisitions were more than offset by the incremental production.

Gathering and Transportation Costs

Apache generally sells oil and natural gas under two types of agreements,
typical in our industry. Both types of agreements include a transportation
charge. One is a netback arrangement, under which Apache sells oil or natural
gas at the wellhead and collects a price, net of transportation incurred by the
purchaser. In this case, the Company records sales at the price received from
the purchaser which is net of transportation costs. Under the other arrangement,
Apache sells oil or natural gas at a specific delivery point, pays
transportation to a third-party carrier and receives from the purchaser a price
with no transportation deduction. In this case, the Company records the
transportation cost as gathering and transportation costs. The Company's
treatment of transportation costs is pursuant to Emerging Issues Task Force
Issue 00-10, "Accounting or Shipping and Handling Fees and Costs" and as a
result a portion of our transporting costs is reflected in sales prices and a
portion is reflected as Gathering and Transportation Costs rendering the
separately identified transportation costs incomplete.

In both the U.S. and Canada, Apache sells oil and natural gas under both
types of arrangements. In the North Sea, Apache pays transportation to a
third-party carrier and receives a purchase price with no transportation
deduction. In Australia, oil and natural gas are sold under netback
arrangements. In China, we incur costs for barges to transport crude oil to
onshore terminal facilities. In Egypt, our oil and natural gas production has
historically been sold to EGPC under netback arrangements. Apache exported three
inaugural cargoes of Egyptian crude oil in 2004 pursuant to netback arrangements
with third parties. Future export cargoes may be sold under similar terms or
Apache may arrange shipping and receive prices without transportation
deductions. The following table presents gathering and transportation costs paid
directly by Apache to third party carriers for each of the periods presented.

These costs are primarily related to the transportation of natural gas in
our North American operations and crude oil in the North Sea. Transportation
costs in the U.S. increased 33 percent on higher volumes transported under
third-party transportation contracts, compared to the prior-year period.
Canada's 2004 costs were 11 percent higher than 2003 because of an increase in
third-party transportation rates and the impact of a weaker U.S. dollar. The
North Sea's costs increased on production growth and a full year of production.

In 2003, the increase in Canada primarily involved higher third-party
transportation charges for gas transported from several fields, increased
production volumes from 2002 acquisitions and transportation charges for crude
oil as we began taking our oil "in-kind" and marketing it ourselves instead of
selling it at the lease. The increase in the U.S. is related to the higher
volumes transported under third-party transportation contracts, compared to the
prior-year period. In the North Sea, these costs are related to the
transportation of crude oil upon our entry to the region in April 2003.

Severance and Other Taxes

Severance and other taxes are comprised primarily of severance taxes on
properties onshore and in state or provincial waters in the U.S. and Australia.
In both 2004 and 2003, these severance taxes, which are generally based on a
percentage of oil and gas production revenues, represented the majority of the
total

31

severance and other taxes incurred. The other tax components are primarily made
up of the Australian Petroleum Resources Rent Tax (PRRT), to which Apache first
became subject in 2002, the Petroleum Revenue Tax (PRT) on the North Sea
properties and the Canadian Large Corporation Tax, Saskatchewan Capital Tax,
Saskatchewan Resource Surtax and Freehold Mineral Tax. Oil and gas production
revenues generated from Egypt, Canada and the North Sea are not subject to
severance taxes. The table below presents a comparison of these expenses.

In 2004, severance and other taxes decreased 23 percent, or $28 million.
Severance and other taxes in the U.S. increased $15 million, in line with higher
production revenues. Australia's taxes increased $36 million as production from
the Legendre field crossed a cumulative threshold, triggering an excise tax.
U.K. PRT tax is based on revenues less qualifying operating costs and capital
spending. Apache was in a PRT credit position for 2004 as deductible capital
spending exceeded taxable cash flows from the Forties field. Canadian taxes
increased $3 million on an increase in Freehold Mineral Taxes.

In 2003, severance and other taxes increased 81 percent, or $54 million.
Twenty million dollars of the increase is associated with PRT expense in the
North Sea, where Apache began operating in April 2003. Canadian taxes increased
$10 million as a result of currency exchange rate increases and higher prices in
2003, and a $2 million refund in 2002. U.S. and Australia severance taxes
increased $17 million and $7 million, respectively, in line with higher
production revenues.

General and Administrative Expenses

General and administrative expenses (G&A) of $1.06 per boe for 2004
increased $.15 per boe over 2003. Absolute costs increased $35 million, or 25
percent. Over $21 million, or 61 percent of the additional expense is related to
the impact Apache's rising stock price had on stock-based compensation programs
and incremental incentive compensation. The impact from the higher stock price
stems from Apache's decision, effective January 1, 2003, to expense stock-based
compensation plans (see Note 8, Capital Stock of Item 15 in this Form 10-K).
Approximately $3 million, or 8 percent, of the increase is related to our new
North Sea operations, with the first full year of operations in 2004. The
balance of the increase was related to higher audit and tax fees, increased
insurance premiums, and expansion of the Company's gas marketing group.

General and administrative expenses of $.91 per boe for 2003 increased $.07
per boe over 2002. Absolute costs increased $34 million, or 32 percent. Over $11
million, or 34 percent, is associated with expensing compensation, including
Stock Appreciation Rights (SARs), stock options, restricted stock and
incremental incentive compensation. Approximately $9 million, or 28 percent, of
the increase is related to our new North Sea operations. The balance of the
increase was related to the Company's decision to increase its charitable
contributions, expansion of the Company's new gas marketing group and transition
costs incurred on acquisitions.

Financing Costs, Net

The major components of financing costs, net, include interest expense and
capitalized interest. Net financing costs were slightly higher than in 2003.
Gross interest expense decreased $1 million in 2004, a result of a lower average
debt balance. This decrease was offset by a $2 million decrease in the amount of
interest

32

capitalized, a result of a lower average unproved property balance. Our
weighted-average cost of borrowing on December 31, 2004 was 6.1 percent compared
to 6.4 percent on December 31, 2003.

Net financing costs for 2003 increased $2 million compared to 2002 with a
$13 million increase in expense largely offset by an increase in capitalized
interest. Five million dollars of the increase is interest expense related to
the write-off of unamortized fees triggered by the retirement of preferred
interests of subsidiaries discussed below. The remaining $8 million of higher
interest expense was attributable to a higher average debt balance in 2003
compared to 2002. Capitalized interest increased $12 million driven by a higher
unproved property balance associated with acquisitions and an active drilling
program. If net financing costs included distributions from Preferred Interests
of Subsidiaries, net financing costs would have decreased by approximately $5
million.

Provision for Income Taxes

2004 income tax expense of $993 million was $166 million or 20 percent
higher than in 2003. The higher taxes were primarily associated with higher
income driven by higher oil and gas production revenues in 2004. Our effective
tax rate was 37.29 percent in 2004 compared to 43.02 percent in 2003. The 2003
effective tax rate included $172 million of additional deferred tax expense
because of currency fluctuations compared to $58 million in 2004.

2003 income tax expense of $827 million was $482 million or 140 percent
higher than the 2002. The higher taxes were primarily associated with higher
income in 2003 and, to a lesser extent, a higher effective tax rate. Our
effective tax rate increased primarily because of $172 million of additional
deferred tax expenses resulting from currency fluctuations. The impact caused by
currency fluctuations was partially offset by a $71 million reduction in
deferred tax expense related to a reduction in Canadian federal statutory income
tax rates. Our effective tax rate for 2003 was 43.02 percent compared to 38.34
percent for the prior year. For a discussion of Apache's sensitivity to foreign
currency fluctuations, please refer to Item 7A, Quantitative and Qualitative
Disclosures about Market Risk, "Foreign Currency Risk" of this Form 10-K.

CAPITAL RESOURCES AND LIQUIDITY

FINANCIAL INDICATORS

(1) Year-end 2002 debt included $437 million of preferred interests of
subsidiaries. The Company retired its preferred interests of subsidiaries in
September 2003.

OVERVIEW

Apache's primary uses of cash are exploration, development and acquisition
of oil and gas properties, costs and expenses necessary to maintain continued
operations, repayment of principal and interest on outstanding debt and payment
of dividends.

Our business, as with other extractive industries, is a depleting one in
which each barrel produced must be replaced or the Company, and a critical
source of our future liquidity, will shrink. Cash investments are continuously
required to fund exploration and development projects and acquisitions which are
necessary to offset the inherent declines in production and proven reserves. See
Item 1 and 2, Business and Properties, "Risks Factors Related to Our Business
and Operations," in this Form 10-K. Future success in maintaining

33

and growing reserves and production will be highly dependent on having adequate
capital resources available, on our success in both exploration and development
activities and on acquiring additional reserves.

Our year-end reserve life index indicates an average decline of 8.5 percent
per year. This projection is based on prices at year-end, except in those
instances where future natural gas and oil sales are covered by physical
contract terms providing for higher or lower amounts, estimates of investments
required to develop estimated proved undeveloped reserves, costs and taxes
reflected in our standardized measure in Note 14, Supplemental Oil and Gas
Disclosures (Unaudited) of Item 15 in this Form 10-K.

The Company funds its exploration and development activities primarily
through net cash provided by operating activities (cash flow) and budgets
capital expenditures based on projected cash flow. Our cash flow, both in the
short and long-term, is impacted by highly volatile oil and natural gas prices,
production levels, industry trends impacting operating expenses and our ability
to continue to acquire or find high-margin reserves at competitive prices. For
these reasons, we only forecast, for internal use by management, an annual cash
flow. Longer term cash flow and capital spending projections are not used by
management to operate our business. The annual cash flow forecasts are revised
monthly in response to changing market conditions and production projections.
Apache routinely adjusts capital expenditure budgets in response to the adjusted
cash flow forecasts and market trends in drilling and acquisitions costs.

The Company has historically utilized internally generated cash flow,
committed and uncommitted credit facilities and access to both debt and equity
capital markets for all other liquidity and capital resources needs. Apache's
ability to access the debt capital market is supported by its investment grade
credit ratings. Because of the liquidity and capital resources alternatives
available to Apache, including internally generated cash flows, Apache's
management believes that its short-term and long-term liquidity is adequate to
fund operations, including its capital spending program, repayment of debt
maturities and any amounts that may ultimately be paid in connection with
contingencies.

Apache's senior unsecured debt is currently rated investment grade by
Moody's, Standard and Poor's and Fitch with ratings of A3, A- and A,
respectively.

The Company's ratio of current assets to current liabilities was 1.05 at
December 31, 2004 compared to 1.10 at the end of last year. Year-end 2004
current receivable and payable balances increased by $450 million and $463
million, respectively, from December 31, 2003. The increase in current
receivables was primarily attributable to the impact of higher commodities
prices and increased production on receivables from the sale of oil and natural
gas. In addition, current receivables include amounts collectible from insurance
proceeds for lost production and physical damage resulting from Hurricane Ivan
in the Gulf of Mexico in the fourth quarter of 2004. The increase in current
payables is primarily attributable to an increase in trade payables because of
an increased number of drilling and development projects in progress at the end
of 2004 versus year-end 2003 and the impact of higher commodity prices and
production on revenue payable to third party royalty and working interest
owners.

NET CASH PROVIDED BY OPERATING ACTIVITIES

Apache's net cash provided by operating activities during 2004 totaled $3.2
billion, up from $2.7 billion in 2003. The increase in 2004 cash flow is
attributed primarily to the significant increase in commodity prices. The
Company's averaged realized oil and natural gas prices increased 27 and 7
percent, respectively; a reflection of higher worldwide commodity prices. Higher
production also increased our 2004 cash flow. Oil and natural gas production
increased 13 and one percent, respectively, a result of acquisitions and a
successful drilling program. These increases were partially offset by higher
production costs attributable to the effect of increased commodity prices, an
increase in exchange rates in Canada, North Sea and Australia, costs related to
Hurricane Ivan and increases in costs from our stock based employee incentive
programs. The Company reviews production costs for each core area on a monthly
basis and pursues alternatives in maintaining efficient levels of costs and
expenses. For a more detailed discussion of commodity prices, production, costs
and expenses, please refer to the Results of Operations section of this Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.

34

Apache's 2003 cash flows totaled $2.7 billion, an increase of 96 percent
from 2002 cash flows of $1.4 billion. The increase was attributable primarily to
higher oil and gas production revenues which were driven by increases in both
production volumes and realized prices and partially offset by higher operating
expenses. Oil and natural gas production increased 34 and 13 percent,
respectively. The increase in oil production was primarily attributable to our
acquisition of properties in the North Sea and first production from our China
operations. The increase in natural gas production was primarily related to two
significant acquisitions in the Gulf of Mexico, which offset declines in other
core areas. Oil and natural gas prices increased 12 and 61 percent, respectively
on higher worldwide commodity prices. Higher lease operating costs were
primarily attributable to the acquisition of the North Sea properties, which
carry a higher rate per unit than our other core areas, and where, upon taking
over operations, we performed multiple platform turnarounds and repair and
maintenance projects aimed at increasing production and lowering operating costs
over the long-term. Outside of the United States, costs were higher with an
increase in exchange rates and the impact of higher commodity prices in Canada,
more workover activity in Egypt and higher repair and maintenance costs in
Australia. For a more detailed discussion of commodity prices, production,
operating costs and acquisitions please refer to the Results of Operations
section of this Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations.

Historically, fluctuations in commodity prices have been the primary reason
for the Company's short-term changes in cash flow from operating activities.
Sales volume changes have also impacted cash flow in the short-term, but have
not been as volatile as commodity prices in the past. Apache's long-term cash
flow from operating activities is dependent on commodity prices, reserve
replacement and the level of costs and expenses required for continued
operations.

DEBT

During 2004, we continued to strengthen our financial flexibility and to
build on the solid financial positions of previous years. We exited 2004 with a
debt-to-capitalization ratio of 24 percent, a decrease of two percent from
year-end 2003, with slightly higher debt offset by increases in equity resulting
from earnings. At year-end 2004 the Company had long-term debt of $2.6 billion,
$261 million higher than year-end 2003, as the Company's $3.4 billion in capital
spending slightly exceeded internally generated cash flow. The Company's
outstanding debt consisted of $396 million under our commercial paper program
and uncommitted lines of credit and a total of $2.2 billion of other debt. This
other debt included notes and debentures maturing in the years 2006 through
2096. Approximately $.3 million, $173 million, $.4 million, $497 million and
$1.9 billion mature in 2006, 2007, 2008, 2009 and thereafter, respectively.
During 2004, the Company maintained its senior unsecured long-term debt ratings
of A3 from Moody's and A- from Standard and Poor's. In June 2004, Fitch upgraded
Apache's senior unsecured long-term debt rating from A- to A.

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances of $392 million and $130 million at December 31, 2004
and 2003, respectively, were classified as long-term debt in the accompanying
consolidated balance sheet as the Company has the ability and intent to
refinance such amounts on a long-term basis through either the rollover of
commercial paper or available borrowing capacity under its U.S. credit
facilities. If the Company is unable to issue commercial paper following a
significant credit downgrade or dislocation in the market, the Company's U.S.
credit facilities are available as a 100 percent backstop. The weighted-average
interest rate for commercial paper was 1.79 percent in 2004 and 1.19 percent in
2003.

As of December 31, 2004, available borrowing capacity under our credit
facilities was $1.1 billion. We had $111 million in cash and cash equivalents on
hand at December 31, 2004, an increase from $34 million at the prior year-end.

On May 28, 2004, the Company's $750 million 364-day U.S. credit facility
matured and was replaced with a new five-year credit facility which matures May
28, 2009. Also on this date, the Company amended its existing $450 million
facility and its two existing $150 million facilities in order to make their
terms consistent with the new five-year facility. Significant changes included
raising the cross-default threshold, increasing

35

flexibility under the negative lien covenant and eliminating covenants which
established minimum levels for tangible net worth and book values for assets of
Apache and certain subsidiaries.

The financial covenants of the credit facilities require the Company to
maintain a debt-to-capitalization ratio of not greater than 60 percent at the
end of any fiscal quarter. The negative covenants include restrictions on the
Company's ability to create liens and security interests on our assets, with
exceptions for liens typically arising in the oil and gas industry, purchase
money liens and liens arising as a matter of law, such as tax and mechanics
liens. The Company may incur liens on assets located in the U.S., Canada and
Australia of up to five percent of the Company's consolidated assets, which
approximated $775 million at December 31, 2004. There are no restrictions on
incurring liens in countries other than the U.S., Canada and Australia. There
are also restrictions on Apache's ability to merge with another entity, unless
the Company is the surviving entity, and a restriction on our ability to
guarantee debt of entities not within our consolidated group.

There are no clauses in the facilities that permit the lenders to
accelerate payments or refuse to lend based on unspecified material adverse
changes (MAC clauses). The credit facility agreements do not have drawdown
restrictions or prepayment obligations in the event of a decline in credit
ratings. However, the agreements allow the lenders to accelerate payments and
terminate lending commitments if Apache Corporation, or any of its U.S.,
Canadian and Australian subsidiaries, defaults on any direct payment obligation
in excess of $100 million or has any unpaid, non-appealable judgment against it
in excess of $100 million. The Company was in compliance with the terms of the
credit facilities as of December 31, 2004.

STOCK TRANSACTIONS

The Company periodically uses access to equity capital markets to fund
significant acquisitions. On January 22, 2003, in conjunction with the BP
transaction, we completed a public offering of approximately 19.8 million shares
of common stock, including 2.6 million shares for the underwriters'
over-allotment option, for net proceeds of $554 million. The Company currently
has no plans to access equity capital markets.

The Company's board of directors approved a stock split and several stock
dividends in 2003, 2002 and 2001; a reflection of their belief that we can
reward our shareholders while remaining focused on our primary objective of
building Apache to last by achieving profitable growth.

On December 18, 2003, we announced that holders of our common stock
approved an increase in the number of authorized common shares to 430 million
from 215 million in order to complete a previously announced two-for-one stock
split. The record date for the stock split was December 31, 2003 and the
additional shares were distributed on January 14, 2004.

On December 18, 2002, our Board of Directors declared a five percent stock
dividend payable on April 2, 2003 to shareholders of record on March 12, 2003.
As a result, in December 2002, we reclassified approximately $396 million from
retained earnings to common stock and paid-in capital, which represents the fair
market value at the date of declaration of the shares distributed. In 2003, at
the date of the distribution, an additional $26 million was reclassified from
retained earnings to common stock and paid-in capital. No fractional shares were
issued and cash payments were made in lieu of fractional shares.

On May 15, 2002, we completed the mandatory conversion of our Series C
Preferred Stock into approximately 13.1 million common shares.

OIL AND GAS CAPITAL EXPENDITURES

The Company funded its exploration and production (E&D) capital
expenditures, including Gathering, Transportation and Marketing (GTM)
facilities, of $2.5 billion, $1.5 billion and $892 million in 2004, 2003 and
2002, respectively, primarily with internally generated cash flow of $3.2
billion, $2.7 billion and $1.4 billion.

The Company uses a combination of internally generated cash flow,
borrowings under the Company's lines of credit and commercial paper program and,
from time to time, issues of public debt or common stock to fund its significant
acquisitions. During the three year period presented, the Company primarily used

36

internally generated cash flow or its lines of credit and commercial paper
program; which were subsequently paid down with internally generated cash flow.
However, in 2003 in conjunction with the BP acquisition, the Company completed a
public offering of approximately 19.8 million shares of common stock, including
2.6 million shares for the underwriters' over-allotment option, for net proceeds
of $554 million.

The following table presents a summary of the Company's Capital
Expenditures for each of our reportable segments for the past three years.

In 2004, Apache drilled a record number of wells and completed two
significant acquisitions. Each of our North America operating areas drilled a
record number of wells in 2004. In the Gulf of Mexico the majority of our
activity focused in and around our existing asset base, including continued
exploitation of the properties purchased from BP and Shell in 2003 and the
Anadarko properties purchased in 2004. In the Central region, where Apache got
its start 50 years ago, estimated proved reserves increased 20 percent in 2004
through a combination of the ExxonMobil acquisition and Apache's most active
drilling year, completing 268 of 283 wells in the region. Canada was our most
active area with over 1,300 wells drilled, three-fourths of which were shallow
development wells, with over 92 percent completed as producers. At the Forties
Field, an experienced workforce is tackling projects to extend the life of the
largest field in the United Kingdom sector of the North Sea. Production
increases at Forties -- the anchor of Apache's newest core area -- were driven
by Apache's first drilling program since acquiring the field and a maintenance
program aimed at improving efficiency of the field. During 2004, Apache
completed 12 of 17 wells drilled as part of a $362 million capital program,
including $150 million of maintenance and operations capital expenditures. In
Egypt and Australia, Apache continued its successful exploration programs with
several new discoveries. Our continuing development program in Egypt increased
gross production to over 100,000 b/d for the first time. Capital expenditures in
China decreased in 2004 with the completion of production facilities and first
production in the second half of 2003. In 2004, Apache added 444.7 MMboe of
estimated proved reserves through acquisitions, drilling and revisions. During
2004, GTM expenditures included additional gathering system pipelines in Egypt
and a gas plant expansion on Varanus Island in Australia.

In 2003, E&D capital expenditures increased approximately $593 million over
the previous year with more drilling and development activity in each of our
cores areas. Apache drilled more wells than it ever had in Canada, completing
913 of 984 wells. Apache's successful drilling program in Egypt pushed
production to then all-time highs and resulted in several discoveries, including
the largest discovery in the history of the Company at the Qasr-1X well in the
Khalda Offset Concession. In the North Sea, which Apache acquired in April 2003,
we began a program of upgrades to the surface facilities to increase
efficiencies.

37

For 2005, we plan another active year of drilling. Because we revise our
estimates of exploration and development capital expenditures frequently
throughout the year based on industry conditions and results to date, accurately
projecting future expenditures is difficult at best. However, our preliminary
estimate of exploration and development capital expenditures for 2005 is in
excess of $2.5 billion. We do not project estimates for acquisitions because
their timing is unpredictable. However, we continually look for properties which
we believe will add value and earn adequate rates of return and will take
advantage of those opportunities as they arise.

CASH DIVIDEND PAYMENTS

The Company has paid cash dividends on its common stock for 40 consecutive
years through 2004. Future dividend payments will depend on the Company's level
of earnings, financial requirements and other relevant factors. Common dividends
paid during 2004 rose 26 percent to $85 million, reflecting the increase in
common shares outstanding and the higher common stock dividend rate. The Company
increased its quarterly cash dividend 33 percent, to eight cents per share from
six cents per share, effective with the November 2004 dividend payment.

During 2004, Apache paid a total of $6 million in dividends on its Series B
Preferred Stock issued in August 1998. Dividends on the Series C Preferred Stock
were paid through May 15, 2002, when the shares automatically converted to
common stock. See Note 8, Capital Stock of Item 15 in this Form 10-K. Common
dividends paid during 2003 rose 19 percent to $67 million, reflecting the
increase in common shares outstanding and the higher common stock dividend rate.

CONTRACTUAL OBLIGATIONS

We are subject to various financial obligations and commitments in the
normal course of operations. These contractual obligations represent known
future cash payments that we are required to make and relate primarily to
long-term debt, operating leases, pipeline transportation commitments and
international commitments. The Company expects to fund these contractual
obligations with cash generated from operating activities. The following table
summarizes the Company's contractual obligations as of December 31, 2004. See
Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further
information regarding these obligations.

(a) This table does not include the liability for dismantlement, abandonment
and restoration costs of oil and gas properties. Effective with adoption of
SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1,
2003, the Company recorded a separate liability for the fair value of this
asset retirement obligation. See Note 4, Asset Retirement Obligation of
Item 15 in this Form 10-K for further discussion.

(b) This table does not include the Company's pension or postretirement benefit
obligations. See Note 10, Commitments and Contingencies of Item 15 in this
Form 10-K for further discussion.
- ---------------

38

Apache is also subject to various contingent obligations that become
payable only if certain events or rulings were to occur. The inherent
uncertainty surrounding the timing of and monetary impact associated with these
events or rulings prevents any meaningful accurate measurement, which is
necessary to assess any impact on future liquidity. Such obligations include
environmental contingencies and potential settlements resulting from litigation.
Apache's management feels that it has adequately reserved for its contingent
obligations. The Company has reserved approximately $11 million for
environmental remediation. The Company has also reserved approximately $10
million for various legal liabilities, in addition to the $71 million, plus
interest, we accrued for the Texaco China B.V. litigation. See Note 10,
Commitments and Contingencies of Item 15 in this Form 10-K for a detailed
discussion of the Company's environmental and legal contingencies.

In 2004, the Company accrued approximately $10 million for an insurance
contingency because of our involvement with Oil Insurance Limited (OIL). Apache
is a member of this insurance pool which insures specific property, pollution
liability and other catastrophic risks of the Company. As part of its
membership, the Company is contractually committed to pay termination fees if
Apache ever withdraws from OIL. Apache does not anticipate withdrawal from the
insurance pool; however, the potential termination fee is calculated annually
based on past losses and the liability reflecting this potential charge has been
accrued. The calculation will change annually based on future period losses
incurred by OIL.

As discussed under Note 2, Acquisitions and Divestitures of Item 15 in this
Form 10-K, Apache assumed obligations for pre-existing VPPs in the 2004
acquisition of properties from Anadarko and the 2003 acquisition of properties
from Shell. Under the terms of the VPP agreements, Apache is scheduled to
deliver a total of 10.7 MMboe in 2005, 7.6 MMboe in 2006, 4.7 MMboe in 2007 and
1.6 MMboe in 2008 to Morgan Stanley as owner of the VPP interests. Morgan
Stanley is entitled to the first production and may demand up to 90 percent of
the production from the assets encumbered by each VPP in any given month to
satisfy the VPP interests. However, they have no right to look to other assets
or production of Apache. Apache does not record the reserves and production
volumes attributable to the VPPs. As of December 31, 2004, Apache has booked a
total of 91 MMboe of reserves attributable to the Anadarko and Shell
transactions. The VPPs are non-operating interests, free of costs incurred for
operations and production. Apache provided a liability for these costs as
reflected in the preceding table.

Upon closing of our acquisition of the North Sea properties, Apache assumed
BP's abandonment obligation for those properties and such costs were considered
in determining the purchase price. The purchase of the properties, however, did
not relieve BP of its liabilities if Apache fails to satisfy the abandonment
obligation. Although not currently required, to ensure Apache's payment of these
costs, Apache agreed to deliver a letter of credit to BP if the rating of our
senior unsecured debt is lowered by both Moody's and Standard and Poor's from
the Company's current ratings of A3 and A-, respectively. Any such letter of
credit would be in an amount equal to the net present value of future
abandonment costs of the North Sea properties as of the date of any such ratings
change. If Apache is required to provide a letter of credit, it will expire if
either rating agency restores its rating to the present level. The letter of
credit amount would be 136 million British pounds, an amount that represents the
letter of credit requirement through March 2006, and will be negotiated annually
based on Apache's future abandonment obligation estimates.

The Company's future liquidity could be impacted by a significant downgrade
of its credit ratings by Standard and Poor's and Moody's; however, we do not
believe that such a sharp downgrade is reasonably likely. The Company's credit
facilities do not require the Company to maintain a minimum credit rating. The
negative covenants associated with our debt are outlined in greater detail under
"Capital Resources and Liquidity, Debt" in this section of this Form 10-K. In
addition, generally under our commodity hedge agreements, Apache may be required
to post margin or terminate outstanding positions if the Company's credit
ratings decline significantly.

39

OFF-BALANCE SHEET ARRANGEMENTS

Apache does not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance liquidity and capital resource positions.
Apache entered into a partnership with ExxonMobil to obtain additional interests
in specific West Texas and New Mexico oil & gas properties acquired from
ExxonMobil in September 2004. As discussed in Note 2, Acquisitions and
Divestitures of Item 15 in this Form 10-K, Apache contributed $29 million into
this partnership which was determined to be a variable interest entity as
defined by Financial Accounting Standards Board (FASB) Interpretation No. 46
"Variable Interest Entities." Apache concluded that they were not the primary
beneficiary of the partnership and, therefore, proportionately consolidated only
the Company's portion of the oil and gas properties.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

FULL-COST METHOD OF ACCOUNTING FOR OIL AND GAS OPERATIONS

The accounting for our business is subject to special accounting rules that
are unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities: the successful-efforts method
and the full-cost method. There are several significant differences between
these methods. Under the successful-efforts method, costs such as geological and
geophysical (G&G), exploratory dry holes and delay rentals, are expensed as
incurred where under the full-cost method these types of charges would be
capitalized to their respective full-cost pool. In the measurement of impairment
of oil and gas properties, the successful-efforts method of accounting follows
the guidance provided in Statement of Financial Accounting Standards (SFAS) No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets," where the
first measurement for impairment is to compare the net book value of the related
asset to its undiscounted future cash flows using commodity prices consistent
with management expectations. Under the full-cost method, the net book value
(full-cost pool) is compared to the future net cash flows discounted at 10
percent using commodity prices in effect on the last day of the reporting period
(ceiling limitation). If the full-cost pool is in excess of the ceiling
limitation, the excess amount is charged through income.

We have elected to use the full-cost method to account for our investment
in oil and gas properties. Under this method, the Company capitalizes all
acquisition, exploration and development costs for the purpose of finding oil
and gas reserves, including salaries, benefits and other internal costs directly
attributable to these finding activities. Although some of these costs will
ultimately result in no additional reserves, we expect the benefits of
successful wells to more than offset the costs of any unsuccessful ones. In
addition, gains or losses on the sale or other disposition of oil and gas
properties are not recognized unless the gain or loss would significantly alter
the relationship between capitalized costs and proved reserves of oil and
natural gas attributable to a country. As a result, we believe that the
full-cost method of accounting better reflects the true economics of exploring
for and developing oil and gas reserves. Our financial position and results of
operations would have been significantly different had we used the
successful-efforts method of accounting for our oil and gas investments.
Generally, the application of the full-cost method of accounting for oil and gas
property results in higher capitalized costs and higher DD&A rates compared to
similar companies applying the successful efforts methods of accounting.

RESERVE ESTIMATES

Our estimate of proved reserves is based on the quantities of oil and gas
which geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. The accuracy of any reserve estimate is a function of the
quality of available data, engineering and geological interpretation, and
judgment. For example, we must estimate the amount and timing of future
operating costs, severance taxes, development costs, and workover costs, all of
which may in fact vary considerably from actual results. In addition, as prices
and cost levels change from year to year, the estimate of proved reserves also
changes. Any significant variance in these assumptions could materially affect
the estimated quantity and value of our reserves. As such, our reserve engineers
review and revise the Company's reserve estimates at least annually.

40

Despite the inherent imprecision in these engineering estimates, our
reserves are used throughout our financial statements. For example, since we use
the units-of-production method to amortize our oil and gas properties, the
quantity of reserves could significantly impact our DD&A expense. Our oil and
gas properties are also subject to a "ceiling" limitation based in part on the
quantity of our proved reserves. Finally, these reserves are the basis for our
supplemental oil and gas disclosures.

We engage an independent petroleum engineering firm to review our estimates
of proved hydrocarbon liquid and gas reserves. During 2004, 2003 and 2002, their
review covered 79, 78 and 68 percent of the reserve value, respectively.

COSTS EXCLUDED

Under the full-cost method of accounting, oil and gas properties include
costs that are excluded from capitalized costs being amortized. These amounts
represent investments in unproved properties and major development projects.
Apache excludes these costs on a country-by-country basis until proved reserves
are found or until it is determined that the costs are impaired. All costs
excluded are reviewed at least quarterly by the Company's accounting,
exploration and engineering staffs to determine if impairment has occurred.
Nonproducing leases are evaluated based on the progress of the Company's
exploration program to date. Exploration costs are transferred to the DD&A pool
upon completion of drilling individual wells. The amount of any impairment is
transferred to the capitalized costs being amortized (the DD&A pool) or a charge
is made against earnings for those international operations where a proved
reserve base has not yet been established. Impairments transferred to the DD&A
pool increase the DD&A rate for that country. For international operations where
a reserve base has not yet been established, all costs associated with a
prospect or play would be considered quarterly for impairment upon full
evaluation of such prospect or play. This evaluation considers among other
factors, seismic data, requirements to relinquish acreage, drilling results,
remaining time in the commitment period, remaining capital plans, and political,
economic, and market conditions.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

We routinely assess the recoverability of all material trade and other
receivables to determine their collectibility. Many of our receivables are from
joint interest owners on properties of which we are the operator. Thus, we may
have the ability to withhold future revenue disbursements to recover any
non-payment of joint interest billings. Our crude oil and natural gas
receivables are typically collected within two months. We accrue a reserve on a
receivable when, based on the judgment of management, it is probable that a
receivable will not be collected and the amount of any reserve may be reasonably
estimated.

Beginning in 2001, we experienced a gradual decline in the timeliness of
receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic
conditions in Egypt lessened the availability of U.S. dollars, resulting in a
one to two month delay in receipts from EGPC. During 2004, we experienced wide
variability in the timing of cash receipts, but our past due balance improved at
year-end. We have not established a reserve for these Egyptian receivables
because we continue to get paid, albeit late, and have no indication that we
will not be able to collect our receivable.

ASSET RETIREMENT OBLIGATION

The Company has significant obligations to remove tangible equipment and
restore land or seabed at the end of oil and gas production operations. Apache's
removal and restoration obligations are primarily associated with plugging and
abandoning wells and removing and disposing of offshore oil and gas platforms.
Estimating the future restoration and removal costs is difficult and requires
management to make estimates and judgments because most of the removal
obligations are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental,
safety and public relations considerations. Prior to 2003, under the full-cost
method of accounting, as described in the preceding critical accounting policy
sections, the

41

estimated undiscounted costs of the abandonment obligations, net of the value of
salvage, were included as a component of our depletion base and expensed over
the production life of the oil and gas properties.

In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." Apache adopted this statement effective January 1, 2003, as
discussed in Note 4, Asset Retirement Obligation of Item 15 of this Form 10-K.
SFAS No. 143 significantly changed the method of accruing for costs an entity is
legally obligated to incur related to the retirement of fixed assets ("asset
retirement obligations" or "ARO"). Primarily, the new statement requires the
Company to record a separate liability for the discounted present value of the
Company's asset retirement obligations, with an offsetting increase to the
related oil and gas properties on the balance sheet. As such, beginning in 2003
our depletion expense is reduced since we will deplete a discounted ARO rather
than the undiscounted value previously depleted in our oil and gas property
base. The lower depletion expense under SFAS No. 143 is offset, however, by
accretion expense, which reflects increases in the discounted asset retirement
obligation over time.

Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing Asset
Retirement Obligation liability, a corresponding adjustment is made to the oil
and gas property balance.

Also, the Company had to determine how to incorporate the asset retirement
obligations into the quarterly calculation of its full-cost ceiling tests (see
Note 1, Summary of Significant Accounting Policies of Item 15 in this Form
10-K). SFAS No. 143 is silent with respect to this issue and, although there
were various views, the Company initially elected to perform the calculation
similarly to the prior year by including expected abandonment costs as a
reduction to the present value of future net revenues used to determine the
ceiling limitation. The oil and gas property balance is capped by this
limitation. Because abandonment costs are now reflected in the oil and gas
property balance, the Company reduced the property balance by the accrued
abandonment liability to place it on a comparable basis with the ceiling.

In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106
to provide new guidance on how asset retirement obligations should impact the
calculation of the ceiling test. The new guidance states that the property
balance should not be adjusted; however, the expected future abandonment costs
should be omitted from the present value ceiling limitation to provide for a
comparable basis when performing the calculation. Based on this guidance, the
Company changed its method of calculating the ceiling test as of year end and
there was no material impact to the financial statements.

INCOME TAXES

Our oil and gas exploration and production operations are currently located
in seven countries. As a result, we are subject to taxation on our income in
numerous jurisdictions. We record deferred tax assets and liabilities to account
for the expected future tax consequences of events that have been recognized in
our financial statements and our tax returns. We routinely assess the
realizability of our deferred tax assets. If we conclude that it is more likely
than not that some portion or all of the deferred tax assets will not be
realized under accounting standards, the tax asset would be reduced by a
valuation allowance. We consider future taxable income in making such
assessments. Numerous judgments and assumptions are inherent in the
determination of future taxable income, including factors such as future
operating conditions (particularly as related to prevailing oil and gas prices).

The Company regularly assesses and, if required, establishes accruals for
tax contingencies that could result from assessments of additional tax by taxing
jurisdictions in countries where the Company operates. Tax reserves have been
established, and include any related interest, despite the belief by the Company
that certain tax positions have been fully documented in the Company's tax
returns. These reserves are subject to a significant amount of judgment and are
reviewed and adjusted on a periodic basis in light of changing facts and
circumstances considering the progress of ongoing tax audits, case law and any
new legislation. The Company believes that the reserves established are adequate
in relation to the potential for any additional tax assessments.
42

DERIVATIVES

Apache uses derivative contracts on a limited basis to manage its exposure
to oil and gas price volatility and foreign currency volatility. The Company
accounts for the contracts in accordance with SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The estimated fair values of
Apache's derivative contracts within the scope of this statement are carried on
the Company's consolidated balance sheet. For oil and gas derivative contracts
designated and qualifying as cash flow hedges, realized gains and losses are
recognized in oil and gas production revenues when the forecasted transaction
occurs. For foreign currency forward contracts designated as qualifying as cash
flow hedges, realized gains and losses are generally recognized in lease
operating expense when the forecasted transaction occurs. SFAS No. 133 requires
that gains and losses from the change in fair value of derivative instruments
that do not qualify for hedge accounting be "marked-to-market" and reported in
current period income, rather than in the period in which the hedged transaction
is settled. Realized gains and losses on derivative contracts not qualifying as
cash flow hedges are reported in Other.

The fair value estimate of Apache's derivative contracts requires judgment;
however, the Company's derivative contracts are either exchange traded or valued
by reference to commodities and currencies that are traded in highly liquid
markets. As such, the ultimate fair value is determined by references to readily
available public data. Option valuations are verified against independent
third-party quotations. See Item 7A, Quantitative and Qualitative Disclosures
about Market Risk, "Commodity Risk" in this Form 10-K for commodity price
sensitivity information and the Company's policies related to the use of
derivatives.

STOCK-BASED COMPENSATION

During 2002, Apache began modifying its stock compensation plans in order
to reflect the cost of these plans in the Statement of Consolidated Operations.
As part of this effort, Apache began issuing stock appreciation rights and
restricted stock and, effective January 1, 2003, adopted the expense provisions
of SFAS No. 123 "Accounting for Stock Based Compensation," as amended, on a
prospective basis for all stock options granted under the Company's existing
option plans. Consistent with the Company's desire to reflect the ultimate cost
of stock compensation plans on the income statement, Apache early adopted the
provisions of SFAS No. 123-R "Share-Based Payment" upon the FASB's issuance of
the revised statement in the fourth quarter 2004. In response to certain changes
in U.S. tax laws passed in 2004, for future compensation the Company plans to
make grants of stock options, rather than share appreciation rights, assuming
the Company's shareholders approve a new stock option plan at the 2005 annual
meeting of shareholders.

Upon adoption of SFAS No. 123-R, all stock based compensation awards that
vested during 2004 are now reflected in the Company's net income for the year.
Awards that vested in prior years continue to be reflected in the income
statement under the accounting guidelines in place for the applicable year.
Awards granted in future periods will be valued on the date of grant and
expensed using a straight-line basis over the required service period. Pro-forma
income statement presentations have been provided for in Note 1. Summary of
Significant Accounting Policies of Item 15 in this Form 10-K to present a
comparative basis of all plans outstanding during the reported periods.

The Company chose to adopt the statement under the "Modified Retrospective"
approach as prescribed under SFAS No. 123-R. Under this approach, the Company is
required to expense all options and stock based compensation that vested during
the year of adoption based on the fair value of the stock compensation
determined on the date of grant. Had the Company not early adopted SFAS No.
123-R under this transition approach, 2004 net income would have been lower by
$89 million ($56 million after tax) or $.17 per diluted share. Normally, net
income would be negatively impacted by adopting SFAS No. 123-R under this
transition method. However, the Company's Share Appreciation Plan which
triggered in 2004 has a fair market value based expense recorded under the
provisions of SFAS No. 123-R that is substantially less than the intrinsic value
cost that would have been recorded under the provisions of APB Opinion No. 25.
Please refer to Note 8, Capital Stock of Item 15 of this Form 10-K for a
detailed description of the Share Appreciation Plan.

Also, inherent in expensing stock options and other stock-based
compensation under SFAS No. 123-R are several judgments and estimates that must
be made. These include determining the underlying valuation
43

methodology for stock compensation awards and the related inputs utilized in
each valuation, such as the Company's expected stock price volatility, expected
term of the employee option, expected dividend yield, the expected risk-free
interest rate, the underlying stock price and the exercise price of the option.
Changes to these assumptions could result in different valuations for individual
share awards and will be carefully scrutinized for each material grant. For
valuation purposes, Apache has historically utilized the Black-Scholes option
pricing model, however, the Company is currently evaluating its policy to
determine if a different method should be used, such as a lattice model.
Apache's next grant to substantially all Company employees is anticipated to
occur in May 2005.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY RISK

The major market risk exposure is in the pricing applicable to our oil and
gas production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to our United States and Canadian
natural gas production. Prices received for oil and gas production have been and
remain volatile and unpredictable. Monthly oil price realizations, including the
impact of fixed-price contracts and hedges, ranged from a low of $28.97 per
barrel to a high of $43.82 per barrel during 2004. Average gas price
realizations, including the impact of fixed-price contracts and hedges, ranged
from a monthly low of $4.40 per Mcf to a monthly high of $5.61 per Mcf during
the same period. Based on the Company's 2004 worldwide oil production levels, a
$1.00 per barrel change in the weighted-average realized price of oil would
increase or decrease revenues by $85 million. Based on the Company's 2004
worldwide gas production levels, a $.10 per Mcf change in the weighted-average
realized price of gas would increase or decrease revenues by $45 million.

If oil and gas prices decline significantly, even if only for a short
period of time, it is possible that non-cash write-downs of our oil and gas
properties could occur under the full-cost accounting method allowed by the
Securities Exchange Commission (SEC). Under these rules, we review the carrying
value of our proved oil and gas properties each quarter on a country-by-country
basis to ensure that capitalized costs of proved oil and gas properties, net of
accumulated depreciation, depletion and amortization, and deferred income taxes,
do not exceed the "ceiling." This ceiling is the present value of estimated
future net cash flows from proved oil and gas reserves, discounted at 10
percent, plus the lower of cost or fair value of unproved properties included in
the costs being amortized, net of related tax effects. If capitalized costs
exceed this limit, the excess is charged to additional DD&A expense. The
calculation of estimated future net cash flows is based on the prices for crude
oil and natural gas in effect on the last day of each fiscal quarter except for
volumes sold under long-term contracts. Write-downs required by these rules do
not impact cash flow from operating activities; however, as discussed above,
sustained low prices would have a material adverse effect on future cash flows.

We periodically enter into hedging activities on a portion of our projected
oil and natural gas production through a variety of financial and physical
arrangements intended to support oil and natural gas prices at targeted levels
and to manage our overall exposure to oil and gas price fluctuations. Apache may
use futures contracts, swaps, options and fixed-price physical contracts to
hedge its commodity prices. Realized gains or losses from the Company's price
risk management activities are recognized in oil and gas production revenues
when the associated production occurs. Apache does not generally hold or issue
derivative instruments for trading purposes. As indicated in Note 3, Hedging and
Derivative Instruments of Item 15 in this Form 10-K, the Company entered into
several derivative positions in conjunction with our 2002, 2003 and 2004
acquisitions. These positions were entered into to preserve our strong financial
position in a period of cyclically high gas and oil prices and were designated
as cash flow hedges of anticipated production.

Apache has historically only hedged long-term oil and gas prices related to
a portion of its expected production associated with acquisitions. As such, the
Company's use of hedging activity remains at a correspondingly low level. In
2004, financial derivative hedges represented approximately 16 percent of the
total worldwide natural gas production and four percent of the total worldwide
crude oil production. Heading into 2005, hedges in place were entirely related
to U.S. production and represented 11 percent and six percent of worldwide
production for natural gas and crude oil, respectively.

44

On December 31, 2004, the Company had open natural gas derivative positions
with a fair value of $(23) million. A 10 percent change in natural gas prices
would change the fair value by plus or minus $41 million. The Company also had
open oil price swap positions with a fair value of $(28) million. A 10 percent
increase in oil prices would reduce the fair value by $31 million. A 10 percent
decrease in oil prices would increase the fair value by $28 million. These fair
value changes assume volatility based on prevailing market parameters at
December 31, 2004. See Note 3, Hedging and Derivative Instruments of Item 15 in
this Form 10-K for notional volumes and terms associated with the Company's
derivative contracts.

Apache conducts its risk management activities for its commodities under
the controls and governance of its risk management policy. The Risk Management
Committee, comprising the Chief Financial Officer, Controller, Treasurer and
other key members of Apache's management, approve and oversee these controls,
which have been implemented by designated members of the treasury department.
The treasury and accounting departments also provide separate checks and reviews
on the results of hedging activities. Controls for our commodity risk management
activities include limits on credit, limits on volume, segregation of duties,
delegation of authority and a number of other policy and procedural controls.

INTEREST RATE RISK

Approximately 85 percent of the Company's year-end 2004 debt is term debt
with fixed interest rates, minimizing the Company's exposure to fluctuations in
short-term interest rates. At December 31, 2004, the Company had $396 million of
floating-rate debt which is subject to fluctuations in short-term interest
rates. A 10 percent change in the floating interest rate (approximately 23 basis
points) on these year-end balances, would change annual interest expense by
approximately $1 million. The Company did not have any open derivative contracts
relating to interest rates at December 31, 2004.

FOREIGN CURRENCY RISK

The Company's cash flow stream relating to certain international operations
is based on the U.S. dollar equivalent of cash flows measured in foreign
currencies. In Australia, oil production is sold under U.S. dollar contracts and
gas production is sold under fixed-price Australian dollar contracts. Over half
the costs incurred for Australian operations are paid in Australian dollars. In
Canada, the majority of oil and gas production is sold under Canadian dollar
contracts. The majority of the costs incurred are paid in Canadian dollars. The
North Sea production is sold under U.S. dollar contracts and the majority of
costs incurred are paid in British pounds. In contrast, all oil and gas
production in Egypt is sold for U.S. dollars and the majority of the costs
incurred are denominated in U.S. dollars. Revenue and disbursement transactions
denominated in Australian dollars, Canadian dollars and British pounds are
converted to U.S. dollar equivalents based on the exchange rate as of the
transaction date.

Prior to October 1, 2002, reported cash flow from Canadian operations was
measured in Canadian dollars and converted to the U.S. dollar equivalent based
on the average of the Canadian and U.S. dollar exchange rates for the period
reported. The majority of Apache's debt in Canada is denominated in U.S. dollars
and, as such, was adjusted for differences in exchange rates at each period end
and recorded as Revenues and Other. In light of the continuing transformation of
the U.S. and Canadian energy markets into a single energy market, we adopted the
U.S. dollar as our functional currency in Canada, effective October 1, 2002.

A 10 percent strengthening of the Australian and Canadian dollars and the
British pound as of December 31, 2004 would result in a foreign currency net
loss of approximately $68 million. This is primarily driven from foreign
currency effects on the Company's deferred tax liability positions in its
international operations. The Company began hedging a portion of its foreign
exchange risk associated with lease operating expenditures in 2004. The
Company's treasury department administers this hedging program. For information
on open derivative contracts, please see Note 3, Hedging and Derivative
Instruments of Item 15 in this Form 10-K.

45

FORWARD-LOOKING STATEMENTS AND RISK

Certain statements in this report, including statements of the future
plans, objectives, and expected performance of the Company, are forward-looking
statements that are dependent upon certain events, risks and uncertainties that
may be outside the Company's control, and which could cause actual results to
differ materially from those anticipated. Some of these include, but are not
limited to, capital expenditure projections, the market prices of oil and gas,
economic and competitive conditions, inflation rates, legislative and regulatory
changes, financial market conditions, political and economic uncertainties of
foreign governments, future business decisions and other uncertainties, all of
which are difficult to predict.

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of actual future
production may vary significantly from reserve and production estimates. The
drilling of exploratory wells can involve significant risks, including those
related to timing, success rates and cost overruns. Lease and rig availability,
complex geology and other factors can affect these risks. Although Apache makes
use of futures contracts, swaps, options and fixed-price physical contracts to
mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation
of low prices, may substantially adversely affect the Company's financial
position, results of operations and cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required
to be filed under this item are presented on pages F-1 through F-65 of this Form
10-K, and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2004, 2003
and 2002, included in this report, have been audited by Ernst & Young LLP,
independent public auditors, as stated in their audit report appearing herein.

ITEM 9A. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

G. Steven Farris, the Company's President, Chief Executive Officer and
Chief Operating Officer, and Roger B. Plank, the Company's Executive Vice
President and Chief Financial Officer, evaluated the effectiveness of our
disclosure controls and procedures as of December 31, 2004, the end of the
period covered by this report. Based on that evaluation and as of the date of
that evaluation, these officers concluded that the Company's disclosure controls
were effective, providing effective means to insure that information we are
required to disclose under applicable laws and regulations is recorded,
processed, summarized and reported in a timely manner. We also made no
significant changes in internal controls over financial reporting during the
quarter ending December 31, 2004 that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting.

We periodically review the design and effectiveness of our disclosure
controls, including compliance with various laws and regulations that apply to
our operations both inside and outside the United States. We make modifications
to improve the design and effectiveness of our disclosure controls, and may take
other corrective action, if our reviews identify deficiencies or weaknesses in
our controls.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management report called for by Item 308(a) of Regulation S-K is
incorporated herein by reference to Report of Management on Internal Control
Over Financial Reporting, included on Page F-1 in Item 15 of this report.

46

The independent auditors attestation report called for by Item 308(b) of
Regulation S-K is incorporated by reference to Report of Independent Registered
Public Accounting Firm on Internal Control Over Financial Reporting, included on
Page F-3 in Item 15 of this report.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in our internal controls over financial reporting
during the period covered by this Annual Report on Form 10-K that materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information set forth under the captions "Nominees for Election as
Directors," "Continuing Directors," "Executive Officers of the Company," and
"Securities Ownership and Principal Holders" in the proxy statement relating to
the Company's 2005 annual meeting of stockholders (the Proxy Statement) is
incorporated herein by reference.

CODE OF BUSINESS CONDUCT

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are
required to adopt a code of business conduct and ethics for our directors,
officers and employees. In February 2004, the Board of Directors adopted the
Code of Business Conduct (Code of Conduct), which also meets the requirements of
a code of ethics under Item 406 of Regulation S-K. You can access the Company's
Code of Conduct on the Investor Relations page of the Company's website at
http://www.apachecorp.com. Any stockholder who so requests may obtain a printed
copy of the Code of Conduct by submitting a request to the Company's Corporate
Secretary. Changes in and waivers to the Code of Conduct for the Company's
Directors, Chief Executive Officer and certain senior financial officers will be
posted on the Company's website within five business days and maintained for at
least 12 months.

ITEM 11. EXECUTIVE COMPENSATION

The information set forth under the captions "Summary Compensation Table,"
"Option/SAR Exercises and Year-End Value Table," "Long-Term Incentive Plan
Awards Table," "Employment Contracts and Termination of Employment and
Change-in-Control Arrangements" and "Director Compensation" in the Proxy
Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information set forth under the captions "Securities Ownership and
Principal Holders" and "Equity Compensation Plan Information" in the Proxy
Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information set forth under the caption "Certain Business Relationships
and Transactions" in the Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information set forth under the caption "Independent Public
Accountants" in the Proxy Statement is incorporated herein by reference.

47

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Documents included in this report:

1. Financial Statements

Report of management........................................ F-1
Report of independent registered public accounting firm..... F-2
Report of independent registered public accounting firm..... F-3
Statement of consolidated operations for each of the three
years in the period ended December 31, 2004............... F-4
Statement of consolidated cash flows for each of the three
years in the period ended December 31, 2004............... F-5
Consolidated balance sheet as of December 31, 2004 and
2003...................................................... F-6
Statement of consolidated shareholders' equity for each of
the three years in the period ended December 31, 2004..... F-7
Notes to consolidated financial statements.................. F-8

2. Financial Statement Schedules

Financial statement schedules have been omitted because they are either
not required, not applicable or the information required to be presented
is included in the Company's financial statements and related notes.

3. Exhibits

- ---------------
* Filed herewith.

+ Management contracts or compensatory plans or arrangements required to be
filed herewith pursuant to Item 15 hereof.

NOTE: Debt instruments of the Registrant defining the rights of long-term
debt holders in principal amounts not exceeding 10 percent of the
Registrant's consolidated assets have been omitted and will be provided to
the Commission upon request.

(b) Reports filed on Form 8-K

The following current reports on Form 8-K were filed by the Company during
the fiscal quarter ended December 31, 2004:

None

53

SIGNATURES

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

APACHE CORPORATION

/s/ G. STEVEN FARRIS
--------------------------------------
G. STEVEN FARRIS
President, Chief Executive Officer and
Chief Operating Officer

Dated: March 11, 2005

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear
below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P.
Anthony Lannie, Thomas L. Mitchell, and Jeffrey B. King, and each of them (with
full power to each of them to act alone), the true and lawful attorney-in-fact
to sign and execute, on behalf of the undersigned, any amendment(s) to this
report and each of the undersigned does hereby ratify and confirm all that said
attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for the preparation and integrity
of the consolidated financial statements appearing in this annual report on Form
10-K. The financial statements were prepared in conformity with accounting
principles generally accepted in the United States and include amounts that are
based on management's best estimates and judgments.

Management of the Company is responsible for establishing and maintaining
effective internal control over financial reporting as such term is defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934 ("Exchange Act"). The
Company's internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of the consolidated financial statements. Our internal control over
financial reporting is supported by a program of internal audits and appropriate
reviews by management, written policies and guidelines, careful selection and
training of qualified personnel and a written code of business conduct adopted
by our Company's Board of Directors, applicable to all Company Directors and all
officers and employees of our Company and subsidiaries.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements and even when determined to be
effective, can only provide reasonable assurance with respect to financial
statement preparation and presentation. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree of compliance
with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company's internal control
over financial reporting as of December 31, 2004. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal
Control -- Integrated Framework. Based on our assessment, management believes
that the Company maintained effective internal control over financial reporting
as of December 31, 2004.

The Company's independent auditors, Ernst & Young LLP, a registered public
accounting firm, are appointed by the Audit Committee of the Company's Board of
Directors. Ernst & Young LLP have audited and reported on the consolidated
financial statements of Apache Corporation and subsidiaries, management's
assessment of the effectiveness of the Company's internal control over financial
reporting and the effectiveness of the Company's internal control over financial
reporting. The reports of the independent auditors follow this report on pages
F-2 and F-3.

G. Steven Farris
President, Chief Executive Officer
and Chief Operating Officer

Roger B. Plank
Executive Vice President and Chief
Financial Officer

Thomas L. Mitchell
Vice President and Controller
(Chief Accounting Officer)

Houston, Texas
March 11, 2005

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache
Corporation and subsidiaries as of December 31, 2004 and 2003, and the related
consolidated statements of operations, shareholders' equity, and cash flows for
each of the three years in the period ended December 31, 2004. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Apache
Corporation and subsidiaries as of December 31, 2004 and 2003 and the
consolidated results of their operations and their cash flows for each of the
three years ended December 31, 2004, in conformity with accounting principles
generally accepted in the United States.

As described in Note 8 to the consolidated financial statements, during
2004, the Company adopted the modified prospective provisions of Statement of
Financial Accounting Standards ("SFAS") No. 123(revised), "Share-Based Payment."
In addition, as described in Notes 1 and 4, effective January 1, 2003, the
Company adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement
Obligations" and the prospective provisions of SFAS No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure."

We also have audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Apache
Corporation and subsidiaries' internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated March 11, 2005
expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that Apache
Corporation and subsidiaries maintained effective internal control over
financial reporting as of December 31, 2004, based on criteria established in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Apache
Corporation's management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an
opinion on management's assessment and an opinion on the effectiveness of the
company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Apache Corporation and
subsidiaries maintained effective internal control over financial reporting as
of December 31, 2004, is fairly stated, in all material respects, based on the
COSO criteria. Also, in our opinion, Apache Corporation and subsidiaries
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Apache Corporation and subsidiaries as of December 31, 2004 and 2003,
and the related consolidated statements of operations, shareholders' equity, and
cash flows for each of the three years in the period ended December 31, 2004 and
our report dated March 11, 2005 expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

The accompanying notes to consolidated financial statements are an integral part
of this statement.
F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

The accompanying notes to consolidated financial statements are an integral part
of this statement.
F-5

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

The accompanying notes to consolidated financial statements are an integral part
of this statement.
F-6

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY

The accompanying notes to consolidated financial statements are an integral part
of this statement.

F-7

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS -- Apache Corporation (Apache or the Company) is an
independent energy company that explores for, develops and produces natural gas,
crude oil and natural gas liquids. The Company's North American exploration and
production activities are divided into two U.S. operating regions (Central and
Gulf Coast) and a Canadian region. Approximately 70 percent of the Company's
proved reserves are located in North America. Outside of North America, Apache
has exploration and production interests in Egypt, offshore Western Australia,
offshore the United Kingdom in the North Sea (North Sea), offshore The People's
Republic of China (China) and in Argentina. In 2003, we ceased operations in
Poland.

The Company's future financial condition and results of operations will
depend upon prices received for its oil and natural gas production and the costs
of finding, acquiring, developing and producing reserves. A substantial portion
of the Company's production is sold under market-sensitive contracts. Prices for
oil and natural gas are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of other factors beyond the Company's
control. These factors include worldwide political instability (especially in
the Middle East), the foreign supply of oil and natural gas, the price of
foreign imports, the level of consumer demand, and the price and availability of
alternative fuels.

All share and per share information in these financial statements and notes
thereto has been restated to reflect the 10 percent and five percent stock
dividends and the two-for-one stock split. See Note 8, Capital Stock, for
further discussion.

PRINCIPLES OF CONSOLIDATION -- The accompanying consolidated financial
statements include the accounts of Apache and its subsidiaries after elimination
of intercompany balances and transactions. The Company consolidates all
investments in which the Company, either through direct or indirect ownership,
has more than a 50 percent voting interest. In addition, Apache consolidates all
variable interest entities where it is the primary beneficiary. The Company's
interests in oil and gas exploration and production ventures and partnerships
are proportionately consolidated, including Apache Offshore Investment
Partnership.

CASH EQUIVALENTS -- The Company considers all highly liquid debt
instruments purchased with an original maturity of three months or less to be
cash equivalents. These investments are carried at cost, which approximates fair
value.

ALLOWANCE FOR DOUBTFUL ACCOUNTS -- The Company routinely assesses the
recoverability of all material trade and other receivables to determine their
collectibility. Many of Apache's receivables are from joint interest owners on
properties which Apache operates. Thus, Apache may have the ability to withhold
future revenue disbursements to recover any non-payment of joint interest
billings. Generally, the Company's crude oil and natural gas receivables are
collected within two months. However, beginning in 2001, the Company experienced
a gradual decline in the timeliness of receipts from the Egyptian General
Petroleum Corporation (EGPC). Deteriorating economic conditions in Egypt
lessened the availability of U.S. dollars, resulting in an additional one to two
month delay in receipts from EGPC. During 2004, we experienced wide variability
in the timing of cash receipts, but our past due balance improved at year-end.
We have not established a reserve for these Egyptian receivables because we
continue to get paid, albeit late, and we have no indication that we will not be
able to collect our receivable.

The Company accrues a reserve on a receivable when, based on the judgment
of management, it is probable that a receivable will not be collected and the
amount of any reserve may be reasonably estimated. As of December 31, 2004 and
2003, the Company had an allowance for doubtful accounts of $22 million and $30
million, respectively.

MARKETABLE SECURITIES -- The Company accounts for investments in debt and
equity securities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." Investments in debt securities classified as "held to maturity" are

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

recorded at amortized cost. Investments in debt and equity securities classified
as "available for sale" are recorded at fair value with unrealized gains and
losses recognized in other comprehensive income, net of income taxes. The
Company utilizes the average-cost method in computing realized gains and losses,
which are included in Revenues and Other in the consolidated statements of
operations.

INVENTORIES -- Inventories consist principally of tubular goods and
production equipment, stated at the lower of weighted-average cost or market,
and oil produced but not sold, stated at the lower of cost (a combination of
production costs and depreciation, depletion and amortization (DD&A) expense) or
market.

PROPERTY AND EQUIPMENT -- The Company uses the full-cost method of
accounting for its investment in oil and gas properties. Under this method, the
Company capitalizes all acquisition, exploration and development costs incurred
for the purpose of finding oil and gas reserves, including salaries, benefits
and other internal costs directly attributable to these activities.
Historically, total capitalized internal costs in any given year have not been
material to total oil and gas costs capitalized in such year. Apache capitalized
$107 million, $65 million and $52 million of these internal costs in 2004, 2003
and 2002, respectively. Costs associated with production and general corporate
activities, however, are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. Unless a significant portion of the Company's proved
reserve quantities in a particular country are sold (greater than 25 percent),
proceeds from the sale of oil and gas properties are accounted for as a
reduction to capitalized costs, and gains and losses are not recognized.

Apache computes the DD&A of oil and gas properties on a quarterly basis
using the unit-of-production method based upon production and estimates of
proved reserve quantities. Unproved properties are excluded from the amortizable
base until evaluated. The cost of exploratory dry wells is transferred to proved
properties and thus subject to amortization immediately upon determination that
a well is dry in those countries where proved reserves exist. In countries where
the Company has not booked proved reserves, all costs associated with a prospect
or play are considered quarterly for impairment upon full evaluation of such
prospect or play. This evaluation considers among other factors, seismic data,
requirements to relinquish acreage, drilling results, remaining time in the
commitment period, remaining capital plans, and political, economic, and market
conditions. Geological and geophysical (G&G) costs are recorded in proved
property and therefore subject to amortization as incurred in mature basins. In
exploration areas, G&G costs are capitalized in unproved property and evaluated
as part of the total capitalized costs associated with a prospect or play.
Future development costs and dismantlement, restoration and abandonment costs,
net of estimated salvage values were added to the amortizable base until the end
of 2002. Beginning in 2003, Apache changed its method of accounting for
dismantlement, restoration and abandonment costs and the related effects on
DD&A. The Company now includes the present value of its dismantlement,
restoration and abandonment costs within the capitalized oil and gas property
balance and, therefore, no longer reflects the recognized abandonment
obligations within the future development costs added to the amortizable base
(see Note 4, Asset Retirement Obligation).

In performing its quarterly ceiling test, the Company limits, on a
country-by-country basis, the capitalized costs of proved oil and gas
properties, net of accumulated DD&A and deferred income taxes, to the estimated
future net cash flows from proved oil and gas reserves discounted at 10 percent,
net of related tax effects, plus the lower of cost or fair value of unproved
properties included in the costs being amortized. If capitalized costs exceed
this limit, the excess is charged as additional DD&A expense. The Company
calculates future net cash flows by applying end-of-the-period prices except in
those instances where future natural gas or oil sales are covered by physical
contract terms providing for higher or lower amounts. Also, included in the
estimated future net cash flows are Canadian provincial tax credits expected to
be realized beyond the date at which the legislation, under its provisions,
could be repealed. To date, the Canadian provincial governments have not
indicated an intention to repeal this legislation. See Note 14, Supplemental

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Oil and Gas Disclosures (Unaudited) "Future Net Cash Flows" for a discussion on
calculation of estimated future net cash flows.

In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106
to provide new guidance on how asset retirement obligations should impact the
calculation of the ceiling test limitation on the amount of properties that can
be capitalized. The new guidance is effective as of year-end 2004 and states
that because asset retirement obligation costs are now reflected in the property
balance, the future net cash flow calculation should omit the expected
abandonment costs to provide for a comparable basis. Apache previously included
abandonment costs in its future net cash flow calculation, but adjusted the
capitalized amounts by the accrued abandonment obligation. The Company's
adoption of SAB No. 106 did not have a material impact on financial results.

Given the volatility of oil and gas prices, it is reasonably possible that
the Company's estimate of discounted future net cash flows from proved oil and
gas reserves could change in the near term. If oil and gas prices decline
significantly, even if only for a short period of time, it is possible that
write-downs of oil and gas properties could occur.

Unproved properties are assessed quarterly for possible impairments or
reductions in value. If a reduction in value has occurred, the impairment is
transferred to proved properties. For international operations where a reserve
base has not yet been established, the impairment is charged to earnings. Apache
began impairing its unproved property costs in Poland in 2001, impairing $20
million ($12 million after tax) in 2002 and the remaining $13 million ($8
million after tax) in 2003.

Buildings, equipment and gas gathering, transmission and processing
facilities are depreciated on a straight-line basis over the estimated useful
lives of the assets, which range from three to 20 years. Accumulated
depreciation for these assets totaled $380 million and $309 million at December
31, 2004 and 2003, respectively.

GOODWILL -- Goodwill totaled $189 million at December 31, 2004 and 2003,
representing the excess of the purchase price over the estimated fair value of
the assets acquired and liabilities assumed in the Fletcher Challenge Energy
(Fletcher) and Repsol YPF (Repsol) 2001 acquisitions. Approximately $103 million
and $86 million of goodwill remain in Canada and Egypt, respectively. Apache
deemed the geographic areas to be the reporting unit. Goodwill of each reporting
unit is tested for impairment on an annual basis, or more frequently if an event
occurs or circumstances change that would reduce the fair value of the reporting
unit below its carrying amount. No impairment of goodwill was recognized during
2004, 2003 and 2002.

ACCOUNTS PAYABLE -- Included in accounts payable at December 31, 2004 and
2003, are liabilities of approximately $116 million and $78 million,
respectively, representing the amount by which checks issued, but not presented
to the Company's banks for collection, exceeded balances in applicable bank
accounts.

REVENUE RECOGNITION -- Oil and gas revenues are recognized when production
is sold to a purchaser at a fixed or determinable price, when delivery has
occurred and title has transferred, and if collectibility of the revenue is
probable. Cash received relating to future revenues is deferred and recognized
when all revenue recognition criteria are met.

Apache uses the sales method of accounting for gas production imbalances.
The volumes of gas sold may differ from the volumes to which Apache is entitled
based on its interests in the properties. These differences create imbalances
that are recognized as a liability only when the properties' estimated remaining
reserves net to Apache will not be sufficient to enable the underproduced owner
to recoup its entitled share through production. The Company's recorded
liability of $6 million and $4 million for gas imbalances on December 31, 2004
and 2003, respectively, is reflected in other non-current liabilities. No
receivables are recorded for those wells where Apache has taken less than its
share of production. Gas imbalances are reflected as adjustments to proved gas
reserves and future cash flows in the unaudited supplemental oil and gas
disclosures.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Adjustments for gas imbalances totaled less than one percent of Apache's proved
gas reserves as of December 31, 2004, 2003 and 2002.

The Company's Egyptian operations are conducted pursuant to production
sharing contracts under which contractor partners pay all operating and capital
costs for exploring and developing the concessions. A percentage of the
production, usually up to 40 percent, is available to the contractor partners to
recover all operating and capital costs. The balance of the production is split
among the contractor partners and EGPC on a contractually defined basis.

Apache began marketing its domestic gas production in July 2003. As the
Company's production fluctuates because of operational issues, it is
occasionally necessary for the Company to purchase gas ("third-party gas") to
fulfill sales obligations and commitments. The trading activities associated
with the purchase and sale of the third-party gas are reported on a net basis in
oil and gas production revenues.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES -- Apache periodically enters
into derivative contracts to manage its exposure to foreign currency risk and
commodity price risk. These derivative contracts, which are generally placed
with major financial institutions that the Company believes are minimal credit
risks, may take the form of forward contracts, futures contracts, swaps or
options. The oil and gas reference prices upon which the commodity derivative
contracts are based, reflect various market indices that have a high degree of
historical correlation with actual prices received by the Company for its oil
and gas production.

Apache accounts for its derivative instruments in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
SFAS No. 133 establishes accounting and reporting standards requiring that all
derivative instruments, other than those that meet the normal purchases and
sales exception, be recorded on the balance sheet as either an asset or
liability measured at fair value (which is generally based on information
obtained from independent parties). SFAS No. 133 also requires that changes in
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Hedge accounting treatment allows unrealized gains and losses
on cash flow hedges to be deferred in other comprehensive income. Realized gains
and losses from the Company's oil and gas cash flow hedges, including terminated
contracts, are generally recognized in oil and gas production revenues when the
forecasted transaction occurs. Realized gains and losses on foreign currency
cash flow hedges are generally recognized in lease operating expense when the
forecasted transaction occurs. Gains and losses from the change in fair value of
derivative instruments that do not qualify for hedge accounting are reported in
current period income as "other." If at any time the likelihood of occurrence of
a hedged forecasted transaction ceases to be "probable," hedge accounting under
SFAS No. 133 will cease on a prospective basis and all future changes in the
fair value of the derivative will be recognized directly in earnings. Amounts
recorded in other comprehensive income prior to the change in the likelihood of
occurrence of the forecasted transaction will remain in other comprehensive
income until such time as the forecasted transaction impacts earnings. If it
becomes probable that the original forecasted production will not occur, then
the derivative gain or loss would be reclassified from accumulated other
comprehensive income into earnings immediately. Hedge effectiveness is measured
at least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time, and any ineffectiveness is
immediately reported under Revenues and Other in the statement of consolidated
operations.

INCOME TAXES -- Our oil and gas exploration and production operations are
currently located in seven countries. As a result, we are subject to taxation on
our income in numerous jurisdictions. We record deferred tax assets and
liabilities to account for the expected future tax consequences of events that
have been recognized in our financial statements and our tax returns. We
routinely assess the realizability of our deferred tax assets. If we conclude
that it is more likely than not that some portion or all of the deferred tax
assets will not be realized under accounting standards, the tax asset is reduced
by a valuation allowance. We consider future taxable income in making such
assessments. Numerous judgments and assumptions are inherent in the

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

determination of future taxable income, including factors such as future
operating conditions (particularly as related to prevailing oil and gas prices).

Earnings from Apache's international operations are permanently reinvested;
therefore, the Company does not recognize U.S. deferred taxes on the unremitted
earnings of its international subsidiaries. If it becomes apparent that some or
all of the unremitted earnings will be remitted, the Company would then reflect
taxes on those earnings.

FOREIGN CURRENCY TRANSLATION -- The U.S. dollar has been determined to be
the functional currency for each of Apache's international operations. The
functional currency is determined country-by-country based on relevant facts and
circumstances of the cash flows, commodity pricing environment, and financing
arrangements in each country.

In light of the continuing transformation of the U.S. and Canadian energy
markets into a single energy market, the Company adopted the U.S. dollar as the
functional currency in Canada, effective October 1, 2002. Prior to this, our
Canadian subsidiaries' functional currency was the Canadian dollar. Translation
adjustments resulting from translating the Canadian subsidiaries' foreign
currency financial statements into U.S. dollar equivalents were reported
separately and accumulated in other comprehensive income. Some of the Company's
Canadian subsidiaries had intercompany debt denominated in U.S. dollars. Prior
to conversion, these transactions were long-term investments, and therefore,
foreign currency gains and losses were recognized in other comprehensive income.
Currency translation adjustments held in other comprehensive income on the
balance sheet will remain there indefinitely unless there is a substantially
complete liquidation of the Company's Canadian operations.

The Company accounts for foreign currency gains and losses in accordance
with SFAS No. 52 "Foreign Currency Translation." Foreign currency translation
gains and losses related to deferred taxes are recorded as a component of its
provision for income taxes, while all other foreign currency gains and losses
are reflected in Revenues and Other. The Company recorded additional deferred
tax expense of $58 million and $172 million in 2004 and 2003, respectively, and
a minimal impact in 2002 as a result of the weaker U.S. dollar (see Note 6,
Income Taxes). Foreign currency gains and losses netted to a loss of $5 million,
$2 million and a gain of $1 million in 2004, 2003 and 2002, respectively.

NET INCOME PER COMMON SHARE -- Diluted net income per common share reflects
the potential dilution that could occur if outstanding stock awards were issued,
outstanding stock options were exercised or if convertible equity securities
were converted into common stock. These potentially dilutive securities are
excluded from the computation when their effect is antidilutive.

Diluted net income per common share for the years ending December 31, 2004
reflects the potential dilution that could occur if the Company's outstanding
Share Appreciation Plan shares and Restricted Stock Plan shares were issued and
if the Company's dilutive outstanding stock options were exercised (using the
average common stock price for the period). Share Appreciation Plan awards
became effective during the 2004 period.

Diluted net income per common share for the year ending December 31, 2003
reflects the potential dilution that could occur if the Company's dilutive
outstanding Restricted Stock Plan shares were issued and if the Company's
dilutive outstanding stock options were exercised (using the average common
stock price for the period).

Diluted net income per common share for the year ending December 31, 2002
reflects the potential dilution that could occur if the Company's outstanding
Restricted Stock Plan shares were issued and if the Company's dilutive
outstanding stock options were exercised (using the average common stock price
for the period) and if the Company's 6.5% Automatically Convertible Equity
Securities, Conversion Preferred Stock,

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Series C (Series C Preferred Stock) were converted to common stock, using the
conversion rate in effect during the period. The Series C Preferred Stock
converted to Apache common stock on May 15, 2002.

STOCK-BASED COMPENSATION -- On December 31, 2004, the Company had several
stock-based employee compensation plans, which include the Stock Option Plans,
the Performance Plan, the 2000 Share Appreciation Plan and restricted stock.
These plans are defined and described more fully in Note 8, Capital Stock. Prior
to 2003, the Company accounted for these plans under the recognition and
measurement provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," and related Interpretations (APB No.
25). No material stock-based employee compensation cost is reflected in 2002 net
income, as all options granted under those plans had an exercise price equal to
the market value of the underlying common stock on the date of grant. Effective
January 1, 2003, the Company adopted the fair value recognition provisions of
SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No.
148, prospectively to all employee awards granted, modified, or settled after
January 1, 2003. By adopting SFAS No. 123 on a prospective basis, only the
options granted under the plans in 2003 and later were expensed by the Company.
Options granted prior to 2003 were still reflected in the income statement based
on APB No. 25 and therefore no material expense was recognized.

During the fourth quarter of 2004, the Financial Accounting Standards Board
(FASB) issued SFAS No. 123-R, a revision to SFAS No. 123, which requires all
companies to expense stock-based compensation. The rule is effective for the
first interim period that begins after June 15, 2005. Apache early adopted this
statement in 2004 electing to transition under the "Modified Retrospective
Approach" as allowed under SFAS No. 123-R. Under this approach, the Company is
required to expense all options and stock-based compensation that vested in the
year of adoption based on the fair value of the stock compensation determined at
the date of grant. Stock vesting in years prior to 2004 was expensed in
accordance with the rules applied by the Company during such period. Had the
Company not early adopted SFAS No. 123-R, net income would have been lower by
$89 million ($56 million after tax), or $.17 per share on both a basic and
diluted per share basis. Normally, net income would be negatively impacted by
adopting SFAS No. 123-R. However, the Company's Share Appreciation Plan, which
triggered in 2004, has a fair-market-value-based expense recorded under the
provisions of SFAS No. 123-R that is substantially less than the intrinsic-value
base cost of approximately $175 million that would have been recorded under the
old APB No. 25 accounting.

In addition to the expensing provisions discussed above, SFAS No. 123-R
requires the Company to begin estimating expected future forfeitures under each
stock compensation plan and to start valuing the Company's liability-based
compensation plan (Stock Appreciation Rights) under a fair value approach
instead of the previously applied intrinsic valuation. The effects of changing
the forfeiture estimates on existing stock plans and the valuation methodology
for the Company's liability plans resulted in Apache recording a Cumulative
Effect of Change in Accounting Principle of $2.1 million ($1.3 million after
tax). SFAS No. 123-R also requires the benefits of tax deductions in excess of
recognized compensation cost to be reported as a financing cash flow rather than
as an operating cash flow as historically reported. This requirement will reduce
net operating cash flows and increase net financing cash flows in periods after
adoption.

In accordance with SFAS No. 123, Apache has historically reflected the
pro-forma impact to net income had all stock-based compensation been expensed
under the provisions of SFAS No. 123. Upon adoption of SFAS No. 123-R, all
stock-based compensation vesting in 2004 has now been reflected in the Company's
net income for 2004. Awards granted in future periods will be valued on the date
of grant and expensed using a straight-line basis over the required service
period. The following table illustrates the effect on income attributable to
common stock and earnings per share for the prior periods had the fair-value
based provisions

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of SFAS No. 123-R been applied to all outstanding and unvested awards for the
Stock Option Plans, the Performance Plan, the 2000 Share Appreciation Plan and
restricted stock.

The amounts reflected in the table above are net of amounts capitalized in
accordance with the Company's policy regarding salaries and benefits directly
attributable to acquisition, exploration and development activities. The pro
forma table in prior years did not reflect such costs net of capitalized
amounts; however, management does not believe that restating the prior year
presentation had a material impact. The stock appreciation rights, described in
Note 8, Capital Stock, are not included in the table above because it is a
cash-based liability plan already reflected in net income attributable to common
stock.

USE OF ESTIMATES -- The preparation of financial statements in conformity
with accounting principles generally accepted in the U.S., requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and related disclosure of contingent assets and liabilities at the
date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Certain accounting policies involve
judgments and uncertainties to such an extent that there is reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been used. Apache
evaluates its estimates and assumptions on a regular basis. The Company bases
its estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about carrying values of assets and liabilities that
are not readily apparent from other sources. Actual results may differ from
these estimates and assumptions used in preparation of its financial statements.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserve quantities and the related present value
of estimated future net cash flows therefrom. See Note 14, Supplemental Oil and
Gas Disclosure (Unaudited).

TREASURY STOCK -- The Company follows the weighted-average-cost method of
accounting for treasury stock transactions.

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS -- On December 21, 2004, the
FASB issued Staff Position 109-1 (FSP No. 109-1), Application of FASB Statement
No. 109 (SFAS No. 109) "Accounting for Income Taxes," to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs Creation Act of
2004 (the Act). FSP No. 109-1 clarifies guidance that applies to the new tax
deduction for

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

qualified domestic production activities. When fully phased-in, the deduction
will be up to nine percent of the lesser of "qualified production activities
income" or taxable income. FSP No. 109-1 clarifies that the deduction should be
accounted for as a special deduction under SFAS No. 109 and will reduce tax
expense in the period or periods that the amounts are deductible on the tax
return because the deduction is contingent on performing activities identified
in the Act. As a result, companies qualifying for the special deduction will not
have a one-time adjustment to deferred tax assets and liabilities in the period
the Act is enacted. Any tax benefits resulting from the new deduction will be
effective for the Company's fiscal year ending December 31, 2005. The Company is
in the process of assessing the impact, if any, the new deduction will have on
its financial statements.

The Act also includes a special one-time dividends received deduction on
the repatriation of certain foreign earnings to U.S. taxpayers, provided certain
conditions are met. On December 21, 2004, the FASB issued staff position
Accounting and Disclosure Guidance for the Foreign Earnings Repatriation
Provision within the American Jobs Creation Act of 2004 (FSP No. 109-2). FSP No.
109-2 allows companies additional time to evaluate the effect of the Act as to
whether unrepatriated foreign earnings continue to qualify for the SFAS No. 109
exception regarding non-recognition of deferred tax liabilities and requires
explanatory disclosure from those who need additional time. The Company is
currently assessing the cash needs in all of its operational areas and may
decide on a formal plan for repatriation later in 2005. The Company could accrue
charges for taxes in future periods depending on the timing of the Company's
decisions related to the repatriation.

RECLASSIFICATIONS -- Certain other prior period amounts have been
reclassified to conform with current year presentations.

2. ACQUISITIONS AND DIVESTITURES

2004 ACQUISITIONS

EXXONMOBIL

During the third quarter of 2004, Apache entered into separate arrangements
with Exxon Mobil Corporation and its affiliates (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. The
following details 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
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
term 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

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

The partnership is subject to the provisions of FASB Interpretation 46
"variable interest entities" (FIN 46). Apache has concluded that it is not the
primary beneficiary of the partnership as defined in that interpretation and
will proportionately consolidate its partnership portion of the oil and gas
properties. Apache's maximum exposure to loss as a result of its involvement
with the partnership is equal to the Company's contribution to the partnership,
which is currently $29 million. Under the partnership agreement, the Company's
subsidiaries are also subject to environmental and legal claims that could arise
in the ordinary course of business. Apache will operate the oil and gas
properties under contract for the partnership.

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.

ANADARKO PETROLEUM

On August 20, 2004, Apache signed a definitive agreement to acquire all of
Anadarko Petroleum Corporation's (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 with 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. 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
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 that is free of costs
incurred for 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, but Morgan Stanley may look only to the acquired
properties for delivery of the scheduled volumes. 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. The Company does not record the reserves and
production volumes attributable to the VPP.

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 million barrels of oil equivalent (boe), of which 50 percent was
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
F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 lines of credit and commercial paper
program.

In 2004, the Company also completed other acquisitions for $73 million.
These acquisitions added approximately 11 MMboe to the Company's proved
reserves.

2003 ACQUISITIONS

On January 13, 2003, Apache announced that it had entered into agreements
to purchase producing properties in the North Sea and Gulf of Mexico from
subsidiaries of BP p.l.c. (BP) for $1.3 billion, with $670 million allocated to
the Gulf of Mexico properties and $630 million allocated to properties in the
North Sea. The properties included estimated proved reserves of 233.2 million
barrels of oil equivalent (MMboe), 147.6 MMboe located in the North Sea with the
balance in the Gulf of Mexico. Both purchase agreements were effective as of
January 1, 2003. As is customary, Apache assumed BP's abandonment obligation for
the properties, which was considered in determining the purchase price. Both the
Gulf of Mexico and North Sea assets acquired from BP were funded with net
proceeds of approximately $554 million from the issuance of 19.8 million shares
of common stock in January 2003, and proceeds from additional debt of
approximately $604 million borrowed under existing lines of credit and
commercial paper.

Apache and BP closed the above referenced acquisition of the Gulf of Mexico
properties on March 13, 2003, which included BP's interest in 56 producing
fields, and 104 blocks. At closing, the $670 million purchase price was adjusted
for normal closing items and preferential rights exercised by third parties. The
exercise of preferential rights by third parties reduced the purchase price by
$73 million and estimated reserves by 9.6 MMboe. The purchase price was further
adjusted for various normal closing items, including revenues and expenditures
related to the properties for the period between the effective and closing
dates. As a result, cash consideration of $509 million was paid by Apache upon
closing. In a separate transaction closed February 21, 2003, Apache purchased
BP's interest in several other Gulf of Mexico properties with estimated proved
reserves of 2.1 MMboe for an adjusted purchase price of $15 million. Including
$4 million of transaction costs, total cash consideration for the two
acquisitions of Gulf of Mexico properties from BP totaled $528 million.

The acquisition of the North Sea properties closed on April 2, 2003, at
which time Apache paid a purchase price, adjusted for normal closing and working
capital adjustments, of $630 million. The acquisition of the North Sea
properties included a 96 percent interest in the Forties Field and established a
new core area for the Company. In conjunction with the Forties acquisition,
Apache may be required to issue a letter of credit to BP to cover the present
value of related asset retirement obligations if the rating of the Company's
senior unsecured debt is lowered by both Moody's and Standard and Poor's from
its current ratings of A3 and A-, respectively. Should this occur, the letter of
credit amount would be 136 million British pounds. Apache agreed to sell all of
the North Sea production through December 2004 to BP at a combination of fixed
and market sensitive prices pursuant to a contract entered into in connection
with the North Sea purchase agreement.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The BP purchase prices were allocated to the assets acquired and
liabilities assumed based upon their estimated fair values as of the date of
acquisition, as follows:

* Property balance includes $12 million of transaction costs (U.S. -- $4
million; North Sea -- $8 million).
- ---------------

On July 3, 2003, Apache announced that it had completed the acquisition of
producing properties on the outer Continental Shelf of the Gulf of Mexico from
Shell Exploration and Production Company (Shell) for $200 million, subject to
normal post-closing adjustments, including preferential rights. The acquisition
included interests in 26 fields and interest in two onshore gas plants, and was
effective July 1, 2003. Apache became operator of 15 of the fields with 91
percent of the production. At the time of the acquisition, Apache recorded
estimated proved recoverable reserves of 124.6 billion cubic feet (Bcf) of
natural gas and 6.6 million barrels of oil.

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 may receive up to 90 percent of production
associated with Apache's interest, but may look only to the 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 represents a non-operating
interest that is free of all costs related to operations and production. As a
result of this VPP obligation, Apache assumed and 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 or production attributable
to the VPP volumes. Apache's purchase price was funded by borrowings under the
Company's lines of credit and commercial paper program.

In 2003, the Company also completed other acquisitions for $126 million.
These acquisitions added approximately 28 MMboe to the Company's proved
reserves.

2002 ACQUISITIONS

On December 17, 2002, Apache announced the acquisition of certain South
Louisiana properties comprising 234,000 net acres (366 square miles) with net
proved reserves of approximately 29.8 MMboe, 88 percent of which is natural gas,
from a private company. The acquisition included 135 producing wells, access to
849 square miles of 3-D seismic covering the relatively contiguous acreage
position and ownership of the surface and mineral rights on most of the acreage,
for approximately $259 million, subject to post-closing adjustments. Apache also
entered into a separate exploration joint venture with the seller whereby the
seller was to have actively generated prospects on certain South Louisiana
acreage for a total cost of $25 million. This obligation was fulfilled during
2004.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 2002, the Company also completed other acquisitions for $95 million.
These acquisitions added approximately 19.5 MMboe to the Company's proved
reserves.

ACQUISITION PRO FORMA

The following unaudited pro forma information shows the effect on the
Company's consolidated results of operations as if the acquisition from BP
occurred on January 1, 2002. The pro forma information includes numerous
assumptions, and is not necessarily indicative of future results of operations:

(1) Pro forma shares assume the issuance of 19.8 million common shares as of
January 1, 2002.
- ---------------

Each transaction described above has been accounted for using the purchase
method of accounting and has been included in the consolidated financial
statements of Apache since the date of acquisition.

DIVESTITURES

During 2004, Apache sold marginal properties containing .5 MMboe of proved
reserves, for $4 million. Apache used the sales proceeds to reduce bank debt.

During 2003, Apache sold marginal properties containing 6.9 MMboe of proved
reserves, for $59 million. Apache used the sales proceeds to reduce bank debt.

During 2002, Apache sold marginal properties containing 1.8 MMboe of proved
reserves, for $7 million. Apache used the sales proceeds to reduce bank debt.

3. HEDGING AND DERIVATIVE INSTRUMENTS

Apache uses a variety of strategies to manage its exposure to fluctuations
in crude oil and natural gas commodity prices. As established by the Company's
hedging policy, Apache primarily enters into cash flow hedges in connection with
selected acquisitions to protect against commodity price volatility. The success
of these acquisitions is significantly influenced by Apache's ability to achieve
targeted production at forecasted prices. These hedges effectively reduce price
risk on a portion of the production from the acquisitions.

Apache entered into, and designated as cash flow hedges, various
fixed-price swaps, option collars and puts in conjunction with the Anadarko,
ExxonMobil, BP and certain South Louisiana property acquisitions. These
positions were entered into in accordance with the Company's hedging policy and
involved several

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

counterparties, all of which are rated A+ or better. As of December 31, 2004,
the outstanding positions of our natural gas and crude oil cash flow hedges were
as follows:

The natural gas and crude oil prices shown in the above table are based on
the NYMEX index and have been valued using actively quoted prices and quotes
obtained from the counterparties to the derivative agreements. The above prices
represent a weighted average of several contracts entered into and are on a per
MMBtu or per barrel basis for gas and oil derivatives, respectively.

Apache entered into a separate crude oil physical sales contract with BP in
February 2003, which ended December 31, 2004. Under the terms of the agreement,
Apache physically delivered 22.5 million barrels of crude oil at an average
fixed Brent index price of $23.38 per barrel. The contract was designated as a
normal purchase and sale under SFAS No. 133 and, therefore, the Company
accounted for the contract under the accrual method.

In November 2004, Apache began hedging a portion of its 2005 foreign
currency exchange risk associated with its forecasted Canadian, Australian and
North Sea lease operating expenditures by entering into forward purchase
contracts. The Company purchased a total of $144 million Canadian dollars at an
average exchange rate of .840, $22 million Australian dollars at an average
exchange rate of .763 and 42 million British pounds at an average exchange rate
of 1.853. The forward contracts mature from January through December 2005. The
fair market value of these contracts as of December 31, 2004 was $1.2 million
($700,000 after tax). Future changes in market value are recorded in other
comprehensive income (loss) and the fair values of the foreign exchange are
based on quotes from either third parties or published indices.

A reconciliation of the components of accumulated other comprehensive
income (loss) in the statement of consolidated shareholders' equity related to
Apache's commodity and foreign currency derivative activities is presented in
the table below:

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Differences between the fair values and the unrealized loss on derivatives
before income taxes recognized in accumulated other comprehensive income (loss)
are primarily related to premiums, recognition of unrealized gains and losses on
certain derivatives that did not qualify for hedge accounting and hedge
ineffectiveness. Based on applicable market prices as of year-end 2004, the
Company recorded an unrealized loss in other comprehensive income (loss) of $33
million ($21 million after tax), primarily representing oil and gas derivative
hedges. Any loss will be realized in future earnings contemporaneously with the
related sales of natural gas and crude oil production applicable to specific
hedges. Of the $33 million unrealized loss on derivatives at December 31, 2004,
approximately $4 million ($3 million after tax) applies to the next 12 months.
However, these amounts are likely to vary materially as a result of changes in
market conditions. The contracts designated as hedges qualified and continue to
qualify for hedge accounting in accordance with SFAS No. 133, as amended.

4. ASSET RETIREMENT OBLIGATION

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires that an asset retirement
obligation (ARO) associated with the retirement of a tangible long-lived asset
be recognized as a liability in the period in which a legal obligation is
incurred and becomes determinable, with an offsetting increase in the carrying
amount of the associated asset. The cost of the tangible asset, including the
initially recognized ARO, is depleted such that the cost of the ARO is
recognized over the useful life of the asset. The ARO is recorded at fair value,
and accretion expense is recognized over time as the discounted liability is
accreted to its expected settlement value. The fair value of the ARO is measured
using expected future cash outflows discounted at the company's credit-adjusted
risk-free interest rate.

The Company adopted SFAS No. 143 on January 1, 2003, and recorded an
increase to net oil and gas properties of $410 million and associated
liabilities of $369 million. These amounts reflect the ARO of the company had
the provisions of SFAS No. 143 been applied since inception and resulted in a
non-cash cumulative effect increase to earnings of $27 million ($41 million
pre-tax). In accordance with the provisions of SFAS No. 143, Apache records an
abandonment liability associated with its oil and gas wells and platforms when
those assets are placed in service, rather than its past practice of accruing
the expected undiscounted abandonment costs on a unit-of-production basis over
the productive life of the associated full-cost pool. Under SFAS No. 143,
depletion expense is reduced since a discounted ARO is depleted in the property
balance rather than the undiscounted value previously depleted under the old
rules. The lower depletion expense under SFAS No. 143 is offset, however, by
accretion expense, which is recognized over time as the discounted liability is
accreted to its expected settlement value.

Inherent in the fair value calculation of ARO are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance.

The $27 million ($41 million pre-tax) cumulative increase to earnings upon
adoption did not take into consideration potential impacts of adopting SFAS No.
143 on previous full-cost property impairment tests. The Company chose not to
re-calculate historical full-cost impairment tests (ceiling test) upon adoption
even though historical oil and gas property balances would have been higher had
the Company applied the provisions of the statement. Management believes this
approach is appropriate because SFAS No. 143 is silent on this issue and was not
effective during the prior ceiling test periods. Had the Company re-calculated
the historical full-cost ceiling tests and included the impact as a component of
the cumulative effect of adoption, the ultimate gain recognized would have
potentially been reduced. A ceiling test calculation was performed

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

upon adoption and at the end of each reporting period subsequent to adoption and
no impairment was necessary.

The following table is a reconciliation of the asset retirement obligation
liability since adoption:

Liabilities incurred as of 2004 and 2003 primarily relate to asset
retirement obligations assumed in connection with the Anadarko, ExxonMobil, BP
Gulf of Mexico, BP North Sea, and Shell property acquisitions. Liabilities
settled during the period relate to individual properties plugged and abandoned
or sold during the period. The downward revisions to the estimated liability
resulted from annual reassessments of the expected cash outflows and assumptions
inherent in the ARO calculation.

The pro forma effect of the implementation on the Company's Income
Attributable to Common Stock and Net Income per Common Share had SFAS No. 143
been adopted by the Company on January 1, 2002 would not have been material.

5. DEBT

Long-Term Debt

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Apache currently has $1.5 billion of syndicated bank credit facilities.
These credit facilities consist of four separate committed bank facilities: a
new $750 million five-year facility in the U.S. that matures on May 28, 2009; a
$450 million facility in the U.S. that matures June 3, 2007; a $150 million
facility in Australia that matures June 3, 2007 and a $150 million facility in
Canada that matures June 3, 2007.

On May 28, 2004, the Company's $750 million 364-day U.S. credit facility
matured and was replaced with the new $750 million five-year facility noted
above. Also on this date, the Company amended its existing $450 million facility
and its two existing $150 million facilities in order to make their terms
consistent with the new five-year facility. Significant changes included raising
the cross-default threshold, increasing flexibility under the negative lien
covenant and eliminating covenants which established minimum levels for tangible
net worth and book values for assets of Apache and certain subsidiaries.

The financial covenants of the credit facilities require the Company to
maintain a debt-to-capitalization ratio of not greater than 60 percent at the
end of any fiscal quarter. The negative covenants include restrictions on the
Company's ability to create liens and security interests on our assets, with
exceptions for liens typically arising in the oil and gas industry, purchase
money liens and liens arising as a matter of law, such as tax and mechanics
liens. The Company may incur liens on assets located in the U.S., Canada and
Australia of up to five percent of the Company's consolidated assets, which
approximated $775 million as of December 31, 2004. There are no restrictions on
incurring liens in countries other than the U.S., Canada and Australia. There
are also restrictions on Apache's ability to merge with another entity, unless
the Company is the surviving entity, and a restriction on our ability to
guarantee debt of entities not within our consolidated group.

There are no clauses in the facilities that permit the lenders to
accelerate payments or refuse to lend based on unspecified material adverse
changes (MAC clauses). The credit facility agreements do not have drawdown
restrictions or prepayment obligations in the event of a decline in credit
ratings. However, the agreements allow the lenders to accelerate payments and
terminate lending commitments if Apache corporation, or any of its U.S.,
Canadian and Australian subsidiaries, defaults on any direct payment obligation
in excess of $100 million or has any unpaid, non-appealable judgment against it
in excess of $100 million. The Company was in compliance with the terms of the
credit facilities as of December 31, 2004. The Company's debt-to-capitalization
ratio as of December 31, 2004 was 24 percent.

At the Company's option, the interest rate for the facilities is based on
(i) the greater of (a) The JP Morgan Chase Bank prime rate or (b) the federal
funds rate plus one-half of one percent or (ii) the London Interbank Offered
Rate (LIBOR) plus a margin determined by the Company's senior long-term debt
rating. The $750 million and the $450 million credit facilities (U.S. credit
facilities) also allow the Company to borrow under competitive auctions.

At December 31, 2004, the margin over LIBOR for committed loans was .27
percent on the $750 million facility and .30 percent on the other three
facilities. If the total amount of the loans borrowed under the $750 million
facility equals or exceeds 50 percent of the total facility commitments, then an
additional .10 percent will be added to the margins over LIBOR. If the total
amount of the loans borrowed under all of the other three facilities equals or
exceeds 33 percent of the total facility commitments, then an additional .125
percent will be added to the margins over LIBOR. The Company also pays quarterly
facility fees of .08 percent on the total amount of the $750 million facility
and .10 percent on the total amount of the other three facilities. The facility
fees vary based upon the Company's senior long-term debt rating. The U.S. credit
facilities are used to support Apache's commercial paper program. The available
borrowing capacity under the credit facilities at December 31, 2004 was $1.1
billion.

At December 31, 2004, the Company also had certain uncommitted money market
lines of credit which are used from time to time for working capital purposes,
under which an aggregate of $4 million was outstanding as of December 31, 2004.
Such borrowings are classified as long-term debt in the accompanying

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

consolidated balance sheet as the Company has the ability and intent to
refinance such amounts on a long-term basis through available borrowing capacity
under its U.S. credit facilities.

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances at December 31, 2004 and 2003 were classified as
long-term debt in the accompanying consolidated balance sheet as the Company has
the ability and intent to refinance such amounts on a long-term basis through
either the rollover of commercial paper or available borrowing capacity under
the U.S. credit facilities. The weighted-average interest rate for commercial
paper was 1.79 percent in 2004 and 1.19 percent in 2003.

On May 15, 2003, Apache Finance Canada Corporation (Apache Finance Canada)
issued $350 million of 4.375 percent, 12-year, senior unsecured notes in a
private placement. On March 4, 2004, the Company completed an exchange offer
with the holders of the notes, issuing publicly traded, registered notes of the
same principal amount and with the same interest rates, payment terms and
maturity. The notes are irrevocably and unconditionally guaranteed by Apache and
are redeemable, as a whole or in part, at Apache Finance Canada's option,
subject to a make-whole premium. Interest is payable semi-annually on May 15 and
November 15 of each year commencing on November 15, 2003. The proceeds of the
original note offering were used to reduce bank debt and outstanding commercial
paper and for general corporate purposes.

The Company does not have the right to redeem any of its notes or
debentures (other than the Apache Corporation 6.25-percent notes due April 15,
2012, the Apache Finance Australia 6.5-percent notes due 2007 and the Apache
Finance Canada 4.375-percent notes due 2015) prior to maturity. Under certain
conditions, the Company has the right to advance maturity on the 7.7-percent
notes, 7.95-percent notes, 7.375-percent debentures and 7.625-percent
debentures.

The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and
Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache
and, in the case of Apache Finance Australia, by Apache North America, Inc., an
indirect wholly-owned subsidiary of the Company. Under certain conditions
related to changes in relevant tax laws, Apache Finance Australia and Apache
Finance Canada have the right to redeem the notes prior to maturity. The Apache
Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent
notes may be redeemed at the Company's option subject to a make-whole premium
(see Note 16. Supplemental Guarantor Information).

The $13 million of discounts on the Company's debt as of December 31, 2004,
is being amortized over the life of the debt issuances as additional interest
expense.

As of December 31, 2004 and 2003, the Company had approximately $21 million
and $22 million, respectively, of unamortized deferred loan costs associated
with its various debt obligations. These costs are included in deferred charges
and other in the accompanying consolidated balance sheet and are being amortized
to expense over the life of the related debt.

The indentures for the notes described above place certain restrictions on
the Company, including limits on Apache's ability to incur debt secured by
certain liens and its ability to enter into certain sale and leaseback
transactions. Upon certain change in control, all of these debt instruments
would be subject to mandatory repurchase, at the option of the holders.

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Aggregate Maturities of Debt

The Company made cash payments for interest, net of amounts capitalized, of
$107 million, $96 million and $99 million for the years ended December 31, 2004,
2003 and 2002, respectively.

6. INCOME TAXES

Income before income taxes is composed of the following:

The total provision for income taxes consists of the following:

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of the U.S. federal statutory income tax amounts to the
effective amounts is shown below:

The net deferred tax liability is comprised of the following:

The Company has not recorded deferred income taxes on the undistributed
earnings of its foreign subsidiaries as management intends to permanently
reinvest such earnings. As of December 31, 2004, the undistributed earnings of
the foreign subsidiaries amounted to approximately $4.7 billion. Upon
distribution of these earnings in the form of dividends or otherwise, the
Company may be subject to U.S. income taxes and foreign withholding taxes. It is
not practical, however, to estimate the amount of taxes that may be payable on
the eventual remittance of these earnings after consideration of available
foreign tax credits. Presently, limited foreign tax credits are available to
reduce the U.S. taxes on such amounts if repatriated. Refer to Note 1, Summary
of Significant Accounting Policies, "Impact of Recently Issued Accounting
Standards" for a discussion of the potential impact on repatriated earnings
resulting from the American Jobs Creation Act of 2004.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2004, the Company had state net operating loss
carryforwards of $198 million and foreign net operating loss carryforwards of
$14 million for China and $553 million for the United Kingdom. The state net
operating losses will expire over the next 20 years, if they are not otherwise
utilized. The foreign net operating loss for China has a five-year carryover
period while the United Kingdom loss has an unlimited carryover period.

The Company is currently under examination by the Internal Revenue Service
for income tax years 2002 and 2003. The Company believes that it has adequately
provided for income taxes.

The Company made payments for income and other taxes, net of refunds, of
$466 million, $309 million and $171 million for the years ended December 31,
2004, 2003 and 2002, respectively.

7. ADVANCES FROM GAS PURCHASERS

In July 1998, Apache received $72 million from a purchaser as an advance
payment for future natural gas deliveries ranging from 6,726 MMBtu per day to
24,669 MMBtu per day, for a total of 45,330,949 MMBtu, over a ten-year period
commencing August 1998. In addition, the purchaser pays Apache a monthly fee of
$.08 per MMBtu on the contracted volumes. Concurrent with this arrangement,
Apache entered into three gas price swap contracts with a third party under
which Apache became a fixed price payor for identical volumes at prices ranging
from $2.34 per MMBtu to $2.56 per MMBtu. The net result of these related
transactions was that gas delivered to the purchaser was reported as revenue at
prevailing spot prices with Apache realizing a premium associated with the
monthly fee paid by the purchaser.

In August 1997, Apache received $115 million from a purchaser as an advance
payment for future natural gas deliveries of 20,000 MMBtu per day over a
ten-year period commencing September 1997. In addition, the purchaser pays
Apache a monthly fee of $.07 per MMBtu on the contracted volumes. Concurrent
with this arrangement, Apache entered into two gas price swap contracts with a
third party under which Apache became a fixed price payor for identical volumes
at average prices starting at $2.19 per MMBtu in 1997 and escalating to $2.59
per MMBtu in 2007. The net result of these related transactions was that gas
delivered to the purchaser was reported as revenue at prevailing spot prices
with Apache realizing a premium associated with the monthly fee paid by the
purchaser.

Contracted volumes relating to these arrangements are included in the
Company's unaudited supplemental oil and gas disclosures.

These advance payments have been classified as advances from gas purchasers
and are being recognized in oil and gas production revenues as gas is delivered
to the purchasers under the terms of the contracts. On December 31, 2004 and
2003, advances of $91 and $109 million, respectively, were outstanding. Gas
volumes delivered to the purchaser are reported as revenue at prices used to
calculate the amount advanced, before imputed interest, plus or minus amounts
paid or received by Apache applicable to the price swap agreements. Interest
expense is recorded based on a rate of eight percent.

In October and November 2001, Apache terminated the gas price swap
contracts associated with these advances and received proceeds of $78 million.
The effect of terminating these derivative instruments reduces future price risk
exposure to natural gas price volatility by establishing a fixed price for the
remaining quantities of gas to be delivered under the terms of the contracts.
Upon termination, Apache designated the remaining contractual volumes of gas
that will be delivered to the purchasers as a normal fixed-price physical sale.
The prices used in settling the derivatives represented an average 51 percent
increase over the prices reflected in the original contracts. No gain or loss
was recognized upon termination of the gas swap contract. The settlement is
carried as advances from gas purchases on the consolidated balance sheet and
will be recognized in monthly sales based on the portion of the proceeds
applicable to each production month over the remaining life of the contracts.

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. CAPITAL STOCK

Common Stock Outstanding

(1) In May 2002, we completed the mandatory conversion of our Series C preferred
stock into approximately 13.1 million common shares.

(2) On January 22, 2003, in conjunction with the BP transaction, we completed a
public offering of 19.8 million shares of common stock, including 2.6
million shares for the underwriters' over-allotment option, raising net
proceeds of $554 million.

(3) On December 18, 2003, the Company announced that holders of its common stock
approved a proposal to increase the number of authorized common shares to
430 million from 215 million in order to complete a previously announced
two-for-one stock split. The record date for the stock split was December
31, 2003 and the additional shares were distributed on January 14, 2004.

NET INCOME PER COMMON SHARE

A reconciliation of the components of basic and diluted net income per
common share for the years ended December 31, 2004, 2003 and 2002 is presented
in the table below:

During 2002, Apache began modifying its stock compensation plans in order
to reflect the cost of these plans in the Statement of Consolidated Operations.
As part of this effort, Apache began issuing stock appreciation rights and
restricted stock and, effective January 1, 2003, adopted the expense provisions
of SFAS No. 123, as amended, on a prospective basis for all stock options
granted under the Company's existing option plans. Consistent with the Company's
desire to expense stock compensation plans, Apache early adopted the provisions
of SFAS 123-R upon the FASBs issuance of the revision in the fourth quarter of
2004. See Note 1, Summary of Significant Accounting Policies.

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK DIVIDENDS

On December 18, 2002, the Company's Board of Directors declared a five
percent stock dividend payable on April 2, 2003 to shareholders of record on
March 12, 2003. As a result, in December 2002, the Company reclassified
approximately $396 million from retained earnings to common stock and paid-in
capital, which represents the fair market value at the date of declaration of
the shares distributed. Since the Company's January 22, 2003 public offering of
19.8 million shares of common stock occurred prior to the record date, an
additional $26 million was reclassified from retained earnings to common stock
and paid-in capital. No fractional shares were issued and cash payments totaling
$1 million were made in lieu of fractional shares.

TWO-FOR-ONE STOCK SPLIT

On December 18, 2003, the Company announced that holders of its common
stock approved an increase in the number of authorized common shares to 430
million from 215 million in order to complete a previously announced two-for-one
stock split. The record date for the stock split was December 31, 2003 and the
additional shares were distributed on January 14, 2004.

STOCK OPTION PLANS

On December 31, 2004, officers and employees have options to purchase
shares of the Company's common stock under one or more employee stock option
plans adopted in 1995, 1998 and 2000 (collectively, the Stock Option Plans).
Under the Stock Option Plans, the exercise price of each option equals the
market price of Apache's common stock on the date of grant. Options generally
become exercisable ratably over a four-year period and expire after 10 years.

The 2000 Stock Option Plan also permits the Company to issue options with a
reload provision, which has been included in certain options granted to officers
and certain key employees of the Company. Options with reload provisions vest
over two years, in equal installments every six months. The reload provision
permits the granting of new options for shares with a current market value equal
to any portion of the original option exercise price, or withholding taxes due
on the exercise of the original option, paid by the optionee by means of the
transfer or attestation of ownership of shares of the Company's common stock or
units in the Company's Deferred Delivery Plan (if the income from the exercise
is to be deferred into that plan). The Deferred Delivery Plan allows the
executive officers and certain key employees of the Company to defer the receipt
of income from equity compensation plans such as the Company's Stock Option
Plans. The new option granted as a reload vests after six months, expiring on
the same date as the original option.

1996 PERFORMANCE STOCK OPTION PLAN

On October 31, 1996, the Company established the 1996 Performance Stock
Option Plan (the Performance Plan) for substantially all full-time employees,
excluding officers and certain key employees. Under the Performance Plan, the
exercise price of each option equals the market price of Apache common stock on
the date of grant. All options become exercisable after nine and one-half years
and expire 10 years from the date of grant. Under the terms of the Performance
Plan, no grants were made after December 31, 1998.

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A summary of the status of the plans described above as of December 31,
2004, 2003 and 2002, and changes during the years then ended, is presented in
the table and narrative below (shares in thousands):

(1) The fair value of each option is estimated as of the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants in 2004, 2003 and 2002, respectively: (i)
risk-free interest rates of 3.65, 2.86 and 4.87 percent; (ii) expected lives
of 4.5 years for 2004, 2003 and 2002 for the Stock Option Plans; (iii)
historical volatility of 36.09, 36.60 and 37.17 percent; and (iv) expected
dividend yields of .55, .66 and .68 percent.

(2) As of February 10, 2005, the Company's authority to issue option grants
under its existing Stock Option Plans terminated. At the time of
termination, 2,537,877 shares of the Company's common stock that were
previously authorized for new grants became unavailable for such purpose.
The only provisions of these plans that are still effective are those
governing grants previously made under the applicable plan.

(3) As of December 31, 2004, the remaining contractual life for options
outstanding and exercisable is 4.9 years and 5.0 years, respectively.

The following table summarizes information about stock options covered by
the plans described above that are outstanding as of December 31, 2004 (shares
in thousands):

The Company expensed $8 million ($5 million after-tax), $1 million and $1
million for 2004, 2003 and 2002, respectively, for the stock option plans
described above. In 2004, $4 million of the compensation cost was capitalized as
part of oil and gas properties. The intrinsic value of options exercised during
2004 was approximately $46 million and the Company realized an additional tax
benefit of approximately $14 million

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for the amount of intrinsic value in excess of compensation cost recognized. The
aggregate intrinsic value of options outstanding and exercisable at year-end was
$215 million and $128 million, respectively.

STOCK APPRECIATION RIGHTS

During 2003, the Company began issuing stock appreciation rights (SARs) to
non-executive employees in lieu of stock options. A total of 1,328,400 and
1,802,210 SARs were issued during 2004 and 2003, respectively, and will be
settled in cash upon exercise throughout the SARs 10-year life. The
weighted-average exercise price of the SARs is $42.68 and $28.78 for those
issued in 2004 and 2003, respectively. The vesting period is over four years and
the Company records compensation expense on the vested SARs outstanding based on
the fair value of the SARs at the end of each period. As of year-end, the
weighted-average fair value of SARs outstanding was $23.37 based on the
Black-Scholes valuation methodology. The number of SARs outstanding was
2,787,323, of which 314,525 were exercisable.

In 2004 and 2003, the Company recorded expenses related to SARs issued, of
$16.7 million ($10.4 million after tax) and $4 million ($2 million after tax),
respectively. During 2004, 109,000 SARs were exercised and approximately 167,000
were forfeited. No material cash payments were made to settle SARs that were
exercised.

RESTRICTED STOCK

In May 2002, Apache's Board of Directors approved an executive restricted
stock plan for all executive officers and certain key employees in lieu of stock
options. The Company awarded 87,500, 121,000 and 229,950 restricted shares at a
market price of $42.68, $28.78 and $27.82 in 2004, 2003 and 2002, respectively.
The value of the stock issued was established by the market price on the date of
grant and will be recorded as compensation expense ratably over the four-year
vesting terms. During 2004, 2003 and 2002, $2.8 million, $2 million and $538
thousand, respectively, was charged to expense. As of December 31, 2004, there
was $7 million of total unrecognized compensation cost related to approximately
269,000 unvested shares. There were no material forfeitures or shares vesting
during the year, and the weighted-average remaining life is 2.4 years.

In December 1998, the Company entered into a conditional stock grant
agreement with an executive of the Company which would award up to 230,992
shares of the Company's common stock in five annual installments. Each
installment has a five-year vesting period, 40 percent of the conditional grants
will be paid in cash at the market value of the stock on the date of payment and
the balance (138,594 shares) will be issued in Apache common stock. In 2001, the
Company modified the conditional stock grant agreement to allow for immediate
vesting upon a change in control of ownership. This modification did not require
recognition of any compensation expense.

SHARE APPRECIATION PLAN

In October 2000, the Company adopted the Share Appreciation Plan under
which grants were made to substantially all full-time employees, including
officers. The Share Appreciation Plan provided for issuance of up to an
aggregate of 8.08 million shares of Apache common stock, based on attainment of
one or more of three share price goals (Share Price Goals) and/or a separate
production goal (Production Goal). Generally, shares are issued in three
installments over 24 months after achievement of each goal. The shares of Apache
common stock contingently issuable under the Share Appreciation Plan were
excluded from the computation of income per common share until the stated goals
were met as described below.

The Share Price Goals were based on achieving a closing price of $43.29,
$51.95 and $77.92 per share on any 10 days out of any 30 consecutive trading
days prior to January 1, 2005. Apache's share price exceeded the first threshold
($43.29) under this plan on April 28, 2004. As such, the Company will issue
approximately

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

900,000 shares of its common stock, after minimum tax withholding requirements,
which will be distributed 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. The
third share-price threshold ($77.92) did not trigger and the related shares were
cancelled as of December 31, 2004. A summary of the number of shares
contingently issued under the Share Price Goals as of December 31, 2004, 2003
and 2002 is presented in the table below:

(1) The outstanding shares at the end of 2004 represent those shares remaining
to be issued in 2005 and 2006 as a result of attainment of the $43.29 and
$51.95 per share price goals. These outstanding shares will be issued net of
minimum tax withholding as employees fulfill the two-year service period
requirement. The outstanding shares shown at the end of 2003 and 2002
represent shares that would have been issued, had the $43.29, $51.95 and
$77.92 been attained, 1,370,624 shares, 3,431,250 shares and 1,522,818
shares, respectively for 2003, and 1,351,792 shares, 3,381,050 shares and
1,501,398 shares, respectively for 2002.

(2) The fair value of each Share Price Goal conditional grant is estimated as of
the date of grant using a Monte Carlo simulation with the following
weighted-average assumptions used for grants in 2004, 2003 and 2002,
respectively: (i) risk-free interest rate of 3.04, 2.77 and 2.90 percent;
(ii) expected volatility of 35.97, 36.69 and 38.77 percent; and (iii)
expected dividend yield of .96, .70 and .70 percent.
- ---------------

Timing of expense recognition under the 2000 Share Appreciation Plan was
based on the accounting policies in place for each year the plan was outstanding
and vesting (See Note 1, Summary of Significant Accounting Policies). The shares
were initially granted in 2000 and were not expensed under APB Opinion No. 25.
In 2004, Apache adopted SFAS 123-R retrospectively, to January 1, 2004, and
expensed stock based compensation vesting during the year. Under SFAS No. 123-R
expense amounts are determined based on the fair value of the plan on the date
of grant and for 2004, the Company recorded $13.1 million ($8.2 million
after-tax) of expense, net of capitalized amounts for this plan of $6.5 million.
Additional expense will be recorded in 2005 and 2006 as the initial service
period is completed.

The Production Goal would have been attained if and when the Company's
average daily production equaled or exceeded .67 barrels of oil equivalent per
diluted share (calculated on an annualized basis) during any fiscal quarter
ending before January 1, 2005. This level of production was approximately twice
the Company's level of production at the time the Share Appreciation Plan was
adopted. The Production Goal was not obtained prior to January 1, 2005 and,
therefore, no shares will be issued under that goal.

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 of $81 to be achieved by the end of 2007.

Preferred Stock

The Company has five million shares of no par preferred stock authorized,
of which 25,000 shares have been designated as Series A Junior Participating
Preferred Stock (the Series A Preferred Stock), 100,000 shares have been
designated as the 5.68 percent Series B Cumulative Preferred Stock (the Series B
Preferred Stock) and, from May 13, 1999 until December 16, 2003, 140,000 shares
were designated as Series C Preferred Stock. The shares of Series A Preferred
Stock are authorized for issuance pursuant to certain rights that trade with
Apache common stock outstanding and are reserved for issuance upon the exercise
of the Rights as defined and discussed below.

RIGHTS TO PURCHASE SERIES A PREFERRED STOCK

In December 1995, the Company declared a dividend of one right (a Right)
for each 2.31 shares (adjusted for the 10 percent and five percent stock
dividends and the two-for-one stock split) of Apache common stock outstanding on
January 31, 1996. Each full Right entitles the registered holder to purchase
from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred
Stock at a price of $100 per one ten-thousandth of a share, subject to
adjustment. The Rights are exercisable 10 calendar days following a public
announcement that certain persons or groups have acquired 20 percent or more of
the outstanding shares of Apache common stock or 10 business days following
commencement of an offer for 30 percent or more of the outstanding shares of
Apache common stock. In addition, if a person or group becomes the beneficial
owner of 20 percent or more of Apache's outstanding common stock (flip in
event), each Right will become exercisable for shares of Apache's common stock
at 50 percent of the then market price of the common stock. If a 20 percent
shareholder of Apache acquires Apache, by merger or otherwise, in a transaction
where Apache does not survive or in which Apache's common stock is changed or
exchanged (flip over event), the Rights become exercisable for shares of the
common stock of the company acquiring Apache at 50 percent of the then market
price for Apache common stock. Any Rights that are or were beneficially owned by
a person who has acquired 20 percent or more of the outstanding shares of Apache
common stock and who engages in certain transactions or realizes the benefits of
certain transactions with the Company will become void. If an offer to acquire
all of the Company's outstanding shares of common stock is determined to be fair
by Apache's Board of Directors, the transaction will not trigger a flip in event
or a flip over event. The Company may also redeem the Rights at $.01 per Right
at any time until 10 business days after public announcement of a flip in event.
The Rights will expire on January 31, 2006, unless earlier redeemed by the
Company. Unless the Rights have been previously redeemed, all shares of Apache
common stock issued by the Company after January 31, 1996 will include Rights.
Unless and until the Rights become exercisable, they will be transferred with
and only with the shares of Apache common stock.

SERIES B PREFERRED STOCK

In August 1998, Apache issued 100,000 shares ($100 million) of Series B
Preferred Stock in the form of one million depositary shares, each representing
one-tenth (1/10) of a share of Series B Preferred Stock, for net proceeds of $98
million. The Series B Preferred Stock has no stated maturity, is not subject to
a sinking fund and is not convertible into Apache common stock or any other
securities of the Company. Apache has the option to redeem the Series B
Preferred Stock at $1,000 per preferred share on or after August 25, 2008.
Holders of the shares are entitled to receive cumulative cash dividends at an
annual rate of $5.68 per depositary share when, and if, declared by Apache's
board of directors.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SERIES C PREFERRED STOCK

In May 1999, Apache issued 140,000 shares ($217 million) of Series C
Preferred Stock in the form of seven million depositary shares each representing
one-fiftieth (1/50) of a share of Series C Preferred Stock, for net proceeds of
$211 million. Holders of the shares were entitled to receive cumulative cash
dividends at an annual rate of 6.5 percent, or $2.015 per depositary share when,
and if, declared by Apache's board of directors.

In 2000, Apache bought back 75,900 depositary shares at an average price of
$34.42 per share. The excess of the purchase price to reacquire the depositary
shares over the original issuance price is reflected as a preferred stock
dividend. The remaining depositary shares converted into 13,109,730 shares of
Apache common stock in 2002.

COMPREHENSIVE INCOME

Components of accumulated other comprehensive income (loss) consist of the
following:

9. FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 2004 and 2003. See Note
3, Hedging and Derivative Instruments for a discussion of the Company's
derivative instruments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair value of the notes and debentures is based upon an estimate
provided to the Company by an independent investment banking firm. The carrying
amount of the commercial paper and money market lines of credit approximated
fair value because the interest rates are variable and reflective of market
rates. The Company's trade receivables and trade payables are by their very
nature short-term. The carrying values included in the accompanying consolidated
balance sheet approximate fair value at December 31, 2004 and December 31, 2003.

10. COMMITMENTS AND CONTINGENCIES

LITIGATION

TEXACO CHINA B.V.

Apache recorded a reserve in the second quarter of 2004 to fully reflect a
pre-tax $71 million international arbitration award to Texaco China B.V. (Texaco
China). The arbitration specifies that the award is subject to interest at nine
percent. Apache accrued $3 million of interest expense in 2004. In September
2001, Texaco China initiated an arbitration proceeding against Apache China
Corporation LDC (Apache China), later adding Apache Bohai Corporation LDC
(Apache Bohai) to the arbitration. In the arbitration Texaco China claimed
damages, plus interest, arising from Apache Bohai's alleged failure to drill
three wells, prior to re-assignment of the interest to Texaco China. Apache
believes that the finding of the arbitrator is unsupported by the facts and the
law, and Apache has filed and is pursuing an application to vacate the award in
federal court. Texaco China has filed an application to confirm the award in the
same court. In January 2005, while awaiting the decision of the U.S. federal
courts, Texaco China also filed a proceeding against Apache China and Apache
Bohai in the People's Republic of China to recognize the arbitral award,
apparently seeking the same relief as sought in U.S. federal court. Apache China
has been served. Apache Bohai has not been served. In February 2005, a federal
magistrate appointed to hear the case has made a recommendation to the federal
court that the arbitration award should be confirmed, as requested by Texaco
China. If the court enters a judgment against Apache China based on the
magistrate's recommendation, the Company plans to appeal the judgment to the
circuit court of appeals.

PREDATOR

In December 2000, certain subsidiaries of the Company and Murphy Oil
Corporation (Murphy) filed a lawsuit in Canada charging The Predator Corporation
Ltd. (Predator) and others with misappropriation and misuse of confidential well
data to obtain acreage offsetting a significant natural gas discovery made by
Apache and Murphy during 2000 in the Ladyfern area of northeast British
Columbia. In February 2001, Predator filed a counterclaim seeking more than C$6
billion and later reduced this amount to no more than C$4 billion. In September
2004, the court in Canada that is hearing this counterclaim granted Apache
Canada's motion for summary judgment and dismissed more than C$3 billion of
Predator's claims against the Company and Murphy, and dismissed all claims
against both Murphy's president and Apache Canada's president. Predator has
appealed the dismissal. Only Predator's claims against Murphy and Apache Canada
for mismanaging operations survive in the trial court at this time. Those claims
total approximately C$365 million, plus interest and attorneys' fees. While
management believes that Predator's claim against Apache Canada is without
merit, an adverse judgment is possible. Exposure related to this lawsuit is not
currently determinable. Apache and Murphy's claims against Predator, filed in
December 2000, are still pending.

GRYNBERG

In 1997, Jack Grynberg began filing lawsuits against other natural gas
producers, gatherers, and pipelines claiming that the defendants have under paid
royalty to the federal government and Indian tribes by mis-measurement of the
volume and heating content of natural gas and are responsible for acts of others
who mis-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

measured natural gas. In 2004, Grynberg filed suit against Apache making the
same claims he had made previously against others in the industry. With the
addition of Apache, there are more than 300 defendants to these actions. Other
plaintiffs have made or may be expected to make similar claims. Although
Grynberg purports to be acting on behalf of the government, the federal
government has declined to join in the cases. While an adverse judgment against
Apache is possible, Apache does not believe the plaintiff's claims have merit
and plans to vigorously pursue its defenses against these claims. Exposure
related to this lawsuit is not currently determinable.

EGYPT TAX AUTHORITY

The Egyptian Tax Authority (ETA) has issued claims for back taxes against
various Apache subsidiaries in Egypt totaling $106 million (at current exchange
rates) relating to periods as far back as 1994. While an adverse judgment
against Apache is possible, Egyptian Concession agreements clearly provide that
the Egyptian General Petroleum Corporation is responsible for the payment of all
taxes related to the operation of the concessions. Apache believes that the
claims of the ETA are unsupported by either the facts or the language of the
concession agreements, which have the force of law in Egypt. Apache's
subsidiaries have, therefore, contested liability with respect to these claims
by filing actions in Egyptian civil court. Apache plans to vigorously pursue its
remedies with respect to these claims. A civil court ruling with respect to the
claims is expected sometime in the second quarter of 2005.

LOUISIANA RESTORATION

Numerous surface owners have filed claims or sent demand letters to various
oil and gas companies, including Apache, claiming that, under either expressed
or implied lease terms or Louisiana law, they are liable for damage measured by
the cost of restoration of leased premises to their original condition. Any
exposure related to these lawsuits and claims is not currently determinable.
While an adverse judgment against Apache is possible, Apache has denied
liability and intends to actively defend the cases.

GENERAL

The Company is involved in other litigation and is subject to governmental
and regulatory controls arising in the ordinary course of business. The Company
has an accrued liability of approximately $10 million for other legal
contingencies that are probable of occurring and can be reasonably estimated. It
is management's opinion that the loss for any such other litigation matters and
claims that are reasonably possible to occur will not have a material adverse
affect on the Company's financial position or results of operations.

OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

The Company, as an owner or lessee and operator of oil and gas properties,
is 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 oil and gas lease for the cost of pollution
clean-up resulting from operations and subject the lessee to liability for
pollution damages. In some instances, the Company may be directed to suspend or
cease operations in the affected area. We maintain insurance coverage, which we
believe is customary in the industry, although we are not fully insured against
all environmental risks.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

any potential liability is determined by considering, among other matters,
incremental direct costs of any likely remediation and the proportionate cost of
employees who are expected to devote a significant amount of time directly to
any possible remediation effort. As it relates to evaluations of purchased
properties, depending on the extent of an identified environmental problem, the
Company may exclude a property from the acquisition, require the seller to
remediate the property to Apache's satisfaction, or agree to assume liability
for the remediation of the property. The Company's general policy is to limit
any reserve additions to any incidents or sites that are considered probable to
result in an expected remediation cost exceeding $100,000. Any environmental
costs and liabilities that are not reserved for are treated as an expense when
actually incurred. In our estimation, neither these expenses nor expenses
related to training and compliance programs, are likely to have a material
impact on our financial condition. As of December 31, 2004, the Company had an
undiscounted reserve for environmental remediation of approximately $11 million.
Apache is not aware of any environmental claims existing as of December 31,
2004, which have not been provided for or would otherwise have a material impact
on its financial position or results of operations. There can be no assurance,
however, that current regulatory requirements will not change, or past
non-compliance with environmental laws will not be discovered on the Company's
properties.

INTERNATIONAL LEASE CONCESSIONS

The Company, through its subsidiaries, has acquired or has been
conditionally or unconditionally granted exploration rights in Australia, Egypt,
China and the North Sea. In order to comply with the contracts and agreements
granting these rights, the Company, through various wholly-owned subsidiaries,
is committed to expend approximately $180 million through 2009.

OPERATING LEASE AND OTHER COMMITMENTS

The Company has leases for buildings, facilities and equipment with varying
expiration dates through 2013. Net rental expense was $17 million for 2004 and
2003, and $16 million for 2002.

As of December 31, 2004, minimum rental commitments under long-term
operating leases, net of sublease rental income, drilling rigs and long-term
pipeline transportation commitments, ranging from one to 19 years, are as
follows:

RETIREMENT AND DEFERRED COMPENSATION PLANS

The Company provides a 401(k) savings plan for employees which allows
participating employees to elect to contribute up to 25 percent of their
salaries, with Apache making matching contributions up to a maximum of six
percent of each employee's salary. In addition, the Company annually contributes
six percent of each participating employee's compensation, as defined, to a
money purchase retirement plan. The 401(k)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

plan and the money purchase retirement plan are subject to certain
annually-adjusted, government-mandated restrictions which limit the amount of
each employee's contributions.

For certain eligible employees, the Company also provides a non-qualified
retirement/savings plan which allows the deferral of up to 50 percent of each
employee's salary, and which accepts employee contributions and the Company's
matching contributions in excess of the above-referenced restrictions on the
401(k) savings plan and money purchase retirement plan. Additionally, Apache
Energy Limited, Apache Canada Ltd. and Apache North Sea Limited maintain
separate retirement plans, as required under the laws of Australia, Canada and
the United Kingdom, respectively.

Vesting in the Company's contributions to the 401(k) savings plan, the
money purchase retirement plan and the non-qualified retirement/savings plan
occurs at the rate of 20 percent per year. Upon a change in control of
ownership, vesting is immediate. Total costs under all plans were $31 million,
$25 million and $18 million for 2004, 2003 and 2002, respectively.

Effective July 1, 2003, as part of the BP North Sea acquisition, Apache
assumed a funded noncontributory defined benefit pension plan (U.K. Pension
Plan) covering existing BP North Sea employees hired by the Company as part of
the acquisition. Contributions made by Apache to BP's plan were immaterial prior
to Apache's plan becoming effective. The pension plan provides defined benefits
based on years of service and final average salary. The plan is closed to newly
hired employees.

Apache also has a postretirement benefit plan covering substantially all of
its U.S. employees. The postretirement benefit plan provides for medical
benefits up until the age of 65. The plan is contributory with participants'
contributions adjusted annually. The postretirement benefit plan does not pay
benefits once participants become eligible for Medicare and is not affected by
the Medicare Modernization Act of 2003.

The following tables set forth the benefit obligation, fair value of plan
assets and funded status as of December 31, 2004 and 2003 and the underlying
weighted average actuarial assumptions used for the U.K. Pension Plan and U.S.
postretirement benefit plan. Apache uses a measurement date of December 31 for
its pension and postretirement benefit plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2004 and 2003, the accumulated benefit obligation for
the pension plan was $65 million and $47 million, respectively.

Apache's defined benefit pension plan assets are held by a non-related
Trustee who has been instructed to invest the assets in an equal blend of equity
securities and low-risk debt securities. The Company believes this blend of
investments will provide a reasonable rate of return and ensure that the
benefits promised to members are provided. The plan's assets do not include any
equity or debt securities of Apache. A breakout of previous allocations for plan
asset holdings and the target allocation for the Company's plan assets are
summarized below.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables set forth the components of the net periodic cost and
the underlying weighted average actuarial assumptions used for the pension and
postretirement benefit plans for the 12-month and 6-month periods ended December
31, 2004 and 2003, respectively.

Assumed health care cost trend rates affect amounts reported for
postretirement benefits. A one-percentage-point change in assumed health care
cost trend rates would have the following effects:

Apache expects to contribute $5 million to its pension plan and $318,000 to
its postretirement benefit plan in 2005. The following benefit payments, which
reflect expected future service, as appropriate, are expected to be paid:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. PREFERRED INTERESTS OF SUBSIDIARIES

In August 2001, Apache entered into a series of financing transactions,
described below, to pay down existing debt and increase financial flexibility.

Apache contributed interests in various fields valued at $923 million to
new subsidiaries in connection with the financing transactions. Additionally,
Apache contributed $116 million in U.S. Government Agency Notes. Unrelated
institutional investors contributed $443 million ($441 million, net of issuance
costs) to the various subsidiaries in exchange for preferred stock ($82 million)
of the subsidiaries and a limited partner interest ($361 million) in one of the
entities. The third party investors were entitled to receive a weighted average
return of 123 basis points above the prevailing LIBOR interest rate. The
preferred stock and limited partner interests were repayable from the assets of
the subsidiaries. Apache retained credit risks related to collection of proceeds
from product sales and intercompany loans. Apache also had an obligation to
contribute an aggregate amount not to exceed $250 million to fund present and
future business operations of the subsidiaries. However, the investors were not
entitled to receive more than their $443 million original investment, plus the
agreed-upon return. One of the subsidiaries also issued $37 million of senior
floating rate notes, which matured and were repaid in August 2003 (see Note 5,
Debt).

The limited partnership was scheduled to terminate as of August 9, 2021.
However, the general partner, an Apache subsidiary, could elect to retire all or
part of the limited partner's interest at any time without penalty. On September
26, 2003, Apache repurchased and retired the preferred interests issued by three
of its subsidiaries for approximately $443 million, plus an additional $1
million for accrued dividends and distributions. The transactions involved the
purchase of preferred stock issued by two of the Company's subsidiaries for
approximately $82 million and the retirement of a limited partnership interest
in a partnership controlled by a subsidiary of the Company for approximately
$361 million. Apache funded the transactions with available cash on hand and by
issuing commercial paper under its existing commercial paper facility.

Prior to the early repurchase, the assets and liabilities of the
subsidiaries were included in Apache's consolidated financial statements at
historical costs, with the preferred stock and limited partner interests of the
subsidiaries reflected as a preferred interests of subsidiaries in the
consolidated balance sheet. The dividends paid on the preferred stock and
distributions paid on the limited partner interests were reflected as preferred
interests of subsidiaries in the statement of consolidated operations.

12. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

Cinergy Corp.

In 1995, Apache and other natural gas producers formed Producers Energy
Marketing LLC (ProEnergy), to market substantially all of its members' domestic
natural gas. In June 1998, Apache sold its 57 percent interest in ProEnergy to
Cinergy Corp. and contracted with Cinergy Corp. to market substantially all the
Company's natural gas production from the U.S. and agreed to develop terms for
the marketing of most of Apache's Canadian production under an amended and
restated gas purchase agreement effective July 1, 1998. Apache received 771,258
shares of Cinergy Corp. common stock for its interest, which the Company
subsequently sold for $26 million. In December 1998, Apache and Cinergy Corp.
agreed to postpone the negotiation of terms to market most of Apache's Canadian
production. Under the terms of the original gas purchase agreement, ProEnergy,
renamed Cinergy Marketing and Trading LLC (Cinergy), was to market Apache's
North American natural gas production until June 30, 2008, with an option,
following prior notice, to terminate on June 30, 2004. During this period,
Apache was generally obligated to deliver most of its U.S. gas production to
Cinergy and, under certain circumstances, reimburse Cinergy if certain gas
throughput thresholds were not met. The prices received for its gas production
under this agreement approximated market prices.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In June 2003, Apache and Cinergy agreed to terminate their agreement
concerning marketing of Apache's U.S. natural gas production and to dismiss the
arbitration between them. The parties reached an amicable settlement, the
amounts of which were immaterial to Apache's financial position and results of
operations. Consequently, the Company began marketing its U.S. natural gas
production previously marketed by Cinergy beginning with July 2003 production.

Related Parties

George D. Lawrence, a member of the Company's board of directors and the
former President and Chief Executive Officer of Phoenix Resource Companies, Inc.
(Phoenix), joined Apache's board in conjunction with the Company's acquisition
of Phoenix by a merger (the "Merger") on May 20, 1996, through which Phoenix
became a wholly-owned subsidiary of Apache. Merger consideration totaled $396.3
million, consisting of approximately 12,190,000 shares of Apache's common stock
(28,158,900 shares after adjustment for the stock dividends and the two-for-one
stock split) valued at $26.00 per share ($11.2554 after adjustment), $14.9
million of net value associated with Phoenix stock options assumed by Apache,
and $64.5 million in cash.

Upon consummation of the Merger, Apache assumed Phoenix stock options that
remained outstanding on May 20, 1996, including those granted to Mr. Lawrence
pursuant to Phoenix's 1990 Employee Stock Option Plan. In March 2003, Mr.
Lawrence received 8,291 shares of Apache common stock (16,582 shares after
adjustment for the stock split) as a result of the exercise of all of his
remaining stock options from the Phoenix 1990 Employee Stock Option Plan. Such
exercise was for 21,656 shares of Apache common stock at an exercise price of
$21.50 per share (43,312 shares of Apache common stock at an exercise price of
$10.75 per share after adjustment for the stock split). Mr. Lawrence paid the
net exercise price of $466,000 and required taxes of $345,000 by surrendering
13,365 shares of Apache common stock valued at $60.65 per share (26,730 shares
at $30.33 after adjustment for the stock split).

In the ordinary course of business, Cimarex Energy, Co. (Cimarex), formerly
Key Production Company, Inc., paid to Apache $6 million during 2004, $4 million
during 2003 and $2 million during 2002 for Cimarex's proportionate share of
drilling and workover costs, mineral interests and routine expenses relating to
oil and gas wells in which Cimarex owns interests and of which Apache is the
operator. Cimarex was paid approximately $5 million in 2004, $6 million in 2003,
and $4 million in 2002 directly by Apache or related entities for its
proportionate share of revenues from wells in which Cimarex marketed its
revenues with Apache as operator. Apache paid to Cimarex approximately $5
million during 2004 and $1 million during 2003 for Apache's proportionate share
of drilling and workover costs, mineral interests and routine expenses relating
to oil and gas wells in which Apache owns interests and of which Cimarex is the
operator. Apache was paid approximately $3 million in 2004 and $2 million in
2003 directly by Cimarex for its proportionate share of revenues from wells in
which Apache marketed its revenues with Cimarex as operator. F. H. Merelli, a
member of Apache's Board of Directors, is chairman of the board, chief executive
officer and president of Cimarex.

In the ordinary course of business, Matador Petroleum Corporation or
related entities (Matador) paid to Apache approximately $793,000 during 2003 and
$708,000 during 2002 for Matador's proportionate share of drilling and workover
costs, mineral interests and routine expenses relating to oil and gas wells in
which Matador owns interests and of which Apache is the operator. Matador was
paid approximately $1 million in 2003 and 2002 directly by Apache for its
proportionate share of revenues from wells in which Matador marketed its
revenues with Apache as operator. Apache paid to Matador during 2003 and 2002
approximately $654,000 and $2 million, respectively, for Apache's proportionate
share of drilling and workover costs, mineral interests and routine expenses
relating to oil and gas wells in which Apache owns interests and of which
Matador is the operator. Apache was paid approximately $915,000 and $621,000 in
2003 and 2002, respectively, directly by Matador for its proportionate share of
revenues from wells in which Apache marketed

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

its revenues with Matador as operator. Eugene C. Fiedorek, a member of Apache's
board of directors, was a member of the board of directors of Matador until its
acquisition by Tom Brown, Inc. in March 2003.

Apache and its subsidiaries made donations of $103,000 and $201,000, in
cash, property and services, to the Ucross Foundation in 2004 and 2003,
respectively. In February 2004, Apache purchased Clear Creek Hunting Preserve,
Inc. (CCHP) from Ucross Foundation for a total purchase price of $77,000. Apache
also paid $22,000 during 2004 to the Ucross Foundation for food, lodging and
other expenses incurred in connection with executive and board meetings held by
Apache at the Ucross Foundation's facilities, and $34,000 to the Ucross
Foundation for the lease of land and other services utilized by CCHP. The Ucross
Foundation was founded in 1981 as a non-profit organization whose primary
objectives include the restoration of the historic Clear Fork headquarters of
the Pratt and Ferris Cattle Company of Wyoming, the promotion of the
preservation of other historical sites in the area, and the maintenance of an
artists-in-residence program for writers and other artists. To help ensure that
the accomplishments of the Ucross Foundation are reasonably secure, Apache's
board of directors has approved a conditional charitable contribution of
$10,000,000 to be made to the Ucross Foundation upon a change of control of the
Company, as defined in the Company's income continuance plan. Raymond Plank,
chairman of Apache's Board of Directors, is chairman of the Board of Trustees of
Ucross Foundation, and G. Steven Farris, a director and officer of Apache,
George D. Lawrence, a member of the Company's Board of Directors, and Roger B.
Plank, an officer of Apache, are trustees of Ucross Foundation.

During 2004, 2003 and 2002, Apache and its subsidiaries made donations of
$5,033,000, $500,000 and $300,000, in cash, property and services, to The Fund
for Teachers: A Foundation to Recognize, Stimulate and Enhance, which is a Texas
non-profit corporation. In addition, during 2004, Apache made a pledge to the
Fund for Teachers for $5,000,000 in cash, property and services that will be
paid in 2005. The Fund for Teachers seeks to provide resources directly to
teachers to support learning experiences of their own design to increase their
effectiveness with students, and is currently focused on funding summer
sabbaticals for selected applicants. The Company's board of directors also
authorized additional donations to The Fund for Teachers of up to $5,000,000 in
cash, property and services for 2005 that may be funded through the end of 2006.
If a change of control of the Company occurs, as defined in the Company's income
continuance plan, any and all of the donations that have not yet been made to
the Fund for Teachers will become immediately due and payable to the Fund for
Teachers. Raymond Plank, chairman of Apache's Board of Directors, is chairman of
the board and president of The Fund for Teachers.

In the ordinary course of business, Apache paid to Maralo, LLC or related
entities ("Maralo") during 2002 approximately $9,000 in revenues relating to
four oil and gas wells in which Maralo owns an interest and of which Apache is
operator. Maralo paid Apache approximately $1,000 in 2002 for Maralo's share of
routine expenses relating to such wells. Also during 2002, Maralo sub-leased
certain office space from Apache, for which Maralo paid Apache approximately
$95,000. Mary Ralph Lowe, a member of Apache's Board of Directors through
December 19, 2003, is president, chief executive officer and the sole
stockholder of Maralo.

During 2002, in the ordinary course of business, Aquila, Inc. ("Aquila")
and related companies paid to Apache approximately $33 million for natural gas
produced by Apache, primarily in Canada. Aquila was paid approximately $348,000
by Apache for gathering, transportation and compression services provided by
Aquila. Janine McArdle, vice-president, Oil and Gas Marketing of Apache since
October 2002, previously was employed by Aquila Europe.

Major Customers

In 2004, purchases by EGPC and BP accounted for 17 percent and 15 percent,
respectively, of the Company's oil and gas production revenues.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 2003, purchases by Cinergy, EGPC and BP accounted for 12 percent, 16
percent and 15 percent of the Company's oil and gas production revenues,
respectively. In 2002, purchases by Cinergy and EGPC accounted for 19 percent
and 22 percent of the Company's oil and gas production revenues, respectively.
No other purchaser has accounted for more than 10 percent of revenues for 2004,
2003 or 2002.

Concentration of Credit Risk

The Company's revenues are derived principally from uncollateralized sales
to customers in the oil and gas industry; therefore, customers may be similarly
affected by changes in economic and other conditions within the industry. Apache
has not experienced significant credit losses on such sales. Apache sells
practically all of its Egyptian crude oil and natural gas to EGPC for U.S.
dollars. Beginning in 2001, we experienced a gradual decline in timeliness of
receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic
conditions during 2001 in Egypt lessened the availability of U.S. dollars,
resulting in a one to two month delay in receipts from EGPC. During 2004, we
experienced variability in the timing of cash receipts, but our past due balance
improved at year-end. We have not established a reserve for these Egyptian
receivables because we continue to get paid, albeit late, and have no indication
that we will not be able to collect our receivable.

13. BUSINESS SEGMENT INFORMATION

Apache has six reportable segments which are primarily in the business of
crude oil and natural gas exploration and production. The accounting policies of
the segments are the same as those described in the summary of significant
accounting policies. The Company evaluates performance based on profit or loss
from oil and gas operations before income and expense items incidental to oil
and gas operations and income taxes.

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Apache's reportable segments are managed separately based on their geographic
locations. Financial information by operating segment is presented below:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating
to the Company's oil and gas exploration and production activities. Apache has
no long-term agreements to purchase oil or gas production from foreign
governments or authorities.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(1) This amount only reflects DD&A of capitalized costs of oil and gas proved
properties and, therefore, does not agree with DD&A reflected on Note 13,
Business Segment Information.

(2) This amount only reflects amounts directly related to oil and gas producing
properties and, therefore, does not agree with severance and other taxes
reflected on Note 13, Business Segment Information.

(3) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement
Obligations." These amounts reflect current year activity only, as prior
periods were adjusted through a one-time cumulative adjustment as described
in Note 4, Asset Retirement Obligation.
- ---------------

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Costs Incurred In Oil And Gas Property Acquisition, Exploration, And
Development Activities

(1) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement
Obligations." The asset retirement obligation costs reflect abandonment
obligations assumed during the year and related revisions. Actual retirement
expenditures reflect plugging and abandonment costs during the year that are
included in exploration and development activity. Prior periods presentation
was not changed to reflect SFAS No. 143 because the amounts were adjusted
through a one-time cumulative adjustment as described in Note 4, Asset
Retirement Obligation.

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Capitalized Costs

The following table sets forth the capitalized costs and associated
accumulated depreciation, depletion and amortization, including impairments,
relating to the Company's oil and gas production, exploration and development
activities:

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not
being amortized at December 31, 2004, by the year in which such costs were
incurred. There are no individually significant properties or significant
development projects included in costs not being amortized. The majority of the
evaluation activities are expected to be completed within five to ten years.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by
the Company's engineers in accordance with Rule 4-10 of Regulation S-X. The
Company engages Ryder Scott Company, L.P. Petroleum Consultants as independent
petroleum engineers, to review the Company's 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.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve data only represents estimates
and should not be construed as being exact.

As of December 31, 2004, 2003 and 2002, on a barrel of equivalent basis
32.7, 28.5 and 27.7 percent of our estimated worldwide reserves, respectively,
were classified as proved undeveloped. Approximately 23 percent of our year-end
2004 estimated proved developed reserves are classified as proved not producing.
These reserves relate to zones that are either behind pipe, or that have been
completed but not yet produced, or zones that have been produced in the past,
but are not now producing because of mechanical reasons. These reserves may be
regarded as less certain than producing reserves because they are frequently
based on volumetric calculations rather than performance data. Future production
associated with behind pipe reserves is scheduled to follow depletion of the
currently producing zones in the same wellbores. It should be noted that
additional capital may have to be spent to access these reserves. The capital
and economic impact of production timing are reflected in this Note 14, under
"Future Net Cash Flows."

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future Net Cash Flows

Future cash inflows are based on year-end oil and gas prices except in
those instances where future natural gas or oil sales are covered by physical
contract terms providing for higher or lower amounts. Operating costs,
production and ad valorem taxes and future development costs are based on
current costs with no escalation.

The following table sets forth unaudited information concerning future net
cash flows for oil and gas reserves, net of income tax expense. Income tax
expense has been computed using expected future tax rates and giving effect to
tax deductions and credits available, under current laws, and which relate to
oil and gas producing activities. This information does not purport to present
the fair market value of the Company's oil and gas assets, but does present a
standardized disclosure concerning possible future net cash flows that would
result under the assumptions used.

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(1) Included in the estimated future net cash flows are Canadian provincial tax
credits expected to be realized beyond the date at which the legislation,
under its provisions, could be repealed. To date, the Canadian provincial
government has not indicated an intention to repeal this legislation.

(2) Estimated future net cash flows before income tax expense, discounted at 10
percent per annum, totaled approximately $22.2 billion, $16.4 billion and
$13.2 billion as of December 31, 2004, 2003 and 2002, respectively.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table sets forth the principal sources of change in the
discounted future net cash flows:

Impact of Pricing

The estimates of cash flows and reserve quantities shown above are based on
year-end oil and gas prices, except in those cases where future natural gas or
oil sales are covered by physical contracts at specified prices. Forward price
volatility is largely attributable to supply and demand perceptions for natural
gas and oil.

Under full-cost accounting rules, the Company reviews the carrying value of
its proved oil and gas properties each quarter on a country-by-country basis.
Under these rules, capitalized costs of proved oil and gas properties, net of
accumulated DD&A and deferred income taxes, may not exceed the present value of
estimated future net cash flows from proved oil and gas reserves, discounted at
10 percent, plus the lower of cost or fair value of unproved properties included
in the costs being amortized, net of related tax effects (the "ceiling"). These
rules generally require pricing future oil and gas production at the unescalated
oil and gas prices at the end of each fiscal quarter and require a write-down if
the "ceiling" is exceeded. Given the volatility of oil and gas prices, it is
reasonably possible that the Company's estimate of discounted future net cash
flows from proved oil and gas reserves could change in the near term. If oil and
gas prices decline significantly, even if only for a short period of time, it is
possible that write-downs of oil and gas properties could occur in the future.

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

(1) The sum of the individual quarterly net income per common share amounts may
not agree with year-to-date net income per common share as each quarterly
computation is based on the weighted average number of common shares
outstanding during that period. All potentially dilutive securities were
included in each quarterly computation of diluted net income per common
share, as none were antidilutive.

(2) Earnings per share have been restated to reflect the five percent stock
dividend declared December 18, 2002, payable April 2, 2003 to shareholders
of record on March 12, 2003, and the two-for-one stock split declared
September 11, 2003, paid January 14, 2004, to shareholders of record on
December 31, 2003.

(3) The first, second and third-quarter totals for 2004 will not agree to the
applicable Form 10-Q filing because interim amounts have been restated to
reflect the early adoption of SFAS No. 123-R, refer to Note 1, Summary of
Significant Accounting Policies.

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. SUPPLEMENTAL GUARANTOR INFORMATION

Prior to 2001, Apache Finance Australia was a finance subsidiary of Apache
with no independent operations. In this capacity, it issued approximately $270
million of publicly traded notes that are fully and unconditionally guaranteed
by Apache and, beginning in 2001, Apache North America, Inc. The guarantors of
Apache Finance Australia have joint and several liability. Similarly, Apache
Finance Canada was also a finance subsidiary of Apache and had issued
approximately $300 million of publicly traded notes that were fully and
unconditionally guaranteed by Apache.

Generally, the issuance of publicly traded securities would subject those
subsidiaries to the reporting requirements of the Securities and Exchange
Commission. Since these subsidiaries had no independent operations and qualified
as "finance subsidiaries," they were exempted from these requirements.

During 2001, Apache contributed stock of its Australian and Canadian
operating subsidiaries to Apache Finance Australia and Apache Finance Canada,
respectively. As a result of these contributions, they no longer qualify as
finance subsidiaries. As allowed by the SEC rules, the following condensed
consolidating financial statements are provided as an alternative to filing
separate financial statements.

Each of the companies presented in the condensed consolidating financial
statements is wholly owned and has been consolidated in Apache Corporation's
consolidated financial statements for all periods presented. As such, the
condensed consolidating financial statements should be read in conjunction with
the financial statements of Apache Corporation and subsidiaries and notes
thereto of which this note is an integral part.

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2004

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2003

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2002

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2004

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2003

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2002

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
FOR THE YEAR ENDED DECEMBER 31, 2004

F-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
FOR THE YEAR ENDED DECEMBER 31, 2003

F-65

BOARD OF DIRECTORS

FREDERICK M. BOHEN(3)(5)
Executive Vice President and
Chief Operating Officer,
The Rockefeller University

G. STEVEN FARRIS(1)
President, Chief Executive Officer and
Chief Operating Officer,
Apache Corporation

RANDOLPH M. FERLIC, M.D.(1)(2)
Founder and Former President,
Surgical Services of the Great Plains, P.C.

EUGENE C. FIEDOREK(2)
Private Investor, Former Managing Director,
EnCap Investments L.C.

A. D. FRAZIER, JR.(3)(5)
Chairman,
WolfCreek Broadcasting, Inc.

PATRICIA ALBJERG GRAHAM(4)
Charles Warren Research Professor
of the History of American Education,
Harvard University

JOHN A. KOCUR(1)(3)
Attorney at Law; Former Vice Chairman of the Board,
Apache Corporation

GEORGE D. LAWRENCE(1)(3)
Private Investor; Former Chief Executive Officer,
The Phoenix Resource Companies, Inc.

F. H. MERELLI(1)(2)
Chairman of the Board, Chief Executive Officer
and President, Cimarex Energy Co.

RODMAN D. PATTON(2)
Former Managing Director,
Merrill Lynch Energy Group

CHARLES J. PITMAN(4)
Former Regional President -- Middle East/Caspian/ Egypt/India, BP Amoco plc;
Sole Member, Shaker Mountain Energy Associates, LLC

RAYMOND PLANK(1)
Chairman of the Board, Apache Corporation

JAY A. PRECOURT(4)
Chairman of the Board and Chief Executive Officer,
Scissor Tail Energy LLC
Chairman of the Board, Hermes Consolidated, Inc.

OFFICERS

RAYMOND PLANK
Chairman of the Board

G. STEVEN FARRIS
President, Chief Executive Officer and
Chief Operating Officer

MICHAEL S. BAHORICH
Executive Vice President -- Exploration and Production Technology

JOHN A. CRUM
Executive Vice President and Managing Director,
Apache North Sea Ltd.

RODNEY J. EICHLER
Executive Vice President and General Manager,
Apache Egypt Companies

ROGER B. PLANK
Executive Vice President and Chief Financial Officer

FLOYD R. PRICE
Executive Vice President -- Eurasia, Latin America
and New Ventures

JON A. JEPPESEN
Senior Vice President

P. ANTHONY LANNIE
Senior Vice President and General Counsel

JEFFREY M. BENDER
Vice President -- Human Resources

MICHAEL J. BENSON
Vice President -- Security

THOMAS P. CHAMBERS
Vice President -- Corporate Planning

JOHN J. CHRISTMANN
Vice President -- Business Development

MATTHEW W. DUNDREA
Vice President and Treasurer

ROBERT J. DYE
Vice President -- Investor Relations

JANICE K. HARTRICK
Vice President and Associate General Counsel

ANTHONY R. LENTINI, JR.
Vice President -- Public and International Affairs

JANINE J. MCARDLE
Vice President -- Oil and Gas Marketing

THOMAS L. MITCHELL
Vice President and Controller

W. KREGG OLSON
Vice President -- Corporate Reservoir Engineering

JON W. SAUER
Vice President -- Tax

CHERI L. PEPER
Corporate Secretary

- ---------------

(1) Executive Committee

(2) Audit Committee

(3) Management Development and Compensation Committee

(4) Corporate Governance and Nominating Committee

(5) Stock Option Plan Committee

SHAREHOLDER INFORMATION

Stock Data

* Per share prices and dividend amounts have been adjusted to reflect the
effects of the two-for-one stock split in 2003.

The Company has paid cash dividends on its common stock for 40 consecutive years
through December 31, 2004. Future dividend payments will depend upon the
Company's level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and
the NASDAQ National Market (symbol APA). At December 31, 2004, the Company's
shares of common stock outstanding were held by approximately 8,000 shareholders
of record and 226,000 beneficial owners. Also listed on the New York Stock
Exchange are:

- Apache Finance Canada's 7.75% notes, due 2029 (symbol APA 29)

CORPORATE OFFICES
One Post Oak Central
2000 Post Oak Boulevard
Suite 100
Houston, Texas 77056-4400
(713) 296-6000

INDEPENDENT PUBLIC ACCOUNTANTS
Ernst & Young LLP
Five Houston Center
1401 McKinney Street, Suite 1200
Houston, Texas 77010-2007

STOCK TRANSFER AGENT AND REGISTRAR
Wells Fargo Bank, N.A.
Attn: Shareowner Services
P.O. Box 64854
South St. Paul, Minnesota 55164-0854
(651) 450-4064 or (800) 468-9716

Communications concerning the transfer of shares, lost certificates, dividend
checks, duplicate mailings or change of address should be directed to the stock
transfer agent. Shareholders can access account information on the website:
http://www.shareowneronline.com.

DIVIDEND REINVESTMENT PLAN

Shareholders of record may invest their dividends automatically in additional
shares of Apache common stock at the market price. Participants may also invest
up to an additional $25,000 in Apache shares each quarter through this service.
All bank service fees and brokerage commissions on purchases are paid by Apache.
A prospectus describing the terms of the Plan and an authorization form may be
obtained from the Company's stock transfer agent, Wells Fargo Bank, N.A.

DIRECT REGISTRATION

Shareholders of record may hold their shares of Apache common stock in
book-entry form. This eliminates costs related to safekeeping or replacing paper
stock certificates. In addition, shareholders of record may request electronic
movement of book-entry shares between your account with the Company's stock
transfer agent and your broker. Stock certificates may be converted to
book-entry shares at any time. Questions regarding this service may be directed
to the Company's stock transfer agent, Wells Fargo Bank, N.A.

ANNUAL MEETING

Apache will hold its annual meeting of shareholders on Thursday, May 5, 2005, at
10 a.m. in the Ballroom, Hilton Houston Post Oak (formerly Doubletree Hotel
Houston -- Post Oak), 2001 Post Oak Boulevard, Houston, Texas. Apache plans to
web cast the annual meeting live; connect through the Apache web site:
http://www.apachecorp.com

STOCK HELD IN "STREET NAME"

The Company maintains a direct mailing list to ensure that shareholders with
stock held in brokerage accounts receive information on a timely basis.
Shareholders wanting to be added to this list should direct their requests to
Apache's Public and International Affairs Department, 2000 Post Oak Boulevard,
Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by
registering on Apache's web site: http://www.apachecorp.com.

FORM 10-K REQUEST

Shareholders and other persons interested in obtaining, without cost, a copy of
the Company's Form 10-K filed with the Securities and Exchange Commission may do
so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard,
Suite 100, Houston, Texas, 77056-4400.

INVESTOR RELATIONS

Shareholders, brokers, securities analysts or portfolio managers seeking
information about the Company are welcome to contact Robert J. Dye, Vice
President of Investor Relations, at (713) 296-6662.

Members of the news media and others seeking information about the Company
should contact Apache's Public and International Affairs Department at (713)
296-6107.

WEB SITE: HTTP://WWW.APACHECORP.COM

INDEX TO EXHIBITS

- ---------------

* Filed herewith.

+ Management contracts or compensatory plans or arrangements required to be
filed herewith pursuant to Item 15 hereof.