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, 2003,
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,
2003...................................................... $10,526,544,439
Number of shares of registrant's common stock outstanding as
of February 29, 2004...................................... 325,035,928

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of registrant's proxy statement relating to registrant's 2004
annual meeting of stockholders have been incorporated by reference into Part III
hereof.

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

ITEM 1. BUSINESS

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
Western Australia, offshore and onshore Egypt, offshore The People's Republic of
China, offshore the United Kingdom in the North Sea 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 since 1960, and on the
NASDAQ National Market (NASDAQ) since January 2004. 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, 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, and any amendments to
these reports. Access to these electronic filings is available as soon as
practicable after filing with the SEC.

We hold interests in many of our U.S., Canadian and 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.

2003 RESULTS

Strong crude oil and natural gas prices and our record production during
2003 provided us with record income attributable to common stock of $1.1 billion
on total revenues of $4.2 billion, and record cash provided by operating
activities of $2.7 billion, a 96 percent increase from 2002. Our 2003 daily
production averaged 214.5 Mbbls of oil and natural gas liquids, and 1,217 MMcf
of natural gas. Our financial and operational performance enabled us to enhance
our financial flexibility by further strengthening our balance sheet and
maintain senior unsecured long-term debt ratings of A3 from Moody's, and A- from
Standard and Poor's and Fitch rating agencies.

We increased our total reserves by 26 percent, compared with the end of
2002, resulting in 1.66 billion boe of estimated proved reserves at year-end, 49
percent of which were natural gas. In 2003, we completed two significant
acquisitions in the Gulf of Mexico and entered a new core area with our purchase
of the Forties Field in the UK North Sea.

In January 2003, we agreed to purchase properties from subsidiaries of BP
p.l.c. (BP) in the Gulf of Mexico and in the North Sea offshore the United
Kingdom for $1.3 billion (subject to normal closing adjustments and the exercise
of preferential rights by third parties), our largest acquisition so far. The
Company closed the Gulf of Mexico portion on March 13, 2003 at an adjusted price
of $509 million. This acquisition had estimated proved reserves of 67.1 MMboe.
The price was adjusted from the originally announced $670 million to account for
the exercise of preferential rights by third parties involved in some of the
properties (a reduction of $73 million), production and expenses since January
1, 2003, the effective date of the transaction, and other minor adjustments. The
North Sea portion closed on April 2, 2003 for an adjusted purchase price of $630
million. The North Sea acquisition had an estimated 143.7 MMboe of reserves. The
acquisition was funded by a combination of proceeds from an equity offering we
completed in January 2003, cash from our operations and debt. On July 3, 2003,
we completed the acquisition of producing properties on the Outer Continental
Shelf of the Gulf of Mexico from Shell Exploration and Production Company for a
purchase price of $200 million, subject to post closing adjustments, including
adjustments for the exercise of preferential rights. The acquisition included 26
fields covering 50 blocks (approximately

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209,000 acres) and interests in two onshore gas plants, and we now operate 15 of
the fields with 91 percent of the production. We recorded proved reserves of
approximately 124.9 Bcf of natural gas and 6.1 million barrels of oil (26.9
MMboe). Prior to the transaction, Morgan Stanley paid Shell $300 million to
acquire an overriding royalty interest in a portion of the lower-risk reserves
to be produced over the next four years.

Throughout this report, per share results and share amounts have been
adjusted for the 10 percent common stock dividend paid on January 21, 2002, to
our shareholders of record on December 31, 2001, the five percent common stock
dividend paid on April 2, 2003, to our shareholders of record on March 12, 2003
and 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

As Apache enters our 50th year, our mission remains the same as at
inception: to grow a significant and profitable company for the benefit of our
shareholders.

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 with proactive exploitation operations, including workovers,
re-completions, and drilling, to increase production, and efforts to reduce
costs per unit produced and enhance profitability. Also over the past decade, we
added an international component to our strategy, which exposed our shareholders
to larger reserve targets and a greater ability to grow production and reserves
through drilling. Our expenditures in 2003 were well balanced between
acquisitions and drilling, with Apache having a robust year for both. During the
year, we invested over $1.6 billion in purchasing 267 MMboe. As for our active
drilling program, Apache invested $1.5 billion drilling 1,449 gross wells to add
234.3 MMboe. We plan on another substantial year of drilling activity in 2004,
with a preliminary capital budget of approximately $1.8 billion. We do not
budget for acquisitions because their timing is unpredictable; however, a
significant part of Apache's growth strategy continues to be directed toward the
purchase of properties to which we can add value and earn adequate rates of
return. Because we maintained our financial flexibility (our yearend ratio of
debt-to-capitalization was just over 26 percent), we are in a good position to
take advantage of acquisition opportunities that may arise.

We take a portfolio approach to the areas in which we drill in an effort to
generate consistent, profitable growth. 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 acquisition,
rather than through drilling activity alone.

Apache's Canadian and International operations provide the potential to
grow through drilling. Canada, Australia, Egypt and, in the last year, the North
Sea, all offer larger reserve targets than those to which we are exposed in the
United States. Also, Apache's international operations in Canada, 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.

In today's industry environment, with high prices and substantial cash flow
and earnings, competing for quality opportunities to grow through drilling or
acquisition is a challenge. However, Apache has grown production 24 of the last
25 years and reserves for 18 consecutive years in differing industry
environments. We are fortunate to have evolved to the point where we believe we
have the ability to continue growing over time through drilling, acquisition or
both.

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REVIEW OF COMPANY'S WORLDWIDE OPERATING AREAS

Our portfolio approach provides diversity in terms of hydrocarbon mix (oil
or gas), geologic risk and geographic location. 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 our core areas.

We currently have interests in seven countries: the United States, Canada,
Egypt, Australia, the United Kingdom, China and Argentina. In 2003, we ceased
operations in Poland. Our core areas are defined as the United States, Canada,
Egypt, Australia, the United Kingdom 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, production began on our interests in China in July
2003, and we have a small production interest in Argentina.

The table below sets out a brief comparative summary of certain 2003 data
for each area. More detailed information regarding the natural gas, oil, and
natural gas liquids (NGLs) production and average prices received in 2003, 2002
and 2001 for our core geographic areas is available in Management's Discussion
and Analysis of Financial Condition and Results of Operations in Item 7 of 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
same geographic areas, see Note 15, Supplemental Oil and Gas Disclosures
(Unaudited), and Note 14, Business Segment Information, both in Item 15 of this
Form 10-K.

The following discussions include references to our plans for 2004. These
only represent initial estimates and will be reviewed and revised throughout the
year in light of changing industry conditions.

United States

An increase in our capital spending over 2002's level led to a busy
drilling year in which we completed 267 out of 293 total wells and replaced 79
percent of our domestic production through extensions, discoveries and other
additions. A continuing goal is to drill quality prospects in and around our
large domestic reserve and production bases.

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.
In 2003, the Gulf Coast region was once again our leading

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region for production volumes and revenues. This region performed 354 workover
and recompletion operations during 2003 and completed 67 out of 85 total wells
drilled, replacing 51 percent of the regions production from extensions,
discoveries and other additions. As of year-end 2003, Gulf Coast accounted for
21 percent of our estimated proved reserves. In 2004, we currently plan on
spending approximately $400 million to drill an estimated 100 wells and to
continue exploitation. We will continue our production enhancement program and
exploitation of properties acquired from BP and Shell in 2003.

Central -- The Central region includes assets in the Permian Basin of west
Texas and New Mexico, the San Juan Basin of New Mexico, east Texas and the
Anadarko Basin of western Oklahoma. At year-end 2003, the Central region
accounted for approximately 23 percent of our estimated proved reserves, the
second largest in the Company. During 2003, we participated in 208 wells, 200 of
which were completed as productive wells, replacing 150 percent of the region's
production from extensions, discoveries and other additions. Apache performed
357 workovers and recompletions in the region during the year. In 2004, we
currently plan to spend approximately $150 million drilling an estimated 200
wells and continuing our production enhancement programs.

Marketing -- The Company began marketing its domestic natural gas
production in July 2003. Our objective is 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, endusers, integrated majors and
marketers. We manage our credit risk by only selling to creditworthy customers
and monitoring our credit exposure daily. 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 published indexes. (See Note
11 under Item 15 of this Form 10-K).

Several years ago, we locked in a portion of our domestic future natural
gas production at a fixed price using long-term fixed price physical contracts.
These contracts, which represented approximately 9 percent of our 2003 domestic
natural gas production, will expire in 2007 and 2008. The contracts provide
protection to the Company in the event of decreasing natural gas prices.

Most of our gas is being sold monthly at market prices. However, to meet
the needs of our customers, we may sell some of our gas under long-term
contracts at prices that fluctuate with market conditions.

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 provide for sales at prices that change with
market conditions.

Canada

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 26 percent of our estimated proved
reserves, the largest in the Company. We hold over 4.7 million net acres in
Canada, the largest of the North American regions.

2003 -- Canada was our most active region for drilling in 2003, with Apache
participating in 984 gross wells, approximately half of which were shallow
development wells, 913 of which were completed as producers. We also conducted
889 workover and recompletion projects. We replaced 275 percent of our Canadian
production through extensions, discoveries and other additions.

2004 -- We currently plan to spend approximately $450 million drilling an
estimated 1,100 wells, continuing the exploration program, exploiting acquired
properties and developing our gas processing infrastructure.

Marketing -- Our Canadian natural gas sales include sales to Local
Distribution Companies (LDCs), utilities, endusers, 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

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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 longer term commitments to sell gas into the
United States in the Pacific Northwest, the upper Midwest and the northeastern
U.S. market regions (See Note 11 under Item 15 of this Form 10-K). The volumes
are relatively small and none of the terms extend beyond 2008. We also have
long-term commitments to supply production to a market in eastern Canada. Again,
the volumes are relatively small and the term is through 2011. The prices we
receive under these contracts fluctuate monthly with market indices. The
remainder of our natural gas production is sold monthly at market prices.

Our Canadian crude oil is primarily sold to refiners, integrated majors and
marketers. Our condensate is primarily sold to heavy oil producers for blending
purposes. All 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 crude 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

In Egypt, our operations are generally conducted pursuant to production
sharing contracts under which contractor partners pay all operating and capital
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 costs. The balance of the production is allocated between this
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. As of December 31, 2003, we held over 6.6 million net
acres encompassing 12 concessions. Apache is the largest producer of liquid
hydrocarbons and the second largest producer of natural gas in the Western
Desert.

2003 -- Egypt accounted for 16 percent of Apache's production revenues on
16 percent of total production for the year and accounted for 10 percent of
total proved reserves at December 31, 2003. Apache had an active drilling
program in Egypt, completing 94 of 107 gross wells, for a success rate of 88
percent.

2004 -- We currently plan to spend approximately $300 million to drill more
than 100 wells and continue exploitation. Our plans seek to maintain momentum
and preserve our flexibility to respond to market conditions with a balanced mix
of exploratory and development drilling.

Marketing -- In 1996, we and our partners in the Khalda Block entered into
a 25-year take-or-pay contract with EGPC, which obligates EGPC to pay for 75
percent of 200 MMcf/d of future production of gas from the Khalda Block. In late
1997, the same partners entered into a supplement to the contract with EGPC to
sell an additional 50 MMcf/d. In connection with our acquisition of interests
from Repsol YPF (Repsol) in 2001, we acquired rights under an existing gas sales
contract for 25 MMcf/d from the South Umbarka area. Gas sales from the contracts
are based on a price that is the energy equivalent of 85 percent of the price of
Suez Blend crude oil, FOB Mediterranean port. Sales of gas under the contract
began in 1999 upon completion of a gas pipeline from the Khalda Block. In 2000,
other producers agreed to accept a negotiated price for an alternative gas
pricing formula for certain quantities of gas purchased from 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. These latest agreements do not
impact our existing gas sales contracts in the Khalda Block or at our Qarun
development lease. However, we have entered into new gas sales contracts
containing Industry Pricing at our Matruh, Ras Kanayes, Ras El Hekma, and Akik
development leases. We also entered into a 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. Reserve recognition and proper
scaling of the significant future development infrastructure are pending
negotiation and completion of the final sales agreement with EGPC and resolution
in delays of certain payments by EGPC.

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In Egypt, 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. At the discretion of Arab Petroleum Pipeline Company, the
operator of the SUMED pipelines, oil from the Qarun Block is pumped into 42-inch
diameter pipelines, which transport significant quantities of Egyptian and other
crude oil from the Gulf of Suez to Sidi Kerir on the Mediterranean Coast.
Alternatively, oil can be transported via pipeline owned by Petroleum Pipeline
Company (PPC) to the Mostorad Refinery south of Cairo. In Egypt, all our oil
production is presently sold to EGPC on a spot basis at a "Western Desert" price
(indexed to Brent Crude Oil).

Australia

Our exploration activity in Australia is focused in the offshore Carnarvon
and Perth Basins where Apache holds 4.4 million net acres in 26 Exploration
Permits, 10 Production Licenses, and four Retention Leases. Production
operations are concentrated in the Carnarvon Basin within 10 Production
Licenses, nine of which are operated by Apache.

2003 -- We produced 17.9 million barrels of oil equivalent in Australia (12
percent of our total) generating $392 million of production revenues. During the
year we participated in drilling 37 wells; 24 exploration and 13 development
wells. Ten of the exploration wells and nine of the development wells were
successful for an overall 51 percent success rate. Additionally, there were 11
workover and recompletion projects performed during the year. Apache added 33.0
million barrels of oil equivalent to our Australian reserve base through
exploration and development activities and another 6.7 million barrels of oil
equivalent by way of acquisitions, as we increased our interest in the John
Brookes gas field from 20 percent to 55 percent and assumed operatorship. The
39.7 million barrels of oil equivalent reserve add equates to a 222 percent
replacement of production, 184 percent of which came through drilling
operations.

Our Australian region had a successful exploration year with five
discoveries, the most significant being Ravensworth, Crosby, and Thomas Bright.
We also had a very substantial appraisal program with 10 successes. On the
development side, the Double Island oil field commenced production in February
2003, 12 months from discovery, at an average net rate of 6,165 barrels of oil
per day and has thus far produced 1.7 million barrels of oil equivalent net to
Apache's 68.5 percent interest. The East Spar-6 development well was placed on
production in mid November at an average rate of 33 million cubic feet of gas
per day and 1,733 barrels of condensate per day net to Apache's 55 percent
interest. Fabrication of the platform for the Linda gas development has been
completed with installation scheduled for February 2004 and first gas expected
in April 2004. Apache owns a 68.5 percent interest in the Linda gas field.

2004 -- First production from the Linda gas development is scheduled for
April 2004 at an average projected rate of 19 million cubic feet of gas and 900
barrels of condensate per day net to Apache's 68.5 percent interest. The John
Brookes gas development is underway with first production anticipated in the
second quarter of 2005. For 2004, we have budgeted expenditures of over $200
million for an estimated 25 exploration wells, nine appraisal wells, eight
development wells, and various production development and enhancement capital
projects.

Marketing -- In Australia, we executed two new gas sales contracts and
extended four existing gas sales contracts during 2003, bringing our total to 22
active contracts. In aggregate, we committed a further 115 billion cubic feet of
gas (gross) for delivery. Under the largest new contract, we will supply more
than 88 billion cubic feet of gas over an 11-year period which commenced in July
2003. Additionally, we were awarded two conditional gas contracts with a
combined commitment of 114 billion cubic feet of gas (gross). The larger
contract would have us deliver 102 billion cubic feet of gas over a 14-year
period beginning in September 2004. Our total Australian net delivery rates are
expected to average approximately 115 million cubic feet of gas per day in 2004.
Generally, natural gas is sold in Western Australia under long-term contracts,
many of which contain escalation clauses that provide for an annual increase in
the contract price based on the Australian consumer price index. The contract
price escalates at an average of 80 percent of the index. These contracts reduce
gas price volatility in Australia.

We continue to export all of our crude oil production to domestic and
international buyers at prices which fluctuate with world market conditions.
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United Kingdom

With the closing of our purchase of the Forties Field in April 2003, we
established a new core area in the North Sea. The Forties Field was first
discovered in 1970, and has been one of the most productive fields in the UK
North Sea. At the time of closing, Apache booked 143.7 MMboe of reserves, and
produced an average of approximately 41 Mbbls/d of oil and 1,400 Mcf/d of
natural gas through year-end. Apache acquired operatorship of the field with a
96 percent interest, which includes five platforms. Our North Sea interests had
production of 10.8 MMboe in 2003, provided us with $273 million of production
revenue, and accounted for nine percent of our year end proved reserves. We plan
a significant capital program for the North Sea during 2004, with a projected
drilling budget of approximately $300 million for 20 wells and various
production, development and enhancement capital projects.

Marketing -- Concurrent with the acquisition of the UK North Sea
properties, the Company entered into a separate crude oil physical sales
contract with BP. The contract provides 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 bopd for the remainder of the term) is
sold at fixed prices. The balance of the crude oil is sold at prevailing market
prices. We are reviewing potential marketing arrangements upon expiration of our
term sales contract with BP. The possible marketing strategies include expanding
the current customer base and selling a portfolio mix of spot and term
arrangements into the export market.

Other International

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

In August, first production came on stream from our interests in the Zhao
Dong block in Bohai Bay, China, at the rate of 6,000 barrels of oil per day from
three wells. Production is projected to reach its peak level of approximately
22,000 barrels per day in the first half of 2004. In 2003, our Chinese interests
produced $26.8 million of production revenue on over 1 MMboe of production. We
are the operator, with a 24.5 percent interest, of the Zhao Dong Block. Since
production began, we have exported our portion of the production to
international companies at prices that change with market conditions. We
currently plan to spend an estimated $20 million of drilling capital this year.

We obtained our first acreage position in Poland in 1997 when we assumed
operatorship and a 50 percent interest in over 5.5 million gross acres from FX
Energy, Inc. During 2003, we ceased operations in Poland, and we wrote off $16
million ($10 million net of tax), of which $13 million was recorded as an
impairment of the remaining unproved property costs.

In 2001, we acquired exploration and production assets of Fletcher
Challenge and Anadarko Petroleum in Argentina. After these transactions, we hold
interests in a 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 another four blocks. For the year, these interests represent under one
percent of our proved reserves and generated small amounts of production and
revenue. Our total net acreage in Argentina is 375,769 acres, with 328,049
developed and 47,720 undeveloped at year-end 2003. In 2004, we plan to spend
approximately $4 million drilling six wells in Argentina.

DRILLING STATISTICS

Worldwide, in 2003, we participated in drilling 1,449 gross wells, with
1,319 (91 percent) completed as producers. Canada was our most active region,
drilling 984 gross new, mostly development wells, with a success rate of 92.8
percent. We also performed over 2,000 major workovers and recompletions during
the year. Our drilling activities in the United States generally concentrate on
exploitation of existing, producing fields rather than exploration. As a general
matter, our international drilling activities focus more on exploration drilling
and our Canadian region on a mix of exploration and exploitation. In addition to
our completed wells, at year-end several wells had not yet reached completion:
17 in the U.S. (9 net); 17 in Canada (15.5 net); 11 in Egypt (10.5 net); one in
Australia (0.6 net); and one in Argentina (0.3 net).

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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, 2003, is set forth below:

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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.

PRODUCTION AND PRICING DATA

The following table describes, for each of the last three fiscal years,
oil, NGLs and gas production for the Company, average production costs and
average sales prices.

ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS

As of December 31, 2003, Apache had total estimated proved reserves of
843.9 million barrels of crude oil, condensate and NGLs and 4.9 Tcf of natural
gas. Combined, these total estimated proved reserves are

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equivalent to 1.66 billion barrels of oil or 9.9 Tcf of gas. The company's
reserves have grown for the 18th consecutive year. Estimated proved developed
reserves comprise 71.5 percent of our total estimated proved reserves on a boe
basis.

The Company's estimates of proved reserves and proved developed reserves at
December 31, 2003, 2002 and 2001, changes in proved reserves during the last
three years, and estimates of future net cash flows and discounted future net
cash flows from proved reserves are contained in Note 15, Supplemental Oil and
Gas Disclosures (Unaudited), in the Apache Corporation 2003 Consolidated
Financial Statements of Item 15 of this Form 10-K.

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. Reserves are
considered proved if economical producibility is supported by either actual
production or conclusive formation tests. 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 installed program in the reservoir provides support for the
engineering analysis on which the project or program is based. Proved developed
oil and gas reserves can be expected to be recovered through existing wells with
existing equipment and operating methods.

Apache emphasizes that the volumes of 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.

We engage an independent petroleum engineering firm to review our estimates
of proved hydrocarbon liquid and gas reserves. During 2003, 2002 and 2001, their
review covered 78, 68, and 61 percent of the reserve value, respectively. This
value, which represents estimated future net cash flows, is based on prices at
year-end and is 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 and is presented in Note 15 to the
accompanying financial statements.

RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS

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 proved reserves, conduct successful exploration and
development activities or, through engineering studies, identify additional
behind-pipe zones or secondary recovery reserves, our 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.

COSTS INCURRED TO CONFORM TO GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY

Our exploration, production and marketing operations are regulated
extensively at the federal, state and local levels, as well as by other
countries in which we do business. We have made and will continue to make all
necessary expenditures in our efforts to comply with the requirements of
environmental and other regulations. Further, the oil and gas regulatory
environment could change in ways that might substantially increase these costs.
Hydrocarbon-producing states regulate conservation practices and the protection
of correlative rights. These regulations affect our operations and limit the
quantity of hydrocarbons we may produce and sell. In addition, at the U.S.
federal level, the Federal Energy Regulatory Commission regulates interstate
transportation of natural gas under the Natural Gas Act. Other regulated matters
include marketing, pricing, transportation and valuation of royalty payments.

10

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 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 maintain insurance coverage, which we believe is customary in the
industry, although we are not fully insured against all environmental risks. We
are not aware of any environmental claims existing as of December 31, 2003,
which would have a material impact upon our financial position or results of
operations.

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 on 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 directly 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. In discussions with
the EPA, Apache has agreed to pay a monetary penalty of $20,650 and undertake a
Supplemental Environmental Project with an estimated cost of $94,500.

As of December 31, 2003, we had an accrued liability of $10 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.

COMPETITION WITH OTHER COMPANIES COULD HARM US

The oil and gas industry is highly competitive. Our business could be
harmed by competition with other companies. Because oil and gas are fungible
commodities, one form of competition is price competition. We strive to maintain
low finding and production costs in order to maximize profits. In addition, as
an independent oil and gas company, we frequently compete for reserve
acquisitions, exploration leases, licenses, concessions and marketing agreements
against companies with financial and other resources substantially larger than
those

11

we possess. Many of our competitors have established strategic long-term
positions and maintain strong governmental relationships in countries in which
we may seek new entry.

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.

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 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.

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, 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 to serve as our new independent auditors for 2002.
Ernst & Young also served as our independent public accountants in 2003.
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.

ISSUES RELATED TO ARTHUR ANDERSEN LLP MAY IMPEDE OUR ABILITY TO ACCESS THE
CAPITAL MARKETS

In the unlikely event that the SEC ceases accepting financial statements
audited by Arthur Andersen LLP, we would be unable to access the public capital
markets unless Ernst & Young LLP, our current independent accounting firm, or
another independent accounting firm, is able to audit the financial statements
originally audited by Arthur Andersen. In addition, investors in any subsequent
offerings for which we use Arthur Andersen's audit reports will not be entitled
to recovery against Arthur Andersen under Section 11 of the Securities Act of
1933, as amended, for any material misstatements or omissions in those financial
statements. Furthermore, Arthur Andersen will be unable to participate in the
"due diligence" process that
12

would customarily be performed by potential investors in our securities, which
process included having Arthur Andersen perform procedures to assure the
continued accuracy of its report on our audited financial statements and to
confirm its review of unaudited interim periods presented for comparative
purposes. As a result, we may not be able to bring to the market successfully an
offering of our securities in a timely and efficient manner. Consequently, our
financing costs may increase or we may miss attractive market opportunities.

EMPLOYEES

On December 31, 2003, we had 2,353 employees. None of our employees is
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 2003, 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 Item 15, Note 11 -- "Operating Leases and
Other Commitments".

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

ITEM 2. PROPERTIES

For information on our domestic and international properties, see the
discussions in Item 1 of this Form 10-K under Review of Company's Worldwide
Operating Areas as identified by country. For tables setting out a description
of our drilling activities, well counts and acreage positions, see the
information in Item 1 under Drilling Statistics, Productive Oil and Gas Wells
and Gross and Net Undeveloped Acreage.

ITEM 3. LEGAL PROCEEDINGS

See the information set forth under the caption "Commitments and
Contingencies" in Note 11 to our financial statements under Item 15 of this Form
10-K.

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

A special meeting of the Company's stockholders was held in Houston, Texas,
at 10:00 a.m. local time, on Thursday, December 18, 2003. Proxies for the
meeting were solicited pursuant to Regulation 14 under the Securities Act of
1934, as amended. There was no solicitation in opposition to the proposal to
amend the Company's Restated Certificate of Incorporation to increase the number
of authorized shares of Apache's common stock from 215,000,000 shares to
430,000,000 shares, and the amendment was approved.

13

Out of a total of 162,037,849 shares of the Company's common stock
outstanding and entitled to vote as of October 29, 2003, the record date for the
special meeting, October 29, 2003, 142,137,696 shares, or 87.7 percent, were
present at the meeting in person or by proxy. The vote tabulation for amendment
of Apache's Restated Certificate of Incorporation was as follows:

The shares referenced above have not been adjusted for the two-for-one
stock split, record date December 31, 2003, distributed January 14, 2004.

PART II

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

During 2003 Apache common stock, par value $0.625 per share, was traded on
the New York Stock Exchange, the Chicago Stock Exchange under the symbol APA.
The table below provides certain information regarding our common stock for 2003
and 2002. Prices were obtained from the New York Stock Exchange 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
and the five percent stock dividend, all of which are described below. Per share
prices and 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 27,
2004 , was $41.17. At February 29, 2004, there were 325,035,928 shares of our
common stock outstanding held by approximately 8,000 shareholders of record and
approximately 157,000 beneficial owners.

We have paid cash dividends on our common stock for 39 consecutive years
through December 31, 2003. 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, our board of directors adopted a stockholder rights plan to
replace the former plan adopted in 1986. 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 the 10
percent and five percent stock dividends and two-for-one stock split) that the
stockholder owned. We refer to these preferred stock purchase rights as the
"rights." Unless the rights have been previously redeemed, all shares of Apache
common stock are issued with rights. The rights trade automatically with our
shares of common stock. Certain triggering events will give the holders of the
rights the ability to purchase shares of our common stock, or the equivalent
stock of a person that acquires us, at a discount. The triggering events relate
to persons or groups acquiring an amount of our common stock in excess of a set
percentage, or attempting to or actually acquiring us. The details of how the
rights operate are set out in our certificate of incorporation and the Rights
Agreement, dated January 31, 1996, between Apache and Wells Fargo Bank
Minnesota, N.A. (formerly Norwest Bank Minnesota, N.A.). Both of those documents
have been filed as exhibits to this Form 10-K and you should review them to
fully understand the effects of the rights. The purpose of the rights is to
encourage potential acquirors to negotiate with our board of directors before
attempting a takeover bid and to provide our board of directors with leverage in
negotiating on behalf of our stockholders the terms of

14

any proposed takeover. The rights may have certain anti-takeover effects. They
should not, however, interfere with any merger or other business combination
approved by our board of directors.

On September 13, 2001, our board of directors declared a 10 percent
dividend on our shares of common stock payable in common stock on January 21,
2002 to shareholders of record on December 31, 2001. Pursuant to the terms of
the declared 10 percent stock dividend, we issued 26,916,872 shares (adjusted
for the 2002 five percent stock dividend and the 2003 stock split) of our common
stock on January 21, 2002 to the holders of the 130,888,270 shares (adjusted for
the five percent stock dividend and the stock split) of common stock outstanding
on December 31, 2001. No fractional shares were issued in connection with the
stock dividend and cash payments totaling $891,132 were made in lieu of
fractional shares.

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 approximately 15,736,496 shares
of (adjusted for the 2003 stock split) our common stock on April 2, 2003 to the
holders of the 307,819,628 of common stock outstanding (adjusted for the 2003
stock split) 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 BP acquisition, the
Company completed the public offering of 19.8 million shares (adjusted for the
stock split) of Apache common stock, including 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 BP
acquisition.

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.

15

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, 2003,
which information has been derived from the Company's audited financial
statements. Our financial statements for the years 1999 through 2001 were
audited by Arthur Andersen LLP, independent public accountants. 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 of this
Form 10-K "Risk Factors Related to our Business and Operations." 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 in Item
15 of this Form 10-K.

For a discussion of significant acquisitions, see Note 3 to the Company's
consolidated financial statements in Item 15 of 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. During 2003 the Company added an additional
international core area with the acquisition of the U.K. North Sea Forties Field
from BP p.l.c. (BP). The Company's other core geographic areas include
operations in the United States, Canada, Australia and Egypt. Smaller, non-core
operations are conducted in China and Argentina.

Apache adheres to a portfolio approach to provide diversity in terms of
hydrocarbon mix (crude oil and natural gas), geologic risk and geographic
location. Our growth strategy focuses on economic growth through drilling,
through acquisitions, or through a combination of both, depending on what the
environment gives us. 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 must be 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 a company's ability to maintain 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 must stay abreast of industry
drilling costs and the price

16

at which properties are available for purchase, when choosing where to allocate
our available funds. We monitor operating costs, on both an absolute dollar and
per unit of production basis, relative to our historical norms and relative to
our industry sector, factoring in the impact from property acquisitions and
changes in industry conditions. Given the inherent volatility and
unpredictability of commodity prices, and changing industry conditions, we
frequently revise our forecasts and adjust our budgets accordingly. Commodity
prices throughout 2003 were relatively high and remained consistently strong
throughout the year. This price consistency allowed us to maintain a fairly
constant level of capital expenditures for exploration and development drilling
throughout the year. Our 2003 drilling and acquisition capital expenditures
(discussed below) were balanced, as we grew both production and reserves to
record levels, while maintaining a balance in terms of hydrocarbon mix. We had
exceptional profitability growth in 2003, achieving several operational and
financial milestones noted below:

- Our 2003 oil and gas production revenues reached a record $4.2 billion,
64 percent higher than in 2002.

- We generated record earnings of $1.1 billion, more than twice our
prior-year level. More importantly, on a diluted share basis earnings
rose 91 percent to a record $3.43 per share.

- Cash from operating activities increased 96 percent from the prior year
to a record $2.7 billion.

- Production averaged a record 417,400 barrels of oil equivalent per day
(boe/d), the 24th increase in the last 25 years.

- In mid-July 2003, production was initiated on the Zhao Dong block in
Bohai Bay, offshore China.

- We began actively marketing our U.S. natural gas effective with July 2003
production. With our 2nd quarter North American daily natural gas
production exceeding one billion cubic feet (Bcf), we felt it was prudent
to bring this responsibility back in-house.

- On December 16, 2003 we announced the signing of a Memorandum of
Understanding (MOU) with the Egyptian General Petroleum Corporation
(EGPC) for a Gas Sales Agreement, Field Development Plan and Deepwater
Development Lease for a minimum of 2.7 trillion cubic feet (Tcf) of
natural gas over 25 years from the deepwater portion of our Egyptian West
Mediterranean Concession. Production is scheduled to commence in 2007,
contingent upon completion of significant development infrastructure and
resolution of delays in certain payments for production by EGPC.

- We ended the year with record proved reserves of 1.66 billion barrels of
oil equivalent (boe), marking the 18th consecutive year of reserve
growth. Nearly half of our proved reserve additions were added through
exploration and development activities.

We began our 49th year in a strong financial position and on January 13,
2003, we announced the BP acquisition, our single-largest acquisition to date,
establishing a new international core area and augmenting our Gulf of Mexico
portfolio. The BP acquisition fit our balanced-portfolio business model and
provides the potential for internal growth similar to what we have experienced
in other areas. It also extends our relationship with one of the world's largest
integrated major companies. In July 2003, we consummated a deal with Shell
Exploration and Production Company (Shell) adding additional oil and gas fields
on the outer Continental Shelf of the Gulf of Mexico. Our total acquisition
costs for 2003 were approximately $1.6 billion, compared to $355 million in the
prior year. These acquisitions are discussed in more detail below.

Our worldwide capital expenditures for exploration and development were
approximately $1.5 billion, 73 percent higher than 2002 and approximately 18
percent higher than our initial plan. Our strong cash flow enabled us to
allocate additional funds to exploration and development during 2003. We spent
approximately 69 percent of our exploration and development capital in North
America, which is consistent with reserve and production contributions. We had
numerous drilling successes throughout the year, particularly in Egypt and
Australia:

- Our most significant exploration success in Egypt, announced in July
2003, was the Qasr-1X well located on the Khalda Concession. In November,
we announced completion of the Qasr-2X confirming the Qasr-1X discovery.
We believe the Qasr discovery has the potential to be the most

17

significant discovery in Apache's 49-years. Production was initiated on a
restricted basis in the fourth quarter of 2003, with full production
expected in 2005, pending completion of additional development wells,
appraisal wells and construction of pipeline facilities.

- In July 2003, we announced that our Ravensworth-1 well discovered oil in
the Exmouth Sub-Basin offshore Western Australia, creating a new oil-play
area for Apache in an oil-prone area and adding a new dimension to our
exploration program offshore Western Australia. Early in October 2003, we
announced our second discovery in the Exmouth Sub-Basin, the Crosby-1,
providing additional confidence that we have established a new oil-play
area. Appraisal wells along with additional exploration drilling will
occur in 2004.

Following a very active year of drilling and acquisitions, our year-end
2003 reserves remained balanced at 51 percent oil and 49 percent natural gas,
compared with 49 percent oil and 51 percent natural gas at year-end 2002. The
increase in oil reserves is primarily attributable to the properties acquired in
the North Sea. During 2003, the U.S. contributed 45 percent of equivalent
production, up from 42 percent in 2002, reflecting the impact of the Gulf of
Mexico assets acquired from BP and Shell.

Apache ended the year in a strong financial position, maintaining single-A
credit ratings on unsecured long-term debt issued by Moody's, Standard and
Poor's and Fitch rating agencies. Also, we reduced debt to 26 percent of
capitalization despite over $3 billion in capital expenditures. To manage our
financial flexibility, we consummated several debt and equity transactions
during 2003:

- On January 22, 2003, in conjunction with the pending BP transaction, we
completed a public offering of 19.8 million shares of common stock,
adjusted for the two-for-one stock split, raising $554 million.

- During the second quarter, the Company issued $350 million of 12-year,
senior unsecured notes at a 4.375-percent coupon rate. Proceeds were used
to reduce bank debt and outstanding commercial paper, and for general
corporate purposes.

- To take advantage of historically low interest rates on commercial paper
and better position ourselves to pay down short-term debt, if we so
elect, on September 26, 2003, Apache repurchased and retired preferred
interests issued by three of its subsidiaries for approximately $443
million, plus an additional $1 million for accrued dividends and
distributions.

- The Company also filed a shelf registration with the Securities and
Exchange Commission that allows Apache to sell up to $1.5 billion in
stock and debt securities.

On September 12, 2003 the Company announced that its Board of Directors, in
recognition of the Company's outstanding growth and progress, voted to increase
the quarterly cash dividend on its common stock 20 percent to 6 cents per share
from 5 cents per share, effective with the November 2003 payment, and to split
the stock two-for-one.

While 2003 was an outstanding year, the current outlook for 2004 is also
encouraging. Recent drilling successes and acquisitions should generate
substantial production. Also, the current NYMEX futures markets indicate oil and
natural gas prices above historical averages in 2004. Lastly, we are well
positioned to access capital should appropriate acquisition opportunities
present themselves. A more detailed discussion of operations follows our
Critical Accounting Policies.

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of
operations are based upon the consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets
and liabilities. 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. We evaluate our estimates and assumptions on a
regular basis. We base our estimates on historical experience and various other
18

assumptions that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about the 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 our financial statements. Below, we have provided expanded
discussion of our more significant accounting policies, estimates and judgments.
We discussed the development, selection and disclosure of each of these with our
audit committee. We believe these accounting policies reflect our more
significant estimates and assumptions used in preparation of our financial
statements. See Results of Operations and Note 1 of Item 15 of this Form 10-K
for a discussion of additional accounting policies and estimates made by
management.

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.

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 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. Typically, the application of the
full-cost method of accounting for oil and gas property generally results in
higher capitalized costs and higher depletion, depreciation and amortization
(DD&A) rates compared to similar companies applying the successful efforts
methods of accounting.

The Company has taken note of a July 2003 inquiry to the Financial
Accounting Standards Board (FASB) regarding whether or not contract-based oil
and gas mineral rights held by lease or contract ("mineral rights") should be
recorded or disclosed as intangible assets. The inquiry presents a view that
these mineral rights are intangible assets as defined in SFAS No. 141, "Business
Combinations," and, therefore, should be classified separately on the balance
sheet as intangible assets. SFAS No. 141, and SFAS No. 142, "Goodwill and Other
Intangible Assets," became effective for transactions subsequent to June 30,
2001 with the disclosure requirements of SFAS No. 142 required as of January 1,
2002. SFAS No. 141 requires that all business combinations initiated after June
30, 2001 be accounted for using the purchase method and that intangible assets
be disaggregated and reported separately from goodwill. SFAS No. 142 established
new accounting guidelines for both finite lived intangible assets and indefinite
lived intangible assets. Under the statement, intangible assets should be
separately reported on the face of the balance sheet and accompanied by
disclosure in the notes to financial statements. SFAS No. 142 scopes out
accounting utilized by the oil and gas industry as prescribed by SFAS No. 19,
and is silent about whether or not its disclosure provisions apply to oil and
gas companies. Apache does not believe that SFAS No. 141 or 142 change the
classification of oil and gas mineral rights and the Company continues to
classify these assets as part of oil and gas properties. The

19

Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral
rights to an upcoming agenda, which may result in a change in how Apache
classifies these assets.

Should such a change be required, the amounts related to business
combinations and major asset purchases after June 30, 2001 that would be
classified as "intangible undeveloped mineral interest" was $78 million and $259
million as of December 31, 2002 and December 31, 2003, respectively. The amounts
related to business combinations and major asset purchases after June 30, 2001
that would be classified as "intangible developed mineral interest" was $332
million and $1.4 billion as of December 31, 2002 and December 31, 2003,
respectively. Intangible developed mineral interest amounts are presented net of
accumulated DD&A. Accumulated DD&A was estimated using historical depletion
rates applied proportionately to the costs of the acquisitions to be classified
as "intangible developed mineral interest". The amounts noted above only include
mineral rights acquired in business combinations or major asset purchases, and
exclude those acquired individually or in groups as we have not historically
tracked these in this manner. The Company has also not historically tracked the
amount of mineral rights in the proved property balances related to producing
leases or relinquished leases. We are currently identifying a methodology to do
so for transactions subsequent to June 30, 2001.

The numbers above are based on our understanding of the issue before the
EITF, if all mineral rights associated with unevaluated property and producing
reserves were deemed to be intangible assets:

- mineral rights with proved reserves that were acquired after June 30,
2001 and mineral rights with no proved reserves would be classified as
intangible assets and would not be included in oil and gas properties on
our consolidated balance sheet;

- results of operations and cash flows would not be materially affected
because mineral rights would continue to be amortized in accordance with
full cost accounting rules; and

- disclosures required by SFAS Nos. 141 and 142 relative to intangibles
would be included in the notes to our financial statements.

If the accounting for mineral rights is ultimately changed, transitional
guidance for intangible assets permits the reclassification of only amounts
acquired after the effective date of SFAS Nos. 141 and 142 if records were not
previously maintained to track acquisition costs based on their intangible or
tangible nature. Lack of these records prior to the effective date could result
in the loss of comparability between historical balances of tangible and
intangible asset balances and among companies in the industry.

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.

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 2003, 2002 and 2001, their
review covered 78, 68 and 61 percent of the reserve value, respectively.

20

Bad Debt Expense

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. Generally, our crude oil and natural gas
receivables are typically collected within two months. However, during 2001 and
2002, we experienced a gradual decline in the timeliness of receipts from EGPC
for our oil and gas sales. Deteriorating economic conditions during 2001 and
2002 in Egypt lessened the availability of U.S. dollars, resulting in an
additional one to two month delay in receipts from EGPC. While hard currency
shortages in Egypt could lead to further delays, we did not experience any
further delays in 2003. Please refer to the Future Trends section in this Item 7
for additional discussion concerning our Egyptian receivables. 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.

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 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 2 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.

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 ARO
liability, a corresponding adjustment is made to the oil and gas property
balance. In addition, increases in the discounted ARO liability resulting from
the passage of time will be reflected as accretion expense in the consolidated
statement of operations.

SFAS No. 143 requires a cumulative adjustment to reflect the impact of
implementing the statement had the rule been in effect since inception. The
Company, therefore, calculated the cumulative accretion expense on the ARO
liability and the cumulative depletion expense on the corresponding property
balance. The sum of these cumulative expenses was compared to the depletion
expense originally recorded. Because the historically recorded depletion expense
was higher than the cumulative expense calculated under SFAS No. 143, the
difference resulted in a gain which the Company recorded as cumulative effect of
change in accounting principle on January 1, 2003.

Upon implementation, the Company also had to determine if the statement
required us to recalculate our historical full-cost ceiling tests (see Note 1 of
Item 15 of this Form 10-K). The Company chose not to re-calculate its historical
full-cost ceiling tests even though its historical oil and gas property balances
would have been higher had we applied the statement from inception. We believe
this approach is appropriate because SFAS No. 143 is silent on this issue and
was not effective during the prior impairment test periods. Had a recalculation
of the historical full-cost ceiling test resulted in impairment, the charge
would have reduced the gain recorded upon adoption.
21

Going forward, our depletion expense will be reduced since we will deplete
a discounted ARO rather than the undiscounted value previously depleted. 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.

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 of Item 15 of this Form 10-K). SFAS No. 143 is silent with respect to
this issue and, although there are various views, the Company elected to
continue including the undiscounted ARO as part of future development costs,
essentially reducing the present value of its future net revenues and full-cost
ceiling limit. To compare the property balance, which included the ARO
component, to the full-cost ceiling limit, which has been reduced by a similar
abandonment cost, we netted the ARO liability against the property balance. The
Company believes its view is appropriate since there must be a comparable basis
between the net book value of the properties and the full-cost ceiling
limitation. Another widely contemplated view is to exclude the ARO from future
development costs when calculating the full-cost ceiling limitation and not
reduce the carrying amount of capitalized costs by the related liability. This
approach would result in a higher full-cost ceiling limitation and a
comparatively higher net oil and gas property balance.

Income Taxes

Oil and gas exploration and production is a global business. 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).

We intend to permanently reinvest earnings from our international
operations; therefore, we do not recognize deferred taxes on the unremitted
earnings of our international subsidiaries. If it becomes apparent that some or
all of the unremitted earnings will be remitted, we would then reflect taxes on
those earnings.

Derivatives

Apache uses commodity derivative contracts on a limited basis to manage its
exposure to oil and gas price volatility and accounts for the contracts in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS 133). 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 contracts designated and qualifying as cash flow
hedges, realized gains and losses are generally recognized in oil and gas
production revenues when the forecasted transaction occurs. SFAS 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. The Company does not currently enter into derivative or other
financial instruments for trading purposes.

The estimate of fair value of Apache's derivative contracts requires
substantial judgment; however, the Company's derivative contracts are generally
exchange traded or valued by reference to commodities 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 Commodity Risk under Item 7a of this
Form 10-K for commodity price sensitivity information).

RESULTS OF OPERATIONS

This section includes a discussion of our 2003 and 2002 results of
operations. Apache has six reportable segments, which are the United States,
Canada, Australia, Egypt, the North Sea and Other International.

22

These segments are primarily in the business of crude oil and natural gas
exploration and production. Please refer to Note 14 of Item 15 of this Form 10-K
for segment information.

Acquisitions and Divestitures

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. The North Sea assets further
diversified our reserves and production, while the Gulf of Mexico properties
provide opportunities in an area that historically enjoys the highest netback
natural gas pricing in North America.

Seventy-two percent of our acquisition capital was spent to acquire North
Sea and Gulf of Mexico properties from BP. Another 13 percent was spent to
acquire additional Gulf of Mexico properties from Shell. The balance of our
activity involved smaller acquisitions in Australia and North America. The North
Sea acquisition establishes a new international operating region for Apache,
providing the potential for future internal growth. The Gulf of Mexico
properties acquired from BP and Shell lay down well with our existing Gulf of
Mexico properties and provide promising prospects for future exploration,
exploitation and development activities. As we have in the past, we expect to
identify and take advantage of efficiencies in field operations and economics of
scale, while concurrently accelerating production and adding reserves.

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 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 (see Note 4 under Item 15 of this Form 10-K).

Prior to the Shell transaction, Morgan Stanley Capital Group, Inc. (Morgan
Stanley) paid Shell $300 million to acquire an overriding royalty interest in a
portion of the reserves to be produced over the next four years. Shell's sale of
an overriding royalty interest to Morgan Stanley is commonly known in the
industry as a volumetric production payment (VPP). Under the terms of the VPP,
Morgan Stanley is to receive a fixed volume of oil and gas production over the
four-year term. The VPP reserves and production will not be recorded by Apache.
In addition, a $60 million liability for the future cost to produce and deliver
volumes subject to the VPP has been recorded by the Company because the
overriding royalties are not burdened by production costs. This liability will
be amortized as the volumes are produced and delivered to Morgan Stanley.

In 2002, we elected to exercise patience on the acquisition front, in
anticipation of lower acquisition prices. We focused our attention on managing
our financial structure by building equity and paying down debt so we would be
in a position to act quickly when attractive assets became available at
reasonable prices. Our oil and gas acquisitions in 2002 totaled approximately
$350 million, adding 49 MMboe to our reserve base, far short of the $880 million
we expended during 2001, which added 213 MMboe of proved reserves. In addition,
the acquisitions added $3 million and $146 million of production, processing and
transportation facilities in 2002 and 2001, respectively, and $197 million of
goodwill in 2001.

Seventy-five percent of our 2002 acquisition activity occurred in the U.S.
and was related to the acquisition of properties primarily located in two
Southern Louisiana parishes. The balance of our 2002 acquisitions primarily
related to two acquisitions in Canada.

In connection with our 2002 South Louisiana acquisition, we entered into
costless-collar hedges to protect Apache from the potential for falling gas
prices and to protect the economics of the transaction. These hedges are
consistent with some of our 2001 and 2000 acquisitions, whereby we entered into
and assumed fixed-price commodity swaps and costless-collars that protected
Apache from falling commodity prices. This enabled us to better predict the
financial performance of our acquisitions. See Note 4 of Item 15 for the terms
of the Company's hedging activity.

23

Our acquisitions over the last three years helped us maintain diversity in
terms of hydrocarbon product (oil or gas), geologic risk and geographic
location. As shown in Note 15 of this Form 10-K, our 2003 year-end international
reserves as a percentage of total reserves climbed to 30 percent from 22 percent
at year-end 2002, while our international average daily production remained
constant at 36 percent of our total production in both 2003 and 2002. Our
hydrocarbon product mix on a boe basis in 2003 remained relatively constant at
49 percent natural gas and 51 percent oil, compared to 51 percent natural gas
and 49 percent oil in 2002. While the U.S., a highly stable 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.

Note that, in light of the uncertainty of how the collapse of Enron Corp.
would impact the derivatives markets, we closed all of our derivatives positions
in October and November 2001, most of which were associated with prior
acquisitions, recognizing a net gain in 2001 of $10 million with additional
gains and losses to be recognized over the original life of the hedge. A net
gain of $24 million was recognized in 2002 and a $4 million net loss was
recognized in 2003. These, as well as the unwinding of our gas price swaps
associated with advances from gas purchasers, increased the Company's average
natural gas price by $.02 per Mcf during 2003, $.04 per Mcf during 2002 and $.09
per Mcf during 2001. They increased our average crude oil price by $.03 per bbl
during 2003, $.15 per bbl during 2002, and reduced our average crude oil price
by $.42 per bbl during 2001. There is no material affect in future periods
related to closed derivative positions.

We routinely evaluate our property portfolio and divest those that are
marginal or no longer fit into our strategic growth program. We divested $59
million, $7 million and $348 million of properties during 2003, 2002 and 2001,
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.
Imbalances in the supply and demand for oil and natural gas can have dramatic
effects on the prices we receive for our 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.

Apache 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.

2) Australia, which has a local market with limited demand and
infrastructure.

3) Egypt, which has a local market and where the price received for the
majority of our production is currently indexed to a weighted-average
Dated-Brent crude oil price.

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

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.

24

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 2003 oil revenues from areas outside the U.S. rose to approximately 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