APACHE CORP - 10-K Annual Report

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

FORM 10-K

(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002,
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: NONE

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). [ ]

Aggregate market value of the voting and non-voting common
equity held by non-affiliates of registrant as of June 28,
2002...................................................... $8,212,561,395
Number of shares of registrant's common stock outstanding as
of February 28, 2003...................................... 153,850,136

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of registrant's proxy statement relating to registrant's 2003
annual meeting of stockholders have been incorporated by reference into Part III
hereof.
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TABLE OF CONTENTS

DESCRIPTION

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

PART I

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 and onshore Argentina, and exploration interests in Poland. Our common
stock, par value $1.25 per share, has been listed on the New York Stock Exchange
since 1969, and on the Chicago Stock Exchange since 1960. Through our website,
http://www.apachecorp.com, you can access electronic copies of 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.

2002 RESULTS

Apache posted a very good year. Rising prices and production within one
percent of 2001's record levels combined to make 2002 our third best year in
terms of earnings and cash flow. Strong financial performance coupled with
curtailed capital spending enabled us to achieve our primary 2002 objective of
enhancing our financial flexibility. Our conservative approach to capital
spending through most of 2002 enabled us to further strengthen our balance sheet
and maintain a senior unsecured long-term debt rating of A3 from Moody's, and A-
from Standard and Poor's and Fitch rating agencies, all of which were reaffirmed
by those agencies after the announcement of our largest acquisition to-date
following year-end from BP p.l.c. (BP). Our 2002 income attributable to common
stock totaled $544 million on total revenues of $2.6 billion, while cash
provided by operating activities was $1.4 billion, a 28 percent decrease from
2001. Our average daily production for the year was 161 Mbbls of oil and natural
gas liquids and 1,080 MMcf of natural gas.

We increased our total reserves by four percent, compared with the end of
2001, resulting in 1,313 MMboe of estimated proved reserves at year-end, 51
percent of which were natural gas. Even though Apache did not pursue an active
acquisition program for most of 2002, at the end of the year we began seeking
acquisitions of additional properties. We completed two acquisitions of
producing properties in Canada and one in South Louisiana, described below in
the discussion of our U.S. and Canadian operations. In January 2003, we agreed
to purchase properties from subsidiaries of 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),
which will be our largest acquisition to-date. The Company closed the Gulf of
Mexico portion on March 13, 2003 at an adjusted price of $509 million, which has
estimated proved reserves of 72.2 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 $70
million), production and expenses since January 1, 2003, the effective date of
the transaction, and other minor adjustments. The North Sea portion is expected
to close early in the second quarter of 2003. The acquisition is being funded by
a combination of proceeds from the equity offering we completed in January 2003,
cash from our operations and debt.

Per share results have been adjusted for the 10 percent common stock
dividend paid on January 21, 2002, to our shareholders of record on December 31,
2001, and the five percent common stock dividend to be paid on April 2, 2003, to
our shareholders of record on March 12, 2003. The stock dividends reflect our
board of

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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

Throughout our 48-year history, Apache has been and continues to be driven
to grow. It is a constant pursuit and part of our culture. However, it is
tempered by the desire to grow economically rather than to grow at any price.

At this point in our progression we have developed our abilities to grow
through drilling, through acquisitions, or through a combination of both,
depending on what the environment gives us.

As indicated in this section a year ago, early in 2002, we planned to
reduce spending on both drilling and acquisition opportunities in favor of
paying down debt and adding financial flexibility. This was not driven by a weak
balance sheet (in fact our balance sheet was then among the strongest in our
sector), it was driven by a highly uncertain industry and economic environment
in which drilling costs were relatively high and prices, for natural gas in
particular, were relatively low and extremely volatile. In addition, our
assessment was that with reasonably priced properties unavailable for purchase,
it was prudent to curtail capital expenditures and wait for better opportunities
to present themselves.

As drilling costs came down and product prices rose during 2002, Apache
authorized incremental drilling and operating capital increases. For example,
when quality properties became available in South Louisiana at year-end from a
privately-held company at a reasonable price, we acted. Despite these drilling
and acquisition capital increases, Apache's 2002 capital expenditures
approximated half those of the prior year, driving a reduction in debt as a
percent of capitalization. Using a strict definition to calculate debt as a
percentage of capitalization, Apache's ratio dropped to 30 percent at year-end
2002 from 34 percent a year earlier. However, the strict measurement ignores two
important considerations particular to Apache's situation. Our balance sheet
includes preferred interests of subsidiaries ($437 million and $441 million at
December 31, 2002 and 2001, respectively) which, although not debt, are
redeemable under certain circumstances and, in our opinion, should be included
in the calculation. We also occasionally have short-term investments and cash
balances ($52 million and $139 million at December 31, 2002 and 2001,
respectively), both of which are available to pay down debt and, in our opinion,
should be subtracted from debt. Allowing for both of these factors, Apache's
adjusted debt-to-capitalization ratio was 34 percent at year-end, higher than
the strict formula, but below the comparable 37 percent ratio at the end of
2001. We believe this is a more conservative way of expressing this ratio.

Apache's financial discipline paid off. Not only were our 2002 finding and
acquisition costs quite competitive within our industry sector, our financial
strength left us as the only publicly traded independent in the U.S. with a
single-A rating by both Moody's and Standard and Poor's.

Our strategy provided us with the financial wherewithal sufficient to
pursue the asset acquisition from BP. This transaction took only 35 days from
initial discussions on December 9, 2002 to the signing of a purchase and sale
agreement and announcement on January 13, 2003. With completion of this
purchase, Apache's production and reserve growth is virtually assured for 2003,
if our assumptions regarding prices and the opportunities available on the BP
properties are correct. Given the existing outlook for high commodity prices, we
expect the BP acquisition to be accretive to both cash flow and earnings.

Looking ahead, we will continue to pursue growth that is economic, whether
it is through drilling, acquisitions, or both. Although we review industry
conditions and our capital expenditures constantly, present conditions are quite
attractive for both drilling and acquisitions and are likely to lead to
increases in drilling and acquisition expenditures in 2003.

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

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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, China, Poland and Argentina. After closing the BP transaction,
we will add a new core area, the U.K. North Sea. In the U.S., our exploration
and production activities are divided into two regions: Gulf Coast and Central.
In 2001, Apache had three domestic regions, which were reconfigured into the
current two in April 2002. At year-end, approximately 78 percent of our
estimated proved reserves were located in North America. Outside North America,
our exploration and production activities are focused primarily in Egypt and
Australia. Additionally, we have a development project underway in China that is
expected to commence production in 2003, and we have a small production interest
in Argentina. We also own exploration acreage in Poland.

The table below sets out a brief comparative summary of certain 2002 data
for our core geographic areas. More detailed information regarding the natural
gas, oil, and natural gas liquids (NGLs) production and average prices received
in 2002, 2001 and 2000 for the 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, information concerning the
amount of revenue, expenses, operating income (loss) and total assets
attributable to each of the same geographic areas is set forth in 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 core area discussions include references to the 2003 Plan.
These represent initial estimates only and will be reviewed and revised
throughout the year in light of changing industry conditions.

United States

In the U.S. we completed one significant acquisition during the year with
the purchase of 234,000 net acres in South Louisiana, holding estimated net
proved reserves of 178 Bcf of gas equivalent, together with access to 849 square
miles of 3-D seismic data and fee interests in most of the acreage, for $259
million. Anticipated net daily production from these properties is expected to
approximate 55 MMcf of natural gas and 2,100 barrels of oil in 2003. The
transaction was effective December 1, 2002. We also entered into a separate
exploration joint venture with the seller under which the seller will generate
exploration prospects on certain South Louisiana acreage for a total cost of $25
million over two years. The new properties are in our Gulf Coast region.

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Our curtailment of capital spending in the first half of the year did not
stop us from having a busy year in the U.S.: we completed 168 out of 194 total
wells and replaced 71 percent of our domestic production through drilling. 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 2002, the Gulf Coast region was our leading region for production volumes and
revenues. This region performed 586 workover and recompletion operations during
2002 and completed 41 out of 56 total wells drilled. As of year-end 2002, Gulf
Coast accounted for 21 percent of our estimated proved reserves. In 2003, we
currently plan on spending approximately $350 million drilling an estimated 90
wells and continuing our production enhancement program and exploiting the
properties acquired from BP in March 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 2002, the Central region
accounted for 27 percent of our estimated proved reserves, the second largest in
the company. During 2002, we participated in 138 wells, 127 of which were
completed as productive wells, replacing 96 percent of the region's production
from drilling. Apache performed 519 workovers and recompletions in the region
during the year. In 2003, we currently plan to spend approximately $100 million
drilling an estimated 200 wells and continuing our production enhancement
programs.

Marketing -- In July 1998, we entered into a gas purchase agreement with
Cinergy Marketing and Trading, LLC (Cinergy) to market most of our U.S. natural
gas production for a 10-year period, with an option by either party, after prior
notice, to terminate after six years. We also agreed to work with Cinergy to
develop terms for the marketing of most of our Canadian gas production. In
December 1998, however, Apache and Cinergy agreed to postpone the negotiation of
Canadian gas sales terms. During the period of the gas purchase agreement, we
are generally obligated to deliver our domestic gas production to Cinergy and,
under certain circumstances, may have to make payments to Cinergy if certain gas
throughput thresholds are not met. All throughput thresholds have been met to
date. The prices received for our gas production under this agreement are based
on published indexes. Disputes have arisen between Cinergy and Apache concerning
various matters, including Cinergy's claim to market our Canadian gas
production. As a result, in September 2001, Cinergy commenced an arbitration
proceeding seeking, among other things, specific performance to require us to
sell our Canadian gas production to Cinergy or pay damages. We are disputing
Cinergy's assertions (including their claim to market our Canadian production),
filing a general denial and counterclaim against Cinergy for amounts arising
from, among other things, an audit commenced in 2001. We do not believe the
arbitration outcome will be material to our financial position or results of
operations. We continue to market most of our U.S. gas production through
Cinergy, although we are actively discussing with Cinergy our gas marketing
arrangements and a resolution of our disputes.

We used long-term, fixed-price physical contracts to lock in a portion of
our domestic future natural gas production at a fixed price. These contracts
represented approximately 11 percent of our 2002 domestic natural gas
production. The contracts provide protection to the Company in the event of
decreasing natural gas prices.

We market our own U.S. crude oil with most of it sold through lease-level
marketing to refiners, traders and transporters. Contracts are generally less
than 30 days and renew automatically until canceled. The oil contracts provide
for sales at specified prices, or 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 30 percent of our estimated proved
reserves, the largest in the Company. We hold over four million net acres in
Canada, the largest of the North American regions.

4

2002 -- We completed two acquisitions in Alberta, Canada; purchasing
properties in August from Burlington Resources affiliates with estimated proved
reserves of 4.8 MMboe for $26 million and completing the purchase of properties
from Canadian affiliates of ConocoPhillips in October with estimated proved
reserves of 10.7 MMboe for $60 million. Canada was our most active region for
drilling in 2002, with Apache participating in 836 gross wells, 799 of which
were completed as producers. We also conducted 707 workover and recompletion
projects. We replaced 144 percent of our Canadian production through drilling
and another 54 percent through acquisition.

2003 -- We currently plan to spend approximately $400 million drilling an
estimated 900 wells, continuing the exploration program, the exploitation of the
acquired properties and developing our gas processing infrastructure.

Marketing -- Our Canadian natural gas sales include sales to supply
aggregators, to whom we dedicate reserves, and direct sales to brokers and
end-users in the United States and Canada. With the expansion of pipeline
transport capacity out of Canada in recent years, Canadian prices have
strengthened and become more closely correlated to United States domestic
prices. To diversify our market exposure, we transport natural gas via our firm
transportation contracts to California (12 MMcf/d), the Chicago area (40
MMcf/d), and Eastern Canada (2 MMcf/d), which are included in Note 11, under
Item 15 of this Form 10-K. Pursuant to an agreement entered into in 1994, we are
also selling 5 MMcf/d of natural gas to the Hermiston Cogeneration Project,
located in the Pacific Northwest of the United States. In 1996, we entered an
agreement to sell 5 MMcf/d into Michigan over a 10-year term. In 2002, with the
acquisition from ConocoPhillips, we entered into two agreements to sell 5 MMcf/d
each into the Northeastern U.S. with one terminating in 2007 and the other in
2008, 3 MMcf/d to an Eastern Canadian Cogeneration project until 2011, and 5
MMcf/d to a broker netback pool until 2005. The prices we receive under these
contracts are generally based on market indices.

Oil and NGLs produced from our Canadian properties are sold to crude oil
purchasers or refiners at market prices, which depend on worldwide crude prices
adjusted for transportation and crude quality.

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, 2002, we held over 6.9 million net
acres encompassing 13 concessions (12 operated). Apache is the largest producer
of liquid hydrocarbons and the second largest producer of natural gas in the
Western Desert and operates 11 percent of Egypt's daily oil and gas output.

2002 -- Egypt accounted for 22 percent of production revenues on 19 percent
of total production for the year and accounted for 10 percent of total proved
reserves at December 31, 2002. During the year we increased production
significantly in Egypt. Net oil production grew by 12 percent and net gas
production by 28 percent over the prior year. The production growth occurred in
most of our concessions, with the most significant increases being in the South
Umbarka concession, where gross oil and condensate production increased from
2,520 b/d to 9,650 b/d (a 283 percent increase), and the Umbarka concession,
where gross oil production increased from 1,277 b/d to 7,127 b/d or 458 percent.
Also, three concessions (Ras Kanayes, Matruh, and Northeast Abu Gharadig)
commenced production in 2002.

Apache had an active onshore drilling program in Egypt, completing 45 of 55
gross wells, for a success rate of 82 percent. The onshore program was weighted
more than 75 percent to development activity with the remaining to exploration
drilling. Apache also drilled four successful exploration wells in the deepwater
portion of the West Mediterranean block, including the first deepwater oil
discovered in the Nile Delta at the El King-1X well. On March 4, 2003, we
announced that the fifth deepwater well had successfully appraised the earlier
discoveries. No reserves have been recorded to-date for the deepwater wells.
Reserve recognition
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and proper scaling of the significant future development infrastructure are
pending negotiation and completion of a sales contract for this gas with EGPC.

Apache made six new field discoveries onshore in 2002. The most significant
were Selkit 1X in the South Umbarka concession, which flowed 5,103 b/d from
Kharita sands; Emerald 1X in the Ras El Hekma concession, which flowed 16.9
MMcf/d and 4,285 b/d of condensate from the AEB 6 sand; and the Tut 52 in the
Khalda concession, which flowed 29.2 MMcf/d and 781 b/d of condensate from
Khatatba sands. In addition to these larger discoveries, Apache also had three
new field discoveries in its East Bahariya concession and drilled 10 consecutive
successful development wells.

2003 -- We currently plan to spend approximately $250 million to drill more
than 100 wells and continue exploitation.

Marketing -- In 1996, we and our partners in the Khalda Block entered into
a 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 with a group of industry
players 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 Qarun. However, we have entered into new gas
sales contracts containing "Industry Pricing" at our Matruh, Ras Kanayes, Ras El
Hekma, and Akik development leases.

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 the
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 sold to EGPC on a spot basis at a "Western Desert" price
(indexed to Brent Crude Oil). We have the right to export our Egyptian crude oil
production, however, EGPC has first call on the purchase of our Egyptian crude
oil and has exercised this right. We expect EGPC to continue to exercise its
call right. Deteriorating economic conditions during 2001 and 2002 in Egypt have
lessened the availability of U.S. dollars, resulting in a one to two month delay
in receipts from EGPC. While the delay in payment has not significantly improved
or deteriorated in 2002, continuation of the hard currency shortage in Egypt
could lead to further delays, deferrals of payment or non-payment in the future.

Australia

2002 -- We produced 18.2 MMboe in Australia (15 percent of our total)
generating $334 million of production revenues. Estimated proved reserves in
Australia were 11 percent of our year-end total. During the year we participated
in drilling 25 wells, 10 completed as producers, and in five workover and
recompletion projects.

We had a successful exploration year in Australia, with discoveries at
Double Island, Victoria, Pedirka, and Little Sandy in the first quarter of the
year. Production from the Victoria, Pedirka, and Little Sandy oil fields
commenced in November 2002, eight months from discovery, while the Double Island
oil development began production in February 2003, 12 months after discovery.
There were three additional discoveries over the remainder of the year at
Hoover, South Simpson, and Endymion.

On the development side, we had six new oil fields and one new gas field
that commenced production during 2002 in the Carnarvon Basin offshore Western
Australia. The Gibson and South Plato oil fields

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(68.5 percent interest) were developed from a common facility and brought
on-line in June 2002 at a combined initial average rate of 10,400 gross barrels
of oil per day. The South Simpson oil field (68.5 percent interest) was placed
on production in October at an average initial rate of 3,000 gross barrels of
oil per day. The Victoria, Pedirka, and Little Sandy oil fields (68.5 percent
interest) were developed from a common facility and commenced production in
November at a combined average rate of 10,000 barrels of oil per day. The
Endymion gas field (68.5 percent interest) commenced production in November at
an average initial rate of 18 MMcf/d.

2003 -- In February 2003, Apache brought the Double Island oil development
(68.5 percent interest) on-line at an average rate of 8,000 barrels of oil per
day. For 2003, we have budgeted expenditures of $100 million for an estimated 30
exploration wells, five development wells, and various production development,
enhancement and other capital projects.

Marketing -- In Australia we entered into two new gas sales contracts and
extended two existing gas sales contracts during 2002, bringing our total to 25
contracts. In aggregate, we committed a further 655 Bcf for delivery. Under the
largest contract, we will supply more than 600 Bcf over a 25-year period
commencing in July 2005. Our total Australian delivery rates are expected to
average approximately 100 MMcf/d in 2003. Generally, natural gas is sold in
Western Australia by AEL 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.

Other International

We have exploration and production interests offshore China and in
Argentina, and exploration interests in Poland.

We are the operator, with a 24.5 percent interest, of the Zhao Dong Block
in Bohai Bay, offshore China. In 1994 and 1995, discovery wells tested at rates
between 1,300 and 4,000 b/d of oil. In early 1997, one well tested at rates up
to 11,571 b/d of oil and another tested at rates up to 15,359 b/d. An overall
development plan for the C and D Fields in the Zhao Dong Block was approved by
Chinese authorities in December 2000. Work commenced in 2001 with the awarding
of contracts for development drilling and the construction of production
facilities in accordance with the approved overall development plan. We
currently plan to spend an estimated $25 million this year. First production is
expected in the second half of 2003.

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. At year-end 2002, we had 1,353,307 net undeveloped acres in Poland.
In 2002, we recorded additional impairments to our properties in Poland, as
described in Item 7 of this Form 10-K. At December 31, 2002, the Company had $13
million of unproved property costs remaining. Apache is considering various
alternatives for maximizing the value of the Poland assets, including sale to a
third party. This evaluation may result in additional impairments in 2003.

In 2001, we acquired exploration and production assets of Fletcher
Challenge and Anadarko Petroleum in Argentina. After these transactions, we held
interests in a number of blocks in Argentina's Neuquen basin. We are the
operator, with a 100 percent interest, of the Lindero de Piedra and El
Santiagueno Blocks. We also hold interests in the following blocks: Agua Salada
(30 percent), Faro Virgenes (20 percent), CNQ-16 (seven percent) and CNQ-16A (25
percent). For the year, these interests held less than one percent of our proved
reserves and generated small amounts of production and revenue. Our total net
acreage in Argentina is 367,690 acres, with 324,790 developed and 42,900
undeveloped at year-end 2002. In light of the social and economic turmoil in
Argentina, we have limited our investments. Hence, our 2003 Plan does not
presently contemplate any drilling activity. Our staff will concentrate on
identifying opportunities and strategies for growth that might be implemented in
anticipation of improved political and economic conditions.

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DRILLING STATISTICS

Worldwide, in 2002, we participated in drilling 1,114 gross new wells, with
1,022 (92 percent) completed as producers. Canada was our most active region,
drilling 836 gross new wells, 599 of which were shallow development wells
drilled in the Hatton field. Canada's success rate was 96 percent. We also
performed over 2,066 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 and Canadian drilling activities focus more on exploration
drilling. In addition to our completed wells at year-end, we were participating
in several wells that had not yet reached completion: four in the U.S. (2.5
net); three in Canada (2.1 net); nine in Egypt (7.2 net); and one in Australia
(0.7 net).

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

8

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, 2002, is set forth below:

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.

ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS

As of December 31, 2002, Apache had total estimated proved reserves of 637
million barrels of crude oil, condensate and NGLs and 4.1 Tcf of natural gas.
Combined, these total estimated proved reserves are equivalent to 1.3 billion
barrels of oil or 7.9 Tcf of gas. The company's reserves have grown for the 17th
consecutive year. Estimated proved developed reserves comprise 72 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, 2002, 2001 and 2000, 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 Footnote 15, Supplemental Oil
and Gas Disclosures (Unaudited), in the Apache Corporation 2002 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.

9

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. While this firm doesn't evaluate
our entire reserve base, they do concentrate on those reserves that represent a
substantial percentage of the Securities and Exchange Commission (SEC) value.
During 2002, 2001 and 2000, their review covered 68, 61 and 72 percent of the
SEC value, respectively.

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.

SUBSTANTIAL 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.

SUBSTANTIAL 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, 2002,
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
10

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 any incidents or sites
that are considered likely to result in an expected remediation cost exceeding
$100,000. Any environmental costs and liabilities not reserved are expensed when
incurred. In our estimation, these expenses are not likely to have a material
impact on our financial condition.

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 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
the lowest finding and production costs possible 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 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.

11

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.
However, included in this annual report on Form 10-K, are financial data and
other information for 2001 and 2000 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 would customarily be performed by potential
investors in our securities, which process includes 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, 2002, we had 1,958 employees.

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 2002, we
maintained regional exploration and/or production offices in Tulsa, Oklahoma;
Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia;
Beijing, China; Warsaw, Poland; and Buenos Aires, Argentina. We established an
office in Aberdeen, Scotland early in 2003.

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.

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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

No matters were submitted for a vote of security holders during the fourth
quarter of 2002.

PART II

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

Apache common stock, par value $1.25 per share, is traded on the New York
Stock Exchange and the Chicago Stock Exchange under the symbol APA. The table
below provides certain information regarding our common stock for 2002 and 2001.
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 10 percent and five percent
stock dividends described below and have been rounded to the indicated decimal
place.

The closing price per share of our common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for February 28,
2003 , was $65.28 ($62.17 adjusted for the five percent dividend). At February
28, 2003, there were 153,850,136 shares of our common stock outstanding
(161,542,642 shares adjusted for the five percent stock dividend) held by
approximately 8,000 shareholders of record and approximately 104,000 beneficial
owners.

We have paid cash dividends on our common stock for 36 consecutive years
through December 31, 2002. During 2000, we implemented a change in the payment
schedule for dividends on our common stock from a quarterly basis to an annual
basis; however, we later implemented a return to a quarterly dividend payment
schedule beginning in 2002. 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 1.155 outstanding shares of common stock (adjusted for the 10
percent and five percent stock dividends) 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
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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 acquirers 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 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.

In May 1999, we issued 140,000 shares of 6.5 percent Automatically
Convertible Equity Securities, Conversion Preferred Stock, Series C (Series C
Preferred Stock) in the form of seven million depositary shares each
representing 1/50th of a share of Series C Preferred Stock. The depositary
shares were traded on the New York Stock Exchange and the Chicago Stock
Exchange. The Series C Preferred Stock was not subject to a sinking fund or
mandatory redemption. 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, $330,000, is reflected
as a preferred stock dividend in the accompanying statement of consolidated
operations. The remaining depositary shares converted into 6,554,865 shares of
Apache common stock in 2002.

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 13,070,068 shares of our
common stock on January 21, 2002 to the holders of the 130,888,270 shares of
common stock outstanding on December 31, 2002. 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 expect to issue approximately 7,868,000
shares of our common stock on April 2, 2003 to the holders of the 153,867,875
shares of common stock outstanding on March 12, 2003. No fractional shares will
be issued in connection with the stock dividend and we expect to make cash
payments totaling approximately $1,347,000 in lieu of fractional shares.

On January 22, 2003, in conjunction with the BP acquisition, the Company
completed the public offering of 9.9 million shares of Apache common stock,
including 1.3 million shares for the underwriters' over-allotment option, at
$58.10 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 BP
acquisition.

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, 2002,
which information has been derived from the Company's audited financial
statements. Our financial statements for the years 1998 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 risks related to Arthur Andersen in Item 1 of this Form
10-K, "Factors That May Affect Future Results -- Risks Relating to Arthur
Andersen LLP." This

14

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, refer to Note 3 to the
Company's consolidated financial statements in Item 15 of this Form 10-K. During
1998, the Company recorded a $243 million pre-tax ($158 million net of tax)
non-cash write-down of the carrying value of the Company's U.S. proved oil and
gas properties in compliance with full-cost accounting rules (refer to Critical
Accounting Policies in Item 7 of this Form 10-K).

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

OVERVIEW

In 2002, Apache reported another very satisfactory year of growth and
progress in our mission to build Apache incrementally to last. We finished the
year with strong results, the third-best year on a per-share basis over our
48-year history. Our strong cash flow provided us the flexibility to make
necessary and appropriate investments in continuation of our long-term
incremental growth strategy.

On the back of a strong fourth quarter, we ended the year with a solid $544
million of net income attributable to common stock and $1.4 billion in cash from
operating activities. We exited 2002 with our best quarter of the year and a
strong financial position. Thirteen days into the new year, we announced the
acquisition of $1.3 billion (subject to normal closing adjustments and the
exercise of preferential rights by third parties) in properties from BP p.l.c.
(BP), setting the stage for an exciting 2003.

Facing 2002 with the prospect of continued volatility in commodity prices,
high service costs (including drilling, materials and contracted geophysical
surveys) and unattractive acquisition prices, we exercised patience and
discipline, restricting capital spending and focusing efforts on maintaining our
competitive position by strengthening our balance sheet, growing our reserve
base and maintaining production levels. As the year progressed, improving
commodity prices and declining drilling costs placed us in an ideal position
where we could continue increasing financial flexibility while simultaneously
increasing capital spending, which we did beginning in the third quarter. Our
worldwide capital expenditures for exploratory and development drilling of $860
million were 46 percent higher than our initial plan, but still well below the
$1.3 billion we spent in 2001. Ultimately, this strategy manifested itself in
lower drilling costs, one of the lowest debt-to-capitalization ratios in our
peer group, and our 17th consecutive year of reserve growth, ending

15

with 1.3 billion barrels of oil equivalent. It also left us positioned to
acquire the BP properties in 2003 while maintaining our financial flexibility.

Our capital expenditure reductions in the first half of 2002 were
selective, both by region and by type of drilling. Rather than decrease
exploration drilling, we increased it in the areas of Canada, Egypt, and
Australia, all core producing areas that saw production growth in 2002. We had a
successful exploration drilling program in 2002, reporting 16 discoveries
worldwide. Production remained within one percent of prior-year levels despite
our capital spending curtailment in the first half of the year and back-to-back
hurricanes, which forced us to shut-in all of our Gulf of Mexico production for
a brief period in late September and then again in early October.

The foundation of Apache's strategy is a portfolio approach that was
developed to provide diversity in terms of hydrocarbon product (oil or gas),
geologic risk and geographic location. In 2002, 58 percent of our equivalent
production came from outside the U.S., up from 51 percent in 2001. At year-end
2002, our reserves were 49 percent oil and 51 percent gas, compared with 47
percent and 53 percent at year-end 2001.

In each of our core producing areas, our front line teams have the
technical knowledge, sense of urgency and drive necessary to wring more value
from Apache's assets. Building local expertise also provides a platform to
compete and expand in our core areas through both operations and acquisitions.
In the latter half of 2001, we felt that acquisition prices had reached
exorbitant levels, relative to commodity prices, leading us to the sidelines
until appropriate opportunities arose at reasonable prices, which began late in
2002. We spent approximately $355 million on acquisitions in 2002, compared with
$1.2 billion in 2001 and $1.4 billion in 2000. The most significant of the 2002
activity came in December, when we announced the acquisition of properties in
South Louisiana. As we have done in the past, and what has become a cornerstone
of our acquisition strategy, we entered into hedges to protect the economics of
the transaction, while at the same time preserving the potential for
significantly higher gas realizations. See Note 4, in Item 15 of this Form 10-K.

In January 2003, we announced that we had entered into a definitive
agreement with BP to purchase producing properties in the North Sea and Gulf of
Mexico for $1.3 billion (subject to normal closing adjustments and the exercise
of preferential rights by third parties), the largest single acquisition in
Apache's history. The acquisition from BP is significant in many respects: it
extends our relationship to one of the world's premier integrated major oil
companies; it adds production and reserves and a new exploitation portfolio in
North America's strongest gas market; and it establishes a new core area in the
North Sea, which fits our balanced-portfolio business model and further
diversifies our reserves and production. The Gulf properties are synergistic
with our existing properties and made Apache the fourth-largest producer and the
second-largest acreage holder in Gulf of Mexico waters to 1,200 feet deep. We
will also become the ninth-largest oil producer in the North Sea. The effective
date of the transaction is January 1, 2003; the Gulf portion closed on March 13,
2003; the North Sea portion is projected to close early in the second quarter.
The acquisition is being financed through a combination of internally generated
funds, the issuance in January 2003 of common equity, and debt. A substantial
portion of the oil and gas production for the first two years has been hedged to
protect the acquisition economics and to maintain Apache's position as a
reliable purchaser of major companies' assets as they rationalize their
portfolios in the future.

On January 22, 2003, in conjunction with the BP transaction, we completed a
public offering of 9.9 million shares of common stock, including 1.3 million
shares for the underwriters' over-allotment option, raising net proceeds of $554
million.

After announcing the BP acquisition, all three rating agencies reaffirmed
Apache's single-A credit ratings, a testament to our financial position, our
conservative financial strategy, where we employ hedges to protect acquisition
economics, and our three-pronged approach to finance large-scale transactions
with internally generated funds, equity and debt.

In December 2002, to recognize the Company's continued progress on both the
financial and operational fronts, Apache's board of directors declared a special
five percent common stock dividend payable on April 2,

16

2003, to shareholders of record on March 12, 2003. All of the share and per
share information included in this filing has been adjusted to reflect this
stock dividend.

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
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. Additional accounting policies and estimates made by management are
discussed in Results of Operations and in Note 1 of Item 15 of this Form 10-K.

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, cost 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 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 at the
end 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. 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.

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

17

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 depreciation, depletion and
amortization (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. While this firm doesn't evaluate
our entire reserve base, they do concentrate on those reserves that represent a
substantial percentage of the Securities and Exchange Commission (SEC) value.
During 2002, 2001 and 2000, their review covered 68, 61 and 72 percent of the
SEC value, respectively.

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. In Egypt, however, we
have experienced a gradual decline in the timeliness of receipts from Egyptian
General Petroleum Corporation (EGPC). Deteriorating economic conditions during
2001 and 2002 in Egypt have lessened the availability of U.S. dollars, resulting
in an additional one to two month delay in receipts from EGPC. Continuation of
the hard currency shortage in Egypt could lead to further delays, deferrals of
payment or non-payment in the future. 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 removal and disposal of offshore oil and gas platforms. The
estimated undiscounted costs, net of salvage value, of dismantling and removing
these facilities are accrued over the production life of the oil and gas
property. Estimating the future asset 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 well as regulatory, political,
environmental, safety and public relations considerations.

In 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 143 (SFAS No. 143), "Accounting for Asset
Retirement Obligations." SFAS No. 143 significantly changed the method of
accruing for costs associated with the retirement of fixed assets an entity is
legally obligated to incur. Primarily, the new statement requires the Company to
record a separate liability for asset retirement obligations that represents the
present value of the costs to be incurred. The separate liability is similar to
our previous estimates in that the obligations are based on expected cost
estimates and expected economic lives of the asset retirement that occurs many
years in the future, but the new rule now requires additional discounting
assumptions to be considered by management. Revisions to the asset retirement
obligation recorded upon adoption of SFAS No. 143 can potentially result from
changes in the assumptions used to estimate the cash flows required to settle
the obligation. Potential changes include adjustments in estimated
probabilities, amounts, and timing of the settlement, as well as changes in the
legal requirements of an asset retirement obligation. Any such changes that
result in upward and downward revisions in the estimated cash flows will adjust
the liability and the related capitalized asset on a prospective basis. Apache
adopted this statement effective January 1, 2003, as discussed in Note 2 of Item
15 of this Form 10-K.

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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. Apache accounts for its commodity
derivative contracts in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). 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. The Company does not enter into derivative or other financial
instruments for trading purposes. SFAS 133 requires that gains and losses from
the change in fair value of derivative instruments that do not qualify for hedge
accounting be reported in current period income, rather than in the period in
which the hedged transaction is settled. This may result in significant
volatility to current period income.

SFAS 133 is complex and subject to a potentially wide range of
interpretations in its application. As such, in 1998 the FASB established the
Derivative Implementation Group (DIG) task force specifically to consider and to
publish official interpretations of issues arising from the implementation of
SFAS 133. The potential exists for additional issues to be brought under review,
therefore, if subsequent interpretations of SFAS 133 are different than our
current policy, it is possible that our policy, as stated above, would be
modified.

RESULTS OF OPERATIONS

Acquisitions and Divestitures

In 2002, we elected to exercise patience on the acquisition front, waiting
for the frenzy that drove acquisition prices to unreasonable levels to ebb. 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 and $1.3 billion we expended during 2001 and 2000,
respectively, which added 213 MMboe and 254 MMboe of proved reserves. In
addition, the acquisitions added $3 million, $146 million and $94 million of
production, processing and transportation facilities in 2002, 2001 and 2000,
respectively, and $197 million of goodwill in 2001. These acquisitions
strengthened our position in core areas and provided promising prospects for
future exploration and development activities. We will continue our strategy of
finding additional reserves on the acquired properties and accelerating the
production of those already identified while endeavoring to lower costs.

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.

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
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associated with prior acquisitions, recognizing a net gain of $10 million. A net
gain of $24 million was recognized in 2002 and a $4 million net loss will be
recognized in 2003 as the originally hedged volumes are produced. 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 $.04 per Mcf
during 2002, $.09 per Mcf during 2001 and $.05 per Mcf during 2000. They
increased our average crude oil price by $.15 per bbl during 2002, and reduced
our average crude oil price by $.42 per bbl during 2001 and $1.62 per bbl during
2000.

We routinely evaluate our property portfolio and divest those that are
marginal or no longer fit into our strategic growth program. We divested $7
million, $348 million and $26 million of properties during 2002, 2001 and 2000,
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 economic
factors such as the current U.S. recession could impact demand.

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

Natural Gas Revenues

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

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decline reduced revenues by $342 million, while lower gas production reduced
revenues by another $49 million. The production decline was concentrated in the
U.S., with declines of 21 percent and 13 percent in the Gulf Coast and Central
regions, respectively. 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 acquisition and subsequent
drilling activity. See Note 3 of Item 15 of this 10-K for further discussion of
acquisition and divestiture activity.

A 36 percent increase in our natural gas production contributed $390
million to 2001 revenues. Canada's increase was primarily driven by our
acquisition of producing properties from Phillips Petroleum Company (Phillips)
in December 2000 and Fletcher Challenge in March 2001 as well as strong
exploration and development results from the Ladyfern area. A full year of
production from the properties we acquired from Occidental Petroleum Corporation
(Occidental) in August 2000 and Collins & Ware, Inc. (Collins & Ware) in June
2000 helped boost our domestic production by 13 percent, while properties
acquired from Repsol helped double our Egyptian production. See Note 3 of Item
15 of this Form 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
protection to the Company in the event of decreasing natural gas prices and
represented approximately 11 percent of our 2002 and 2001 domestic natural gas
production. In 2002, these contracts positively impacted our average realized
price in by $.01 per Mcf. Historically high prices in the first half of 2001
resulted in a negative impact of $.06 per Mcf in that year. Additionally,
substantially all of our natural gas production sold in Australia is subject to
long-term fixed-price contracts.

Crude Oil Revenues

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 and subsequent drilling. U.S. production declined nine
percent related to natural decline, 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.

Our crude oil revenues increased in 2001 despite a 15 percent drop in the
average realized price, as crude oil production increased 29 percent. The
acquisition and subsequent exploitation of properties acquired from Repsol, in
March 2001, contributed to a 41 percent increase in our year-over-year Egyptian
production. Strong results on properties acquired from Fletcher Challenge in
March 2001 and Phillips in December 2000 helped us increase our Canadian oil
production by 76 percent. We also had success on the drilling front, increasing
our Australian production by nearly 51 percent with successful development of
the Legendre, Gipsy/North Gipsy and Simpson fields.

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Operating Expenses

The table below presents a detail of our expenses.

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. During 2002, our full-cost DD&A per boe increased by
$.24 to $6.29, the result of higher finding costs and estimates of future costs
necessary to extract reserves. During 2001, full-cost DD&A expense increased by
$.30 to $6.05 per boe, reflecting higher finding costs and negative reserve
revisions associated with declining prices.

Depreciation on other assets remained flat in 2002 after increasing $25
million in 2001 associated with additional facilities acquired from Fletcher
Challenge and Repsol in March 2001 and the amortization of goodwill. In
connection with the adoption of a new accounting principle effective January 1,
2002, we no longer amortize our goodwill. Instead, it is assessed for periodic
impairment, as discussed in the impairment section below.

Impairments

We periodically assess all of our unproved properties for possible
impairment 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). At December 31, 2002, the Company had $13 million of
unproved property costs remaining in Poland. We are continuing to evaluate our
operations in Poland, which may result in additional impairments in 2003.

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

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 pricing

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environments. Repair and maintenance costs are higher on offshore properties and
in areas with plants and facilities.

During 2002, LOE was $3.71 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. In 2001, LOE was $3.22 per boe, a $.56
increase from 2000. This increase was driven by our acquisitions of Canadian and
offshore Gulf of Mexico oil properties, higher service costs and increased
workover activity in the U.S. and Canada.

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 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.

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.
Severance taxes, which are generally based on a percentage of oil and gas
production revenues, decreased in 2002. The decrease reflects the impact of
lower gas realizations in the U.S. and a higher percentage of total oil and gas
production revenues generated from Egypt and Canada, core areas that are not
subject to these taxes. Partially offsetting this decrease were higher severance
taxes in Australia. The 2002 increase in Australia resulted from higher oil
realizations and a change in the production mix. A higher portion of production
was attributable to properties in provincial waters, such as Legendre and
Harriet relative to production from federal waters.

In 2001, severance taxes increased in line with our production-driven
increase in oil and gas revenues and a higher effective production tax rate.
Available incentives granted by the state of Oklahoma decline with rising
commodity prices, increasing the effective tax rate. Also contributing to the
2001 increase is additional Canadian Large Corporation Tax, a component of
Severance and Other Taxes, related to production from properties acquired from
Fletcher in March 2001.

General and Administrative Expenses

Overall, general and administrative expenses (G&A) trended higher in 2002,
rising $.13 to $.84 per boe. 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.

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During 2001 absolute G&A increased as the size of our company grew from
acquisitions. However, 2001 G&A on an equivalent-barrel basis declined 10
percent from 2000 to $.71 as the incremental production was added at a lower G&A
rate.

Financing Costs, Net

Net financing costs decreased by five percent in 2002. The major components
of net financing costs are interest expense and capitalized interest. Lower
average debt outstanding during 2002 resulted in a decrease in interest expense
of $23 million. A reduction in capitalized interest of $16 million, associated
with lower unproved property balances, partially offset this decrease. Net
financing costs increased 11 percent in 2001, related to higher average
outstanding borrowings coupled with lower capitalized interest, partially offset
by lower average effective interest rates. Our weighted-average cost of
borrowing on December 31, 2002 was 6.3 percent compared to 5.9 percent on
December 31, 2001. The rate is higher at year-end 2002 as a lower percentage of
our debt is at floating rates, which carry a lower rate than fixed-rate debt.

OIL AND GAS CAPITAL EXPENDITURES

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 2003 is approximately $1.3
billion (excluding acquisitions), including $850 million for North America.
Preliminary North American capital expenditures include $350 million in the Gulf
Coast region, $100 million in the Central region and $400 million in Canada. The
Company has estimated its international capital expenditures in 2003 at $400
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 $13 million in dividends during 2002 on its Series B
Preferred Stock issued in August 1998 and its Series C Preferred Stock issued in
May 1999. 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 2002 rose 61 percent to
$56 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 36 consecutive years through 2002. Future

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dividend payments will depend on the Company's level of earnings, financial
requirements and other relevant factors.

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
adjust