APACHE CORP - 10-K Annual Report

Back to GetFilings.com

.
.
.

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

1

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.

2

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

3

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

4

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.

5

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.
6

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).

7

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:

8

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

9

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
much lesser extent, initial production from China. The percentage contribution
from all other areas fell, reflecting the impact from the North Sea revenues and
China revenues.

In 2002, oil revenues outside the U.S. reached approximately 65 percent of
consolidated oil revenues, up from 60 percent in 2001. This increase primarily
occurred in Egypt and Australia where crude oil revenues rose to 29 percent and
20 percent of total oil revenues, respectively. Canada contributed 16 percent of
oil revenue, down from 17 percent in 2001.

Natural Gas Contribution

The preponderance of consolidated natural gas revenues comes from our North
American operations. In 2003, 89 percent of Apache's natural gas revenues came
from North America, 62 percent from the U.S. and 27 percent from Canada. The
U.S. contribution rose 11 percent from 2002, primarily because of the properties
acquired from BP and Shell in 2003, and properties acquired in South Louisiana
in December 2002. Our U.S. Gulf Coast region, which contributed 71 percent of
Apache's U.S. 2003 production, is characterized by reservoirs which demonstrate
high initial production rates followed by steep declines when compared to most
other U.S. producing areas. Higher U.S. natural gas prices also contributed, but
to a much lesser extent. Canada's contribution was down two percent from 2002
primarily because of the production growth in the U.S. Egypt's contribution to
total gas revenues declined to eight percent from 15 percent in 2002. Egypt's
total natural gas revenues were relatively flat year-over-year, as additional
revenues generated from higher natural gas prices were offset by lower
production-generated revenues. Australia's contribution to 2003 natural gas
revenues declined to three percent from five percent in 2002.

In 2002, 80 percent of Apache's natural gas revenues came from the North
American market, 51 percent from the U.S. and 29 percent from Canada. The
remaining 20 percent was split between Egypt, 15 percent, and Australia, 5
percent.

25

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

26

Natural Gas Revenues

Our 2003 consolidated natural gas revenues climbed $916 million with a
$1.74 per Mcf increase in our average natural gas price realizations generating
an additional $686 million of revenues. Higher production added the remaining
$230 million. Virtually all of the additional revenues attributable to price
came from the U.S. and Canada. The additional revenues attributable to
production were concentrated in the U.S., where natural gas production increased
32 percent, reflecting the impact from the 2003 BP and Shell acquisitions and
the December 2002 acquisition of the South Louisiana properties. Partially
offsetting the additional U.S. production revenues were lower production in
Egypt, Australia and Canada, down seven percent, six percent and three percent,
respectively. Egypt's lower production related to gas production curtailment
imposed by EGPC and scheduled plant shutdowns, while Australia saw lower
customer demand.

Consolidated natural gas revenues declined $391 million in 2002, consistent
with an $.83 per Mcf decline in the weighted-average realized price for natural
gas and a four percent decline in production. The price decline reduced revenues
by $342 million, while lower gas production reduced revenues by another $49
million. A gas production decline of 18 percent was experienced in the U.S.,
with declines of 21 percent and 13 percent in the Gulf Coast and Central
regions, respectively. The Gulf Coast region, which contributed 61.5 percent of
Apache's U.S. 2002 production, is characterized by reservoirs which demonstrate
high initial rates followed by steep declines when compared to other US
producing regions. Natural decline coupled with capital curtailments, property
sales in late 2001 and back-to-back hurricanes in September and October 2002
contributed to the production decline in the U.S. Collectively, Canada, Egypt,
Australia and Argentina saw a 13 percent increase in natural gas production.
Canada's increase was the result of previous acquisitions and subsequent
drilling activity, coupled with successful results at Ladyfern, which offset
natural decline at Zama. Egypt's increase also came from previous acquisitions
and subsequent drilling activity. See Note 3 of Item 15 of this 10-K for further
discussion of acquisition and divestiture activity.

We have used long-term, fixed-price physical contracts to lock in a small
portion of our domestic future natural gas production. The contracts provide a
measure of protection to the Company in the event of decreasing natural gas
prices and represented approximately nine and 11 percent of our 2003 and 2002
domestic natural gas production, respectively. In 2003, these contracts reduced
our average realized price $.08 per Mcf. In 2002, these contracts added $.01 per
Mcf. Additionally, substantially all of our natural gas production sold in
Australia is subject to long-term fixed-price contracts that are periodically
adjusted for changes in Australia's consumer price index. Our realized prices
are also impacted by a change in the value of the Australian dollar relative to
the U.S. dollar. In 2003, we saw an increase in our realized prices primarily
because of the stronger Australian dollar.

Crude Oil Revenues

Our 2003 consolidated oil revenues increased $698 million with a 34 percent
increase in oil production generating an additional $531 million of revenues.
Crude oil prices improved in all areas, pushing our worldwide weighted-average
crude oil price up $2.98 per barrel, adding the remaining $167 million. Revenues
from properties acquired in the North Sea accounted for over half of the
increase in oil revenues attributable to production. A portion of the revenue
from the North Sea is tied to a separate crude oil physical sales contract
entered into in conjunction with the acquisition. See Note 4 of Item 15 of this
Form 10-K for a discussion of the terms of this contract. Production in the U.S.
increased 31 percent, primarily from the Gulf of Mexico BP properties and to a
lesser extent from properties acquired from Shell and in South Louisiana in
December 2002. Initial production from China and a nine percent increase in
production from Egypt also contributed to the revenue gains.

Oil revenues improved $137 million in 2002 with both a higher realized
price and higher production. The weighted-average realized price for oil
improved $1.60 per barrel, adding $86 million to oil revenues, while oil
production gains added another $51 million. The price improvement was across the
board, while production gains of 29 percent and 12 percent occurred in Australia
and Egypt, respectively. The Legendre, Simpson and Gibson/South Plato
developments drove Australia's gain, while Egypt's increase was related to the
Repsol acquisition in 2001 and subsequent drilling. U.S. production declined
nine percent related to natural decline,

27

back-to-back hurricanes in late September and early October and property sales.
See Note 3 of Item 15 of this Form 10-K for further discussion of acquisition
and divestiture activity.

Operating Expenses

The tables below present a comparison of our expenses on an absolute dollar
basis and an equivalent unit of production (boe) basis. Our discussion may
reference either expenses on a boe basis or expenses on an absolute dollar
basis, or both, depending on their relevance. During 2003, we saw tremendous
growth in production and reserves accompanied by a corresponding rise in
operating costs.

Depreciation, Depletion and Amortization

Apache's full-cost DD&A expense is driven by many factors including certain
costs incurred in the exploration, development, and acquisition of producing
reserves, production levels, and estimates of proved reserve quantities and
future developmental costs.

2003 full-cost DD&A expense of $1 billion is comprised of the U.S., $489
million; Canada, $158 million; Egypt, $161 million; Australia, $110 million; the
North Sea, $72 million; and China, $12 million. Full-cost DD&A expense increased
$220 million compared to 2002. The majority of the increase in absolute costs
was in the U.S., up $119 million; and the North Sea, $72 million; related to
increases in production driven by our recent acquisitions. First production in
China added $12 million. The remaining increase is concentrated in Egypt and
Australia.

On a boe basis, our average full-cost DD&A rate in 2003 increased $.30 to
$6.59 from $6.29 in 2002. The bulk of the increase occurred in Australia, Egypt
and the U.S. contributing $.12, $.09 and $.06, respectively. The increases in
Australia and Egypt reflect the impact of higher finding and development costs,
while the increase in the U.S. reflects the impact of higher finding and
development costs and higher acquisition costs. China and the North Sea each
added $.03, while Canada's rate lowered the consolidated rate $.03.

In 2002, our full-cost DD&A expense increased $24 million. Areas outside
the U.S. saw an increase in their expense, while DD&A expense decreased in the
U.S. The areas experiencing the largest increase in absolute costs were Egypt,
up $29 million and Australia, up $24 million (consistent with their overall
increase in production), while the U.S. experienced a $39 million decline in
full-cost DD&A expense on lower production levels. Canada also had higher DD&A
expense of $7 million relating to higher production levels.

On a boe basis our 2002 full-cost DD&A rate rose $.24 to $6.29. The U.S.
contributed $.13 to the increase in rate, driven by higher finding costs and
higher future development costs. The remaining increase in the consolidated rate
is split between Egypt and Australia. The impact from Egypt is related to higher
finding and development costs. The impact from Australia is primarily related to
higher future development costs.

Depreciation of other assets increased $10 million, in 2003 in line with
our overall growth.

28

Impairments

We assess all of our unproved properties for possible impairment on a
quarterly basis based on geological trend analysis, dry holes or relinquishment
of acreage. When an impairment occurs, costs associated with these properties
are generally transferred to our proved property base where they become subject
to amortization. In some of our international exploration plays, however, we
have not yet established proved reserves. As such, any impairments in these
areas are immediately charged to earnings. During 2001, we impaired a portion of
our unproved property costs in Poland and China by $65 million ($41 million
after-tax). In 2002, we impaired an additional $20 million in Poland ($12
million after-tax). In 2003, we impaired the remaining $13 million ($8 million
after-tax) of unproved property costs in Poland.

Goodwill is subject to a periodic fair-value-based impairment assessment
beginning in 2002. Goodwill totals $189 million at December 31, 2003 and no
impairment was recorded in 2003 or 2002. For further discussion, see Note 1 of
Item 15 of this Form 10-K.

Lease Operating Costs

Lease operating costs (LOE) is generally comprised of several components;
direct operating costs, repair and maintenance costs, workover costs and ad
valorem costs. LOE is driven in part by the type of commodity produced, the
level of workover activity and the geographical location of the properties. Oil
is inherently more expensive to produce than natural gas. Workovers continue to
be an important part of our strategy. They enable us to exploit our existing
reserves by accelerating production and taking advantage of high priced
environments. Repair and maintenance costs are higher on offshore properties and
in areas with plants and facilities.

During 2003, the Company saw a substantial increase in its LOE costs on
both an absolute dollar basis and boe basis. The majority of the increase on an
absolute dollar basis was expected, given the BP and Shell acquisitions and the
acquisition of the South Louisiana properties. On a boe basis, 2003 LOE
increased $.92 to $4.59, with all of the increase occurring outside the U.S. The
North Sea properties, which are located offshore and produce oil, added
approximately $109 million of costs, increasing our consolidated rate $.46 per
boe. Canada's LOE costs increased $44 million, adding $.30 to our consolidated
boe rate. The impact from a weaker U.S. dollar, a full year of LOE on properties
acquired in the second half of 2002, costs associated with new fields, and
higher power and fuel rates drove the increase in Canadian costs. Egypt's
operating costs increased $13 million, adding $.09 to the overall rate. The
majority of the increase in Egypt was attributable to higher workover activity.
Australia's LOE increased $7 million because of an increase in repair and
maintenance and higher oil production. Australia added $.10 to the overall boe
rate. The LOE rate in the U.S. declined as the impact from the additional costs
associated with the acquisitions discussed above were more than offset by the
incremental production. The U.S. reduced the overall rate by $.05 per boe.

During 2002, LOE was $3.67 per boe, a $.49 increase from 2001. Higher
absolute costs accounted for 94 percent, $.46 per boe, of this rate increase,
with lower production accounting for the remaining $.03 per boe. We experienced
higher absolute costs in the Gulf Coast region, Egypt and Canada. In the Gulf
Coast region increased repairs and maintenance, related to both routine
operations and hurricane repairs, generally higher costs on properties operated
by others on offshore Gulf of Mexico properties and increased workover activity
in the region, contributed to higher LOE. In Egypt, higher workover activity on
the Khalda, South Umbarka and East Bahariya concessions drove up LOE. In Canada,
the increased costs reflect the impact of the Fletcher, Conoco and Burlington
acquisitions, which carry higher production costs than our other operations, and
increased workover activity, with the heaviest activity at House Mountain,
Hatton, Zama and Simonette fields.

Gathering and Transportation Costs

During 2002, the Company adopted Emerging Issues Task Force Issue 00-10,
"Accounting for Shipping and Handling Fees and Costs." Prior to adoption,
amounts paid to third parties for transportation had been reported as a
reduction of revenue instead of an increase in operating expenses. Recent
property acquisitions and their associated transportation arrangements have
increased the significance of transportation costs paid to
29

third parties. For comparative purposes, previously reported transportation
costs paid to third parties were reclassified as corresponding increases to oil
and gas production revenues and operating expenses with no impact on income
attributable to common stock.

Apache generally sells oil and natural gas under two types of transactions,
both of which include a transportation charge. One is a netback arrangement,
under which Apache sells oil or natural gas at the wellhead and collects a
price, net of transportation incurred by the purchaser. Under the other
arrangement, Apache sells oil or natural gas at a specific delivery point, pays
transportation to a carrier and receives from the purchaser a price with no
transportation deduction. In both the U.S. and Canada, Apache sells oil and
natural gas under both types of arrangements. In the North Sea, Apache pays
transportation to a carrier and receives a purchase price with no transportation
deduction. In Egypt and Australia, oil and natural gas are sold under the
netback arrangement. Gathering and transportation costs disclosed here only
include transportation paid by Apache to a carrier.

These costs are primarily related to the transportation of natural gas in
our North American operations. In 2003, these costs totaled $28 million in
Canada and $21 million in the U.S., up from $21 million and $17 million in 2002,
respectively. The increase in Canada primarily involved higher third-party
transportation charges for gas transported from several fields and increased
production volumes from 2002 acquisitions. Canada also incurred transportation
charges for crude oil as we began taking our oil "in-kind" and marketing it
ourselves instead of selling it at the lease. The increase in the U.S. is
related to the higher production from the Gulf of Mexico acquisitions. In the
North Sea, these costs are related to the transportation of crude oil and
totaled $11 million in 2003. Overall, transportation costs in 2002 were
relatively flat to 2001.

Severance and Other Taxes

Severance and other taxes are comprised primarily of severance taxes on
properties onshore and in state or provincial waters in the U.S. and Australia.
In both 2003 and 2002, these severance taxes, which are generally based on a
percentage of oil and gas production revenues, represented over 60 percent of
the total severance and other taxes expense incurred. The other tax component is
primarily made up of the Australian Petroleum Resources Rent Tax (PRRT), to
which Apache first became subject in 2002, the Petroleum Revenue Tax (PRT) on
the North Sea properties and the Canadian Large Corporation Tax, Saskatchewan
Capital Tax, Saskatchewan Resource Surtax and Freehold Mineral Tax. Oil and gas
production revenues generated from Egypt, Canada and the North Sea are not
subject to severance taxes.

In 2003, severance and other taxes totaled $122 million ($53 million in the
U.S., $28 million in Australia, $20 million in the North Sea, $20 million in
Canada and $1 million in Argentina). Severance and other taxes increased 81
percent or $54 million. Twenty million dollars of the increase is associated
with North Sea's PRT expense. Canadian taxes increased $10 million as a result
of exchange rate increases and higher prices in 2003, and a $2 million refund in
2002. U.S. and Australia severance taxes increased $17 million and $7 million,
respectively, in line with higher production revenues.

In 2002, severance and other taxes totaled $67 million, comprised of U.S.,
$35 million, Australia, $23 million and Canada, $9 million. Overall, severance
and other taxes decreased $7 million. A $14 million decline in U.S. severance
taxes, and a $3 million decline in Canada Saskatchewan Resource Surtax were
partially offset by initial PRRT of $4 million and a $7 million increase in
Australian severance taxes. The decrease in U.S. severance taxes reflects the
impact of lower gas price realizations. The increase in Australia's severance
taxes was attributable to higher oil price realizations and a change in
production mix as a higher portion of production was from properties in
provincial waters, such as Legendre and Harriet, relative to production from
federal waters. Canada's decline was primarily related to a refund of the
Saskatchewan Resource Surtax.

General and Administrative Expenses

General and administrative expenses (G&A) of $.91 per boe for 2003
increased $.07 per boe over 2002. Absolute costs increased $34 million, or 32
percent. Over $11 million, or 34 percent, is associated with expensing
compensation, including Stock Appreciation Rights (SARs), stock options,
restricted stock and
30

incremental incentive compensation, in light of our record year. The increased
stock compensation expense stems from Apache's decision to expense stock related
compensation plans (see Note 9 in Item 15 of this Form 10-K). Approximately $9
million, or 28 percent, of the increase is related to our new North Sea
operations. The balance of the increase was related to the Company's decision to
increase its charitable contributions, expansion of the Company's new gas
marketing group and transition costs incurred on acquisitions.

Overall, general and administrative expenses trended higher in 2002, rising
$.13 to $.84 per boe. On an absolute cost basis, thirty-eight percent of the
increase is tied to rising medical costs, a sharp increase in premiums on
business insurance policies renewed subsequent to the September 11, 2001
terrorist attacks and the addition of a sizeable political risk insurance
package added in mid-2001. The remaining increase is related to non-recurring
employee separation costs, a consequence of our region realignment in the U.S.,
higher outside legal support costs related to arbitration proceedings with our
gas marketer, Cinergy and litigation with Predator (see Note 11 of this Form
10-K), costs associated with the implementation of and compliance with various
sections of Sarbanes-Oxley, and a full year of expense related to additional
staff and office costs incurred with the acquisition of Canadian subsidiaries of
Fletcher during 2001. Realignment of our three U.S. regions into two involved
both reassignment and reduction of personnel. All corresponding costs were
expensed as incurred.

Financing Costs, Net

The major components of net financing costs are interest expense and
capitalized interest. Net financing costs increased $2 million compared to 2002
with a $13 million increase in expense largely offset by an increase in
capitalized interest. Five million dollars of the increase is interest expense
related to the write-off of unamortized fees triggered by the retirement of
preferred interests of subsidiaries discussed below. The remaining $8 million of
higher interest expense was attributable to a higher average debt balance in
2003 compared to 2002. Capitalized interest increased $12 million driven by a
higher unproved property balance associated with acquisitions and an active
drilling program. If net financing costs included distributions from Preferred
Interests of Subsidiaries, net financing costs would have decreased by
approximately $5 million. Net financing costs decreased by five percent in 2002.
Lower average debt outstanding during 2002 resulted in a decrease in interest
expense of $23 million compared to 2001. A reduction in capitalized interest of
$16 million, associated with lower unproved property balances, partially offset
this decrease. Our weighted-average cost of borrowing on December 31, 2003 was
6.4 percent compared to 6.3 percent on December 31, 2002. The rate is higher at
year-end 2003 as a lower percentage of our debt is at floating rates, which
carry a lower rate than fixed-rate debt.

Provision for Income Taxes

2003 income tax expense of $827 million was $482 million or 140 percent
higher than the 2002. The higher taxes were primarily associated with higher
income in 2003 and, to a lesser extent, a higher effective tax rate. Our
effective tax rate increased primarily because of $172 million of additional
deferred tax expenses resulting from currency fluctuations. For a discussion of
Apache's sensitivity to foreign currency fluctuations, please refer to "Foreign
Currency Risk" under Item 7A of this Form 10-K. The impact caused by currency
fluctuations was partially offset by a $71 million reduction in deferred tax
expense related to a reduction in Canadian federal statutory income tax rates.
Our effective tax rate for 2003 was 43.02 percent compared to 38.34 percent for
the prior year. Our 2002 effective tax rate was slightly lower than 2001.

31

OIL AND GAS CAPITAL EXPENDITURES

In 2003, Apache added 503.2 MMboe of proved reserves through acquisitions,
drilling and revisions, replacing 330 percent of production.

In 2002, Apache added 172.1 MMboe of proved reserves through acquisitions,
drilling and revisions, replacing 138 percent of production.

The preliminary capital expenditure budget for 2004 is approximately $1.8
billion (excluding acquisitions), including $1 billion for North America.
Preliminary North American capital expenditures include $400 million in the Gulf
Coast region, $100 million in the Central region and $500 million in Canada. The
Company has estimated its international capital expenditures in 2004 at $800
million. Capital expenditures will be reviewed periodically, and possibly
adjusted throughout the year in light of changing industry conditions.

CASH DIVIDEND PAYMENTS

Apache paid a total of $6 million in dividends during 2003 on its Series B
Preferred Stock issued in August 1998. Dividends on the Series C Preferred Stock
were paid through May 15, 2002, when the shares automatically converted to
common stock (see Note 9, under Item 15 of this Form 10-K). Common dividends
paid during 2003 rose 19 percent to $67 million, reflecting the increase in
common shares outstanding and the higher common stock dividend rate. The Company
has paid cash dividends on its common stock for 39 consecutive years through
2003. Future dividend payments will depend on the Company's level of earnings,
financial requirements and other relevant factors. The Company has increased its
quarterly cash dividend 20 percent, to six cents per share from five cents per
share, effective with the November 2003 dividend payment.

CAPITAL RESOURCES

Apache's primary needs for cash are for exploration, development and
acquisition of oil and gas properties, repayment of principal and interest on
outstanding debt and payment of dividends. The Company funds its exploration and
development activities primarily through internally generated cash flows and
budgets capital expenditures based on projected cash flows. Apache routinely
adjusts capital expenditures in response to changes in oil and natural gas
prices, drilling and acquisition costs, and cash flow. The Company has

32

historically utilized net cash provided by operating activities, debt, preferred
interests of subsidiaries and equity as capital resources to obtain necessary
funding for all other cash needs.

Net Cash Provided by Operating Activities

Apache's net cash provided by operating activities during 2003 totaled $2.7
billion, an increase of 96 percent from 2002 driven by higher oil and gas
production revenues partially offset by higher operating expenses. Oil
production revenues increased with a 34 percent increase in production and a 12
percent increase in prices. Gas production revenues increased with a 13 percent
production increase and a 61 percent price increase. Net cash provided by
operating activities during 2002 decreased 28 percent to $1.4 billion from $1.9
billion in 2001. The decrease was driven by lower oil and gas production
revenues and slightly higher operating expenses. Oil and gas production revenues
fell with a 22 percent decline in gas prices, which was partially offset by a
seven percent improvement in oil prices. The impact of lower gas production was
partially offset by rising oil production.

Debt

At December 31, 2003, Apache had outstanding debt of $135 million under its
commercial paper program and uncommitted lines of credit and a total of $2.2
billion of other debt. This other debt included notes and debentures maturing in
the years 2005 through 2096. Based on our current plan for capital spending and
projections of debt and interest rates, interest payments on the Company's debt
for 2004 are projected to be $160 million (using weighted-average balances for
floating rate obligations).

On June 3, 2002, Apache entered into a new $1.5 billion global credit
facility to replace its existing global and 364-day credit facilities. The new
global credit facility consists of four separate bank facilities: a $750 million
364-day facility in the United States; a $450 million five-year facility in the
United States; a $150 million five-year facility in Australia; and a $150
million five-year facility in Canada. Loans under the global credit facility do
not require the Company to maintain a minimum credit rating.

The five-year facilities are scheduled to mature on June 3, 2007 and the
364-day facility is currently scheduled to mature on May 28, 2004. The 364-day
facility allows the Company the option to convert outstanding revolving loans at
maturity into one-year term loans. The Company may request extensions of the
maturity dates subject to approval of the lenders.

Please see Note 6 "Debt" of Item 15 for a summary of the financial
covenants of the global credit facility. The negative covenants include
restrictions on the Company's ability to create liens and security interests on
our assets (with exceptions for liens typically arising in the oil and gas
industry, purchase money liens and liens arising as a matter of law, such as tax
and mechanics liens), restrictions on Apache's ability to merge with another
entity, unless the Company is the surviving entity, and a restriction on our
ability to guarantee the debt of entities not within our consolidated group.

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances at December 31, 2003 and 2002 were classified as
long-term debt in the accompanying consolidated balance sheet as the Company has
the ability and intent to refinance such amounts on a long-term basis through
either the rollover of commercial paper or available borrowing capacity under
the U.S. five-year facility and the 364-day facility. If the Company is unable
to issue commercial paper following a significant credit downgrade or
dislocation in the market, the Company's U.S. five-year credit facility and
364-day credit facility are available as a 100 percent backstop. The
weighted-average interest rate for commercial paper was 1.19 percent in 2003 and
1.85 percent in 2002.

Preferred Interests of Subsidiaries

During 2001, several of our subsidiaries issued a total of $443 million
($441 million, net of issuance costs) of preferred stock and limited partner
interests to unrelated institutional investors, adding to the Company's
financial liquidity. We paid a weighted-average return to the investors of 123
basis points above the prevailing LIBOR interest rate. These subsidiaries were
consolidated in the accompanying financial

33

statements with the $437 million at December 31, 2002 reflected as preferred
interests of subsidiaries on the balance sheet.

On September 26, 2003, Apache repurchased and retired the preferred
interests issued by three of its subsidiaries for approximately $443 million,
plus an additional $1 million for accrued dividends and distributions. The
transactions involved the purchase of preferred stock issued by two of the
Company's subsidiaries for approximately $82 million and the retirement of a
limited partnership interest in a partnership controlled by a subsidiary of the
Company for approximately $361 million. Apache funded the transactions with
available cash on hand and by issuing commercial paper under its existing
commercial paper facility.

Stock Transactions

On September 13, 2001, our Board of Directors declared a 10 percent stock
dividend payable on January 21, 2002 to shareholders of record on December 31,
2001. As a result, we reclassified approximately $545 million from retained
earnings to common stock and paid-in capital, which represents the fair market
value at the date of declaration of the shares distributed. No fractional shares
were issued and cash payments totaling $891,000 were made in lieu of fractional
shares.

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

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

On January 22, 2003, we completed a public offering of approximately 19.8
million shares of common stock, including 2.6 million shares for the
underwriters' over-allotment option, for net proceeds of $554 million.

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

LIQUIDITY

During 2003, we strengthened our financial flexibility and continued to
build upon the solid financial performances of previous years. Cash will be
required to fund expenditures necessary to offset the inherent declines in
production and proven reserves typical in an extractive industry like ours.
Future success in growing reserves and production will be highly dependent on
capital resources available and our success in acquiring or finding additional
reserves. We believe that cash on hand, net cash generated from operating
activities, and unused committed borrowing capacity under our global credit
facility will be adequate to satisfy future financial obligations and liquidity
needs.

Net cash generated from operating activities is a function of commodity
prices, which are inherently volatile and unpredictable, production and capital
spending. Our business, as with other extractive industries, is a depleting one
in which each barrel produced must be replaced or the Company, and a critical
source of our future liquidity, will shrink, as stated in Item 1, "Risk Factors
Related to Our Business and Operations". Based on the year-end reserve life
index, the Company's overall decline is approximately nine percent per year.
This projection assumes the capital investment, prices, costs and taxes
reflected in our standardized measure in Item 15 -- Note 15, of this Form 10-K.
Less predictable than production declines from our proved reserves is the impact
of constantly changing oil and natural gas prices on cash flows and, therefore,
capital budgets.

34

For these reasons, we only forecast, for internal use by management, an
annual cash flow. These annual forecasts are revised monthly and capital budgets
are reviewed by management and adjusted as warranted by market conditions.
Longer term cash flow and capital spending projections are neither developed nor
used by management to operate our business.

As of December 31, 2003, available borrowing capacity under our global
credit facility was $1.4 billion. We had $34 million in cash and cash
equivalents on hand at December 31, 2003, a decrease from $52 million at the
prior year-end. In addition, the ratio of current assets to current liabilities
decreased from 1.44 at the end of last year to 1.10 at December 31, 2003.

We have assumed various financial obligations and commitments in the normal
course of operations. These contractual obligations represent known future cash
payments that we are required to make and relate primarily to long-term debt,
operating leases, pipeline transportation commitments and international
commitments. The Company expects to fund these contractual obligations with cash
generated from operating activities. The following table summarizes the
Company's contractual obligations as of December 31, 2003. Please see the
indicated Note to the Company's consolidated financial statements, under Item 15
of this Form 10-K for further information regarding these obligations.

(a) This table does not include the liability for dismantlement, abandonment
and restoration costs of oil and gas properties. Effective with adoption of
SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1,
2003, the Company recorded a separate liability for the fair value of this
asset retirement obligation. See Note 2, under Item 15 of this Form 10-K
for further discussion.

(b) This table does not include the Company's pension or postretirement benefit
obligations. See Note 11 under Item 15 of this Form 10-K for further
discussion.
- ---------------

Apache is also subject to various contingent obligations that become
payable only if certain events or rulings were to occur. The inherent
uncertainty surrounding the timing of and monetary impact associated with these
events or rulings prevents any meaningful accurate measurement, which is
necessary to assess any impact on future liquidity. Such obligations include
environmental contingencies and potential settlements resulting from litigation.
Apache's management feels that it has adequately reserved for its contingent
obligations. The Company has reserved approximately $10 million for
environmental remediation. The Company's exposure to other legal contingent
liabilities is estimated at less than $8 million and is fully reserved. The
Company does not believe it has any material exposure for any contingencies (see
Note 11 under Item 15 of this Form 10-K).

Upon closing of our acquisition of the North Sea properties, Apache will
assume BP's abandonment obligation for those properties and such costs were
considered in determining the purchase price. The purchase of the properties,
however, does not relieve BP of its liabilities if Apache does not satisfy the
abandonment obligation. Although not currently required, to ensure Apache's
payment of these costs, Apache agreed to deliver a letter of credit to BP if the
rating of our senior unsecured debt is lowered by both Moody's and

35

Standard and Poor's from the Company's current ratings of A3 and A-,
respectively. Any such letter of credit would be in an amount equal to the net
present value of future abandonment costs of the North Sea properties as of the
date of any such ratings change. If Apache is obligated to provide a letter of
credit, it will expire if either rating agency restores its rating to the
present level. The initial letter of credit amount would be 175 million British
pounds ($306 million U.S. at December 31, 2003). This amount represents the
letter of credit requirement through March 2004, and will be negotiated annually
based on Apache's future abandonment obligation estimates. In addition, under
Apache's long-term oil physical sales contract with BP, related to the BP
acquisition, Apache may be required to post margin if the mark-to-market
exposure, as defined, exceeds the credit threshold limits. The outstanding
position of the term oil physical sales contract with BP is described in greater
detail in Note 4 under Item 15 of this Form 10-K.

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

OFF-BALANCE SHEET ARRANGEMENTS

Apache does not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance liquidity and capital resource positions, or
for any other purpose. Any future transactions involving off-balance sheet
arrangements would be scrutinized and disclosed by the Company's management.

FUTURE TRENDS

Apache's strategy is to increase its oil and gas reserves, production, cash
flow and earnings through a balanced growth program that involves:

- exploiting our existing asset base;

- acquiring properties to which we can add incremental value; and

- investing in high-potential exploration prospects.

Apache's present plans are to increase 2004 worldwide capital expenditures
for exploratory and development drilling to approximately $1.8 billion from $1.5
billion in 2003. We will continue to monitor commodity prices and adjust our
capital expenditures accordingly. We will also continue to evaluate and pursue
acquisition opportunities.

Exploiting Existing Asset Base

Apache seeks to maximize the value of our existing asset base by increasing
production and reserves while containing operating costs per unit. In order to
achieve these objectives, we rigorously pursue production enhancement
opportunities such as workovers, recompletions and moderate-risk drilling, while
divesting marginal and non-strategic properties and identifying other activities
to reduce costs. Our 2003 acquisitions from BP and Shell added to our inventory
at a time of high commodity prices.

Acquiring Properties to Which We Can Add Incremental Value

Apache seeks to purchase reserves at appropriate prices by generally
avoiding auction processes where we are competing against other buyers. Our aim
is to follow each acquisition with a cycle of reserve enhancement, property
consolidation and cash flow acceleration, facilitating asset growth and debt
reduction. We evaluate potential purchases on an ongoing basis, but we are very
selective. Practically all of our 2003 acquisition activity was completed by
early July. We remained in the market during the second half of 2003, but we did

36

not identify any assets that fit our balanced-portfolio business model. We
believe attractive assets will be available, as larger energy companies look to
shed non-core assets.

Investing in High-Potential Exploration Prospects

Apache seeks to concentrate its exploratory investments in a select number
of international areas and to become the dominant operator in those regions. We
believe that these investments, although generally higher-risk, offer potential
for attractive investment returns and significant reserve additions. Our
international investments and exploration activities are a significant component
of our long-term growth strategy. They complement our North American operations,
which are more development oriented.

A critical component in implementing our three-pronged growth strategy is
maintenance of significant financial flexibility. All three rating agencies have
"A-credit ratings" on Apache's senior unsecured long-term debt, a testament to
our conservative financial structure and commitment to preserving a strong
balance sheet while building a solid foundation and competitive advantage with
which to pursue our growth initiatives.

Egyptian Receivables

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.

It is currently our intention to resolve the delays in EGPC's payments
prior to incurring the substantial capital expenditures required to develop our
deepwater interests in the West Mediterranean Concession or signing the gas
sales agreement provided for by the MOU for a minimum of 2.7 Tcf of natural gas
over 25 years from such concession.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY RISK

The major market risk exposure is in the pricing applicable to our oil and
gas production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to our United States and Canadian
natural gas production. Prices received for oil and gas production have been and
remain volatile and unpredictable. Monthly oil price realizations ranged from a
low of $25.53 per barrel to a high of $31.66 per barrel during 2003. Average gas
price realizations ranged from a monthly low of $4.11 per Mcf to a monthly high
of $6.66 per Mcf during the same period. Based on the Company's 2003 worldwide
oil production levels, a $1.00 per barrel change in the weighted-average
realized price of oil would increase or decrease revenues by $75 million. Based
on the Company's 2003 worldwide gas production levels, a $.10 per Mcf change in
the weighted-average realized price of gas would increase or decrease revenues
by $44 million.

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

We periodically enter into hedging activities on a portion of our projected
oil and natural gas production through a variety of financial and physical
arrangements intended to support oil and natural gas prices at targeted levels
and to manage our overall exposure to oil and gas price fluctuations. Apache may
use futures
37

contracts, swaps, options and fixed-price physical contracts to hedge its
commodity prices. Realized gains or losses from the Company's price risk
management activities are recognized in oil and gas production revenues when the
associated production occurs. Apache does not generally hold or issue derivative
instruments for trading purposes. As indicated in Notes 3 and 4, under Item 15
of this Form 10-K, the Company entered into several derivative positions in
conjunction with the South Louisiana acquisition in December 2002 and with the
acquisition from BP in 2003. These positions were entered into to preserve our
strong financial position in a period of cyclically high gas and oil prices and
were designated as cash flow hedges of anticipated production.

On December 31, 2003, the Company had open natural gas derivative positions
with a fair value of $(60) million. A 10 percent increase in natural gas prices
would change the fair value by $(32) million. A 10 percent decrease in prices
would change the fair value by $31 million. The Company also had open oil price
swap positions with a fair value of $(9) million. A 10 percent change in oil
prices would change the fair value by plus or minus $5 million. These fair value
changes assume volatility based on prevailing market parameters at December 31,
2003. See Note 4 under Item 15 of this Form 10-K for notional volumes associated
with the Company's derivative contracts.

INTEREST RATE RISK

Approximately 94 percent of the Company's yearend 2003 debt is term debt
with fixed interest rates, minimizing the Company's exposure to fluctuations in
short-term interest rates. At December 31, 2003, the Company had $135 million of
floating-rate debt which is subject to fluctuations in short-term interest
rates. A 10 percent change in the floating interest rate (approximately 11 basis
points) on these year-end balances, would change annual interest expense
$148,000. The Company did not have any open derivative contracts relating to
interest rates at December 31, 2003 or 2002.

FOREIGN CURRENCY RISK

The Company's cash flow stream relating to certain international operations
is based on the U.S. dollar equivalent of cash flows measured in foreign
currencies. In Australia, gas production is sold under fixed-price Australian
dollar contracts and over half the costs incurred are paid in Australian
dollars. The North Sea production is sold under U.S. dollar contracts, however,
the majority of costs incurred are paid in British pounds. Revenue and
disbursement transactions denominated in Australian dollars and British pounds
are converted to U.S. dollar equivalents based on the exchange rate as of the
transaction date. Prior to October 1, 2002, reported cash flow from Canadian
operations was measured in Canadian dollars and converted to the U.S. dollar
equivalent based on the average of the Canadian and U.S. dollar exchange rates
for the period reported. The majority of Apache's debt in Canada is denominated
in U.S. dollars and, as such, was adjusted for differences in exchange rates at
each period end and recorded as Revenues and Other. In light of the continuing
transformation of the U.S. and Canadian energy markets into a single energy
market, we adopted the U.S. dollar as our functional currency in Canada,
effective October 1, 2002. A 10 percent strengthening of the Australian and
Canadian dollars and the British pound as of December 31, 2003 will result in a
foreign currency net loss of approximately $66 million. This is primarily driven
from foreign currency effects on the Companies deferred tax liability positions
in its international operations. The Company did not have any open derivative
contracts relating to foreign currencies at December 31, 2003 or 2002.

FORWARD-LOOKING STATEMENTS AND RISK

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

38

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required
to be filed under this item are presented on pages F-1 through F-61 of this Form
10-K, and are incorporated herein by reference.

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

The financial statements for the fiscal years ended December 31, 2003 and
2002, included in this report, have been audited by Ernst & Young LLP,
independent public auditors, as stated in their audit report appearing herein.
The financial statements for the fiscal year ended December 31, 2001, included
in this report, have been audited by Arthur Andersen LLP, independent public
accountants, as stated in their audit report appearing herein. Arthur Andersen
has not consented to the inclusion of their audit report in this report. For a
discussion of the risks relating to Arthur Andersen's audit of our financial
statements, please see "Risks relating to Arthur Andersen LLP" in Item 1.

Arthur Andersen's audit reports on our consolidated financial statements
for the fiscal year ended December 31, 2001, included elsewhere in this report,
did not contain an adverse opinion or disclaimer of opinion, nor were they
qualified or modified as to uncertainty, audit scope or accounting principles.

During the year ended December 31, 2001 and through the date we dismissed
Arthur Andersen LLP, there were no disagreements with Arthur Andersen on any
matter of accounting principle or practice, financial statement disclosure, or
auditing scope or procedure which, if not resolved by Arthur Andersen's
satisfaction, would have caused them to make reference to the subject matter in
connection with their report on our consolidated financial statements for such
years; and there were no reportable events as set forth in applicable SEC
regulations.

We provided Arthur Andersen LLP with a copy of the above disclosures on
April 2, 2002. In a letter dated April 2, 2002, Arthur Andersen confirmed its
agreement with these statements.

ITEM 9A. CONTROLS AND PROCEDURES

G. Steven Farris, the Company's President, Chief Executive Officer and
Chief Operating Officer, and Roger B. Plank, the Company's Executive Vice
President and Chief Financial Officer, evaluated the effectiveness of our
disclosure controls and procedures as of December 31, 2003, the end of the
period covered by this report. Based on that evaluation and as of the date of
that evaluation, these officers concluded that the Company's disclosure controls
were effective, providing effective means to insure that information we are
required to disclose under applicable laws and regulations is recorded,
processed, summarized and reported in a timely manner. We also made no
significant changes in internal controls over financial reporting during the
quarter ending December 31, 2003 that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting.

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

39

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information set forth under the captions "Nominees for Election as
Directors", "Continuing Directors", "Executive Officers of the Company", and
"Securities Ownership and Principal Holders" in the proxy statement relating to
the Company's 2004 annual meeting of stockholders (the Proxy Statement) is
incorporated herein by reference.

Code of Business Conduct

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

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

40

PART IV

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

(a) Documents included in this report:

1. Financial Statements

Report of management........................................ F-1
Report of Independent Auditors.............................. F-2
Report of independent public accountants.................... F-3
Statement of consolidated operations for each of the three
years in the period ended December 31, 2003............... F-4
Statement of consolidated cash flows for each of the three
years in the period ended December 31, 2003............... F-5
Consolidated balance sheet as of December 31, 2003 and
2002...................................................... F-6
Statement of consolidated shareholders' equity for each of
the three years in the period ended December 31, 2003..... F-7
Notes to consolidated financial statements.................. F-8

2. Financial Statement Schedules

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

3. Exhibits

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

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

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

(b) Reports filed on Form 8-K

The following current reports on Form 8-K were filed by the Company during
the fiscal quarter ended December 31, 2003:

Item 5 -- Other Events -- dated December 18, 2003, filed December 22, 2003

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

46

SIGNATURES

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

APACHE CORPORATION

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

Dated: March 11, 2004

POWER OF ATTORNEY

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

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

REPORT OF MANAGEMENT

The financial statements and related financial information of Apache
Corporation and subsidiaries were prepared by and are the responsibility of
management. The statements have been prepared in conformity with accounting
principles generally accepted in the United States and include amounts that are
based on management's best estimates and judgments.

Management maintains and places reliance on systems of internal control
designed to provide reasonable assurance, weighing the costs with the benefits
sought, that all transactions are properly recorded in the Company's books and
records, that policies and procedures are adhered to, and that assets are
safeguarded. The systems of internal controls are supported by written policies
and guidelines, internal audits and the selection and training of qualified
personnel.

The consolidated financial statements of Apache Corporation and
subsidiaries have been audited by the independent auditors, Ernst & Young LLP
for 2003 and 2002 and Arthur Andersen LLP for 2001. Their audits included
developing an overall understanding of the Company's accounting systems,
procedures and internal controls and conducting tests and other auditing
procedures sufficient to support their opinion on the fairness of the
consolidated financial statements.

The Apache Corporation Board of Directors exercises its oversight
responsibility for the financial statements through its Audit Committee,
composed solely of outside directors who are not current employees of Apache or
who have not been employees of Apache within the past ten years. The Audit
Committee meets periodically with management, internal auditors and the
independent auditors to ensure that they are successfully completing designated
responsibilities. The internal auditors and independent auditors have open
access to the Audit Committee to discuss auditing and financial reporting
issues.

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

Roger B. Plank
Executive Vice President and Chief
Financial Officer

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

Houston, Texas
March 11, 2004

F-1

REPORT OF INDEPENDENT AUDITORS

To the Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache
Corporation (a Delaware corporation) and subsidiaries as of December 31, 2003
and 2002 and the related consolidated statements of operations, shareholders'
equity, and cash flows for each of the two years in the period ended December
31, 2003. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The financial statements of Apache Corporation
as of December 31, 2001, and for the year then ended, were audited by other
auditors who have ceased operations and whose report dated March 12, 2002
expressed an unqualified opinion on those financial statements before the
adjustments described in Note 1. Their report, however, had an explanatory
paragraph indicating that the Company, as described in Note 1 to the
consolidated financial statements, changed its method of accounting for crude
oil inventories effective January 1, 2000, and as discussed in Notes 1 and 4 to
the consolidated financial statements changed its method of accounting for
derivative instruments effective January 1, 2001.

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

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Apache
Corporation and subsidiaries as of December 31, 2003 and 2002 and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States.

As discussed above, the financial statements of Apache Corporation as of
December 31, 2001, and for the year then ended, were audited by other auditors
who have ceased operations. As described in Note 1, these financial statements
have been revised to reflect third party gathering and transportation costs as
an operating cost instead of a reduction of revenues as previously reported. We
audited the adjustments described in Note 1 that were applied to revise the 2001
consolidated statement of operations. As described in Note 1, the Company's
Board of Directors approved a five percent stock dividend and a two-for-one
stock split, and all references to number of shares and per share information in
the financial statements have been adjusted to reflect the stock dividend and
stock split on a retroactive basis. We audited the adjustments that were applied
to restate the number of shares and per share information reflected in the 2001
financial statements. Our procedures included (a) agreeing the authorization for
the five percent stock dividend and the two-for-one stock split the Company's
underlying records obtained from management, and (b) testing the mathematical
accuracy of the restated number of shares, basic and diluted earnings per share.
In our opinion, such adjustments are appropriate and have been properly applied.
However, we were not engaged to audit, review, or apply any procedures to the
2001 financial statements of Apache Corporation other than with respect to such
adjustments; accordingly, we do not express an opinion or any other form of
assurance on the 2001 financial statements taken as a whole.

As discussed in Notes 1 and 2 to the consolidated financial statements,
effective January 1, 2003, the Company change its method of accounting for Asset
Retirement Obligations and stock-based compensation.

ERNST & YOUNG LLP

Houston, Texas
March 11, 2004

F-2

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheet of Apache
Corporation (a Delaware corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of operations, shareholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Apache
Corporation and subsidiaries as of December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States.

As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for crude oil
inventories. In addition, as discussed in Notes 1 and 4 to the consolidated
financial statements, effective January 1, 2001, the Company changed its method
of accounting for derivative instruments.

ARTHUR ANDERSEN LLP

Houston, Texas
March 12, 2002

THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN
LLP, AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN. SEE ITEM 9 OF THIS FORM 10-K
FOR FURTHER INFORMATION.
F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

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

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

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

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

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

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

Stock Dividends -- On September 13, 2001, the Company's Board of Directors
declared a 10 percent stock dividend payable on January 21, 2002 to shareholders
of record on December 31, 2001. As a result, the Company reclassified
approximately $545 million from retained earnings to common stock and paid-in
capital, which represents the fair market value at the date of declaration of
the shares distributed. No fractional shares were issued and cash payments
totaling $891,000 were made in lieu of fractional shares.

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

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

All share and per share information in these financial statements and notes
thereto have been restated to reflect the 10 percent and five percent stock
dividends and the two-for-one stock split.

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

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

Allowance for Doubtful Accounts -- The Company routinely assesses the
recoverability of all material trade and other receivables to determine their
collectibility. Many of Apache's receivables are from joint interest owners on
properties of which the Company is the operator. Thus, Apache may have the
ability to withhold future revenue disbursements to recover any non-payment of
joint interest billings. Generally, the
F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's crude oil and natural gas receivables are collected within two months.
However, during 2001 and 2002, the Company experienced a gradual decline in the
timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC).
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.

The Company accrues a reserve on a receivable when, based on the judgment
of management, it is probable that a receivable will not be collected and the
amount of any reserve may be reasonably estimated. As of December 31, 2003 and
2002, the Company had an allowance for doubtful accounts of $30 million and $31
million, respectively.

Marketable Securities -- The Company accounts for investments in debt and
equity securities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." Investments in debt securities classified as "held to maturity" are
recorded at amortized cost. Investments in debt and equity securities classified
as "available for sale" are recorded at fair value with unrealized gains and
losses recognized in other comprehensive income, net of income taxes. The
Company utilizes the average-cost method in computing realized gains and losses,
which are included in Revenues and Other in the consolidated statements of
operations.

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

Property and Equipment -- The Company uses the full-cost method of
accounting for its investment in oil and gas properties. Under this method, the
Company capitalizes all acquisition, exploration and development costs incurred
for the purpose of finding oil and gas reserves, including salaries, benefits
and other internal costs directly attributable to these activities.
Historically, total capitalized internal costs in any given year have not been
material to total oil and gas costs capitalized in such year. Apache capitalized
$65 million, $52 million and $55 million of these internal costs in 2003, 2002
and 2001, respectively. Costs associated with production and general corporate
activities, however, are expensed in the period incurred. Interest costs related
to unproved properties and properties under development are also capitalized to
oil and gas properties. Unless a significant portion of the Company's proved
reserve quantities in a particular country are sold (greater than 25 percent),
proceeds from the sale of oil and gas properties are accounted for as a
reduction to capitalized costs, and gains and losses are not recognized.

Apache computes the DD&A of oil and gas properties on a quarterly basis
using the unit-of-production method based upon production and estimates of
proved reserve quantities. Unproved properties are excluded from the amortizable
base until evaluated. The cost of exploratory dry wells is transferred to proved
properties and thus subject to amortization immediately upon determination that
a well is dry in those countries where proved reserves exist. In countries where
the Company has not booked proved reserves, all costs associated with a prospect
or play are considered quarterly for impairment upon full evaluation of such
prospect or play. This evaluation considers among other factors, seismic data,
requirements to relinquish acreage, drilling results, remaining time in the
commitment period, remaining capital plans, and political, economic, and market
conditions. Geological and geophysical (G&G) costs are recorded in Proved
Property and therefore subject to amortization as incurred in mature basins. In
exploration areas, G&G costs are capitalized in Unproved Property and evaluated
as part of the total capitalized costs associated with a prospect or play. Prior
to 2003, future development costs and dismantlement, restoration and abandonment
costs, net of estimated salvage values, were added to the amortizable base.
Beginning in 2003, Apache changed its method of accounting for dismantlement,
restoration and abandonment costs (see Note 2).

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In performing its quarterly ceiling test, the Company limits, on a
country-by-country basis, the capitalized costs of proved oil and gas
properties, net of accumulated DD&A and deferred income taxes, to the estimated
future net cash flows from proved oil and gas reserves discounted at 10 percent,
net of related tax effects, plus the lower of cost or fair value of unproved
properties included in the costs being amortized. If capitalized costs exceed
this limit, the excess is charged to additional DD&A expense. Included in the
estimated future net cash flows are Canadian provincial tax credits expected to
be realized beyond the date at which the legislation, under its provisions,
could be repealed. To date, the Canadian provincial governments have not
indicated an intention to repeal this legislation. Please see Note 15 "Future
Net Cash Flows" for a discussion on calculation of estimated future net cash
flows.

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

Unproved properties are assessed quarterly for possible impairments or
reductions in value. If a reduction in value has occurred, the impairment is
transferred to proved properties. Unproved properties that are individually
insignificant are generally amortized over an average holding period. For
international operations where a reserve base has not yet been established, the
impairment is charged to earnings. During 2003 and 2002, the Company recorded
approximately $13 million ($8 million after tax) and $20 million ($12 million
after tax), respectively, in impairments of unproved property costs in Poland.
During 2001, the Company recorded a $65 million ($41 million after tax)
impairment of unproved property costs in China and Poland.

The Company has taken note of a July 2003 inquiry to the Financial
Accounting Standards Board 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 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" were $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"
were $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 depletion, depreciation and amortization (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

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

Buildings, equipment and gas gathering, transmission and processing
facilities are depreciated on a straight-line basis over the estimated useful
lives of the assets, which range from three to 20 years. Accumulated
depreciation for these assets totaled $309 million and $240 million at December
31, 2003 and 2002, respectively.

Goodwill -- The Company adopted SFAS No. 142 effective January 1, 2002.
SFAS No. 142 addresses financial accounting and reporting for acquired goodwill
and other intangible assets and supersedes Accounting Principles Board (APB)
Opinion No. 17 "Intangible Assets." As a result of this pronouncement, goodwill
is no longer subject to amortization. Rather, goodwill of each reporting unit is
tested for impairment on an annual basis, or more frequently if an event occurs
or circumstances change that would reduce the fair value of the reporting unit
below its carrying amount. Goodwill totaled $189 million at December 31, 2003
and 2002, representing the excess of the purchase price over the estimated fair
value of the assets acquired and liabilities assumed in the Fletcher Challenge
Energy (Fletcher) and Repsol YPF (Repsol) acquisitions, adjusted for currency
fluctuations. Approximately $103 million and $86 million of goodwill remain in
Canada and Egypt, respectively. Apache deemed the geographic areas to be the
reporting unit. Apache recognized no impairment of goodwill during 2003 or 2002.
Had the principles of SFAS No. 142 been applied to prior years, goodwill
amortization of $7 million ($4 million after tax) expensed during 2001 would not
have been incurred. Income attributable to common stock for the comparative
period, adjusted to exclude the effect of goodwill amortization, would have
increased diluted earnings per share by $.01.

Accounts Payable -- Included in accounts payable at December 31, 2003 and
2002, are liabilities of approximately $78 million and $43 million,
respectively, representing the amount by which checks issued, but not presented
to the Company's banks for collection, exceeded balances in applicable bank
accounts.

Revenue Recognition -- Oil and gas revenues are recognized when production
is sold to a purchaser at a fixed or determinable price, when delivery has
occurred and title has transferred, and if collectibility of the revenue is
probable.

Apache uses the sales method of accounting for gas production imbalances.
The volumes of gas sold may differ from the volumes to which Apache is entitled
based on its interests in the properties. These differences create imbalances
that are recognized as a liability only when the estimated remaining reserves
will not be

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

sufficient to enable the underproduced owner to recoup its entitled share
through production. The Company's recorded liability of $4 million for gas
imbalances on December 31, 2003 was unchanged from the prior year-end. The
liability is reflected in other non-current liabilities. No receivables are
recorded for those wells where Apache has taken less than its share of
production. Gas imbalances are reflected as adjustments to proved gas reserves
and future cash flows in the unaudited supplemental oil and gas disclosures.
Adjustments for gas imbalances totaled less than one percent of Apache's proved
gas reserves at December 31, 2003, 2002 and 2001. Cash received relating to
future revenues is deferred and recognized when all revenue recognition criteria
are met.

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

Derivative Instruments and Hedging Activities -- Apache periodically enters
into commodity derivative contracts to manage its exposure to oil and gas price
volatility. Commodity derivative contracts, which are usually placed with major
financial institutions that the Company believes are minimal credit risks, may
take the form of futures contracts, swaps or options. The oil and gas reference
prices upon which these commodity derivative contracts are based, reflect
various market indices that have a high degree of historical correlation with
actual prices received by the Company for its oil and gas production.

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

Income Taxes -- Oil and gas exploration and production is a global
business. As a result, Apache is subject to taxation on our income in numerous
jurisdictions. The Company records deferred tax assets and liabilities to
account for the expected future tax consequences of events that have been
recognized in its financial statements and tax returns. Apache routinely
assesses the realizability of its deferred tax assets. If the Company concludes
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. The Company considers 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).

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

In respect to the U. S. dollar denominated debt issued by our Canadian
subsidiaries, the Company believes any deferred tax asset generated because of
fluctuations in the U.S./Canadian dollar exchange rates is not realizable and,
consequently, no deferred tax asset should be recognized. Any potential future
deferred tax liabilities are recognized as appropriate.

Foreign Currency Translation -- The U.S. dollar has been determined to be
the functional currency for each of Apache's international operations. The
functional currency is determined country-by-country based on relevant facts and
circumstances of the cash flows, commodity pricing environment, and financing
arrangements in each country. In light of the continuing transformation of the
U.S. and Canadian energy markets into a single energy market, the Company
adopted the U.S. dollar as the functional currency in Canada, effective October
1, 2002. Prior to this, our Canadian subsidiaries' functional currency was the
Canadian dollar. Translation adjustments resulting from translating the Canadian
subsidiaries' foreign currency financial statements into U.S. dollar equivalents
were reported separately and accumulated in other comprehensive income. Some of
the Company's Canadian subsidiaries had intercompany debt denominated in U.S.
dollars. Prior to conversion, these transactions were long-term investments, and
therefore, foreign currency gains and losses were recognized in other
comprehensive income. Transaction gains and losses are recognized in Revenues
and Other. Currency translation adjustments held in other comprehensive income
on the balance sheet will remain there indefinitely unless there is a
substantially complete liquidation of the Company's Canadian operations.

The Company accounts for foreign currency gains and losses in accordance
with SFAS No. 52 "Foreign Currency Translation." Foreign currency translation
gains and losses related to deferred taxes are recorded as a component of its
provision for income taxes, while all other foreign currency gains and losses
are reflected in Revenues and Other. In 2003, the Company recorded additional
deferred tax expense of $172 million as a result of the weaker U.S. dollar (see
Note 7, Income Taxes). Foreign currency gains and losses in 2003, reflected in
Revenues and Other netted to a loss of $2 million.

Net Income Per Common Share -- Basic net income per common share is
computed by dividing income attributable to common stock by the weighted-average
number of common shares outstanding during the period. Diluted net income per
common share reflects the potential dilution that could occur if the Company's
dilutive outstanding stock options were exercised using the average common stock
price for the period and if the Company's 6.5% Automatically Convertible Equity
Securities, Conversion Preferred Stock, Series C (Series C Preferred Stock) was
converted to common stock using the conversion rate in effect during the period.
The Series C Preferred Stock converted to Apache common stock on May 15, 2002.
These potentially dilutive securities are excluded from the computation of
dilutive earnings per share when their effect is antidilutive. Contingently
issuable shares under the 2000 Share Appreciation Plan (Share Appreciation Plan)
will be excluded from the calculation of income per common share until the
stated goals are met (see Note 9).

Stock-Based Compensation -- On December 31, 2003, the Company had several
stock-based employee compensation plans, which include the Stock Option Plans,
the Performance Plan, the Share Appreciation Plan and restricted stock. These
plans are defined and described more fully in Note 9. Prior to 2003, the Company
accounted for those plans under the recognition and measurement provisions of
APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related
Interpretations. No material stock-based employee compensation cost is reflected
in 2002 and 2001 net income, as all options granted under those plans had an
exercise price equal to the market value of the underlying common stock on the
date of grant. Effective January 1, 2003, the Company adopted the fair value
recognition provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation," as amended by SFAS No. 148, prospectively to all employee awards
F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

granted, modified, or settled after January 1, 2003. Therefore, the cost related
to stock-based employee compensation included in the determination of net income
for 2003 is less than that which would have been recognized if the fair value
based method had been applied to all awards since the original effective date of
SFAS No. 123, as amended. The following table illustrates the effect on income
attributable to common stock and earnings per share had the fair value based
provisions of SFAS No. 123, as amended, been applied to all outstanding and
unvested awards for the Stock Option Plans, the Performance Plan, the Share
Appreciation Plan and restricted stock.

The effects of applying SFAS No. 123, as amended, in this pro forma
disclosure should not be interpreted as being indicative of future effects. SFAS
No. 123, as amended, does not apply to awards prior to 1995, and the extent and
timing of additional future awards cannot be predicted. The stock appreciation
rights, described in Note 9, are not included in the above table because it is a
cash based plan.

Use of Estimates -- The preparation of financial statements in conformity
with accounting principles generally accepted in the U.S. requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and related disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Certain accounting policies involve
judgments and uncertainties to such an extent that there is reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been used. Apache
evaluates its estimates and assumptions on a regular basis. The Company bases
its estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about carrying values of assets and liabilities that
are not readily apparent from other sources. Actual results may differ from
these estimates and assumptions used in preparation of its financial statements.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserve quantities and the related present value
of estimated future net cash flows therefrom (see Note 15).

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

Change in Accounting Principle -- In May 2003, the SEC issued Staff
Accounting Bulletin No. 103, "Update of Codification of Staff Accounting
Bulletins" (SAB No. 103) to update existing codification of all staff accounting
bulletins. SAB No. 103 provided new guidance regarding the calculation of the
"ceiling" or

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

limitation on the amount of oil and gas properties that can be capitalized on
the balance sheet under the full-cost method of accounting. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. SAB No. 103 codifies the view
that using end-of-period prices, as adjusted for cash flow hedges, represents
the best measure of estimated future cash flows to calculate the ceiling
limitation. Consistent with the guidance in SAB No. 103, the Company now adjusts
the end-of-period price by the effect of cash flow hedges.

Reclassifications -- To comply with the consensus reached on Emerging
Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and
Costs," third party gathering and transportation costs have been reported as an
operating cost instead of a reduction of revenues as previously reported.
Reclassifications have been made to reflect this change in prior period
statements of consolidated operations. Certain other prior period amounts have
been reclassified to conform with current year presentations.

2. NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

The $27 million ($41 million pretax) cumulative increase to earnings upon
adoption did not take into consideration potential impacts of adopting SFAS No.
143 on previous full-cost property impairment tests. The Company chose not to
re-calculate historical full-cost impairment tests (ceiling test) upon adoption
even though historical oil and gas property balances would have been higher had
the Company applied the provisions of the statement. Management believes this
approach is appropriate because SFAS No. 143 is silent on this issue and was not
effective during the prior ceiling test periods. Had the Company re-calculated
the historical full-cost ceiling tests and included the impact as a component of
the cumulative effect of adoption, the ultimate gain recognized would have
potentially been reduced. A ceiling test calculation was performed upon adoption
and at the end of each reporting period subsequent to adoption and no impairment
was
F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

necessary. In calculating ceiling limitations, the Company includes 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, the Company nets
the ARO liability against the property balance. The Company believes this is
appropriate since there must be a comparable basis between the net book value of
the properties and the full-cost ceiling limitation.

The following table is a reconciliation of the asset retirement obligation
liability since adoption (in thousands):

Asset retirement obligation upon adoption on January 1,
2003...................................................... $368,537
Liabilities incurred........................................ 392,287
Liabilities settled......................................... (35,315)
Accretion expense........................................... 37,763
Revisions in estimated liabilities.......................... (23,497)
--------
Asset retirement obligation at December 31, 2003............ $739,775
========

Liabilities incurred during the period primarily relate to asset retirement
obligations assumed in connection with the BP p.l.c. (BP) Gulf of Mexico, BP
North Sea and Shell Exploration and Production Company (Shell) property
acquisitions. Liabilities settled during the period relate to individual
properties plugged and abandoned, and approximately $2.8 million of liabilities
associated with property sold. The downward revision to the estimated liability
resulted primarily from having an independent review of expected obligations of
abandoning the North Sea platforms, offset by the Company's annual reassessment
of the expected cash outflows and assumptions inherent in the ARO calculation.

The pro forma asset retirement obligation would have been approximately
$334 million at January 1, 2002 had the Company adopted the provisions of SFAS
143 on January 1, 2002. The following table shows the pro forma effect of the
implementation on the Company's Income Attributable to Common Stock and Net
Income per Common Share had SFAS No. 143 been adopted by the Company on January
1, 2001.

In January 2003, the FASB issued Interpretation No. 46 "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires a company to consolidate a variable
interest entity (VIE) if the company has a variable interest (or combination of
variable

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

interests) that is exposed to a majority of the entity's expected losses if they
occur, receive a majority of the entity's expected residual returns if they
occur, or both. In addition, more extensive disclosure requirements apply to the
primary and other significant variable interest owners of the VIE. This
interpretation applies immediately to VIEs created after January 31, 2003, and
to VIEs in which an enterprise obtains an interest after that date. It is also
generally effective for the first fiscal year or interim period beginning after
December 31, 2003, to VIEs in which a company holds a variable interest that is
acquired before February 1, 2003. This interpretation did not affect the
Company's consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes standards on how companies classify and measure certain financial
instruments with characteristics of both liabilities and equity. The statement
requires that the Company classify as liabilities the fair value of all
mandatorily redeemable financial instruments that had previously been recorded
as equity or elsewhere in the consolidated financial statements. This statement
is effective for financial instruments entered into or modified after May 31,
2003, and otherwise effective for all existing financial instruments, except for
minority interests in limited-life entities, beginning in the third quarter of
2003. As stated in Note 12, the Company paid off the Preferred Interests of
Subsidiaries in September 2003; therefore, this statement did not have a
material impact on the Company's financial statements.

3. ACQUISITIONS AND DIVESTITURES

Acquisitions

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

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

The acquisition of the UK North Sea properties closed on April 2, 2003, at
which time Apache paid a purchase price, adjusted for normal closing and working
capital adjustments, of $630 million. The acquisition of the North Sea
properties includes a 96 percent interest in the Forties Field and establishes a
new core area for the Company. In conjunction with the Forties acquisition,
Apache may be required to issue a letter of credit to BP to cover the present
value of related asset retirement obligations if the rating of the Company's
senior unsecured debt is lowered by both Moody's and Standard and Poor's from
its current ratings of A3 and
F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A-, respectively. Should this occur, the initial letter of credit amount would
be 175 million British pounds ($306 million U.S. at December 31, 2003). Apache
has agreed to sell all of the North Sea production through December 2004 to BP
at a combination of fixed and market sensitive prices pursuant to a contract
entered into in connection with the North Sea purchase agreement.

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

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

On July 3, 2003, Apache announced that it had completed the acquisition of
producing properties on the Outer Continental Shelf of the Gulf of Mexico from
Shell for $200 million, subject to normal post-closing adjustments, including
preferential rights. Prior to the 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 approximately four years beginning in August 2003 for gas and
November 2003 for oil. The VPP reserves and production will not be recorded by
Apache.

Apache recorded estimated proved reserves of 124.6 billion cubic feet (Bcf)
of natural gas and 6.6 million barrels of oil. In addition, a $60 million
liability for the future cost to produce and deliver volumes subject to the VPP
will be 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. The purchase agreement was
effective as of July 1, 2003. The acquisition included interests in 26 fields
covering 50 blocks (approximately 209,000 acres) and interests in two onshore
gas plants. Apache will operate 15 of the fields with 91 percent of the
production. The purchase price was funded by borrowings under the Company's
lines of credit and commercial paper program.

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

On December 17, 2002, Apache announced the acquisition of certain South
Louisiana properties comprising 234,000 net acres (366 square miles) with net
proved reserves of approximately 29.8 MMboe, 88 percent of which is natural gas,
from a private company. The acquisition includes 135 producing wells, access to
849 square miles of 3-D seismic covering the relatively contiguous acreage
position and ownership of the surface and mineral rights on most of the acreage,
for approximately $259 million, subject to post-closing adjustments. Apache also
entered into a separate exploration joint venture with the seller whereby the
seller will actively generate prospects on certain South Louisiana acreage for a
total cost of $25 million over a two-year period (see Note 11).

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

In March 2001, Apache completed the acquisition of substantially all of
Repsol's oil and gas concession interests in Egypt for approximately $447
million in cash, subject to normal post closing adjustments. The properties
included interests in seven Western Desert concessions and had estimated proved
reserves of 66 MMboe as of the acquisition date. The Company already held
interests in five of the seven concessions.

In March 2001, Apache completed the acquisition of subsidiaries of Fletcher
for approximately $465 million in cash and 3.8 million restricted shares of
Apache common stock issued to Shell Overseas Holdings (valued at $26.425 per
share), subject to normal post closing adjustments. The transaction included
properties located primarily in Canada's Western Sedimentary Basin. Estimated
proved reserves totaled 120.8 MMboe as of the acquisition date. Apache assumed a
liability of $103 million representing the fair value of derivative instruments
and fixed-price commodity contracts entered into by Fletcher.

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

In August 2001, Apache completed the acquisition of properties located in
Texas, Oklahoma and New Mexico with estimated proved reserves of 9.2 MMboe as of
the acquisition date for approximately $53 million in cash and the assumption of
certain liabilities, representing the fair value of derivative instruments of $9
million, subject to normal post-closing adjustments.

In November 2001, Apache completed the acquisition of all of Novus Bukha
Limited's (Novus) oil and gas concession interests in Egypt for approximately
$66 million in cash. The acquisition included estimated proved reserves of
approximately 11.7 MMboe as of the acquisition date. The properties included
interests in three Western Desert concessions, in which Apache previously held
an interest.

In 2001, the Company also completed other acquisitions for cash
consideration totaling $44 million. These acquisitions added approximately 4.9
MMboe to the Company's proved reserves.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following unaudited pro forma information shows the effect on the
Company's consolidated results of operations as if the acquisitions from BP
occurred on January 1, 2002 and the Fletcher and Repsol transactions occurred on
January 1, 2001. The pro forma information includes only significant
acquisitions and numerous assumptions, and is not necessarily indicative of
future results of operations:

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

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

Divestitures

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

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

During 2001, Apache sold marginal properties, primarily in North America,
containing 88 MMboe of proved reserves, for $348 million. Apache used the
proceeds to reduce bank debt.

4. DERIVATIVE INSTRUMENTS AND FIXED-PRICE PHYSICAL CONTRACTS

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

During the first quarter of 2003, in conjunction with the acquisitions from
BP and during the fourth quarter of 2002, in conjunction with the South
Louisiana properties acquisition, Apache entered into, and designated as cash
flow hedges, natural gas and crude oil fixed-price swaps and natural gas option
collars. These positions were entered into in accordance with the Company's
hedging policy and involved several

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

counterparties which are rated A+ or better. As of December 31, 2003, the
outstanding positions of our cash flow hedges were as follows:

In addition to the fixed-price swaps and option collars, Apache entered
into a separate crude oil physical sales contract with BP. The sales contract is
a normal purchase and sale under SFAS No. 133 and, therefore, the Company has
designated and accounted for the contract under the accrual method. As of
December 31, 2003, the outstanding terms of the contract were as follows:

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

Based on current market prices, the Company recorded an unrealized loss in
other comprehensive income of $69 million ($43 million after tax). Any loss will
be realized in future earnings contemporaneously with the related sales of
natural gas and crude oil production applicable to specific hedges. Were current
prices to hold, a loss of $63 million ($39 million after tax) would be realized
over the next 12 months. However, these amounts could vary materially as a
result of changes in market conditions. The contracts designated as hedges
qualified and continue to qualify for hedge accounting in accordance with SFAS
No. 133, as amended.

2001 Unwind -- Prior to Apache's derivative activity during 2002, the
Company had entered into derivative positions divided into three general
categories: (1) Apache's hedging activity, (2) derivatives assumed in
acquisitions (Acquired Contracts), and (3) advances from gas purchasers. Driven
by the uncertainty of how the collapse of Enron Corporation could have impacted
the derivative markets, Apache closed all of its derivative positions and
certain fixed-price physical contracts during October and November 2001,
receiving proceeds of approximately $62 million (referred to as the "Unwind").

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Upon adoption of SFAS No. 133 on January 1, 2001, or as of the acquisition
date in the case of the Acquired Contracts, the fair value of Apache's
derivative instruments was:

At the time SFAS No. 133 was implemented, natural gas prices were
approaching record highs. Although Apache was realizing higher prices on its
un-hedged production, the fair value of the Company's cash flow hedges was
out-of-the-money by approximately $116 million ($71 million, net of income tax).
This unrealized loss was reflected as a charge to other comprehensive income.
Throughout the year, commodity prices were trending downward. As a result,
Apache realized only $40 million of this loss during the year. In connection
with the Unwind, the Company closed out the rest of these open positions and
received cash proceeds of $8 million. These proceeds were recognized in earnings
as the original hedged production occurred.

The Company also uses long-term, fixed-price physical contracts to lock in
a portion of its natural gas production at a given price. In the Unwind, the
Company received approximately $13 million to terminate contracts with certain
counterparties. Since the Company has no continuing performance obligations
under the contracts, the amount was recognized as a gain in Revenues and Other
in 2001.

In addition to the cash flow hedges the Company entered into, Apache
assumed $113 million of derivative and physical contracts in connection with two
acquisitions. Because these derivatives were out-of-the-money when the Company
acquired them, the liability was factored into the consideration paid to the
sellers (see Note 3). Since commodity prices generally decreased after the
acquisitions, Apache was able to settle this liability in the Unwind for only
$67 million, including $37 million paid to terminate the remaining open
positions. As a result, Apache recognized a gain of $32 million during 2001 and
$14 million during 2002 and a loss of $336,000 during 2003. As of December 31,
2003, an immaterial amount remains and will be recognized in 2004.

Effective January 1, 2001, Apache recognized a derivative asset of $121
million reflecting the fair value of gas price swaps entered into in connection
with certain advance payments received from gas purchasers in 1998 and 1997.
Apache also recognized a derivative liability of $121 million reflecting the
fair value of an embedded fixed price physical contract. The net effect of these
transactions resulted in Apache delivering natural gas to the advance purchasers
at prevailing market prices. Apache terminated the gas price swaps in the
Unwind, receiving proceeds of $78 million. These proceeds will be recognized
into earnings over the remaining life of the contracts and effectively increase
the original contract's fixed prices by approximately 51 percent. Upon
termination, Apache designated the remaining contractual volumes of gas that
will be delivered to the purchaser as a normal, fixed-price physical contract.
See Note 8 for additional information on the advances from gas purchasers.

5. SHORT-TERM INVESTMENTS

In August 2001, Apache purchased $116 million in U.S. Government Agency
Notes. The Company subsequently sold $13 million of the notes in 2001. Of the
remaining balance, $17 million were designated as "available for sale"
securities and were sold for approximately $17 million in January 2002.
Approximately $86 million were designated as "held to maturity" and carried at
amortized cost. These notes paid interest at rates from 6.25 percent to 6.375
percent and matured on October 15, 2002.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. DEBT

Long-Term Debt

On June 3, 2002, Apache entered into a new $1.5 billion global credit
facility to replace its existing global and 364-day credit facilities. The new
global credit facility consists of four separate bank facilities: a $750 million
364-day facility in the United States (364-day facility); a $450 million
five-year facility in the United States (U.S. five-year facility); a $150
million five-year facility in Australia; and a $150 million five-year facility
in Canada. The financial covenants of the global credit facility require the
Company to: (i) maintain a consolidated tangible net worth, plus the aggregate
amount of any non-cash write-downs, of at least $2.8 billion as of December 31,
2003, adjusted for subsequent earnings, (ii) maintain an aggregate book-value
for assets of Apache and certain subsidiaries, as defined, on an unconsolidated
basis of at least $2 billion as of December 31, 2003, and (iii) maintain a ratio
of debt to capitalization of not greater than 60 percent at the end of any
fiscal quarter. The Company was in compliance with all financial covenants at
December 31, 2003.

The five-year facilities are scheduled to mature on June 3, 2007 and the
364-day facility is currently scheduled to mature on May 28, 2004. The 364-day
facility allows the Company the option to convert outstanding revolving loans at
maturity into one-year term loans. The Company may request extensions of the
maturity dates subject to approval of the lenders. At the Company's option, the
interest rate is based on (i) the

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

greater of (a) The JP Morgan Chase Bank prime rate or (b) the federal funds rate
plus one-half of one percent or (ii) the London Interbank Offered Rate (LIBOR)
plus a margin determined by the Company's senior long-term debt rating. In
addition, the U.S. five-year facility allows the Company the option to borrow
under competitive auctions. At December 31, 2003, the margin over LIBOR for
committed loans was .30 percent on the five-year facilities and .32 percent on
the 364-day facility. If the total amount of the loans borrowed under all of the
facilities equals or exceeds 33 percent of the total facility commitments, then
an additional .125 percent will be added to the margins over LIBOR. The Company
also pays a quarterly facility fee of .10 percent on the total amount of each of
the five-year facilities and .08 percent on the total amount of the 364-day
facility. The facility fees vary based upon the Company's senior long-term debt
rating. The U.S. five-year facility and the 364-day facility are used to support
Apache's commercial paper program. The available borrowing capacity under the
global credit facility at December 31, 2003 was $1.4 billion.

At December 31, 2003, the Company also had certain uncommitted money market
lines of credit which are used from time to time for working capital purposes,
under which an aggregate of $5.2 million was outstanding as of December 31,
2003. Such borrowings are classified as long-term debt in the accompanying
consolidated balance sheet as the Company has the ability and intent to
refinance such amounts on a long-term basis through available borrowing capacity
under the U.S. five-year facility and the 364-day facility.

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances at December 31, 2003 and 2002 were classified as
long-term debt in the accompanying consolidated balance sheet as the Company has
the ability and intent to refinance such amounts on a long-term basis through
either the rollover of commercial paper or available borrowing capacity under
the U.S. five-year facility and the 364-day facility. The weighted average
interest rate for commercial paper was 1.19 percent in 2003 and 1.85 percent in
2002.

In April 2002, the Company issued $400 million principal amount, $397
million net of discount, of senior unsecured 6.25-percent notes maturing on
April 15, 2012. The notes are redeemable, as a whole or in part, at Apache's
option, subject to a make-whole premium. The proceeds were used to repay a
portion of the Company's outstanding commercial paper and for general corporate
purposes.

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

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

The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and
Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache
and, in the case of Apache Finance Australia, by Apache North America, Inc., an
indirect wholly-owned subsidiary of the Company. Under certain conditions
related to changes in relevant tax laws, Apache Finance Australia and Apache
Finance Canada have the right to redeem the notes prior to maturity. The Apache
Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent
notes may be redeemed at the Company's option subject to a make-whole premium
(see Note 17).

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In August 2003, the Apache Clearwater, Inc. notes matured and were repaid
using commercial paper.

The $14 million of discounts on the Company's debt at December 31, 2003, is
being amortized over the life of the debt issuances as additional interest
expense.

As of December 31, 2003 and 2002, the Company had approximately $22 million
and $19 million, respectively, of unamortized deferred loan costs associated
with its various debt obligations. These costs are included in deferred charges
and other in the accompanying consolidated balance sheet and are being amortized
to expense over the life of the related debt.

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

Aggregate Maturities of Debt

The Company made cash payments for interest, net of amounts capitalized, of
$96 million, $99 million and $105 million for the years ended December 31, 2003,
2002 and 2001, respectively.

7. INCOME TAXES

Income before income taxes is composed of the following:

The total provision for income taxes consists of the following:

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

The net deferred tax liability is comprised of the following:

The Company has not recorded deferred income taxes on the undistributed
earnings of its foreign subsidiaries as management intends to permanently
reinvest such earnings. As of December 31, 2003, the undistributed earnings of
the foreign subsidiaries amounted to approximately $3.2 billion. Upon
distribution of these earnings in the form of dividends or otherwise, the
Company may be subject to U.S. income taxes and foreign withholding taxes. It is
not practical, however, to estimate the amount of taxes that may be payable on
the eventual remittance of these earnings after consideration of available
foreign tax credits. Presently, limited foreign tax credits are available to
reduce the U.S. taxes on such amounts if repatriated.

At December 31, 2003, the Company had U.S. federal net operating loss
carryforwards of $62 million, state net operating loss carryforwards of $381
million and foreign net operating loss carryforwards of $8 million for China and
$513 million for the United Kingdom. The state and federal net operating losses
will expire over the next 15 and 20 years, respectively, if they are not
otherwise utilized. The foreign net operating loss for China has a 5-year
carryover period while the United Kingdom loss has an unlimited carryover
period. The

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company has alternative minimum tax (AMT) credit carryforwards of $9 million
that can be carried forward indefinitely, but which can be used only to reduce
regular tax liabilities in excess of AMT liabilities.

The Company made cash payments for income and other taxes, net of refunds,
of $309 million, $171 million and $172 million for the years ended December 31,
2003, 2002 and 2001, respectively.

8. ADVANCES FROM GAS PURCHASERS

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

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

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

These advance payments have been classified as advances from gas purchasers
and are being recognized in oil and gas production revenues as gas is delivered
to the purchasers under the terms of the contracts. At December 31, 2003 and
2002, advances of $109 and $125 million, respectively, were outstanding. Gas
volumes delivered to the purchaser are reported as revenue at prices used to
calculate the amount advanced, before imputed interest, plus or minus amounts
paid or received by Apache applicable to the price swap agreements. Interest
expense is recorded based on a rate of eight percent .

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

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. CAPITAL STOCK

Common Stock Outstanding

(1) In March 2001, Apache issued to Shell Overseas Holdings 3.8 million
restricted shares for net proceeds of $100 million in connection with the
Fletcher acquisition.

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

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

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

Net Income Per Common Share -- A reconciliation of the components of basic
and diluted net income per common share for the years ended December 31, 2003,
2002 and 2001 is presented in the table below:

During 2002, Apache began modifying its stock compensation plans in order
to reflect the cost of these plans in the Statement of Consolidated Operations.
As part of this effort, Apache issued stock appreciation rights and restricted
stock and, effective January 1, 2003, adopted the expense provisions of SFAS No.
123, as amended, on a prospective basis for all stock options granted under the
Company's existing option plans.

Stock Option Plans -- On December 31, 2003, officers and employees have
options to purchase shares of the Company's common stock under one or more
employee stock option plans adopted in 1990, 1995, 1998

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and 2000 (collectively, the Stock Option Plans). Under the Stock Option Plans,
the exercise price of each option equals the market price of Apache's common
stock on the date of grant. Options generally become exercisable ratably over a
four-year period and expire after 10 years.

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

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

A summary of the status of the plans described above as of December 31,
2003, 2002 and 2001, and changes during the years then ended, is presented in
the table and narrative below (shares in thousands):

(1) The fair value of each option is estimated as of the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants in 2003, 2002 and 2001, respectively: (i)
risk-free interest rates of 2.86, 4.87 and 4.95 percent; (ii) expected lives
of 4.5 years for 2003 and 2002 and five years for 2001 for the Stock Option
Plans; (iii) expected volatility of 36.60, 37.17 and 41.39 percent; and (iv)
expected dividend yields of .66, .68 and .51 percent.
- ---------------

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options covered by
the plans described above that are outstanding at December 31, 2003 (shares in
thousands):

Stock Appreciation Rights -- During 2003, the Company began issuing stock
appreciation rights (SARs) to non-executive employees in lieu of stock options.
A total of 1,802,210 SARs were issued during 2003 and will be settled in cash
upon exercise. The vesting period is over four years and the Company records
compensation expense on the vested SARs outstanding as the price of the
Company's common stock fluctuates. Total expense of $4 million ($2 million
after-tax) was recorded in 2003 for SARs issued during the year.

Restricted Stock -- In May 2002, Apache's board of directors approved an
executive restricted stock plan for all executive officers and certain key
employees in lieu of stock options. The Company awarded 121,000 and 229,950
restricted shares in 2003 and 2002, respectively, that are subject to ratable
vesting over four years. The value of the stock issued was established by the
market price on the date of grant and will be recorded as compensation expense
over the vesting terms. During 2003 and 2002, $2 million and $538 thousand,
respectively, was charged to expense.

Share Appreciation Plan -- In October 2000, the Company adopted the Share
Appreciation Plan under which grants were made to the Company's officers and
substantially all full-time employees. The Share Appreciation Plan provides for
issuance of up to an aggregate of 8.08 million shares of Apache common stock,
based on attainment of one or more of three share price goals (Share Price
Goals) and/or a separate production goal (Production Goal). Generally, shares
will be issued in three installments over 24 months after achievement of each
goal. When and if the goals are achieved, the Company will recognize
compensation expense over the 24-month vesting period equal to the value of the
stock on the date the particular goal is achieved. The shares of Apache common
stock contingently issuable under the Share Appreciation Plan will be excluded
from the computation of income per common share until the stated goals are met.

The Share Price Goals are based on achieving a closing share price of
$43.29, $51.95 and $77.92 per share on any 10 days out of any 30 consecutive
trading days before January 1, 2005. A summary of the number

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of shares contingently issuable under the Share Price Goals as of December 31,
2003, 2002 and 2001 is presented in the table below (shares in thousands):

(1) Represents shares issuable upon attainment of $43.29, $51.95 and $77.92 per
share price goals of 1,370,624 shares, 3,431,250 shares and 1,522,818
shares, respectively, in 2003, 1,351,792 shares, 3,381,050 shares and
1,501,398 shares, respectively, in 2002 and 1,386,268 shares, 3,464,788
shares and 1,539,794 shares, respectively, in 2001.

(2) The fair value of each Share Price Goal conditional grant is estimated as of
the date of grant using a Monte Carlo simulation with the following
weighted-average assumptions used for grants in 2003, 2002 and 2001,
respectively: (i) risk-free interest rate of 2.77, 2.90 and 4.16 percent;
(ii) expected volatility of 36.69, 38.77 and 46.27 percent; and (iii)
expected dividend yield of .70, .70 and .77 percent.
- ---------------

The Production Goal will be attained if and when the Company's average
daily production equals or exceeds .67 barrels of oil equivalent per diluted
share (calculated on an annualized basis) during any fiscal quarter ending
before January 1, 2005. Such level of production was approximately twice the
Company's level of production at the time the Share Appreciation Plan was
adopted. Shares issuable in connection with the Production Goal will be a number
of shares of the Company's common stock equal to (a) 37.5 percent, 75 percent or
150 percent of a participant's annual base salary (at the time of attainment),
as applicable, divided by (b) the average daily per share closing price of the
Company's common stock for the fiscal quarter during which the Production Goal
is attained.

In 2001, the Company modified the Stock Option Plans, 1996 Performance
Stock Option Plan and 2000 Share Appreciation Plan to allow for immediate
vesting upon a change in control of ownership. This modification did not require
recognition of any compensation expense.

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

Preferred Stock

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

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

that trade with Apache common stock outstanding and are reserved for issuance
upon the exercise of the Rights as defined and discussed below.

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

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

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

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

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

The unrealized gain (loss) on available for sale securities at December 31,
2001 is net of income tax expense of $67,000. The currency translation
adjustments are not adjusted for income taxes as they relate to a permanent
investment in non-U.S. subsidiaries.

10. FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 2003 and 2002. See Note 6
for a discussion of the Company's derivative instruments.

The following methods and assumptions were used to estimate the fair value
of the financial instruments summarized in the table above. The Company's trade
receivables and trade payables are by their very nature short-term. The carrying
values included in the accompanying consolidated balance sheet approximate fair
value at December 31, 2003 and December 31, 2002.

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Long-Term Debt -- The fair value of the notes and debentures is based upon
an estimate provided to the Company by an independent investment banking firm.
The carrying amount of the global credit facility, commercial paper, money
market lines of credit and Apache Clearwater notes approximated fair value
because the interest rates are variable and reflective of market rates.

11. COMMITMENTS AND CONTINGENCIES

Litigation

China -- Texaco China, B.V. initiated an arbitration proceeding against
Apache China Corporation LDC in September 2001. Texaco China later added Apache
Bohai Corporation LDC to the arbitration. In the arbitration Texaco claims $47
million in damages, plus interest, arising from Apache Bohai's alleged failure
to drill three wells, prior to re-assignment of the interest to Texaco. Apache
China and Apache Bohai believe they have not breached their contract obligations
to Texaco and that, in any event, Texaco has not suffered any damages. Texaco
will fully recover its costs associated with drilling the wells under its cost
recovery contract with the Chinese national oil company, and the value of the
interest re-assigned by Apache to Texaco far exceeds any damages that could be
claimed by Texaco. Therefore, Apache believes that any material recovery by
Texaco is remote. The hearing was held in January 2004, and a decision is
expected in the second quarter of 2004.

Canada -- In December 2000, certain subsidiaries of the Company and Murphy
Oil Corporation (Murphy) filed a lawsuit in Canada charging The Predator
Corporation Ltd. (Predator) and others with misappropriation and misuse of
confidential well data to obtain acreage offsetting a significant natural gas
discovery made by Apache and Murphy during 2000 in the Ladyfern area of
northeast British Columbia. In February 2001, Predator filed a counterclaim
seeking more than C$6 billion and has since reduced this amount to no more than
C$4 billion. Management believes that the counterclaim is without merit, the
amount claimed by Predator is frivolous, and the likelihood of success is
remote.

The Company is involved in litigation and is subject to governmental and
regulatory controls arising in the ordinary course of business. The Company has
an accrued liability of less than $8 million for legal contingencies that are
probable of occurring and can be reasonably estimated. It is management's
opinion that the loss for any litigation matters and claims that are reasonably
possible to occur will not have a material adverse affect on the Company's
financial position or results of operations.

Environmental -- The Company, as an owner or lessee and operator of oil and
gas properties, is subject to various federal, provincial, state, local and
foreign country laws and regulations relating to discharge of materials into,
and protection of, the environment. These laws and regulations may, among other
things, impose liability on the lessee under an oil and gas lease for the cost
of pollution clean-up resulting from operations and subject the lessee to
liability for pollution damages. In some instances, the Company may be directed
to suspend or cease operations in the affected area. We maintain insurance
coverage, which we believe is customary in the industry, although we are not
fully insured against all environmental risks.

Apache manages its exposure to environmental liabilities on properties to
be acquired by identifying existing problems and assessing the potential
liability. The Company also conducts periodic reviews, on a company-wide basis,
to identify changes in its environmental risk profile. These reviews evaluate
whether there is a probable liability, its amount, and the likelihood that the
liability will be incurred. The amount of any potential liability is determined
by considering, among other matters, incremental direct costs of any likely
remediation and the proportionate cost of employees who are expected to devote a
significant amount of time directly to any possible remediation effort. As it
relates to evaluations of purchased properties, depending on the extent of an
identified environmental problem, the Company may exclude a property from the
acquisition, require the seller to remediate the property to Apache's
satisfaction, or agree to assume liability for the remediation of the property.
The Company's general policy is to limit any reserve additions to any incidents
or

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

sites that are considered probable to result in an expected remediation cost
exceeding $100,000. Any environmental costs and liabilities that are not
reserved for are treated as an expense when actually incurred. In our
estimation, neither these expenses nor expenses related to training and
compliance programs, are likely to have a material impact on our financial
condition. As of December 31, 2003, the Company had an undiscounted reserve for
environmental remediation of approximately $10 million. Apache is not aware of
any environmental claims existing as of December 31, 2003, which have not been
provided for or would otherwise have a material impact on its financial position
or results of operations. There can be no assurance, however, that current
regulatory requirements will not change, or past non-compliance with
environmental laws will not be discovered on the Company's properties.

Exploration Agreement -- In conjunction with the purchase of oil and gas
properties in December 2002, Apache entered into a separate exploration joint
venture with the seller whereby the seller will actively generate prospects on
certain South Louisiana acreage through December 31, 2004. Under the terms of
the agreement, Apache will pay up to $25 million for the seller's share of
seismic, lease acquisition and drilling and completion cost on covered
prospects, with no more than $13 million of carried cost required to be paid on
behalf of the seller through December 31, 2003. Apache has the option, but not
the obligation, to participate in any individual prospect proposed by the
seller. If Apache does not pay a total of $25 million of covered cost through
December 31, 2004, it is obligated to pay the difference to the seller within 90
days of the expiration of the agreement. Covered costs of $5 million have been
paid by Apache through December 31, 2003.

International Lease Concessions -- The Company, through its subsidiaries,
has acquired or has been conditionally or unconditionally granted exploration
rights in Australia, Egypt, China and the North Sea. In order to comply with the
contracts and agreements granting these rights, the Company, through various
wholly-owned subsidiaries, is committed to expend approximately $52 million
through 2007.

Retirement and Deferred Compensation Plans -- The Company provides a 401(k)
savings plan for employees which allows participating employees to elect to
contribute up to 25 percent of their salaries, with Apache making matching
contributions up to a maximum of six percent of each employee's salary. In
addition, the Company annually contributes six percent of each participating
employee's compensation, as defined, to a money purchase retirement plan. The
401(k) plan and the money purchase retirement plan are subject to certain
annually-adjusted, government-mandated restrictions which limit the amount of
each employee's contributions.

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

Vesting in the Company's contributions to the 401(k) savings plan, the
money purchase retirement plan and the non-qualified retirement/savings plan
occurs at the rate of 20 percent per year. Upon a change in control of
ownership, vesting is immediate. Total costs under all plans were $25 million,
$18 million and $16 million for 2003, 2002 and 2001, respectively. The unfunded
liability for all plans as of December 31, 2003 and 2002 has been recorded in
other accrued expenses.

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

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Apache also has a postretirement benefit plan covering substantially all of
its U.S. employees. The postretirement benefit plan provides for medical
benefits up until the age of 65. The plan is contributory with participants'
contributions adjusted annually.

The following tables set forth the benefit obligation, fair value of plan
assets and funded status at December 31, 2003 and the underlying weighted
average actuarial assumptions used for the UK Pension Plan and U.S.
postretirement benefit plan. Apache uses a measurement date of December 31 for
its pension and postretirement benefit plans. Although the postretirement
benefit plan was in effect during 2002 and 2001, tabular information is not
provided as the total provisions were immaterial to the Company.

As of December 31, 2003, the accumulated benefit obligation for the pension
plan was $46.7 million. The following table sets forth the components of the net
periodic cost.

F-36

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

Apache expects to contribute $5 million to its pension plan in 2004. The
following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid (in thousands):

2004........................................................ $ 9
2005........................................................ 108
2006........................................................ 128
2007........................................................ 388
2008........................................................ 778
Years 2009 -- 2013.......................................... 10,621

The Company does not anticipate any material contributions or benefit
payments to be made in future years with respect to the postretirement benefit
plan.

Operating Lease and Other Commitments -- The Company has leases for
buildings, facilities and equipment with varying expiration dates through 2013.
Net rental expense was $17 million, $16 million and $18 million for 2003, 2002
and 2001, respectively.

F-37

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2003, minimum rental commitments under long-term
operating leases, net of sublease rentals, drilling rigs and long-term pipeline
transportation commitments, ranging from one to 20 years, are as follows:

12. PREFERRED INTERESTS OF SUBSIDIARIES

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

Apache contributed interests in various fields valued at $923 million to
new subsidiaries in connection with the financing transactions. Additionally,
Apache contributed $116 million in U.S. Government Agency Notes (see Note 5).
Unrelated institutional investors contributed $443 million ($441 million, net of
issuance costs) to the various subsidiaries in exchange for preferred stock ($82
million) of the subsidiaries and a limited partner interest ($361 million) in
one of the entities. The third party investors were entitled to receive a
weighted average return of 123 basis points above the prevailing LIBOR interest
rate. The preferred stock and limited partner interests were repayable from the
assets of the subsidiaries. Apache retained credit risks related to collection
of proceeds from product sales and intercompany loans. Apache also had an
obligation to contribute an aggregate amount not to exceed $250 million to fund
present and future business operations of the subsidiaries. However, the
investors were not entitled to receive more than their $443 million original
investment, plus the agreed-upon return. One of the subsidiaries also issued $37
million of senior floating rate notes, which matured and were repaid in August
2003 (see Note 6).

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

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

F-38

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

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

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

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

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

In the ordinary course of business, Cimarex Energy, Co. (Cimarex), formerly
Key Production Company, Inc., paid to Apache $4 million during 2003, $2 million
during 2002 and $4 million during 2001 for Cimarex's proportionate share of
drilling and workover costs, mineral interests and routine expenses relating to
oil and gas wells in which Cimarex owns interests and of which Apache is the
operator. Cimarex was paid approximately $6 million in 2003, $4 million in 2002,
and $7 million in 2001 directly by Apache or related entities for its
proportionate share of revenues from wells in which Cimarex marketed its
revenues with Apache as operator. Apache paid to Cimarex approximately $1
million during 2003 and $217,000 during 2002 for Apache's proportionate share of
drilling and workover costs, mineral interests and routine expenses relating to
oil and gas wells in which Apache owns interests and of which Cimarex is the
operator. Apache was paid approximately $2 million in 2003 and $785,000 in 2002
directly by Cimarex for its proportionate share of revenues from wells in which
Apache marketed its revenues with Cimarex as operator. F. H. Merelli, a

F-39

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

member of Apache's board of directors, is chairman of the board, chief executive
officer and president of Cimarex.

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

During 2003, Apache and its subsidiaries made donations of $201,000, in
cash, property and services, to the Ucross Foundation. During 2003, Apache also
paid $40,000 to the Ucross Foundation for food, lodging and other expenses
incurred in connection with executive retreats held at the Ucross Foundation's
facilities. On February 5, 2004, Apache entered into an agreement to purchase
the Clear Creek Hunting Preserve, Inc. from Ucross Foundation for a total
purchase price of $77,000. The Ucross Foundation was founded in 1981 as a
non-profit organization whose primary objectives include the restoration of the
historic Clear Fork headquarters of the Pratt and Ferris Cattle Company of
Wyoming, the promotion of the preservation of other historical sites in the
area, and the maintenance of an artists-in-residence program for writers and
other artists. To help ensure that the accomplishments of the Ucross Foundation
are reasonably secure, Apache's board of directors has approved a conditional
charitable contribution of $10,000,000 to be made to the Ucross Foundation upon
a change of control of the Company, as defined in the Company's income
continuance plan. Raymond Plank, chairman of Apache's board of directors, is
chairman of the board of trustees of Ucross Foundation, and G. Steven Farris, a
director and officer of Apache, and Roger B. Plank, an officer of Apache, are
trustees of Ucross Foundation.

During 2003, 2002 and 2001, Apache and its subsidiaries made donations of
$500,000, $300,000 and $3 million, in cash, property and services, to The Fund
for Teachers: A Foundation to Recognize, Stimulate and Enhance, which is a Texas
non-profit corporation. In addition, during 2003, Apache accrued a $4,650,000
donation to the Fund for Teachers that was pledged in 2003 and will be paid in
2004. The Fund for Teachers seeks to provide resources directly to teachers to
support learning experiences of their own design to increase their effectiveness
with students, and is currently focused on funding summer sabbaticals for
selected applicants. The Company's board of directors also authorized potential
donations to The Fund for Teachers of up to $5,000,000 in cash, property and
services to be made in each of 2004 and 2005. If a change of control of the
Company occurs, as defined in the Company's income continuance plan, any and all
of the donations that have not yet been made to the Fund for Teachers will
become immediately due and payable to the Fund for Teachers. Raymond Plank,
chairman of Apache's board of directors, is chairman of the board and president
of The Fund for Teachers.

In the ordinary course of business, Apache paid to Maralo, LLC or related
entities ("Maralo") during 2002 approximately $9,000 in revenues relating to
four oil and gas wells in which Maralo owns an interest and of which Apache is
operator. During 2001, Apache paid Maralo approximately $70,000 in revenues
relating to five oil and gas wells in which Maralo owns an interest and of which
Apache is the operator. Maralo paid Apache approximately $1,000 in 2002 and
$16,000 in 2001 for Maralo's share of routine expenses relating to such wells.
Also during 2002 and 2001, Maralo sub-leased certain office space from Apache,
for which Maralo

F-40

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

paid Apache approximately $95,000 in both years. Mary Ralph Lowe, a member of
Apache's board of directors through December 19, 2003, is president, chief
executive officer and the sole stockholder of Maralo.

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

Major Customers -- In 2003, purchases by Cinergy and EGPC accounted for 12
percent and 15 percent of the Company's oil and gas production revenues,
respectively. In 2002, purchases by Cinergy and EGPC accounted for 19 percent
and 22 percent of the Company's oil and gas production revenues, respectively.
In 2001, purchases by Cinergy and EGPC accounted for 35 percent and 17 percent
of the Company's oil and gas production revenues, respectively. No other
purchaser has accounted for more than 10 percent of revenues for 2003, 2002 or
2001.

Concentration of Credit Risk -- The Company's revenues are derived
principally from uncollateralized sales to customers in the oil and gas
industry; therefore, customers may be similarly affected by changes in economic
and other conditions within the industry. Apache has not experienced significant
credit losses on such sales. Apache sells all of its Egyptian crude oil and
natural gas to the EGPC for U.S. dollars. 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.

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. BUSINESS SEGMENT INFORMATION

Apache has six reportable segments which are primarily in the business of
crude oil and natural gas exploration and production. The accounting policies of
the segments are the same as those described in the summary of significant
accounting policies. The Company evaluates performance based on profit or loss
from oil and gas operations before income and expense items incidental to oil
and gas operations and income taxes. Apache's reportable segments are managed
separately based on their geographic locations. Financial information by
operating segment is presented below:

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

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

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(1) This amount only reflects DD&A of capitalized costs of oil and gas proved
properties and, therefore, does not agree with DD&A reflected on Note 14,
Business Segment Information.

(2) This amount only reflects amounts directly related to oil and gas producing
properties and, therefore, does not agree with severance and other taxes
reflected on Note 14, Business Segment Information.

(3) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement
Obligations." These amounts reflect current year activity only, as prior
periods were adjusted through a one-time cumulative adjustment as described
in Note 2, New Accounting Pronouncements.
- ---------------

Costs Not Being Amortized -- The following table sets forth a summary of
oil and gas property costs not being amortized at December 31, 2003, by the year
in which such costs were incurred. There are no individually significant
properties or significant development projects included in costs not being
amortized. The majority of the evaluation activities are expected to be
completed within five to ten years.

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Capitalized Costs Incurred -- The following table sets forth the
capitalized costs incurred in oil and gas producing activities:

(1) Acquisitions include unproved costs of $184 million, $70 million and $77
million for transactions completed in 2003, 2002 and 2001, respectively.

(2) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement
Obligations". The asset retirement obligation costs reflect abandonment
obligations assumed during the year and related revisions. Actual retirement
expenditures reflect plugging and abandonment costs during the year that are
included in exploration and development activity. Prior periods presentation
was not changed to reflect SFAS No. 143 because the amounts were adjusted
through a one-time cumulative adjustment as described in Note 2, New
Accounting Pronouncements.

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement
Obligations." Prior year amounts do not reflect similar asset retirement
obligation costs, as they were adjusted through a one-time cumulative
adjustment as described in Note 2, New Accounting Pronouncements.

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Oil and Gas Reserve Information -- Proved oil and gas reserve quantities
are based on estimates prepared by the Company's engineers in accordance with
Rule 4-10 of Regulation S-X. The Company's estimates of proved reserve
quantities of its U.S., Canadian and international properties are subject to
review by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum
engineers. During 2003, 2002 and 2001, their review covered 78 percent, 68
percent and 61 percent of the reserve value, respectively.

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

As of December 31, 2003, 2002 and 2001, on a barrel of equivalent basis 29,
28 and 25 percent of our worldwide reserves, respectively, were classified as
proved undeveloped. Approximately 19 percent of our proved developed reserves
are classified as proved not producing. These reserves relate to zones that are
either behind pipe, or that have been completed but not yet produced or zones
that have been produced in the past, but are not now producing due to mechanical
reasons. These reserves may be regarded as less certain than producing reserves
because they are frequently based on volumetric calculations rather than
performance data. Future production associated with behind pipe reserves is
scheduled to follow depletion of the currently producing zones in the same
wellbores. It should be noted that additional capital may have to be spent to
access these reserves. The capital and economic impact of production timing are
reflected in our standardized measure Note 15.

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

(2) Estimated future net cash flows before income tax expense, discounted at 10
percent per annum, totaled approximately $16.4 billion, $13.2 billion and
$7.4 billion as of December 31, 2003, 2002 and 2001, respectively.
F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

(1) The sum of the individual quarterly net income per common share amounts may
not agree with year-to-date net income per common share as each quarterly
computation is based on the weighted average number of common shares
outstanding during that period. In addition, certain potentially dilutive
securities were not included in certain of the quarterly computations of
diluted net income per common share because to do so would have been
antidilutive.

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

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

17. SUPPLEMENTAL GUARANTOR INFORMATION

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

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

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

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

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2002

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2001

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
FOR THE YEAR ENDED DECEMBER 31, 2002

F-61

BOARD OF DIRECTORS

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

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

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

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

A. D. FRAZIER, JR.(3)(5)
President and Chief Executive Officer,
Caremark Rx, Inc.

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

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

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

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

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

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

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

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

OFFICERS

RAYMOND PLANK
Chairman of the Board

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

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

JOHN A. CRUM
Executive Vice President -- Eurasia and New Ventures

RODNEY J. EICHLER
Executive Vice President

ROGER B. PLANK
Executive Vice President and Chief Financial Officer

FLOYD R. PRICE
Executive Vice President and
President, Apache Canada Ltd.

JON A. JEPPESEN
Senior Vice President

JEFFREY M. BENDER
Vice President -- Human Resources

MICHAEL J. BENSON
Vice President -- Security

THOMAS P. CHAMBERS
Vice President -- Corporate Planning

JOHN J. CHRISTMANN
Vice President -- Business Development

MATTHEW W. DUNDREA
Vice President and Treasurer

ROBERT J. DYE
Vice President -- Investor Relations

ERIC L. HARRY
Vice President and Associate General Counsel

JANICE K. HARTRICK
Vice President and Associate General Counsel

P. ANTHONY LANNIE
Vice President and General Counsel

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

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

THOMAS L. MITCHELL
Vice President and Controller

W. KREGG OLSON
Vice President -- Corporate Reservoir Engineering

JON W. SAUER
Vice President -- Tax

CHERI L. PEPER
Corporate Secretary

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

(1) Executive Committee

(2) Audit Committee

(3) Management, Development and Compensation Committee

(4) Corporate Governance and Nominating Committee

(5) Stock Option Plan Committee

SHAREHOLDER INFORMATION

Stock Data

* Per share prices and dividend amounts have been adjusted to reflect the
effects of the five percent stock dividend in 2002, and the two-for-one stock
split in 2003.

The Company has paid cash dividends on its common stock for 39 consecutive years
through December 31, 2003. Future dividend payments will depend upon the
Company's level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and
the NASDAQ National Market (symbol APA). At December 31, 2003, the Company's
shares of common stock outstanding were held by approximately 8,000 shareholders
of record and 157,000 beneficial owners. Also listed on the New York Stock
Exchange are:

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

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

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

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

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

DIVIDEND REINVESTMENT PLAN

Shareholders of record may invest their dividends automatically in additional
shares of Apache common stock at the market price. Participants may also invest
up to an additional $5,000 in Apache shares each quarter through this service.
All bank service fees and brokerage commissions on purchases are paid by Apache.
A prospectus describing the terms of the Plan and an authorization form may be
obtained from the Company's stock transfer agent, Wells Fargo Bank, N.A.

DIRECT REGISTRATION

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

ANNUAL MEETING

Apache will hold its annual meeting of shareholders on Thursday, May 6, 2004, at
10 a.m. in the Ballroom, Doubletree Hotel Houston -- Post Oak, 2001 Post Oak
Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live;
connect through the Apache web site: http://www.apachecorp.com.

STOCK HELD IN "STREET NAME"

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

FORM 10-K REQUEST

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

INVESTOR RELATIONS

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

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

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

INDEX TO EXHIBITS