Edgar Filing: APACHE CORP

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

FORM 10-K/A
(AMENDMENT NO. 1)

(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,

[ ] 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:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------

Common Stock, $0.625 par Value New York Stock Exchange
Chicago Stock Exchange

Preferred Stock Purchase Rights New York Stock Exchange
Chicago Stock Exchange

Automatically Convertible Equity Securities New York Stock Exchange
Conversion Preferred Stock, 6.5% Series C Chicago Stock Exchange

9.25% Notes due 2002 New York Stock Exchange

Apache Finance Canada Corporation New York Stock Exchange
7.75% Notes Due 2029
Irrevocably and Unconditionally
Guaranteed by Apache Corporation

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). [X]

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.......................................... 323,085,284

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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EXPLANATORY NOTE

We are filing this Amendment No. 1 to our Annual Report on Form 10-K/A for
the year ended December 31, 2002 to respond to certain comments received by us
from the Staff of the Securities and Exchange Commission ("SEC") in connection
with its review of our Registration Statement on Form S-3 (File No. 333-105536).
Our consolidated financial position and consolidated results of operations for
the periods presented have not been restated from the consolidated financial
position and consolidated results of operations originally reported. Except
where otherwise indicated, all share amounts and per share amounts have been
adjusted to reflect the effects of the two-for-one stock split for our common
stock declared in September 2003.

For convenience and ease of reference we are filing this Annual Report in
its entirety with the applicable changes. Unless otherwise stated, all
information contained in this amendment is as of March 25, 2003, the filing date
of our Annual Report on Form 10-K for the year ended December 31, 2002.
Accordingly, this Amendment No. 1 to the Annual Report on Form 10-K/A should be
read in conjunction with our subsequent filings with the SEC.

TABLE OF CONTENTS

DESCRIPTION

ITEM PAGE
---- ----

PART I
1. BUSINESS.................................................... 2
2. PROPERTIES.................................................. 15
3. LEGAL PROCEEDINGS........................................... 15
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 15

PART II
5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS......................................... 15
6. SELECTED FINANCIAL DATA..................................... 17
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................... 17
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK........................................................ 36
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 38
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.................................... 38

PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 38
11. EXECUTIVE COMPENSATION...................................... 38
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 38
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 39
14. CONTROLS AND PROCEDURES..................................... 39

PART IV
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K......................................................... 39

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 $0.625 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 two-for-one stock split
distributed on January 14, 2004 to our shareholders of record on December 31,
2003, 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 paid on April 2, 2003, to our shareholders of record on March 12, 2003.
The stock split and stock dividends reflect

our board of directors' belief that we can reward our shareholders while
remaining focused on our primary objective of building Apache to last by
achieving profitable growth.

OUR GROWTH STRATEGY

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 motivated by a
weak balance sheet (in fact we believe our balance sheet was strong, as
evidenced by our single-A debt rating and low debt-to-capitalization ratio, both
of which are discussed below). 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, and based on our planned capital expenditures, production forecasts
and reserve estimates, we believe Apache's production and reserves will grow in
2003 over 2002 levels. Of course, our forward looking statements are dependent
upon events which can be impacted by risk and uncertainties that may be outside
the Company's control as discussed in Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk, "Forward-Looking Statements and Risk." For a
discussion of risks, refer to "Risk Factors related to Our Business and
Operations" below.

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 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, for information concerning
the amount of revenue, expenses, operating income (loss) and total assets
attributable to each of the same geographic areas, see Note 15, Supplemental Oil
and Gas Disclosures (Unaudited), and Note 14, Business Segment Information, both
in Item 15 of this Form 10-K.

12/31/02 PERCENTAGE 2002
2002 ESTIMATED OF TOTAL 2002 GROSS NEW
2002 PRODUCTION PROVED ESTIMATED GROSS NEW PRODUCING
PRODUCTION REVENUE RESERVES PROVED WELLS WELLS
(IN MMBOE) (IN MILLIONS) (IN MMBOE) RESERVES DRILLED COMPLETED
---------- -------------- ----------- ---------- --------- ---------

Region/Country:
Gulf Coast................. 32.2 $ 699.5 276.3 21.0% 56 41
Central.................... 20.2 401.9 354.4 27.0 138 127
----- -------- ------- ----- ----- --------
Total U.S. .............. 52.4 1,101.4 630.7 48.0 194 168
----- -------- ------- ----- ----- --------
Canada..................... 29.9 557.7 386.8 29.5 836 799
----- -------- ------- ----- ----- --------
Total North America...... 82.3 1,659.1 1,017.5 77.5 1,030 967
----- -------- ------- ----- ----- --------
Egypt...................... 23.4 560.1 136.6 10.4 59 45
Australia.................. 18.2 334.0 145.2 11.1 25 10
China...................... -- -- 11.3 0.9 -- --
Poland..................... -- -- -- -- -- --
Argentina.................. 0.7 6.5 1.9 0.1 -- --
----- -------- ------- ----- ----- --------
Total International...... 42.3 900.6 295.0 22.5 84 55
----- -------- ------- ----- ----- --------
Total.................... 124.6 $2,559.7 1,312.5 100.0% 1,114 1,022
===== ======== ======= ===== ===== ========

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.

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 (See Note 11 of this Form 10-K).

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.

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. Seventeen percent of our natural gas
was sold to aggregators, four percent to end users, and 79 percent to brokers in
2002. 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), see 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 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 (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.

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:

NET EXPLORATORY NET DEVELOPMENT TOTAL NET WELLS
------------------------- ------------------------- -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- ---- ----- ---------- ---- ----- ---------- ---- -----

2002
United States........ 3.0 3.5 6.5 92.8 17.1 109.9 95.8 20.6 116.4
Canada............... 25.9 10.1 36.0 714.2 20.4 734.6 740.1 30.5 770.6
Egypt................ 7.7 7.0 14.7 32.3 6.0 38.3 40.0 13.0 53.0
Australia............ 6.3 7.6 13.9 1.3 -- 1.3 7.6 7.6 15.2
Other
International...... -- -- -- -- -- -- -- -- --
---- ---- ---- ----- ---- ----- ----- ---- -----
Total.............. 42.9 28.2 71.1 840.6 43.5 884.1 883.5 71.7 955.2
==== ==== ==== ===== ==== ===== ===== ==== =====
2001
United States........ 5.9 4.4 10.3 202.9 32.0 234.9 208.8 36.4 245.2
Canada............... 0.7 7.0 7.7 348.4 17.2 365.6 349.1 24.2 373.3
Egypt................ 4.5 4.5 9.0 25.0 7.5 32.5 29.5 12.0 41.5
Australia............ 1.4 5.2 6.6 5.0 2.6 7.6 6.4 7.8 14.2
Other
International...... -- 3.4 3.4 0.3 -- 0.3 0.3 3.4 3.7
---- ---- ---- ----- ---- ----- ----- ---- -----
Total.............. 12.5 24.5 37.0 581.6 59.3 640.9 594.1 83.8 677.9
==== ==== ==== ===== ==== ===== ===== ==== =====
2000
United States........ 5.8 9.1 14.9 201.0 41.6 242.6 206.8 50.7 257.5
Canada............... 1.0 7.0 8.0 58.7 11.7 70.4 59.7 18.7 78.4
Egypt................ 5.0 5.8 10.8 9.7 1.6 11.3 14.7 7.4 22.1
Australia............ 1.4 13.7 15.1 4.3 -- 4.3 5.7 13.7 19.4
Other
International...... -- 0.9 0.9 -- -- -- -- 0.9 0.9
---- ---- ---- ----- ---- ----- ----- ---- -----
Total.............. 13.2 36.5 49.7 273.7 54.9 328.6 286.9 91.4 378.3
==== ==== ==== ===== ==== ===== ===== ==== =====

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:

GAS OIL TOTAL
------------- ------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ------ -----

Gulf Coast............................. 895 560 995 690 1,890 1,250
Central................................ 2,488 1,233 3,242 1,992 5,730 3,225
Canada................................. 4,445 3,858 2,555 1,037 7,000 4,895
Egypt.................................. 23 21 201 185 224 206
Australia.............................. 9 5 38 19 47 24
Argentina.............................. 23 6 31 20 54 26
----- ----- ----- ----- ------ -----
Total................................ 7,883 5,683 7,062 3,943 14,945 9,626
===== ===== ===== ===== ====== =====

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.

UNDEVELOPED ACREAGE DEVELOPED ACREAGE
----------------------- ---------------------
GROSS NET GROSS NET
ACRES ACRES ACRES ACRES
---------- ---------- --------- ---------

United States.......................... 1,092,822 632,970 2,116,100 1,232,026
Canada................................. 3,225,171 2,493,056 2,686,271 1,853,500
Egypt.................................. 9,406,675 5,957,898 1,106,823 992,516
Australia.............................. 8,518,240 4,179,110 467,770 274,470
China.................................. 5,314 2,657 5,911 1,448
Poland................................. 1,471,524 1,353,307 -- --
Argentina.............................. 191,418 42,900 520,572 324,790
---------- ---------- --------- ---------
Total Company........................ 23,911,164 14,661,898 6,903,447 4,678,750
========== ========== ========= =========

PRODUCTION AND PRICING DATA

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

PRODUCTION AVERAGE SALES PRICE
--------------------------- AVERAGE ------------------------------------
OIL NGLs GAS PRODUCTION OIL NGLs GAS
YEAR ENDED DECEMBER 31, (Mbbls) (Mbbls) (MMcf) COST PER Boe (PER bbl) (PER bbl) (PER Mcf)
----------------------- ------- ------- ------- ------------ ---------- ---------- ----------

2002
United States................... 19,348 2,442 183,708 5.21 25.31 15.29 3.15
Canada.......................... 9,205 641 120,210 3.83 23.46 12.41 2.74
Egypt........................... 15,977 -- 44,769 2.95 24.65 -- 3.71
Australia....................... 11,082 -- 42,998 3.06 25.17 -- 1.28
Other International............. 225 -- 2,656 2.58 23.90 -- 0.42
------ ----- -------
Total......................... 55,837 3,083 394,341 4.12 24.78 14.69 2.87
====== ===== =======
2001
United States................... 21,353 2,803 224,600 4.46 24.39 16.60 4.15
Canada.......................... 9,451 464 108,925 3.41 19.22 17.45 3.81
Egypt........................... 14,322 -- 35,010 2.45 23.59 -- 3.51
Australia....................... 8,595 -- 42,684 2.77 23.89 -- 1.22
Other International............. 43 -- 236 4.71 17.90 -- 1.20
------ ----- -------
Total......................... 53,764 3,267 411,455 3.69 23.18 16.72 3.70
====== ===== =======
2000
United States................... 20,687 2,207 199,361 3.82 27.85 20.04 4.02
Canada.......................... 5,387 441 47,758 2.39 22.25 18.36 3.65
Egypt........................... 10,155 -- 17,372 2.17 27.81 -- 4.51
Australia....................... 5,691 -- 39,489 2.49 29.99 -- 1.34
------ ----- -------
Total......................... 41,920 2,648 303,980 3.22 27.41 19.76 3.64
====== ===== =======

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 Note 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.

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

We engage an independent petroleum engineering firm to review our estimates
of proved hydrocarbon liquid and gas reserves. During 2002, 2001 and 2000, their
review covered 68, 61 and 72 percent of the reserve value, respectively. This
value, which represents estimated future net cash flows, is based on prices at
year-end and is calculated in accordance with SFAS No. 69, "Disclosures about
Oil and Gas producing Activities." Disclosure of this value and related reserves
has been prepared in accordance with the Securities and Exchange Commission
(SEC) Regulation S-X Rule 4-10 and is presented in Note 15 to the accompanying
financial statements.

RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS

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

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

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

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

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.

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
13

no assurance that acquisitions will not have an adverse effect upon our
operating results, particularly during the periods in which the operations of
acquired businesses are being integrated into our ongoing operations.

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

On March 14, 2002, our previous independent public accountant, Arthur
Andersen LLP, was indicted on federal obstruction of justice charges arising
from the federal government's investigation of Enron Corp. On June 15, 2002, a
jury returned with a guilty verdict against Arthur Andersen following a trial.
As a public company, we are required to file with the SEC periodic financial
statements audited or reviewed by an independent public accountant. On March 29,
2002, we decided not to engage Arthur Andersen as our independent auditors, and
engaged Ernst & Young LLP to serve as our new independent auditors for 2002.
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. None of our employees is
subject to collective bargaining agreements.

OFFICES

Our principal executive offices are located at One Post Oak Central, 2000
Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 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. Apache leases all of its primary
office space. The current lease on our principal executive offices runs through
April 30, 2007. For information regarding the Company's obligations under its
office leases, see the information appearing in the table in Item 7
-- Management's Discussion and Analysis of Financial Condition and Results of
Operations, "Liquidity" and Item 15, Note 11 -- "Operating Leases and Other
Commitments."

TITLE TO INTERESTS

We believe that our title to the various interests set forth above is
satisfactory and consistent with the standards generally accepted in the oil and
gas industry, subject only to immaterial exceptions which do not detract
substantially from the value of the interests or materially interfere with their
use in our operations. The

interests owned by us may be subject to one or more royalty, overriding royalty
and other outstanding interests customary in the industry. The interests may
additionally be subject to obligations or duties under applicable laws,
ordinances, rules, regulations and orders of arbitral or governmental
authorities. In addition, the interests may be subject to burdens such as
production payments, net profits interests, liens incident to operating
agreements and current taxes, development obligations under oil and gas leases
and other encumbrances, easements and restrictions, none of which detract
substantially from the value of the interests or materially interfere with their
use in our operations.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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 $0.625 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 two-for-one stock split and
the 10 percent and five percent stock dividends, all of which are described
below. Per share prices and dividends shown below have been rounded to the
indicated decimal place.

2002 2001
------------------------------------- -------------------------------------
PRICE RANGE DIVIDENDS PER SHARE PRICE RANGE DIVIDENDS PER SHARE
--------------- ------------------- --------------- -------------------
HIGH LOW DECLARED PAID HIGH LOW DECLARED PAID
------ ------ --------- ------- ------ ------ -------- ------

First Quarter......... $27.72 $21.13 $.0475 $.0475 $31.55 $23.47 $ -- $ --
Second Quarter........ 28.62 25.04 .0475 .0475 28.92 20.80 -- --
Third Quarter......... 28.57 21.46 .0475 .0475 23.55 16.56 .121 --
Fourth Quarter........ 28.88 23.55 .0475 .0475 23.87 17.57 .0475 .121

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 ($31.09 adjusted for the five percent stock dividend and
two-for-one stock split). At February 28, 2003, there were 153,850,136 shares of
our common stock outstanding (323,085,284 shares adjusted for the five percent
stock dividend and two-for-one stock split) 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 2.31 outstanding shares of common stock (adjusted for the 10
percent and five percent stock dividends and two-for-one stock split) that the
stockholder owned. We refer to these preferred stock purchase rights as the
"rights." Unless the rights have been previously redeemed, all shares of Apache
common stock are issued with rights. The rights trade automatically with our
shares of common stock. Certain triggering events will give the holders of the
rights the ability to purchase shares of our common stock, or the equivalent
stock of a person that acquires us, at a discount. The triggering events relate
to persons or groups acquiring an amount of our common stock in excess of a set
percentage, or attempting to or actually acquiring us. The details of how the
rights operate are set out in our certificate of incorporation and the Rights
Agreement, dated January 31, 1996, between Apache and Wells Fargo Bank
Minnesota, N.A. (formerly Norwest Bank Minnesota, N.A.). Both of those documents
have been filed as exhibits to this Form 10-K and you should review them to
fully understand the effects of the rights. The purpose of the rights is to
encourage potential acquirors to negotiate with our board of directors before
attempting a takeover bid and to provide our board of directors with leverage in
negotiating on behalf of our stockholders the terms of 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
(13,109,730 shares adjusted for the two-for-one stock split) 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 (26,140,136
shares adjusted for the two-for-one stock split) of our common stock on January
21, 2002 to the holders of the 130,888,270 shares (261,776,540 shares adjusted
for the two-for-one stock split) of common stock outstanding on December 31,
2001. No fractional shares were issued in connection with the stock dividend and
cash payments totaling $891,132 were made in lieu of fractional shares.

On December 18, 2002, our board of directors declared a five percent
dividend on our shares of common stock payable in common stock on April 2, 2003
to shareholders of record on March 12, 2003. Pursuant to the terms of the
declared five percent stock dividend, we expect to issue approximately 7,868,000
shares (15,736,000 shares adjusted for the two-for-one stock split) of our
common stock on April 2, 2003 to the holders of the 153,867,875 shares
(307,735,750 shares adjusted for the two-for-one stock split) 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 $1,437,000 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 (19.8 million shares
adjusted for the two-for-one stock split) of Apache common stock, including 1.3
million shares (2.6 million shares adjusted for the two-for-one stock split) for
the underwriters' over-allotment option, at $58.10 per share ($29.05 adjusted
for the two-for-one stock split). 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.

On September 11, 2003 our board of directors declared a two-for-one stock
split, which was distributed on January 14, 2004 to shareholders of record on
December 31, 2003.

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 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.

AS OF OR FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

INCOME STATEMENT DATA
Total revenues................... $2,559,873 $2,809,391 $2,301,978 $1,161,697 $ 772,791
Income (loss) attributable to
common stock................... 543,514 703,798 693,068 186,406 (131,391)
Net income (loss) per common
share:
Basic.......................... 1.83 2.44 2.54 .75 (.58)
Diluted........................ 1.80 2.37 2.46 .74 (.58)
Cash dividends declared per
common share................... .19 .17 .09 .12 .12
BALANCE SHEET DATA
Total assets..................... 9,459,851 8,933,656 7,481,950 5,502,543 3,996,062
Long-term debt................... 2,158,815 2,244,357 2,193,258 1,879,650 1,343,258
Preferred interests of
subsidiaries................... 436,626 440,683 -- -- --
Shareholders' equity............. 4,924,280 4,418,483 3,754,640 2,669,427 1,801,833
Common shares outstanding........ 302,506 287,916 285,596 263,332 225,846

For a discussion of significant acquisitions, see 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 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. Oil and gas
production for the first two years has been hedged to provide Apache with fixed
prices on expected production to protect against commodity price volatility (see
Note 4 of Item 15 in this Form 10-K).

On January 22, 2003, in conjunction with the BP transaction, we completed a
public offering of 9.9 million shares (19.8 million shares adjusted for the
two-for-one stock split) of common stock, including

1.3 million shares (2.6 million shares adjusted for the two-for-one stock split)
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 strong 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. We believe that
this reaffirmation of our credit ratings further establishes Apache's financial
wherewithal and reputation as a reliable purchaser of major companies' assets as
they sell assets in the future.

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, 2003, to shareholders of
record on March 12, 2003. On September 11, 2003, our board of directors declared
a two-for-one stock split, which was distributed on January 14, 2004 to
shareholders of record on December 31, 2003. All of the share and per share
information included in this filing has been adjusted to reflect this stock
dividend and the two-for-one stock split except where otherwise indicated.

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. See Results of Operations and Note 1 of Item 15 of this Form 10-K
for a discussion of additional accounting policies and estimates made by
management.

FULL-COST METHOD OF ACCOUNTING FOR OIL AND GAS OPERATIONS

The accounting for our business is subject to special accounting rules that
are unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities: the successful-efforts method
and the full-cost method. There are several significant differences between
these methods. Under the successful-efforts method, 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.

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

Should such a change be required, the amounts related to business
combinations and major asset purchases after June 30, 2001 that would be
classified as "intangible undeveloped mineral interest" was $9 million and $78
million as of December 31, 2001 and December 31, 2002, respectively. The amounts
related to business combinations and major asset purchases after June 30, 2001
that would be classified as "intangible developed mineral interest" was $88
million and $332 million as of December 31, 2001 and December 31, 2002,
respectively. Intangible developed mineral interest amounts are presented net of
accumulated depletion, depreciation and amortization (DD&A). Accumulated DD&A
was estimated using historical depletion rates applied proportionately to the
costs of the acquisitions to be classified as "intangible developed mineral
interest". The amounts noted above only include mineral rights acquired in
business combinations or major asset purchases, and exclude those acquired
individually or in groups as we have not historically tracked these in this
manner. The Company has also not historically tracked the amount of mineral
rights in the proved property balances related to producing leases or
relinquished leases. We are currently identifying a methodology to do so for
transactions subsequent to June 30, 2001.

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

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

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

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

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

RESERVE ESTIMATES

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

Despite the inherent imprecision in these engineering estimates, our
reserves are used throughout our financial statements. For example, since we use
the units-of-production method to amortize our oil and gas properties, the
quantity of reserves could significantly impact our 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.

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 removing and disposing of offshore oil and gas platforms.
Under the full-cost method of accounting, as described in the preceding critical
accounting policy sections, the estimated undiscounted costs of the abandonment
obligations, net of salvage, are currently included as a component of our
depletion base and expensed over the production life of the oil and gas
properties. 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." Apache adopted this statement effective January
1, 2003, as discussed in Note 2 of Item 15 of this Form 10-K. SFAS No. 143
significantly changed the method of accruing for costs an entity is legally
obligated to incur related to the retirement of fixed assets ("asset retirement
obligations" or "ARO"). Primarily, the new statement requires the Company to
record a separate liability for the discounted present value of the Company's
asset retirement obligations, with an offsetting increase to the related oil and
gas properties on the balance sheet.

Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance. In addition, increases in the discounted ARO liability resulting from
the passage of time will be reflected as accretion expense in the consolidated
statement of operations.

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

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

Going forward, our depletion expense will be reduced since we will deplete
a discounted ARO rather than the undiscounted value previously depleted. The
lower depletion expense under SFAS No. 143 is offset, however, by higher
accretion expense, which reflects increases in the discounted asset retirement
obligation over time.

Also going forward, the Company had to determine how to incorporate the
asset retirement obligations into the quarterly calculation of its full-cost
ceiling tests (see Note 1 of Item 15 of this Form 10-K). SFAS No. 143 is silent
with respect to this issue and, although there are various views, the Company
elected to continue including the undiscounted ARO as part of future development
costs, essentially reducing the present value of its future net revenues and
full-cost ceiling limit. To compare the property balance, which included the ARO
component, to the full-cost ceiling limit, which has been reduced by a similar
abandonment cost, we netted the ARO liability against the property balance. The
Company believes its view is appropriate since there must be a comparable basis
between the net book value of the properties and the full-cost ceiling
limitation. Another widely contemplated view is to exclude the ARO from future
development costs when calculating the full-cost ceiling limitation and not
reduce the carrying amount of capitalized costs by the related liability. This
approach would result in a higher full-cost ceiling limitation and a higher net
oil and gas property balance.

INCOME TAXES

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

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

DERIVATIVES

Apache uses commodity derivative contracts on a limited basis to manage its
exposure to oil and gas price volatility. 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

This section includes a discussion of our 2002 and 2001 results of
operations. Apache has five reportable segments, which are the United States,
Canada, Australia, Egypt and Other International. These segments are primarily
in the business of crude oil and natural gas exploration and production. Please
refer to Note 14 of Item 15 of this Form 10-K for segment information.

ACQUISITIONS AND DIVESTITURES

In 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.

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

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

Over ninety percent of our 2001 activity was spent on three acquisitions,
one in Canada and two in Egypt. The Fletcher acquisition in Canada totaled 55
percent while the Repsol and Novus acquisitions in Egypt totaled 37 percent of
our acquisition activity. All three acquisitions added significant reserves and
production.

Over ninety percent of our 2000 activity involved four North American
transactions, three in the U.S. and one in Canada. The U.S. acquisitions, which
totaled 56 percent of our acquisition outlays, included properties acquired from
Occidental Petroleum Corporation, Collins & Ware, Inc. and Repsol YPF. Our
Canadian

acquisition from Phillips Petroleum Company represented 36 percent of the year's
activity. These four transactions added significant reserves and production.

Our acquisitions over the last three years helped us maintain diversity in
terms of hydrocarbon product (oil or gas), geologic risk and geographic
location. As shown in Note 15 of this Form 10-K, our 2002 year-end international
reserves as a percentage of total reserves climbed to 52 percent from 41 percent
at year-end 2000. Similarly, our international average daily production in 2002
rose to 58 percent of our total production versus 41 percent in 2000. Our
hydrocarbon product mix on a boe basis has remained relatively constant at 53
percent natural gas and 47 percent oil. While the U.S., a highly stable
environment, remains our largest core area, Apache will continue to evaluate
acquisition opportunities in existing core areas and in new areas should they
arise.

Note that, in light of the uncertainty of how the collapse of Enron Corp.
would impact the derivatives markets, we closed all of our derivatives positions
in October and November 2001, most of which were associated with prior
acquisitions, recognizing a net gain 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.

Oil and Natural Gas Prices

While the market price received for crude oil and natural gas varies among
geographic areas, crude oil trades in a world-wide market, whereas natural gas,
which has a limited global transportation system, is subject to local supply and
demand conditions. Consequently, price movements for all types and grades of
crude oil generally move in the same direction, while natural gas price
movements generally follow local market conditions.

Apache sells its natural gas into three markets:

1) North America, which has a common market and where production is
currently in short supply relative to demand.

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

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

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

Contributions to Oil and Natural Gas Revenues

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

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

OIL REVENUES GAS REVENUES
--------------------------------- ---------------------------------
FOR THE YEAR ENDED DECEMBER 31, FOR THE YEAR ENDED DECEMBER 31,
--------------------------------- ---------------------------------
2002 2001 2000 2002 2001 2000
------- ------- ------- --------- --------- ---------

United States..................... 35% 40% 47% 51% 61% 72%
Canada............................ 16% 17% 13% 29% 27% 16%
---- ---- ---- ------- ------- -------
North America..................... 51% 57% 60% 80% 88% 88%
Egypt............................. 29% 27% 25% 15% 8% 7%
Australia......................... 20% 16% 15% 5% 4% 5%
Other International............... -- -- -- -- -- --
---- ---- ---- ------- ------- -------
Total........................... 100% 100% 100% 100.00% 100.00% 100.00%
==== ==== ==== ======= ======= =======

Crude Oil Contribution

In 2002, oil revenues outside the U.S. reached approximately 65 percent of
consolidated oil revenues, up from 60 percent in 2001. This increase primarily
occurred in Egypt and Australia where crude oil revenues rose to 28 percent and
20 percent of total oil revenues, respectively. Canada contributed 16 percent of
oil revenue, down from 17 percent in 2001.

In 2001, oil revenues outside the U.S. totaled 60 percent of consolidated
oil revenues, up from 53 percent in 2000. This increase was spread among Egypt,
Canada and Australia. Egypt's contribution totaled 27 percent, while Canada and
Australia contributed 17 percent and 16 percent, respectively.

Natural Gas Contribution

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

In 2001, 88 percent of Apache's natural gas revenues came from the North
American market, 61 percent from the U.S. and 27 percent from Canada. The
remaining natural gas revenues were primarily split between Egypt, 8 percent,
and Australia, 3 percent.

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

FOR THE YEAR ENDED DECEMBER 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------

Revenues (in thousands):
Natural gas............................................ $1,130,692 $1,521,959 $1,107,486
Oil.................................................... 1,383,749 1,246,384 1,149,028
Natural gas liquids.................................... 45,307 54,616 52,319
---------- ---------- ----------
Total............................................... $2,559,748 $2,822,959 $2,308,833
========== ========== ==========
Natural Gas Volume -- Mcf per day:
United States.......................................... 503,310 615,341 544,703
Canada................................................. 329,344 298,424 130,485
Egypt.................................................. 122,655 95,918 47,464
Australia.............................................. 117,802 116,943 107,894
Argentina.............................................. 7,276 648 --
---------- ---------- ----------
Total............................................... 1,080,387 1,127,274 830,546
========== ========== ==========
Average Natural Gas Price -- Per Mcf:
United States.......................................... $ 3.15 $ 4.15 $ 4.02
Canada................................................. 2.74 3.81 3.65
Egypt.................................................. 3.71 3.51 4.51
Australia.............................................. 1.28 1.22 1.34
Argentina.............................................. .42 1.20 --
Total............................................... 2.87 3.70 3.64
Oil Volume -- Barrels per day:
United States.......................................... 53,009 58,501 56,521
Canada................................................. 25,220 25,895 14,720
Egypt.................................................. 43,772 39,238 27,745
Australia.............................................. 30,361 23,548 15,551
Argentina.............................................. 617 117 --
---------- ---------- ----------
Total............................................... 152,979 147,299 114,537
========== ========== ==========
Average Oil Price -- Per barrel:
United States.......................................... $ 25.31 $ 24.39 $ 27.85
Canada................................................. 23.46 19.22 22.25
Egypt.................................................. 24.65 23.59 27.81
Australia.............................................. 25.17 23.89 29.99
Argentina.............................................. 23.90 17.90 --
Total............................................... 24.78 23.18 27.41
NGL Volume -- Barrels per day:
United States.......................................... 6,691 7,679 6,030
Canada................................................. 1,756 1,272 1,204
---------- ---------- ----------
Total............................................... 8,447 8,951 7,234
========== ========== ==========
Average NGL Price -- Per barrel:
United States.......................................... $ 15.29 $ 16.60 $ 20.04
Canada................................................. 12.41 17.45 18.36
Total............................................... 14.69 16.72 19.76

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

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 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.

OPERATING EXPENSES

The table below presents a detail of our expenses.

YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
(IN MILLIONS)

Depreciation, depletion and amortization:
Oil and gas property and equipment........................ $ 784 $ 760 $ 548
Other assets.............................................. 60 61 36
International impairments................................... 20 65 --
Lease operating costs....................................... 462 405 254
Gathering and transportation costs.......................... 38 35 19
Severance and other taxes................................... 63 70 59
General and administrative expenses......................... 105 89 76
Financing costs, net........................................ 113 118 106
------ ------ ------
Total.................................................. $1,645 $1,603 $1,098
====== ====== ======

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.

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

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

In 2001, our full-cost DD&A expense increased $212 million. The higher
expense was spread among Canada, up $87 million, the U.S., up $63 million,
Egypt, up $43 million and Australia, up $19 million, which is consistent with
their overall increase in production.

On a boe basis our 2001 full-cost DD&A rate rose $.30 to $6.05. The U.S.
contributed two-thirds to the increase in rate, related to higher finding costs
and negative reserve revisions associated with declining prices. Canada
contributed $.04 to the increase in the overall rate, reflecting the impact of
higher future development costs. Australia also contributed $.04 to the increase
in the overall rate, reflecting higher future development costs during 2001.

Depreciation on other assets remained flat in 2002 after increasing $25
million in 2001 associated with additional facilities acquired in March 2001
from Fletcher in Canada, and Repsol in Egypt, 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.

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. For further discussion, see Note 1 of Item 15
of this Form 10-K.

Lease Operating Costs

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

These costs are primarily related to the transportation of natural gas in
our North American operations. In 2002, the costs totaled $21 million in Canada
and $17 million in the U.S., relatively flat to the prior year.

In 2001, these costs totaled $19 million in Canada and $16 million in the
U.S., up from $12 million in Canada and $8 million in the U.S. The increase over
the 2000 period is related to higher volumes subject to such rates, principally
from properties acquired from Fletcher in Canada, and Gulf of Mexico properties
acquired from Occidental Petroleum Corporation in August 2000.

Severance and Other Taxes

Severance and other taxes are comprised primarily of severance taxes on
properties onshore and in state or provincial waters in the U.S. and Australia.
In both 2002 and 2001, these severance taxes, which are generally based on a
percentage of oil and gas production revenues, represented over 80 percent of
the total severance and other taxes expense incurred in each period. The other
tax component is primarily made up of the Australian Petroleum Resources Rent
Tax (PRRT), to which Apache first became subject in 2002, and the Canadian Large
Corporation Tax, Saskatchewan Capital Tax and Saskatchewan Resource Surtax. Oil
and gas production revenues generated from Egypt and Canada are not subject to
severance taxes.

In 2002, severance and other taxes totaled $63 million, comprised of U.S.,
$35 million, Australia, $23 million and Canada, $5 million. Overall, severance
and other taxes decreased $7 million. A $14 million decline in U.S. severance
taxes, and a $3 million decline in Canada Saskatchewan Resource Surtax were
partially offset by initial PRRT of $4 million and a $7 million increase in
Australian severance taxes. The decrease in U.S. severance taxes reflects the
impact of lower gas price realizations. The increase in Australia's severance
taxes was attributable to higher oil price realizations and a change in
production mix as a higher portion of production was from properties in
provincial waters, such as Legendre and Harriet, relative to production from
federal waters. Canada's decline was primarily related to a refund of the
Saskatchewan Resource Surtax.

In 2001, severance and other taxes totaled $70 million ($50 million in the
U.S., $12 million in Australia and $8 million in Canada). Severance and other
taxes increased $11 million from the prior year. The increase related to higher
severance taxes in Australia and, collectively, a $3 million increase in
Canada's Large Corporation Tax and Saskatchewan Resource Surtax. The increase in
Australia's severance taxes was attributable to higher production-driven oil and
gas revenues. Canada's increase was related to properties acquired from Fletcher
in March 2001 and Phillips Petroleum Company in December 2000. U.S. severance
and other taxes were up $2 million over the prior year. Higher production-driven
oil and gas revenues and a higher effective production tax rate accounted for
the majority of the increase in the U.S. Available incentives granted by the
state of Oklahoma decline with rising commodity prices, increasing the effective
tax rate.

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.
Realignment of our three U.S. regions into two involved both reassignment and
reduction of personnel. All corresponding costs were expensed as incurred.

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
30

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

YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
-------- ---------- ----------
(IN THOUSANDS)

Exploration and Development:
United States........................................... $302,611 $ 699,180 $ 495,803
Canada.................................................. 258,191 410,345 135,627
Egypt................................................... 171,160 127,603 84,949
Australia............................................... 89,813 85,169 73,835
Other international..................................... 38,409 20,838 18,077
-------- ---------- ----------
$860,184 $1,343,135 $ 808,291
======== ========== ==========
Capitalized Interest...................................... $ 40,691 $ 56,749 $ 62,000
======== ========== ==========
Gas Gathering Transmission and Processing Facilities...... $ 32,155 $ 28,759 $ 121,294
======== ========== ==========
Acquisitions:
Oil and gas properties.................................. $351,707 $ 880,286 $1,324,427
Gas gathering, transmission and processing facilities... 2,875 146,295 94,000
Goodwill................................................ -- 197,200 --
-------- ---------- ----------
$354,582 $1,223,781 $1,418,427
======== ========== ==========

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 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
adjusts capital expenditures in response to changes in oil and natural gas
prices, drilling and acquisition costs, and cash flow. The Company has

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

NET CASH PROVIDED BY OPERATING ACTIVITIES

Apache's net cash provided by operating activities during 2002 totaled $1.4
billion, a decrease of 28 percent from 2001 driven by lower oil and gas
production revenues and slightly higher operating expenses. Oil and gas
production revenues fell with a 22 percent decline in gas prices, which was
partially offset by a seven percent improvement in oil prices. The impact of
lower gas production was partially offset by rising oil production. Net cash
provided by operating activities during 2001 increased 26 percent to a record
$1.9 billion from $1.5 billion in 2000. The primary reason for the increase is
attributed to the additional oil and gas revenues from production on properties
acquired during 2000 and 2001.

DEBT

At December 31, 2002, Apache had outstanding debt of $280 million under its
commercial paper program and uncommitted lines of credit and a total of $1.9
billion of other debt. This other debt included notes and debentures maturing in
the years 2003 through 2096. Based on our current plan for capital spending and
projections of debt and interest rates, interest payments on the Company's debt
for 2003 are projected to be $157 million (using weighted-average balances for
floating rate obligations).

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

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

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances at December 31, 2002 and 2001 were classified as
long-term debt in the accompanying consolidated balance sheet as the Company has
the ability and intent to refinance such amounts on a long-term basis through
either the rollover of commercial paper or available borrowing capacity under
the U.S. five-year facility and the 364-day facility. If the Company is unable
to issue commercial paper following a significant credit downgrade or
dislocation in the market, the Company's U.S. five-year credit facility and
364-day credit facility are available as a 100 percent backstop. The
weighted-average interest rate for commercial paper was 1.85 percent in 2002 and
4.10 percent in 2001.

PREFERRED INTERESTS OF SUBSIDIARIES

During 2001, several of our subsidiaries issued a total of $443 million
($441 million, net of issuance costs) of preferred stock and limited partner
interests to unrelated institutional investors, adding to the Company's
financial liquidity. We pay a weighted-average return to the investors of 123
basis points above the prevailing LIBOR interest rate. These subsidiaries are
consolidated in the accompanying financial statements with the $437 million and
$441 million at December 31, 2002 and 2001, respectively, reflected as preferred
interests of subsidiaries on the balance sheet.

STOCK TRANSACTIONS

In December 2002, our board of directors declared a five percent stock
dividend, payable on April 2, 2003, to shareholders of record on March 12, 2003.
No fractional shares will be issued and cash payments will be made in lieu of
fractional shares. In connection with the declaration of this stock dividend, a
reclassification was made to transfer $396 million from retained earnings to
common stock and additional paid-in-capital in the accompanying consolidated
balance sheet.

On May 15, 2002, we completed the mandatory conversion of our Series C
Preferred Stock into approximately 6.6 million (13.1 million shares adjusted for
the two-for-one stock split) common shares.

In September 2001, our Board of Directors declared a 10 percent stock
dividend, which was paid on January 21, 2002, to shareholders of record on
December 31, 2001. No fractional shares were issued and cash payments were made
in lieu of fractional shares. In connection with the declaration of this stock
dividend, a reclassification was made to transfer $545 million from retained
earnings to common stock and additional paid-in-capital in the accompanying
consolidated balance sheet.

On January 22, 2003, we completed a public offering of approximately 9.9
million shares (19.8 million shares adjusted for the two-for-one stock split) of
common stock, including 1.3 million shares (2.6 million shares adjusted for the
two-for-one stock split) for the underwriters' over-allotment option, for net
proceeds of $554 million.

LIQUIDITY

During 2002, we strengthened our financial flexibility and continued to
build upon the solid financial performances of previous years. Cash will be
required to fund expenditures necessary to offset the inherent declines in
production and proven reserves typical in an extractive industry like ours.
Future success in growing reserves and production will be highly dependent on
capital resources available and our success in acquiring or finding additional
reserves. We believe that cash on hand, net cash generated from operating
activities, and unused committed borrowing capacity under our global credit
facility will be adequate to satisfy future financial obligations and liquidity
needs.

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

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

As of December 31, 2002, available borrowing capacity under our global
credit facility was $1.2 billion. We had $52 million in cash and cash
equivalents on hand at December 31, 2002, an increase from $36 million at the
prior year-end. In addition, the ratio of current assets to current liabilities
increased from 1.34 at the end of last year to 1.44 at December 31, 2002.

In August 2001, we purchased $116 million in U.S. Government Agency Notes
and subsequently sold $13 million of the notes in 2001. Of the remaining
balance, $17 million were designated as "available for sale" securities and were
sold for approximately $17 million in January 2002. The remaining $86 million
were designated as "held to maturity" and carried at amortized cost until they
matured on October 15, 2002. The sales proceeds were used to pay down on our
commercial paper balance.

We have assumed various financial obligations and commitments in the normal
course of operations. These contractual obligations represent known future cash
payments that we are required to make and relate primarily to long-term debt,
preferred interests of subsidiaries, operating leases, pipeline transportation
commitments and international commitments. The Company expects to fund these
contractual obligations with cash generated from operating activities. The
following table summarizes the Company's contractual obligations as of December
31, 2002. Please see the indicated Note to the Company's consolidated financial
statements, under Item 15 of this Form 10-K for further information regarding
these obligations.

NOTE
CONTRACTUAL OBLIGATIONS REFERENCE TOTAL 2003 2004 2005 2006 2007 THEREAFTER
----------------------- --------- ---------- -------- ------- ------- ------- -------- ----------
(IN THOUSANDS)

Long-term debt........ Note 6 $2,158,815 $ -- $ -- $ 830 $ 274 $489,559 $1,668,152
Preferred interests of
subsidiaries........ Note 12 436,626 -- -- -- -- -- 436,626
Operating leases and
other commitments... Note 11 310,143 107,234 49,735 33,769 31,158 23,096 65,151
International lease
commitments......... Note 11 71,456 40,780 17,099 7,010 6,567 -- --
Exploration
agreement........... Note 11 25,000 12,500 12,500 -- -- -- --
Properties acquired
requiring future
payments to
Occidental Petroleum
Corporation......... Note 3 20,478 10,609 9,869 -- -- -- --
Operating costs
associated with a
pre-existing
volumetric production
payment of acquired
properties.......... Note 3 13,879 4,502 3,770 3,047 2,530 30 --
---------- -------- ------- ------- ------- -------- ----------
Total Contractual
Obligations(a)...... $3,036,397 $175,625 $92,973 $44,656 $40,529 $512,685 $2,169,929
========== ======== ======= ======= ======= ======== ==========

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

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

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

Upon closing of our acquisition of the North Sea properties, Apache will
assume BP's abandonment obligation for those properties and such costs were
considered in determining the purchase price. The purchase of the properties,
however, does not relieve BP of its liabilities if Apache does not satisfy the
abandonment obligation. Although not currently required, to ensure Apache's
payments of these costs, Apache agreed to

deliver a letter of credit to BP if the rating of our senior unsecured debt is
lowered by both Moody's and Standard and Poor's from the Company's current
ratings of A3 and A-, respectively. Any such letter of credit would be in an
amount equal to the net present value of future abandonment costs of the North
Sea properties as of the date of any such ratings change. If Apache is obligated
to provide a letter of credit, it will expire if either rating agency restores
its rating to the present level. The initial letter of credit amount would be
$282 million. This amount represents the letter of credit requirement through
March 2004, and will be negotiated annually based on Apache's future abandonment
obligation estimates. In addition, under Apache's long-term oil physical sales
contract with BP, related to the BP acquisition, Apache may be required to post
margin if the mark-to-market exposure, as defined, exceeds the credit threshold
limits.

In addition to the letter of credit requirements covering BP's abandonment
obligations, our liquidity could be further impacted by a downgrade of the
credit rating for our senior unsecured long-term debt by Standard and Poor's to
BBB- or lower and by Moody's to Baa3 or lower; however, we do not believe that
such a sharp downgrade is reasonably likely. If our debt were to receive such a
downgrade, our subsidiaries that issued the preferred interests could be in
violation of their covenants which may require them to redeem some of the
preferred interests (see Note 12, under Item 15 of this Form 10-K). In addition,
generally under our commodity hedge agreements, Apache may be required to post
margin or terminate outstanding positions if the Company's credit ratings
decline significantly.

OFF-BALANCE SHEET ARRANGEMENTS

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

FUTURE TRENDS

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

- exploiting our existing asset base;

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

- investing in high-potential exploration prospects.

Apache's present plans are to increase 2003 worldwide capital expenditures
for exploratory and development drilling to approximately $1.3 billion from $860
million in 2002. We will continue to monitor commodity prices and adjust our
capital expenditures accordingly. We will also continue to evaluate and pursue
acquisition opportunities should they become available at reasonable prices.

EXPLOITING EXISTING ASSET BASE

Apache seeks to maximize the value of our existing asset base by increasing
production and reserves while reducing operating costs per unit. In order to
achieve these objectives, we rigorously pursue production enhancement
opportunities such as workovers, recompletions and moderate-risk drilling, while
divesting marginal and non-strategic properties and identifying other activities
to reduce costs. We expended a lot of effort in 2002 identifying exploitation
opportunities which, when combined with our South Louisiana property purchase
and our acquisition from BP, give us a large inventory at a time of high
commodity prices.

ACQUIRING PROPERTIES TO WHICH WE CAN ADD INCREMENTAL VALUE

Apache seeks to purchase reserves at appropriate prices by generally
avoiding auction processes where we are competing against other buyers. Our aim
is to follow each acquisition with a cycle of reserve enhancement, property
consolidation and cash flow acceleration, facilitating asset growth and debt
reduction. Exorbitant acquisition prices caused Apache to sideline its 2002
acquisition activities early in the year until appropriate opportunities arose
at reasonable prices, which began at the end of the year.

INVESTING IN HIGH-POTENTIAL EXPLORATION PROSPECTS

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY RISK

The major market risk exposure is in the pricing applicable to our oil and
gas production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to our United States and Canadian
natural gas production. Prices received for oil and gas production have been and
remain volatile and unpredictable. Monthly oil price realizations ranged from a
low of $18.85 per barrel to a high of $28.79 per barrel during 2002. Average gas
price realizations ranged from a monthly low of $2.11 per Mcf to a monthly high
of $3.62 per Mcf during the same period. Based on the Company's 2002 worldwide
oil production levels, a $1.00 per barrel change in the weighted-average
realized price of oil would increase or decrease revenues by $56 million. Based
on the Company's 2002 worldwide gas production levels, a $.10 per Mcf change in
the weighted-average realized price of gas would increase or decrease revenues
by $39 million.

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

We periodically enter into hedging activities on a portion of our projected
oil and natural gas production through a variety of financial and physical
arrangements intended to support oil and natural gas prices at targeted levels
and to manage our overall exposure to oil and gas price fluctuations. Apache may
use futures contracts, swaps, options and fixed-price physical contracts to
hedge its commodity prices. Realized gains or losses from the Company's price
risk management activities are recognized in oil and gas production revenues
when the associated production occurs. Apache does not generally hold or issue
derivative instruments for trading purposes. As indicated in Notes 3 and 4,
under Item 15 of this Form 10-K, the Company entered into several derivative
positions in conjunction with the South Louisiana acquisition in December 2002
and following year-end, with the acquisition from BP. These positions were
entered into to preserve our strong financial position in a period of cyclically
high gas and oil prices and were designated as cash flow hedged at anticipated
production.

At December 31, 2002, the Company had natural gas commodity collars with a
negative fair value of $4 million. A 10 percent increase in gas prices would
change the fair values of the gas collars by $(5) million. A 10 percent decrease
in gas prices would change the fair values of the gas collars by $5 million. The
model

used to arrive at the fair values for the commodity collars is based on a
third-party option pricing model. Changes in fair value, assuming 10 percent
price changes, assume non-constant volatility with volatility based on
prevailing market parameters at December 31, 2002. The natural gas and crude oil
fixed-price swaps and crude oil fixed-price physical contracts entered into
during the first quarter 2003 involved substantially more oil and gas volumes
than the 2002 collars. For additional detail on our 2003 derivative positions,
see Notes 3 and 4 of Item 15 of this Form 10-K.

We sell all of our Egyptian crude oil and natural gas to the EGPC for U.S.
dollars. Deteriorating economic conditions in Egypt during 2001 and 2002 have
lessened the availability of U.S. dollars resulting in a 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.

INTEREST RATE RISK

Approximately 85 percent of the Company's debt is issued at fixed interest
rates, minimizing the Company's exposure to fluctuations in short-term interest
rates. At December 31, 2002, the Company had $317 million of floating-rate debt
and $437 million of preferred interests of subsidiaries, both of which are
subject to fluctuations in short-term interest rates. A 10 percent change in the
floating interest rate (approximately 22 basis points) on these year-end
balances, would be approximately $2 million. The Company did not have any open
derivative contracts relating to interest rates at December 31, 2002 or 2001.

FOREIGN CURRENCY RISK

The Company's cash flow stream relating to certain international operations
is based on the U.S. dollar equivalent of cash flows measured in foreign
currencies. Australian gas production is sold under fixed-price Australian
dollar contracts and over half the costs incurred are paid in Australian
dollars. Revenue and disbursement transactions denominated in Australian dollars
are converted to U.S. dollar equivalents based on the exchange rate as of the
transaction date. Prior to October 1, 2002, reported cash flow from Canadian
operations was measured in Canadian dollars and converted to the U.S. dollar
equivalent based on the average of the Canadian and U.S. dollar exchange rates
for the period reported. The majority of Apache's debt in Canada is denominated
in U.S. dollars and, as such, was adjusted for differences in exchange rates at
each period end. This unrealized adjustment was recorded as Revenues and Other.
In light of the continuing transformation of the U.S. and Canadian energy
markets into a single energy market, we adopted the U.S. dollar as our
functional currency in Canada, effective October 1, 2002. A 10 percent
strengthening of the Australian and Canadian dollar will result in a foreign
currency net loss of approximately $31 million. The Company did not have any
open derivative contracts relating to foreign currencies at December 31, 2002,
or 2001.

FORWARD-LOOKING STATEMENTS AND RISK

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

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

fluctuations in oil and gas prices, or a prolonged continuation of low prices,
may substantially adversely affect the Company's financial position, results of
operations and cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required
to be filed under this item are presented on pages F-1 through F-54 of this Form
10-K, and are incorporated herein by reference.

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

The financial statements for the fiscal year ended December 31, 2002,
included in this report, have been audited by Ernst & Young LLP, independent
public auditors, as stated in their audit report appearing herein. The financial
statements for the fiscal years ended December 31, 2001, and December 31, 2000,
included in this report, have been audited by Arthur Andersen LLP, independent
public accountants, as stated in their audit report appearing herein. Arthur
Andersen has not consented to the inclusion of their audit report in this
report. For a discussion of the risks relating to Arthur Andersen's audit of our
financial statements, please see "Risks relating to Arthur Andersen LLP" in Item
1.

Arthur Andersen's audit reports on our consolidated financial statements
for each of the fiscal years ended December 31, 2001, and December 31, 2000,
included elsewhere in this report, did not contain an adverse opinion or
disclaimer of opinion, nor were they qualified or modified as to uncertainty,
audit scope or accounting principles.

During the years ended December 31, 2001 and December 31, 2000, and through
the date we dismissed Arthur Andersen LLP, there were no disagreements with
Arthur Andersen on any matter of accounting principle or practice, financial
statement disclosure, or auditing scope or procedure which, if not resolved by
Arthur Andersen's satisfaction, would have caused them to make reference to the
subject matter in connection with their report on our consolidated financial
statements for such years; and there were no reportable events as set forth in
applicable SEC regulations.

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

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information set forth under the captions "Nominees for Election as
Directors", "Continuing Directors", "Executive Officers of the Company", and
"Securities Ownership and Principal Holders" in the proxy statement relating to
the Company's 2003 annual meeting of stockholders (the Proxy Statement) is
incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

ITEM 14. CONTROLS AND PROCEDURES

G. Steven Farris, the Company's President, Chief Executive Officer and
Chief Operating Officer, and Roger B. Plank, the Company's Executive Vice
President and Chief Financial Officer, evaluated the effectiveness of our
disclosure controls and procedures within the last 90 days preceding the date of
this report. Based on that review and as of the date of that evaluation, these
officers found the company's disclosure controls to be adequate, providing
effective means to insure that we timely and accurately disclose the information
we are required to disclose under applicable laws and regulations. We also made
no significant changes in internal controls or any other factors that could
affect our internal controls since our most recent internal controls evaluation.

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

PART IV

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

(a) Documents included in this report:

1. Financial Statements

Report of management........................................ F-1
Report of Independent Auditors.............................. F-2
Reports of independent public accountants................... F-4
Statement of consolidated operations for each of the three
years in the period ended December 31, 2002............... F-5
Statement of consolidated cash flows for each of the three
years in the period ended December 31, 2002............... F-6
Consolidated balance sheet as of December 31, 2002 and
2001...................................................... F-7
Statement of consolidated shareholders' equity for each of
the three years in the period ended December 31, 2002..... F-8
Notes to consolidated financial statements.................. F-9

2. Financial Statement Schedules

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

3. Exhibits

EXHIBIT
NO. DESCRIPTION
------- -----------

2.1 -- Agreement and Plan of Merger among Registrant, YPY
Acquisitions, Inc. and The Phoenix Resource Companies, Inc.,
dated March 27, 1996 (incorporated by reference to Exhibit
2.1 to Registrant's Registration Statement on Form S-4,
Registration No. 333-02305, filed April 5, 1996).
2.2 -- Purchase and Sale Agreement by and between BP Exploration &
Production Inc., as seller, and Registrant, as buyer, dated
January 11, 2003 (incorporated by reference to Exhibit 2.1
to Registrant's Current Report on Form 8-K, filed January
13, 2003, SEC File No. 1-4300).
2.3 -- Sale and Purchase Agreement by and between BP Exploration
Operating Company Limited, as seller, and Apache North Sea
Limited, as buyer, dated January 11, 2003 (incorporated by
reference to Exhibit 2.2 to Registrant's Current Report on
Form 8-K, filed January 13, 2003, SEC File No. 1-4300).
3.1 -- Restated Certificate of Incorporation of Registrant, dated
December 16, 1999, as filed with the Secretary of State of
Delaware on December 17, 1999 (incorporated by reference to
Exhibit 99.1 to Registrant's Current Report on Form 8-K,
filed February 7, 2000, SEC File No. 1-4300).
3.2 -- Bylaws of Registrant, as amended May 2, 2002 (incorporated
by reference to Exhibit 3.1 to Registrant's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2002, SEC File
No. 1-4300).
4.1 -- Form of Certificate for Registrant's Common Stock
(incorporated by reference to Exhibit 4.1 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1995,
SEC File No. 1-4300).
4.2 -- Form of Certificate for Registrant's 5.68% Cumulative
Preferred Stock, Series B (incorporated by reference to
Exhibit 4.2 to Amendment No. 2 on Form 8-K/A, filed August
25, 1998, to Registrant's Current Report on Form 8-K, filed
August 18, 1998, SEC File No. 1-4300).
4.3 -- Form of Certificate for Registrant's Automatically
Convertible Equity Securities, Conversion Preferred Stock,
Series C (incorporated by reference to Exhibit 99.8 to
Amendment No. 1 on Form 8-K/A, filed May 12, 1999, to
Registrant's Current Report on Form 8-K, filed April 29,
1999, SEC File No. 1-4300).
4.4 -- Rights Agreement, dated January 31, 1996, between Registrant
and Norwest Bank Minnesota, N.A., rights agent, relating to
the declaration of a rights dividend to Registrant's common
shareholders of record on January 31, 1996 (incorporated by
reference to Exhibit (a) to Registrant's Registration
Statement on Form 8-A, dated January 24, 1996, SEC File No.
1-4300).
10.1 -- Credit Agreement, dated June 12, 1997, among Registrant, the
lenders named therein, Morgan Guaranty Trust Company, as
Global Documentation Agent and U.S. Syndication Agent, The
First National Bank of Chicago, as U.S. Documentation Agent,
NationsBank of Texas, N.A., as Co-Agent, Union Bank of
Switzerland, Houston Agency, as Co-Agent, and The Chase
Manhattan Bank, as Global Administrative Agent (incorporated
by reference to Exhibit 10.1 to Registrant's Current Report
on Form 8-K, filed June 25, 1997, SEC File No. 1-4300).
10.2 -- Form of Credit Agreement, dated as of June 3, 2002, among
Registrant, the Lenders named therein, JPMorgan Chase Bank,
as Global Administrative Agent, Bank of America, N.A., as
Global Syndication Agent, Citibank, N.A., as Global
Documentation Agent, Bank of America, N.A. and Wachovia
Bank, National Association, as U.S. Co-Syndication Agents,
and Citibank, N.A. and Union Bank of California, N.A., as
U.S. Co-Documentation Agents (excluding exhibits and
schedules) (incorporated by reference to Exhibit 10.2 to
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002, SEC File No. 1-4300).

EXHIBIT
NO. DESCRIPTION
------- -----------

10.3 -- Form of 364-Day Credit Agreement, dated as of June 3, 2002,
among Registrant, the Lenders named therein, JPMorgan Chase
Bank, as Global Administrative Agent, Bank of America, N.A.,
as Global Syndication Agent, Citibank, N.A., as Global
Documentation Agent, Bank of America, N.A. and BNP Paribas,
as 364-Day Co-Syndication Agents, and Deutsche Bank AG, New
York Branch, and Societe Generale, as 364-Day
Co-Documentation Agents (excluding exhibits and schedules)
(incorporated by reference to Exhibit 10.3 to Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2002, SEC File No. 1-4300).
10.4 -- Credit Agreement, dated June 12, 1997, among Apache Canada
Ltd., a wholly-owned subsidiary of the Registrant, the
Lenders named therein, Morgan Guaranty Trust Company, as
Global Documentation Agent, Royal Bank of Canada, as
Canadian Documentation Agent, The Chase Manhattan Bank of
Canada, as Canadian Syndication Agent, Bank of Montreal, as
Canadian Administrative Agent, and The Chase Manhattan Bank,
as Global Administrative Agent (incorporated by reference to
Exhibit 10.2 to Registrant's Current Report on Form 8-K,
filed June 25, 1997, SEC File No. 1-4300).
10.5 -- Form of Credit Agreement, dated as of June 3, 2002, among
Apache Canada Ltd, a wholly-owned subsidiary of Registrant,
the Lenders named therein, JPMorgan Chase Bank, as Global
Administrative Agent, Bank of America, N.A., as Global
Syndication Agent, Citibank, N.A., as Global Documentation
Agent, Royal Bank of Canada, as Canadian Administrative
Agent, The Bank of Nova Scotia and The Toronto-Dominion
Bank, as Canadian Co-Syndication Agents, and BNP Paribas
(Canada) and Bayerische Landesbank Girozentrale, as Canadian
Co-Documentation Agents (excluding exhibits and schedules)
(incorporated by reference to Exhibit 10.4 to Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2002, SEC File No. 1-4300).
10.6 -- Credit Agreement, dated June 12, 1997, among Apache Energy
Limited and Apache Oil Australia Pty Limited, wholly-owned
subsidiaries of the Registrant, the Lenders named therein,
Morgan Guaranty Trust Company, as Global Documentation
Agent, Bank of America National Trust and Savings
Association, Sydney Branch, as Australian Documentation
Agent, The Chase Manhattan Bank, as Australian Syndication
Agent, Citisecurities Limited, as Australian Admin-
istrative Agent, and The Chase Manhattan Bank, as Global
Administrative Agent (incorporated by reference to Exhibit
10.3 to Registrant's Current Report on Form 8-K, filed June
25, 1997, SEC File No. 1-4300).
10.7 -- Form of Credit Agreement, dated as of June 3, 2002, among
Apache Energy Limited, a wholly-owned subsidiary of
Registrant, the Lenders named therein, JPMorgan Chase Bank,
as Global Administrative Agent, Bank of America, N.A., as
Global Syndication Agent, Citibank, N.A., as Global
Documentation Agent, Citisecurities Limited, as Australian
Administrative Agent, Bank of America, N.A., Sydney Branch,
and Deutsche Bank AG, Sydney Branch, as Australian Co-
Syndication Agents, and Royal Bank of Canada and Bank One,
NA, Australia Branch, as Australian Co-Documentation Agents
(excluding exhibits and schedules) (incorporated by
reference to Exhibit 10.5 to Registrant's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2002, SEC File
No. 1-4300).
10.8 -- Concession Agreement for Petroleum Exploration and
Exploitation in the Khalda Area in Western Desert of Egypt
by and among Arab Republic of Egypt, the Egyptian General
Petroleum Corporation and Phoenix Resources Company of
Egypt, dated April 6, 1981 (incorporated by reference to
Exhibit 19(g) to Phoenix's Annual Report on Form 10-K for
year ended December 31, 1984, SEC File No. 1-547).
10.9 -- Amendment, dated July 10, 1989, to Concession Agreement for
Petroleum Exploration and Exploitation in the Khalda Area in
Western Desert of Egypt by and among Arab Republic of Egypt,
the Egyptian General Petroleum Corporation and Phoenix
Resources Company of Egypt incorporated by reference to
Exhibit 10(d)(4) to Phoenix's Quarterly Report on Form 10-Q
for quarter ended June 30, 1989, SEC File No. 1-547).

EXHIBIT
NO. DESCRIPTION
------- -----------

10.10 -- Farmout Agreement, dated September 13, 1985 and relating to
the Khalda Area Concession, by and between Phoenix Resources
Company of Egypt and Conoco Khalda Inc (incorporated by
reference to Exhibit 10.1 to Phoenix's Registration
Statement on Form S-1, Registration No. 33-1069, filed
October 23, 1985).
10.11 -- Amendment, dated March 30, 1989, to Farmout Agreement
relating to the Khalda Area Concession, by and between
Phoenix Resources Company of Egypt and Conoco Khalda Inc
(incorporated by reference to Exhibit 10(d)(5) to Phoenix's
Quarterly Report on Form 10-Q for quarter ended June 30,
1989, SEC File No. 1-547).
10.12 -- Amendment, dated May 21, 1995, to Concession Agreement for
Petroleum Exploration and Exploitation in the Khalda Area in
Western Desert of Egypt between Arab Republic of Egypt, the
Egyptian General Petroleum Corporation, Repsol Exploracion
Egipto S.A., Phoenix Resources Company of Egypt and Samsung
Corporation (incorporated by reference to exhibit 10.12 to
Registrant's Annual Report on Form 10-K for year ended
December 31, 1997, SEC File No. 1-4300).
10.13 -- Concession Agreement for Petroleum Exploration and
Exploitation in the Qarun Area in Western Desert of Egypt,
between Arab Republic of Egypt, the Egyptian General
Petroleum Corporation, Phoenix Resources Company of Qarun
and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated
by reference to Exhibit 10(b) to Phoenix's Annual Report on
Form 10-K for year ended December 31, 1993, SEC File No.
1-547).
10.14 -- Agreement for Amending the Gas Pricing Provisions under the
Concession Agreement for Petroleum Exploration and
Exploitation in the Qarun Area, effective June 16, 1994
(incorporated by reference to Exhibit 10.18 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1996,
SEC File No. 1-4300).
+10.15 -- Apache Corporation Corporate Incentive Compensation Plan A
(Senior Officers' Plan), dated July 16, 1998 (incorporated
by reference to Exhibit 10.13 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1998, SEC File No.
1-4300).
+10.16 -- Apache Corporation Corporate Incentive Compensation Plan B
(Strategic Objectives Format), dated July 16, 1998
(incorporated by reference to Exhibit 10.14 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.17 -- Apache Corporation 401(k) Savings Plan, dated August 1, 2002
(incorporated by reference to Exhibit 10.1 to Registrant's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002, SEC File No. 1-4300).
+**10.18 -- Amendment to Apache Corporation 401(k) Savings Plan, dated
January 27, 2003, effective as January 1, 2003.
+10.19 -- Apache Corporation Money Purchase Retirement Plan, dated
August 1, 2002 (incorporated by reference to Exhibit 10.2 to
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2002, SEC File No. 1-4300).
+**10.20 -- Amendment to Apache Corporation Money Purchase Retirement
Plan, dated January 27, 2003, effective as of January 1,
2003.
+10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation,
restated as of January 1, 1997, and amendments effective as
of January 1, 1997, January 1, 1998 and January 1, 1999
(incorporated by reference to Exhibit 10.17 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache
Corporation, dated February 22, 2000, effective as of
January 1, 1999 (incorporated by reference to Exhibit 4.7 to
Registrant's Registration Statement on Form S-8,
Registration No. 333-31092, filed February 25, 2000); and
Amendment dated July 27, 2000 (incorporated by reference to
Exhibit 4.8 to Post-Effective Amendment No. 1 to
Registrant's Registration Statement on Form S-8,
Registration No. 333-31092, filed August 18, 2000).

EXHIBIT
NO. DESCRIPTION
------- -----------

+10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache
Corporation, dated August 3, 2001, effective as of September
1, 2000 and July 1, 2001 (incorporated by reference to
Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended June 30,
2001, SEC File No. 1-4300).
+10.24 -- Apache Corporation 1990 Stock Incentive Plan, as amended and
restated September 13, 2001, (incorporated by reference to
Exhibit 10.01 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).
+10.25 -- Apache Corporation 1995 Stock Option Plan, as amended and
restated September 13, 2001, (incorporated by reference to
Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).
+**10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended
and restated February 5, 2003, effective as of March 12,
2003.
+10.27 -- Apache Corporation 1996 Performance Stock Option Plan, as
amended and restated September 13, 2001 (incorporated by
reference to Exhibit 10.03 to Registrant's Quarterly Report
on Form 10-Q, as amended by Form 10-Q/A, for the quarter
ended September 30, 2001, SEC File No. 1-4300).
+10.28 -- Apache Corporation 1998 Stock Option Plan, as amended and
restated September 13, 2001 (incorporated by reference to
Exhibit 10.04 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).
+10.29 -- Apache Corporation 2000 Stock Option Plan, as amended and
restated March 5, 2003 (incorporated by reference to Exhibit
4.5 to Registrant's Registration Statement on Form S-8,
Registration No. 333-103758, filed March 12, 2003).
+10.30 -- 1990 Employee Stock Option Plan of The Phoenix Resource
Companies, Inc., as amended through September 29, 1995,
effective April 9, 1990 (incorporated by reference to
Exhibit 10.33 to Registrant's Annual Report on Form 10-K for
year ended December 31, 1996, SEC File No. 1-4300).
+10.31 -- Apache Corporation Income Continuance Plan, as amended and
restated May 3, 2001 (incorporated by reference to Exhibit
10.30 to Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, SEC File No. 1-4300).
+10.32 -- Apache Corporation Deferred Delivery Plan, as amended and
restated December 18, 2002, effective as of May 2, 2002
(incorporated by reference o Exhibit 4.5 to Post-Effective
Amendment No. 2 to Registrant's Registration Statement on
Form S-8, Registration No. 333-31092, filed March 11, 2003).
+10.33 -- Apache Corporation Executive Restricted Stock Plan, as
amended and restated December 18, 2002, effective as of May
2, 2002 (incorporated by reference to Exhibit 4.5 to
Post-Effective Amendment No. 1 to Registrant's Registration
Statement on Form S-8, Registration No. 333-97403, filed
December 30, 2002).
+10.34 -- Apache Corporation Non-Employee Directors' Compensation
Plan, as amended and restated December 17, 1998
(incorporated by reference to Exhibit 10.26 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.35 -- Apache Corporation Outside Directors' Retirement Plan, as
amended and restated May 3, 2001 (incorporated by reference
to Exhibit 10.08 to Registrant's Quarterly Report on Form
10-Q, as amended by Form 10-Q/A, for the quarter ended June
30, 2001, SEC File No. 1-4300).
+10.36 -- Apache Corporation Equity Compensation Plan for Non-Employee
Directors, as amended and restated May 3, 2001 (incorporated
by reference to Exhibit 10.09 to Registrant's Quarterly
Report on Form 10-Q, as amended by Form 10-Q/A, for the
quarter ended June 30, 2001, SEC File No. 1-4300).
+10.37 -- Amended and Restated Employment Agreement, dated December 5,
1990, between Registrant and Raymond Plank (incorporated by
reference to Exhibit 10.39 to Registrant's Annual Report on
Form 10-K for year ended December 31, 1996, SEC File No.
1-4300).

EXHIBIT
NO. DESCRIPTION
------- -----------

+10.38 -- First Amendment, dated April 4, 1996, to Restated Employment
Agreement between Registrant and Raymond Plank (incorporated
by reference to Exhibit 10.40 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1996, SEC File No.
1-4300).
+10.39 -- Amended and Restated Employment Agreement, dated December
20, 1990, between Registrant and John A. Kocur (incorporated
by reference to Exhibit 10.10 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1990, SEC File No.
1-4300).
+10.40 -- Employment Agreement, dated June 6, 1988, between Registrant
and G. Steven Farris (incorporated by reference to Exhibit
10.6 to Registrant's Annual Report on Form 10-K for year
ended December 31, 1989, SEC File No. 1-4300).
+10.41 -- Amended and Restated Conditional Stock Grant Agreement,
dated June 6, 2001, between Registrant and G. Steven Farris
(incorporated by reference to Exhibit 10.10 to Registrant's
Quarterly Report on Form 10-Q, as amended by Form 10-Q/A,
for the quarter ended June 30, 2001, SEC File No. 1-4300).
10.42 -- Amended and Restated Gas Purchase Agreement, effective July
1, 1998, by and among Registrant and MW Petroleum
Corporation, as seller, and Producers Energy Marketing, LLC,
as buyer (incorporated by reference to Exhibit 10.1 to
Registrant's Current Report on Form 8-K, filed June 23,
1998, SEC File No. 1-4300).
10.43 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made
by Registrant in favor of BP Exploration Operating Company
Limited (incorporated by reference to Exhibit 10.1 to Regis-
trant's Current Report on Form 8-K, filed January 13, 2003,
SEC File No. 1-4300).
**12.1 -- Statement of Computation of Ratios of Earnings to Fixed
Charges and Combined Fixed Charges and Preferred Stock
Dividends
**21.1 -- Subsidiaries of Registrant
*23.1 -- Consent of Ernst & Young LLP
**23.2 -- Consent of Ryder Scott Company L.P., Petroleum Consultants
**24.1 -- Power of Attorney (included as a part of the signature pages
to this report)
*31.1 -- Certification of Chief Executive Officer
*31.2 -- Certification of Chief Financial Officer
*32.1 -- Certification of Chief Executive Officer and Chief Financial
Officer

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

** Previously filed.

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

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

SIGNATURES

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

APACHE CORPORATION

/s/ G. STEVEN FARRIS
--------------------------------------

G. Steven Farris

President, Chief Executive Officer
and Chief Operating Officer

Dated: January 23, 2004

POWER OF ATTORNEY

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

NAME TITLE DATE
---- ----- ----

/s/ G. STEVEN FARRIS Director, President, Chief January 23, 2004
-------------------------------------- Executive Officer and Chief
G. Steven Farris Operating Officer (Principal
Executive Officer)

/s/ ROGER B. PLANK Executive Vice President and January 23, 2004
-------------------------------------- Chief Financial Officer
Roger B. Plank (Principal Financial Officer)

/s/ THOMAS L. MITCHELL Vice President and Controller January 23, 2004
-------------------------------------- (Principal Accounting Officer)
Thomas L. Mitchell

* Chairman of the Board January 23, 2004
--------------------------------------
Raymond Plank

* Director January 23, 2004
--------------------------------------
Frederick M. Bohen

* Director January 23, 2004
--------------------------------------
Randolph M. Ferlic

* Director January 23, 2004
--------------------------------------
Eugene C. Fiedorek

* Director January 23, 2004
--------------------------------------
A. D. Frazier, Jr.

NAME TITLE DATE
---- ----- ----

* Director January 23, 2004
--------------------------------------
Patricia Albjerg Graham

* Director January 23, 2004
--------------------------------------
John A. Kocur

* Director January 23, 2004
--------------------------------------
George D. Lawrence

* Director January 23, 2004
--------------------------------------
F. H. Merelli

* Director January 23, 2004
--------------------------------------
Rodman D. Patton

* Director January 23, 2004
--------------------------------------
Charles J. Pitman

* Director January 23, 2004
--------------------------------------
Jay A. Precourt

*By /s/ ROGER B. PLANK January 23, 2004
------------------------------
Roger B. Plank
Attorney-in-Fact

REPORT OF MANAGEMENT

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

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

The consolidated financial statements of Apache Corporation and
subsidiaries have been audited by the independent auditors, Ernst & Young LLP
for 2002 and Arthur Andersen LLP for 2001 and 2000. Their audits included
developing an overall understanding of the Company's accounting systems,
procedures and internal controls and conducting tests and other auditing
procedures sufficient to support their opinion on the fairness of the
consolidated financial statements.

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

Houston, Texas

March 14, 2003

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

ROGER B. PLANK
Executive Vice President and Chief
Financial Officer

THOMAS L. MITCHELL
Vice President and Controller
(Chief Accounting Officer)

F-1

REPORT OF INDEPENDENT AUDITORS

To the Shareholders of Apache Corporation:

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

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

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

As discussed above, the financial statements of Apache Corporation as of
December 31, 2001, and for each of the two years in the period then ended, were
audited by other auditors who have ceased operations. As described in Note 1,
these financial statements have been revised to reflect third party gathering
and transportation costs as an operating cost instead of a reduction of revenues
as previously reported. We audited the adjustments described in Note 1 that were
applied to revise the 2001 and 2000 consolidated statement of operations. As
described in Note 1, in 2002 the Company's Board of Directors approved a five
percent stock dividend, and all references to number of shares and per share
information in the financial statements have been adjusted to reflect the stock
dividend on a retroactive basis. We audited the adjustments that were applied to
restate the number of shares and per share information reflected in the 2002
financial statements. Our procedures included (a) agreeing the authorization for
the five percent stock dividend to the Company's underlying records obtained
from management, and (b) testing the mathematical accuracy of the restated
number of shares, basic and diluted earnings per share. In our opinion, such
adjustments are appropriate and have been properly applied. However, we were not
engaged to audit, review, or apply any procedures to the 2001 and 2000 financial
statements of Apache Corporation other than with respect to such adjustments and
the adjustments described below related to the two-for-one stock split;
accordingly, we do not express an opinion or any other form of assurance on the
2001 and 2000 financial statements taken as a whole.

Since the date of completion of our audit of the financial statements and
initial issuance of our report thereon dated March 14, 2003, as described in
Note 1, the Company's Board of Directors approved a two-for-one stock split
distributed in the form of a stock dividend, and all references to number of
shares and per share information in the financial statements have been adjusted
to reflect the stock split on a retroactive basis. As discussed above, the
financial statements of Apache Corporation as of December 31, 2001, and for each
of the two years in the period then ended, were audited by other auditors who
have ceased operations. We audited the adjustments that were applied to restate
the number of shares and per share information reflected in the 2002 financial
statements. Our procedures included (a) agreeing the authorization for the
two-for-one stock split to the Company's underlying records obtained from
Management, and (b) testing the mathematical accuracy of the restated number of
shares, basic and diluted earnings per share. In our opinion, such

F-2

adjustments are appropriate and have been properly applied. However, we were not
engaged to audit, review, or apply any procedures to the 2001 and 2000 financial
statements of Apache Corporation other than with respect to such adjustments and
the adjustments described in the preceding paragraph relating to the five
percent stock dividend and, accordingly, we do not express an opinion or any
other form of assurance on the 2001 and 2000 financial statements taken as a
whole.

ERNST & YOUNG LLP

Houston, Texas
March 14, 2003

Except for the two-for-one stock split discussed in Note 1 and the Statement of
Financial Accounting Standards No. 141 and 142 disclosure discussed in Note 1
for which the date is January 16, 2004.

F-3

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Apache Corporation:

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

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

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

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

ARTHUR ANDERSEN LLP

Houston, Texas
March 12, 2002

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

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------
2002 2001 2000
------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER COMMON SHARE DATA)

REVENUES AND OTHER:
Oil and gas production revenues........................ $2,559,748 $2,822,959 $2,308,833
Other.................................................. 125 (13,568) (6,855)
---------- ---------- ----------
2,559,873 2,809,391 2,301,978
---------- ---------- ----------
OPERATING EXPENSES:
Depreciation, depletion and amortization............... 843,879 820,831 583,546
International impairments.............................. 19,600 65,000 --
Lease operating costs.................................. 462,124 404,814 253,709
Gathering and transportation costs..................... 38,567 34,584 19,616
Severance and other taxes.............................. 63,088 69,827 59,173
General and administrative............................. 104,588 88,710 75,615
Financing costs:
Interest expense.................................... 155,667 178,915 168,121
Amortization of deferred loan costs................. 1,859 2,460 2,726
Capitalized interest................................ (40,691) (56,749) (62,000)
Interest income..................................... (4,002) (5,864) (2,209)
---------- ---------- ----------
1,644,679 1,602,528 1,098,297
---------- ---------- ----------
PREFERRED INTERESTS OF SUBSIDIARIES...................... 16,224 7,609 --
---------- ---------- ----------
INCOME BEFORE INCOME TAXES............................... 898,970 1,199,254 1,203,681
Provision for income taxes............................. 344,641 475,855 483,086
---------- ---------- ----------
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE............. 554,329 723,399 720,595
Cumulative effect of change in accounting principle,
net of income tax................................... -- -- (7,539)
---------- ---------- ----------
NET INCOME............................................... 554,329 723,399 713,056
Preferred stock dividends.............................. 10,815 19,601 19,988
---------- ---------- ----------
INCOME ATTRIBUTABLE TO COMMON STOCK...................... $ 543,514 $ 703,798 $ 693,068
========== ========== ==========
BASIC NET INCOME PER COMMON SHARE:
Before change in accounting principle.................. $ 1.83 $ 2.44 $ 2.57
Cumulative effect of change in accounting principle.... -- -- (.03)
---------- ---------- ----------
$ 1.83 $ 2.44 $ 2.54
========== ========== ==========
DILUTED NET INCOME PER COMMON SHARE:
Before change in accounting principle.................. $ 1.80 $ 2.37 $ 2.49
Cumulative effect of change in accounting principle.... -- -- (.03)
---------- ---------- ----------
$ 1.80 $ 2.37 $ 2.46
========== ========== ==========

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

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 554,329 $ 723,399 $ 713,056
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization................ 843,879 820,831 583,546
Provision for deferred income taxes..................... 137,672 305,214 350,703
Amortization of deferred loan costs..................... 1,859 2,460 2,726
International impairments............................... 19,600 65,000 --
Cumulative effect of change in accounting principle, net
of income tax......................................... -- -- 7,539
Other................................................... 9,531 10,469 9,719
Changes in operating assets and liabilities, net of
effects of acquisitions:
(Increase) decrease in receivables...................... (122,830) 199,160 (253,721)
(Increase) decrease in advances to oil and gas ventures
and other............................................. (26,116) (14,474) (6,167)
(Increase) decrease in product inventory................ 717 (3,005) 722
(Increase) decrease in deferred charges and other....... 496 (922) 5,967
Increase (decrease) in payables......................... 32,219 (143,969) 111,841
Increase (decrease) in accrued expenses................. (16,595) 10,065 33,263
Increase (decrease) in advances from gas purchasers..... (14,574) (13,079) (27,850)
Increase (decrease) in deferred credits and noncurrent
liabilities........................................... (39,469) (56,149) (13,976)
----------- ----------- -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES............. 1,380,718 1,905,000 1,517,368
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment....................... (1,037,368) (1,528,984) (955,576)
Acquisition of Louisiana properties....................... (258,885) -- --
Acquisition of Fletcher subsidiaries, net of cash
acquired................................................ -- (465,018) --
Acquisition of Repsol properties, net of cash acquired.... -- (446,933) (118,678)
Acquisition of Phillips properties........................ -- -- (490,250)
Acquisition of Occidental properties...................... (11,000) (11,000) (321,206)
Acquisition of Collins & Ware properties.................. -- -- (320,682)
Proceeds from sales of oil and gas properties............. 7,043 348,296 26,271
Proceeds from (purchase of ) short-term investments,
net..................................................... 101,723 (103,863) --
Other, net................................................ (37,520) (76,835) (36,875)
----------- ----------- -----------
NET CASH USED IN INVESTING ACTIVITIES................. (1,236,007) (2,284,337) (2,216,996)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings...................................... 1,467,929 2,759,740 1,125,981
Payments on long-term debt................................ (1,553,471) (2,733,641) (793,531)
Dividends paid............................................ (68,879) (54,492) (52,945)
Preferred stock activity.................................. -- -- (2,613)
Common stock activity..................................... 30,708 10,205 465,306
Treasury stock activity, net.............................. 1,991 (42,959) (17,730)
Cost of debt and equity transactions...................... (6,728) (1,718) (838)
Proceeds from preferred interests of subsidiaries......... -- 440,654 --
----------- ----------- -----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES... (128,450) 377,789 723,630
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 16,261 (1,548) 24,002
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 35,625 37,173 13,171
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 51,886 $ 35,625 $ 37,173
=========== =========== ===========

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

DECEMBER 31,
-------------------------
2002 2001
----------- -----------
(IN THOUSANDS)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 51,886 $ 35,625
Receivables, net of allowance............................. 527,687 404,793
Inventories............................................... 109,204 102,536
Drilling advances......................................... 45,298 26,438
Prepaid assets and other.................................. 32,706 25,407
Short-term investments.................................... -- 102,950
----------- -----------
766,781 697,749
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full cost accounting:
Proved properties....................................... 12,827,459 11,390,692
Unproved properties and properties under development,
not being amortized.................................... 656,272 839,921
Gas gathering, transmission and processing facilities..... 784,271 748,675
Other..................................................... 194,685 168,915
----------- -----------
14,462,687 13,148,203
Less: Accumulated depreciation, depletion and
amortization............................................ (5,997,102) (5,135,131)
----------- -----------
8,465,585 8,013,072
----------- -----------
OTHER ASSETS:
Goodwill, net............................................. 189,252 188,812
Deferred charges and other................................ 38,233 34,023
----------- -----------
$ 9,459,851 $ 8,933,656
=========== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 214,288 $ 179,778
Accrued operating expense................................. 47,382 50,584
Accrued exploration and development....................... 146,871 175,943
Accrued compensation and benefits......................... 32,680 30,947
Accrued interest.......................................... 30,880 28,592
Accrued income taxes...................................... 44,256 40,030
Other..................................................... 15,878 16,584
----------- -----------
532,235 522,458
----------- -----------
LONG-TERM DEBT.............................................. 2,158,815 2,244,357
----------- -----------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes.............................................. 1,120,609 991,723
Advances from gas purchasers.............................. 125,453 140,027
Oil and gas derivative instruments........................ 3,507 --
Other..................................................... 158,326 175,925
----------- -----------
1,407,895 1,307,675
----------- -----------
PREFERRED INTERESTS OF SUBSIDIARIES......................... 436,626 440,683
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 11)
SHAREHOLDERS' EQUITY:
Preferred stock, no par value, 5,000,000 shares
authorized --
Series B, 5.68% Cumulative Preferred Stock, 100,000
shares issued and outstanding.......................... 98,387 98,387
Series C, 6.5% Conversion Preferred Stock, 138,482
shares issued and outstanding for 2001................. -- 208,207
Common stock, $0.625 par, 430,000,000 shares authorized,
310,929,080 and 296,460,766 shares issued,
respectively............................................ 194,331 185,288
Paid-in capital........................................... 3,427,450 2,803,825
Retained earnings......................................... 1,427,607 1,336,478
Treasury stock, at cost, 8,422,656 and 8,544,090 shares,
respectively............................................ (110,559) (111,885)
Accumulated other comprehensive loss...................... (112,936) (101,817)
----------- -----------
4,924,280 4,418,483
----------- -----------
$ 9,459,851 $ 8,933,656
=========== ===========

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

F-7

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY

SERIES B SERIES C
COMPREHENSIVE PREFERRED PREFERRED COMMON PAID-IN RETAINED
INCOME STOCK STOCK STOCK CAPITAL EARNINGS
------------- --------- --------- -------- ---------- ----------
(IN THOUSANDS)

BALANCE AT DECEMBER 31, 1999.................. $98,387 $ 210,490 $168,057 $1,694,474 $ 558,721
Comprehensive income (loss):
Net income................................ $713,056 -- -- -- -- 713,056
Currency translation adjustments.......... (31,389) -- -- -- -- --
Marketable securities..................... (397) -- -- -- -- --
--------
Comprehensive income........................ $681,270
========
Cash dividends:
Preferred................................. -- -- -- -- (19,658)
Common ($.09 per share)................... -- -- -- -- (25,258)
Preferred stock repurchased................. -- (2,283) -- -- (330)
Common shares issued........................ -- -- 14,579 453,771 --
Treasury shares purchased, net.............. -- -- -- 428 --
------- --------- -------- ---------- ----------
BALANCE AT DECEMBER 31, 2000.................. 98,387 208,207 182,636 2,148,673 1,226,531
Comprehensive income (loss):
Net income................................ $723,399 -- -- -- -- 723,399
Currency translation adjustments.......... (74,028) -- -- -- -- --
Commodity hedges.......................... 12,136 -- -- -- -- --
Marketable securities..................... 307 -- -- -- -- --
--------
Comprehensive income........................ $661,814
========
Cash dividends:
Preferred................................. -- -- -- -- (19,601)
Common ($.17 per share)................... -- -- -- -- (48,980)
Ten percent common stock dividend........... -- -- -- 544,848 (544,871)
Common shares issued........................ -- -- 2,652 109,086 --
Treasury shares purchased, net.............. -- -- -- 1,218 --
------- --------- -------- ---------- ----------
BALANCE AT DECEMBER 31, 2001.................. 98,387 208,207 185,288 2,803,825 1,336,478
Comprehensive income (loss):
Net income................................ $554,329 -- -- -- -- 554,329
Currency translation adjustments.......... 5,328 -- -- -- -- --
Commodity hedges.......................... (16,322) -- -- -- -- --
Marketable securities..................... (125) -- -- -- -- --
--------
Comprehensive income........................ $543,210
========
Cash dividends:
Preferred................................. -- -- -- -- (10,815)
Common ($.19 per share)................... -- -- -- -- (56,565)
Five percent common stock dividend.......... -- -- -- 395,820 (395,820)
Common shares issued........................ -- -- 1,240 26,044 --
Conversion of Series C Preferred Stock...... -- (208,207) 7,803 200,404 --
Treasury shares issued, net................. -- -- -- 666 --
Other....................................... -- -- -- 691 --
------- --------- -------- ---------- ----------
BALANCE AT DECEMBER 31, 2002.................. $98,387 $ -- $194,331 $3,427,450 $1,427,607
======= ========= ======== ========== ==========

ACCUMULATED
OTHER TOTAL
TREASURY COMPREHENSIVE SHAREHOLDERS'
STOCK INCOME (LOSS) EQUITY
--------- ------------- -------------
(IN THOUSANDS)

BALANCE AT DECEMBER 31, 1999.................. $ (52,256) $ (8,446) $2,669,427
Comprehensive income (loss):
Net income................................ -- -- 713,056
Currency translation adjustments.......... -- (31,389) (31,389)
Marketable securities..................... -- (397) (397)
Comprehensive income........................
Cash dividends:
Preferred................................. -- -- (19,658)
Common ($.09 per share)................... -- -- (25,258)
Preferred stock repurchased................. -- -- (2,613)
Common shares issued........................ -- -- 468,350
Treasury shares purchased, net.............. (17,306) -- (16,878)
--------- --------- ----------
BALANCE AT DECEMBER 31, 2000.................. (69,562) (40,232) 3,754,640
Comprehensive income (loss):
Net income................................ -- -- 723,399
Currency translation adjustments.......... -- (74,028) (74,028)
Commodity hedges.......................... -- 12,136 12,136
Marketable securities..................... -- 307 307
Comprehensive income........................
Cash dividends:
Preferred................................. -- -- (19,601)
Common ($.17 per share)................... -- -- (48,980)
Ten percent common stock dividend........... -- -- (23)
Common shares issued........................ -- -- 111,738
Treasury shares purchased, net.............. (42,323) -- (41,105)
--------- --------- ----------
BALANCE AT DECEMBER 31, 2001.................. (111,885) (101,817) 4,418,483
Comprehensive income (loss):
Net income................................ -- -- 554,329
Currency translation adjustments.......... -- 5,328 5,328
Commodity hedges.......................... -- (16,322) (16,322)
Marketable securities..................... -- (125) (125)
Comprehensive income........................
Cash dividends:
Preferred................................. -- -- (10,815)
Common ($.19 per share)................... -- -- (56,565)
Five percent common stock dividend.......... -- -- --
Common shares issued........................ -- -- 27,284
Conversion of Series C Preferred Stock...... -- -- --
Treasury shares issued, net................. 1,326 -- 1,992
Other....................................... -- -- 691
--------- --------- ----------
BALANCE AT DECEMBER 31, 2002.................. $(110,559) $(112,936) $4,924,280
========= ========= ==========

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations -- Apache Corporation (Apache or the Company) is an
independent energy company that explores for, develops and produces natural gas,
crude oil and natural gas liquids. The Company's North American exploration and
production activities are divided into two U.S. operating regions (Central and
Gulf Coast) and a Canadian region. Approximately 78 percent of the Company's
proved reserves are located in North America. Internationally, Apache has
exploration and production interests in Egypt, offshore Western Australia and in
Argentina, a development project underway offshore The People's Republic of
China (China) that is expected to commence production in 2003 and exploration
interests in Poland.

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

Stock Split -- On September 11, 2003, the Company's board of directors
declared a two-for-one common stock split which was distributed on January 14,
2004 to shareholders of record on December 31, 2003.

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

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

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

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

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

Allowance for Doubtful Accounts -- The Company routinely assesses the
recoverability of all material trade and other receivables to determine their
collectibility. Many of Apache's receivables are from joint interest owners on
properties of which the Company is the operator. Thus, Apache may have the
ability to withhold future revenue disbursements to recover any non-payment of
joint interest billings. Generally, the Company's crude oil and natural gas
receivables are typically collected within two months. In Egypt, however, the
Company has experienced a gradual decline in the timeliness of receipts from the
Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions
during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars,
resulting in an additional one to two month delay in receipts from

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EGPC. Continuation of the hard currency shortage in Egypt could lead to further
delays, deferrals of payment or non-payment in the future. The Company accrues a
reserve on a receivable when, based on the judgment of management, it is
probable that a receivable will not be collected and the amount of any reserve
may be reasonably estimated. As of December 31, 2002 and 2001, the Company had
an allowance for doubtful accounts of $31 million and $24 million, respectively.

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

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

Property and Equipment -- The Company uses the full-cost method of
accounting for its investment in oil and gas properties. Under this method, the
Company capitalizes all acquisition, exploration and development costs incurred
for the purpose of finding oil and gas reserves, including salaries, benefits
and other internal costs directly attributable to these activities.
Historically, total capitalized internal costs in any given year have not been
material to total oil and gas costs capitalized in such year. Exclusive of
field-level costs, Apache capitalized $22 million, $20 million and $23 million
of these internal costs in 2002, 2001 and 2000, respectively. Costs associated
with production and general corporate activities, however, are expensed in the
period incurred. Interest costs related to unproved properties and properties
under development are also capitalized to oil and gas properties. Unless a
significant portion of the Company's proved reserve quantities in a particular
country are sold (greater than 25 percent), proceeds from the sale of oil and
gas properties are accounted for as a reduction to capitalized costs, and gains
and losses are not recognized.

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

In performing its quarterly ceiling test, the Company limits, on a
country-by-country basis, the capitalized costs of proved oil and gas
properties, net of accumulated DD&A and deferred income taxes, to the estimated
future net cash flows from proved oil and gas reserves discounted at 10 percent,
net of related tax effects, plus the lower of cost or fair value of unproved
properties included in the costs being amortized. If capitalized costs exceed
this limit, the excess is charged to additional DD&A expense. Included in the
estimated future net cash flows are Canadian provincial tax credits expected to
be realized beyond the date at

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

which the legislation, under its provisions, could be repealed. To date, the
Canadian provincial governments have not indicated an intention to repeal this
legislation. Please see Note 15 "Future Net Cash Flows" for a discussion on
calculation of estimated future net cash flows.

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

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

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

Buildings, equipment and gas gathering, transmission and processing
facilities are depreciated on a straight-line basis over the estimated useful
lives of the assets, which range from three to 20 years. Accumulated
depreciation for these assets totaled $240 million and $182 million at December
31, 2002 and 2001, respectively.

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

Accounts Payable -- Included in accounts payable at both December 31, 2002
and 2001, are liabilities of approximately $37 million representing the amount
by which checks issued, but not presented to the Company's banks for collection,
exceeded balances in applicable bank accounts.

Revenue Recognition -- Oil and gas revenues are recognized when production
is sold to a purchaser at a fixed or determinable price, when delivery has
occurred and title has transferred, and if collectibility of the revenue is
probable. Apache uses the sales method of accounting for gas production
imbalances. Apache uses the sales method of accounting for natural gas revenues.
Under this method, revenues are recognized based on actual volumes of gas sold
to purchasers. The volumes of gas sold may differ from the volumes to which
Apache is entitled based on its interests in the properties. These differences
create imbalances that are recognized as a liability only when the estimated
remaining reserves will not be sufficient to enable the underproduced owner to
recoup its entitled share through production. In both years ended December 31,
2002 and 2001, the Company recorded liabilities of $4 million for gas
imbalances, which are reflected in other non-

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

current liabilities. No receivables are recorded for those wells where Apache
has taken less than its share of production. Gas imbalances are reflected as
adjustments to proved gas reserves and future cash flows in the unaudited
supplemental oil and gas disclosures. Adjustments for gas imbalances totaled
less than one percent of Apache's proved gas reserves at December 31, 2002, 2001
and 2000. Cash received relating to future revenues is deferred and recognized
when all revenue recognition criteria are met.

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

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

Effective January 1, 2001, Apache adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS No. 133, as
amended, establishes accounting and reporting standards requiring that all
derivative instruments be recorded in the balance sheet as either an asset or
liability measured at fair value (which is generally based on information
obtained from independent parties) and requires that changes in fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Hedge accounting treatment allows unrealized gains and losses on cash flow
hedges to be deferred in other comprehensive income. Realized gains and losses
from the Company's cash flow hedges, including terminated contracts, are
generally recognized in oil and gas production revenues when the forecasted
transaction occurs. If at any time the likelihood of occurrence of a hedged
forecasted transaction ceases to be "probable," hedge accounting under SFAS No.
133 will cease on a prospective basis and all future changes in the fair value
of the derivative will be recognized directly in earnings. Amounts recorded in
other comprehensive income prior to the change in the likelihood of occurrence
of the forecasted transaction will remain in other comprehensive income until
such time the forecasted transaction impacts earnings. If it becomes probable
that the original forecasted production will not occur, then the derivative gain
or loss would be reclassified from accumulated other comprehensive income into
earnings immediately. Hedge effectiveness is measured at least quarterly based
on the relative changes in fair value between the derivative contract and the
hedged item over time and any ineffectiveness is immediately reported in other
revenue (losses) in the statement of consolidated operations.

Upon adoption, Apache formally documented and designated all hedging
relationships and verified that its hedging instruments were effective in
offsetting changes in actual prices received by the Company. Prior to the
adoption of SFAS No. 133, as amended, derivative instruments were not reflected
as derivative assets and liabilities and, therefore, had no carrying value. The
contracts designated as hedges qualified and continue to qualify for hedge
accounting in accordance with SFAS No. 133, as amended.

Income Taxes -- Oil and gas exploration and production is a global
business. As a result, Apache is subject to taxation on our income in numerous
jurisdictions. The Company records deferred tax assets and liabilities to
account for the expected future tax consequences of events that have been
recognized in its financial statements and tax returns. Apache routinely
assesses the realizability of its deferred tax assets. If the Company concludes
that it is more likely than not that some portion or all of the deferred tax
assets will not be realized under accounting standards, the tax asset would be
reduced by a valuation allowance. The Company considers future taxable income in
making such assessments. Numerous judgments and assumptions are

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

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

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

Stock-Based Compensation -- At December 31, 2002, the Company had several
stock-based employee compensation plans, which are defined and described more
fully in Note 9. The Company accounts for those plans under the recognition and
measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations. Under this method, the Company records
no compensation expense for stock options granted when the exercise price of
those options is equal to or greater than the market price of the Company's
common stock on the date of grant, unless the awards are subsequently modified.
The following table illustrates the effect on income attributable to common
stock and earnings per share if the Company had applied the fair value
recognition provisions of SFAS No. 123, "Accounting for

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Stock-Based Compensation," as amended, to stock-based employee compensation for
the Stock Option Plans, the Performance Plan, and the Share Appreciation Plan.

FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
2002 2001 2000
--------- --------- ---------
(IN THOUSANDS)

Income attributable to Common Stock, as reported..... $543,514 $703,798 $693,068
Add: Stock-based employee compensation expense
included in reported net income, net of related tax
effects............................................ 751 -- --
Deduct: Total stock-based employee compensation
expense determined under fair value based method
for all awards (see Note 9), net of related tax
effects............................................ (20,494) (22,463) (13,212)
-------- -------- --------
Pro forma Income Attributable to Common Stock........ $523,771 $681,335 $679,856
======== ======== ========
Net Income per Common Share:
Basic:
As reported..................................... $ 1.83 $ 2.44 $ 2.54
Pro forma....................................... $ 1.76 $ 2.37 $ 2.49
Diluted:
As reported..................................... $ 1.80 $ 2.37 $ 2.46
Pro forma....................................... $ 1.74 $ 2.29 $ 2.41

The effects of applying SFAS No. 123, as amended, in this pro forma
disclosure should not be interpreted as being indicative of future effects. SFAS
No. 123, as amended, does not apply to awards prior to 1995, and the extent and
timing of additional future awards cannot be predicted.

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

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

Change in Accounting Principle -- In December 2000, the staff of the
Securities and Exchange Commission (SEC) announced that commodity inventories
should be carried at cost, not market value. As a result, Apache changed its
accounting for crude oil inventories in the fourth quarter of 2000, retroactive
to the beginning of the year, and recognized a non-cash cumulative-effect charge
to earnings effective January 1, 2000 of $8 million, net of income tax, to value
crude oil inventory at cost.

Reclassifications -- To comply with the consensus reached on Emerging
Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and
Costs," third party gathering and transportation costs have

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

been reported as an operating cost instead of a reduction of revenues as
previously reported. Reclassifications have been made to reflect this change in
prior period statements of consolidated operations.

2. NEW ACCOUNTING PRONOUNCEMENTS

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses
financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. This statement requires companies to record the present value of
obligations associated with the retirement of tangible long-lived assets in the
period in which it is incurred. The liability is capitalized as part of the
related long-lived asset's carrying amount. Over time, accretion of the
liability is recognized as an operating expense and the capitalized cost is
depreciated over the expected useful life of the related asset. The Company's
asset retirement obligations relate primarily to the plugging dismantlement,
removal, site reclamation and similar activities of its oil and gas properties.
Prior to adoption of this statement, such obligations were accrued ratably over
the productive lives of the assets through its depreciation, depletion and
amortization for oil and gas properties without recording a separate liability
for such amounts.

Effective January 1, 2003, the Company adopted SFAS No. 143 which will
result in an increase to net oil and gas properties of $410 million and
additional liabilities related to asset retirement obligations of $369 million.
These entries reflect the asset retirement obligation of Apache had the
provisions of SFAS No. 143 been applied since inception. This will result in a
non-cash cumulative-effect increase to earnings of $27 million ($41 million
pretax). The cumulative increase to earnings did not take into consideration
potential impacts of adopting SFAS 143 on previous full-cost property impairment
tests. SFAS 143 is silent with respect to whether prior period ceiling tests
should be reflected in the implementation entry calculation and Management
believes that any impairment on the properties should only be reflected for
future periods. A ceiling test calculation, however, was performed at the end of
each reporting period subsequent to the adoption of this statement and no
impairment was necessary. The cumulative increase to earnings did not take into
consideration potential impacts of adopting SFAS No. 143 on previous full-cost
property impairment tests. Management chose not to re-calculate historical
full-cost impairment tests upon adoption even though historical oil and gas
property balances would have been higher had we applied the provisions of the
statement. Management believes this approach is appropriate because SFAS No. 143
is silent on this issue and was not effective during the prior impairment test
periods. Had we re-calculated the historical full-cost impairment tests and
included the impact as a component of the cumulative effect of adoption, the
ultimate gain recognized would have potentially been reduced. A ceiling test
calculation, however, was performed upon adoption and at the end of each
reporting period subsequent to adoption of this statement and no impairment was
necessary.

In November 2002, the FASB issued Interpretation No. 45 "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This Interpretation elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial measurement
provisions of this Interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The Company adopted this pronouncement upon the
FASB's issuance and the implementation had no impact on the consolidated
financial statements.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires a company to consolidate a variable
interest entity (VIE) if the company has a variable interest (or combination of
variable interests) that is exposed to a majority of the entity's expected
losses if they occur, receive a majority of the

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

entity's expected residual returns if they occur, or both. In addition, more
extensive disclosure requirements apply to the primary and other significant
variable interest owners of the VIE. This interpretation applies immediately to
VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains
an interest after that date. It is also effective for the first fiscal year or
interim period beginning after June 15, 2003, to VIEs in which a company holds a
variable interest that is acquired before February 1, 2003. The guidance
regarding this interpretation is extremely complex and, although we do not
believe we have an interest in a VIE, the Company continues to assess the
impact, if any, this interpretation will have on the Company's consolidated
financial statements.

3. ACQUISITIONS AND DIVESTITURES

ACQUISITIONS

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

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

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

In March 2001, Apache completed the acquisition of subsidiaries of Fletcher
for approximately $465 million in cash and 1.9 million (3.8 million shares
adjusted for the two-for-one stock split) restricted shares of Apache common
stock issued to Shell Overseas Holdings (valued at $52.85 per share ($26.43 per
share adjusted for the two-for-one stock split)), subject to normal post closing
adjustments. The transaction included properties located primarily in Canada's
Western Sedimentary Basin. Estimated proved reserves totaled 120.8 MMboe as of
the acquisition date. Apache assumed a liability of $103 million representing
the fair value of derivative instruments and fixed-price commodity contracts
entered into by Fletcher.

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

FLETCHER REPSOL
--------- --------
(IN THOUSANDS)

Value of properties acquired, including gathering and
transportation facilities................................. $ 571,718 $299,933
Goodwill.................................................... 107,200 90,000
Derivative instruments and fixed-price contracts............ (103,486) --
Common stock issued......................................... (100,325) --
Working capital acquired, net............................... (2,846) 57,000
Notes assumed............................................... (5,356) --
Deferred income tax liability............................... (1,887) --
--------- --------
Cash paid, net of cash acquired............................. $ 465,018 $446,933
========= ========

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

In January 2000, Apache completed the acquisition of producing properties
in Western Oklahoma and the Texas Panhandle, formerly owned by a subsidiary of
Repsol, for approximately $119 million, plus assumed liabilities of
approximately $30 million. The properties were subject to an existing volumetric
production payment, which burdens future production from the acquired
properties. The $30 million assumed liability represents the estimated operating
costs associated with the volumetric production payment. The acquisition
included estimated proved reserves of approximately 28.7 MMboe, which was net of
the 8.4 MMboe production payment as of the acquisition date.

In June 2000, Apache completed the acquisition of long-lived producing
properties in the Permian Basin and South Texas from Collins & Ware, Inc.
(Collins & Ware) for approximately $321 million. The acquisition included
estimated proved reserves of approximately 83.7 MMboe as of the acquisition
date. One-third of the reserves were liquid hydrocarbons.

In August 2000, Apache completed the acquisition of a Delaware limited
liability company (LLC) owned by subsidiaries of Occidental Petroleum
Corporation (Occidental) and related natural gas production for approximately
$321 million including a discounted liability of $37 million, as of the
acquisition date, representing the present value of future payments of
approximately $44 million over four years. The remaining discounted liability at
December 31, 2002 was $20 million. The Occidental properties are located in 32
fields on 93 blocks on the Outer Continental Shelf of the Gulf of Mexico. The
acquisition included estimated proved reserves of approximately 53.1 MMboe as of
the acquisition date.

In December 2000, Apache completed the acquisition of Canadian properties
from Canadian affiliates of Phillips Petroleum Company (Phillips) for
approximately $490 million. The acquisition included estimated proved reserves
of approximately 70.0 MMboe as of the acquisition date. The properties comprise
approximately 212,000 net developed acres and 275,000 net undeveloped acres, 786
square miles of 3-D seismic and 4,155 miles of 2-D seismic located in the Zama
area of Northwest Alberta. The assets also include three sour gas plants with a
total capacity of 150 million cubic feet per day (MMcf/d), 13 compressor
stations and 150 miles of owned and operated gas gathering lines.

In 2000, the Company also completed other acquisitions for cash
consideration totaling $104 million. These acquisitions added approximately 18.3
MMboe to the Company's proved reserves.

The following unaudited pro forma information shows the effect on the Company's
consolidated results of operations as if the Fletcher and Repsol transactions
occurred on January 1, 2001, and the Collins & Ware, Occidental and Phillips
acquisitions occurred on January 1, 2000. The pro forma information includes
only

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

significant acquisitions and numerous assumptions, and is not necessarily
indicative of future results of operations:

FOR THE YEAR ENDED DECEMBER 31, 2000
---------------------------------------------------
2001 2000
------------------------ ------------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- ---------- ----------- ----------
(UNAUDITED) (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA)

Revenues............................. $2,809,391 $2,916,346 $2,301,978 $3,090,248
Net income........................... 723,399 748,976 713,056 908,974
Preferred stock dividends............ 19,601 19,601 19,988 19,988
Income attributable to common
stock.............................. 703,798 729,375 693,068 888,986
Net income per common share:
Basic.............................. $ 2.44 $ 2.52 $ 2.54 $ 3.08
Diluted............................ 2.37 2.45 2.46 2.98
Average common shares outstanding.... 288,014 288,900 272,530 288,810

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

PENDING ACQUISITIONS

On January 13, 2003, Apache announced the acquisition of producing
properties in the U.K. North Sea and the Gulf of Mexico, with estimated proved
reserves of 233.2 MMboe, from BP p.l.c. (BP), for $1.3 billion, subject to
normal closing adjustments, with an effective date of January 1, 2003.
Approximately two-thirds of the reserves are in the North Sea's Forties oil
field, establishing a new international operating region for the Company. Apache
will become field operator with a 97 percent working interest. In conjunction
with the Forties acquisition, Apache may be required to issue a letter of credit
to BP to cover the present value of related asset retirement obligations if the
rating of our senior unsecured debt is lowered by both Moody's and Standard and
Poor's from the Company's current ratings of A- and A3, respectively.
Additionally, Apache has hedged a portion of Forties production at fixed prices
(see Note 4) and will create a defined benefit pension plan for certain
employees (see Note 11). The Gulf of Mexico properties are located offshore
Texas and Louisiana, where the Company has substantial existing operations. The
assets comprise 113 total blocks and 61 fields and 70 percent of the production
is operated. Apache will acquire a 100 percent working interest in 19 of the
fields. The Gulf of Mexico segment of the transaction closed March 13, 2003 and
the North Sea segment is expected to close early in the second quarter. The
Company is financing the acquisition with a combination of internally generated
funds, previously issued equity and debt.

DIVESTITURES

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

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

During 2000, Apache sold proprietary rights to certain Canadian seismic
data and various non-strategic oil and gas properties, collecting cash of $26
million.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

4. DERIVATIVE INSTRUMENTS AND FIXED-PRICE PHYSICAL CONTRACTS

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

Apache 2002 Derivative Activity -- As part of the South Louisiana
properties acquired in December 2002, Apache entered into, and designated as a
cash flow hedge, natural gas option agreements to establish floor and ceiling
prices on anticipated future natural gas production. As of December 31, 2002,
the Company had the following natural gas volumes hedged through natural gas
options:

TOTAL WEIGHTED FAIR VALUE
PRODUCTION OPTION VOLUMES AVERAGE ASSET/
PERIOD TYPE (MMBTU) FLOOR/CEILING (LIABILITY)
---------- ------- ---------- ------------- --------------
(IN THOUSANDS)

2003 Collars 13,750,000 $3.50/6.09 $ (859)
2004 Collars 18,300,000 3.25/5.81 (1,921)
2005 Collars 9,050,000 3.25/5.20 (727)

The fair value of derivative assets and liabilities recorded for the
Company's hedging activity represents the market value of the natural gas
options as of December 31, 2002. The hedging activity had no impact on natural
gas revenues during 2002. There was no material ineffectiveness associated with
the cash flow hedges during the period the options were outstanding.

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

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

APACHE HEDGING ACQUIRED ADVANCES FROM GAS
ACTIVITY CONTRACTS PURCHASER
(JANUARY 1, 2001) (ACQUISITION DATE) (JANUARY 1, 2001)
----------------- ------------------ -----------------
(IN THOUSANDS)

Commodity derivatives instruments.... $(116,229) $ (98,557) $ 121,453
Fixed-price physical contracts....... -- (14,085) (121,453)
--------- --------- ---------
$(116,229) $(112,642) $ --
========= ========= =========

At the time SFAS 133 was implemented, natural gas prices were approaching
record highs. Although Apache was realizing higher prices on its un-hedged
production, the fair value of the Company's cash flow hedges was
out-of-the-money by approximately $116 million ($71 million, net of income tax).
This unrealized loss was reflected as a charge to other comprehensive income.
Throughout the year, commodity prices were trending downward. As a result,
Apache realized only $40 million of this loss during the year. In connection
with the Unwind, the Company closed out the rest of these open positions and
received cash proceeds of $8 million. These proceeds will be recognized in
earnings as the original hedged production occurs. As of December 31, 2002, $3
million remains to be recognized in 2003.

The Company also uses long-term, fixed-price physical contracts to lock in
a portion of its natural gas production at a given price. In the Unwind, the
Company received approximately $13 million to terminate

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

contracts with certain counterparties. Since the Company has no continuing
performance obligations under the contracts, the amount was recognized as a gain
in Revenues and Other in 2001.

In addition to the cash flow hedges the Company entered into, Apache
assumed $113 million of derivative and physical contracts in connection with two
acquisitions. Because these derivatives were out-of-the-money when the Company
acquired them, the liability was factored into the consideration paid to the
sellers (see Note 3). Since commodity prices generally decreased after the
acquisitions, Apache was able to settle this liability in the Unwind for only
$67 million, including $37 million paid to terminate the remaining open
positions. As a result, Apache recognized a gain of $32 million during 2001, and
$14 million during 2002. As of December 31, 2002, a loss of $527,000 remains and
will be recognized in 2003 and 2004.

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

Apache 2003 Derivative Activity -- Subsequent to year end and in
conjunction with the BP acquisition, Apache entered into several derivative
transactions in order to preserve the Company's financial position in a period
of cyclically high gas and oil prices. The Company entered into the following
natural gas and crude oil fixed-price swaps:

NATURAL GAS FIXED-PRICE SWAPS (NYMEX) CRUDE OIL FIXED-PRICE SWAPS (NYMEX)
--------------------------------------- ----------------------------------------
PRODUCTION TOTAL VOLUMES AVERAGE PRODUCTION TOTAL VOLUMES AVERAGE
PERIOD (MMBTU) FIXED PRICE PERIOD (BARRELS) FIXED PRICE
---------- ------------- ----------- ---------- ------------- -----------

2003 61,675,000 $5.19 2003 16,700,000 $26.59
2004 51,240,000 4.52 2004 1,550,000 26.59

Although the fixed-price swaps are settled at NYMEX, the Company's hedged
forecasted sales are based on pricing at different locations. The Company
believes the hedging relationships are highly effective; however, Apache entered
into separate natural gas basis swap contracts to fix a portion of the sales
price differential. Apache designated all of the natural gas and crude oil
fixed-price swaps and basis swaps as cash flow hedges of anticipated sales.

In addition to the fixed-price swaps, Apache entered into a separate crude
oil physical sales contract with BP.

CRUDE OIL FIXED-PRICE PHYSICAL CONTRACTS (BRENT)
--------------------------------------------------
PRODUCTION TOTAL VOLUMES AVERAGE
PERIOD (MMBTU) FIXED PRICE
---------- ------------- -----------

2003 8,350,000 $25.32
2004 14,175,000 22.24

5. SHORT-TERM INVESTMENTS

In August 2001, Apache purchased $116 million in U.S. Government Agency
Notes. The Company subsequently sold $13 million of the notes in 2001. Of the
remaining balance, $17 million were designated as "available for sale"
securities and were sold for approximately $17 million in January 2002.
Approximately

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$86 million were designated as "held to maturity" and carried at amortized cost.
These notes paid interest at rates from 6.25 percent to 6.375 percent and
matured on October 15, 2002.

6. DEBT

LONG-TERM DEBT

DECEMBER 31,
-----------------------
2002 2001
---------- ----------
(IN THOUSANDS)

Apache:
Money market lines of credit.............................. $ 8,900 $ 1,600
Global credit facility -- U.S. ........................... -- 100,000
Commercial paper.......................................... 271,400 530,700
9.25-percent notes due 2002, net of discount.............. -- 99,974
6.25-percent debentures due 2012, net of discount......... 397,307 --
7-percent notes due 2018, net of discount................. 148,446 148,391
7.625-percent notes due 2019, net of discount............. 149,134 149,109
7.7-percent notes due 2026, net of discount............... 99,660 99,655
7.95-percent notes due 2026, net of discount.............. 178,614 178,595
7.375-percent debentures due 2047, net of discount........ 148,009 148,003
7.625-percent debentures due 2096, net of discount........ 149,175 149,175
---------- ----------
1,550,645 1,605,202
---------- ----------
Subsidiary and other obligations:
Money market lines of credit.............................. -- 1,196
Global credit facility -- Canada.......................... -- 30,000
Fletcher notes............................................ 5,356 5,356
Apache Finance Australia 6.5-percent notes due 2007, net
of discount............................................ 169,260 169,137
Apache Finance Australia 7-percent notes due 2009, net of
discount............................................... 99,535 99,478
Apache Finance Canada 7.75-percent notes due 2029, net of
discount............................................... 297,019 296,988
Apache Clearwater notes due 2003.......................... 37,000 37,000
---------- ----------
608,170 639,155
---------- ----------
Total debt.................................................. 2,158,815 2,244,357
Less: current maturities.................................... -- --
---------- ----------
Long-term debt.............................................. $2,158,815 $2,244,357
========== ==========

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

On June 3, 2002, Apache entered into a new $1.5 billion global credit
facility to replace its existing global and 364-day credit facilities. The new
global credit facility consists of four separate bank facilities: a $750 million
364-day facility in the United States (364-day facility); a $450 million
five-year facility in the United States (U.S. five-year facility); a $150
million five-year facility in Australia; and a $150 million five-year facility
in Canada. The financial covenants of the global credit facility require the
Company to:

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(i) maintain a consolidated tangible net worth, plus the aggregate amount of any
non-cash write-downs, of at least $2.3 billion as of December 31, 2002, adjusted
for subsequent earnings, (ii) maintain an aggregate book-value for assets of
Apache and certain subsidiaries, as defined, on an unconsolidated basis of at
least $2 billion as of December 31, 2002, and (iii) maintain a ratio of debt to
capitalization of not greater than 60 percent at the end of any fiscal quarter.
The Company was in compliance with all financial covenants at December 31, 2002.

The five-year facilities are scheduled to mature on June 3, 2007 and the
364-day facility is scheduled to mature on June 1, 2003. The 364-day facility
allows the Company the option to convert outstanding revolving loans at maturity
into one-year term loans. The Company may request extensions of the maturity
dates subject to approval of the lenders. At the Company's option, the interest
rate is based on (i) the greater of (a) The JP Morgan Chase Bank prime rate or
(b) the federal funds rate plus one-half of one percent or (ii) the London
Interbank Offered Rate (LIBOR) plus a margin determined by the Company's senior
long-term debt rating. In addition, the U.S. five-year facility allows the
Company the option to borrow under competitive auctions. At December 31, 2002,
the margin over LIBOR for committed loans was .30 percent on the five-year
facilities and .32 percent on the 364-day facility. If the total amount of the
loans borrowed under all of the facilities equals or exceeds 33 percent of the
total facility commitments, then an additional .125 percent will be added to the
margins over LIBOR. The Company also pays a quarterly facility fee of .10
percent on the total amount of each of the five-year facilities and .08 percent
on the total amount of the 364-day facility. The facility fees vary based upon
the Company's senior long-term debt rating. The U.S. five-year facility and the
364-day facility are used to support Apache's commercial paper program. The
available borrowing capacity under the global credit facility at December 31,
2002 was $1.2 billion.

At December 31, 2002, the Company also had certain uncommitted money market
lines of credit which are used from time to time for working capital purposes,
under which an aggregate of $9 million was outstanding as of December 31, 2002.
Such borrowings are classified as long-term debt in the accompanying
consolidated balance sheet as the Company has the ability and intent to
refinance such amounts on a long-term basis through available borrowing capacity
under the U.S. five-year facility and the 364-day facility.

The Company has a $1.2 billion commercial paper program which enables
Apache to borrow funds for up to 270 days at competitive interest rates. The
commercial paper balances at December 31, 2002 and 2001 were classified as
long-term debt in the accompanying consolidated balance sheet as the Company has
the ability and intent to refinance such amounts on a long-term basis through
either the rollover of commercial paper or available borrowing capacity under
the U.S. five-year facility and the 364-day facility. The weighted average
interest rate for commercial paper was 1.85 percent in 2002 and 4.10 percent in
2001.

The 9.25-percent notes matured June 1, 2002 and were repaid using
commercial paper. These notes were classified as long-term debt at December 31,
2001, in the accompanying consolidated balance sheet as the Company had the
ability and intent to refinance such amount on a long-term basis through
available borrowing capacity under the global credit facility and 364-day
facility.

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

The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and
Apache Finance Canada Corporation (Apache Finance Canada) are irrevocably and
unconditionally guaranteed by Apache and, in the case of Apache Finance
Australia, by Apache North America, Inc., an indirect wholly-owned subsidiary of
the Company. Under certain conditions related to changes in relevant tax laws,
Apache Finance Australia and Apache Finance Canada have the right to redeem the
notes prior to maturity. In the case of the 6.5-percent

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

notes, Apache Finance Australia may also redeem the notes at its option subject
to a make-whole premium (see Note 17).

In August 2001, Apache Clearwater, Inc. (Apache Clearwater), a subsidiary
of Apache, issued $37 million of senior floating rate notes, which mature August
9, 2003. The notes bear interest at a rate equal to three-month LIBOR plus 1.05
percent and are redeemable at the Company's discretion. The balance is
classified as long-term debt in the accompanying consolidated balance sheet as
the Company has the ability and intent to refinance such amounts on a long-term
basis through available borrowing capacity under the U.S. five-year facility and
the 364-day facility.

The $14 million of discounts on the Company's debt at December 31, 2002, is
being amortized over the life of the debt issuances as additional interest
expense.

As of December 31, 2002 and 2001, the Company had approximately $19 million
and $14 million, respectively, of unamortized deferred loan costs associated
with its various debt obligations. These costs are included in deferred charges
and other in the accompanying consolidated balance sheet and are being amortized
to expense over the life of the related debt.

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

AGGREGATE MATURITIES OF DEBT

(IN THOUSANDS)

2003........................................................ $ --
2004........................................................ --
2005........................................................ 830
2006........................................................ 274
2007........................................................ 489,559
Thereafter.................................................. 1,668,152
----------
$2,158,815
==========

The Company made cash payments for interest, net of amounts capitalized, of
$99 million, $105 million and $93 million for the years ended December 31, 2002,
2001 and 2000, respectively.

7. INCOME TAXES

Income before income taxes is composed of the following:

FOR THE YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
-------- ---------- ----------
(IN THOUSANDS)

United States..................................... $286,840 $ 605,392 $ 654,136
Foreign........................................... 612,130 593,862 549,545
-------- ---------- ----------
Total........................................... $898,970 $1,199,254 $1,203,681
======== ========== ==========

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The total provision for income taxes consists of the following:

FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
2002 2001 2000
--------- --------- ---------
(IN THOUSANDS)

Current taxes:
Federal............................................ $ 25,657 $ 19,054 $ 12,000
State.............................................. 1,564 4,995 --
Foreign............................................ 179,748 146,592 120,383
Deferred taxes....................................... 137,672 305,214 350,703
-------- -------- --------
Total.............................................. $344,641 $475,855 $483,086
======== ======== ========

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

FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
2002 2001 2000
--------- --------- ---------
(IN THOUSANDS)

Statutory income tax................................. $314,639 $419,739 $421,288
State income tax, less federal benefit............... 7,171 15,135 9,650
Effect of foreign operations......................... 35,283 38,890 52,354
Realized tax basis in investment..................... (16,321) (1,350) --
All other, net....................................... 3,869 3,441 (206)
-------- -------- --------
$344,641 $475,855 $483,086
======== ======== ========

The net deferred tax liability is comprised of the following:

DECEMBER 31,
-----------------------
2002 2001
---------- ----------
(IN THOUSANDS)

Deferred tax assets:
Deferred income........................................... $ (1,120) $ (3,744)
Federal net operating loss carryforwards.................. (40,700) (2,462)
State net operating loss carryforwards.................... (16,436) (13,469)
Statutory depletion carryforwards......................... (5,652) --
Alternative minimum tax credits........................... (13,836) (14,472)
Foreign net operating loss carryforwards.................. (9,764) (9,444)
Accrued expenses and liabilities.......................... (5,818) (8,088)
Other..................................................... (3,539) (3,415)
---------- ----------
Total deferred tax assets.............................. (96,865) (55,094)
Valuation allowance....................................... 9,764 --
---------- ----------
Net deferred tax assets................................ (87,101) (55,094)
---------- ----------
Deferred tax liabilities:
Depreciation, depletion and amortization.................. 1,207,710 1,043,687
Other..................................................... -- 3,130
---------- ----------
Total deferred tax liabilities......................... 1,207,710 1,046,817
---------- ----------
Net deferred income tax liability........................... $1,120,609 $ 991,723
========== ==========

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company has not recorded deferred income taxes on the undistributed
earnings of its foreign subsidiaries as management intends to permanently
reinvest such earnings. As of December 31, 2002, the undistributed earnings of
the foreign subsidiaries amounted to approximately $2.1 billion. Upon
distribution of these earnings in the form of dividends or otherwise, the
Company may be subject to U.S. income taxes and foreign withholding taxes. It is
not practical, however, to estimate the amount of taxes that may be payable on
the eventual remittance of these earnings after consideration of available
foreign tax credits. Presently, limited foreign tax credits are available to
reduce the U.S. taxes on such amounts if repatriated.

At December 31, 2002, the Company had federal net operating loss
carryforwards of $116 million, state net operating loss carryforwards of $317
million and foreign net operating loss carryforwards of $10 million. The state
and federal net operating losses will expire over the next 15 and 20 years,
respectively, if they are not otherwise utilized. The foreign net operating loss
carryforwards relate to foreign pre-production expenditures which will not be
deductible for foreign income tax purposes until production begins, which is
expected to be in 2003. Once these expenditures are deducted for foreign income
tax purposes, any net operating loss has a five-year carryforward period. A full
valuation allowance has been provided on these foreign losses. The Company has
alternative minimum tax (AMT) credit carryforwards of $14 million that can be
carried forward indefinitely, but which can be used only to reduce regular tax
liabilities in excess of AMT liabilities.

The Company made cash payments for income and other taxes, net of refunds,
of $171 million, $172 million and $123 million for the years ended December 31,
2002, 2001 and 2000, respectively.

8. ADVANCES FROM GAS PURCHASERS

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

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

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

These advance payments have been classified as advances from gas purchasers
and are being recognized in oil and gas production revenues as gas is delivered
to the purchasers under the terms of the contracts. At December 31, 2002 and
2001, advances of $125 and $140 million, respectively, were outstanding. Gas
volumes delivered to the purchaser are reported as revenue at prices used to
calculate the amount advanced, before imputed interest, plus or minus amounts
paid or received by Apache applicable to the price swap agreements. Interest
expense is recorded based on a rate of eight percent .

In October and November 2001, Apache terminated the gas price swap
contracts associated with these advances and received proceeds of $78 million.
The effect of terminating these derivative instruments reduces

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

9. CAPITAL STOCK

The following shares have been restated to reflect the 10 percent and five
percent stock dividends, and two-for-one stock split as discussed in Note 1 of
these financial statements.

COMMON STOCK OUTSTANDING

2002 2001 2000
----------- ----------- -----------

Balance, beginning of year.................... 287,916,676 285,596,268 263,331,832
Treasury shares issued (acquired), net........ 121,432 (1,923,564) (1,061,398)
Shares issued for:
Public offering(1)(4)....................... -- -- 21,252,000
Acquisition of Fletcher subsidiaries(2)..... -- 3,796,550 --
Conversion of Series C Preferred Stock(3)... 13,109,730 -- --
Stock option plans.......................... 1,358,586 484,940 2,073,834
Fractional shares repurchased............... -- (37,518) --
----------- ----------- -----------
Balance, end of year.......................... 302,506,424 287,916,676 285,596,268
=========== =========== ===========

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

(1) In August 2000, Apache completed a public offering of 21.3 million shares of
common stock, including 2.8 million shares for the underwriters'
over-allotment option, for net proceeds of $434 million.

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

(3) On May 15, 2002, we completed the mandatory conversion of our Series C
preferred stock into approximately 13.1 million common shares.

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

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net Income Per Common Share -- A reconciliation of the components of basic
and diluted net income per common share for the years ended December 31, 2002,
2001 and 2000 is presented in the table below:

2002 2001 2000
------------------------------ ------------------------------ ------------------------------
INCOME SHARES PER SHARE INCOME SHARES PER SHARE INCOME SHARES PER SHARE
-------- ------- --------- -------- ------- --------- -------- ------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

BASIC:
Income attributable
to common stock.... $543,514 297,234 $1.83 $703,798 288,014 $2.44 $693,068 272,530 $2.54
===== ===== =====
EFFECT OF DILUTIVE
SECURITIES:
Stock options and
other.............. -- 2,566 -- 2,122 -- 2,418
Series C Preferred
Stock.............. 5,149 4,812 13,952 13,110 14,307 13,146
-------- ------- -------- ------- -------- -------
DILUTED:
Income attributable
to common stock,
including assumed
conversions........ $548,663 304,612 $1.80 $717,750 303,246 $2.37 $707,375 288,094 $2.46
======== ======= ===== ======== ======= ===== ======== ======= =====

Stock Option Plans -- At December 31, 2002, officers and employees had
options to purchase shares of the Company's common stock under one or more
employee stock option plans adopted in 1990, 1995, 1998 and 2000 (collectively,
the Stock Option Plans). Under the Stock Option Plans, the exercise price of
each option equals the market price of Apache's common stock on the date of
grant. Options generally become exercisable ratably over a four-year period and
expire after 10 years.

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

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

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A summary of the status of the plans described above as of December 31,
2002, 2001 and 2000, and changes during the years then ended, is presented in
the table and narrative below (shares in thousands):

2002 2001 2000
----------------- ----------------- ------------------
WEIGHTED WEIGHTED WEIGHTED
SHARES AVERAGE SHARES AVERAGE SHARES AVERAGE
UNDER EXERCISE UNDER EXERCISE UNDER EXERCISE
OPTION PRICE OPTION PRICE OPTION PRICE
------ -------- ------ -------- ------- --------

Outstanding, beginning of
year........................ 11,544 $17.62 10,354 $15.76 10,956 $14.12
Granted....................... 1,786 27.99 2,402 24.95 2,042 21.50
Exercised..................... (1,544) 14.88 (596) 13.66 (2,220) 12.89
Forfeited..................... (458) 20.21 (616) 18.79 (424) 16.46
------ ------ -------
Outstanding, end of year(1)... 11,328 19.53 11,544 17.62 10,354 15.76
====== ====== =======
Exercisable, end of year...... 5,730 17.25 5,156 15.34 3,558 13.48
====== ====== =======
Available for grant, end of
year........................ 1,068 2,558 3,414
====== ====== =======
Weighted average fair value of
options granted during the
year(2)..................... $10.14 $10.44 $ 9.03
====== ====== =======

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

(1) Includes 220,608, 285,862 and 329,176 shares as of December 31, 2002, 2001
and 2000, respectively, issuable under stock options assumed by Apache in
connection with the 1996 acquisition of The Phoenix Resource Companies, Inc.

(2) The fair value of each option is estimated as of the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants in 2002, 2001 and 2000, respectively: (i)
risk-free interest rates of 4.87, 4.95 and 6.74 percent; (ii) expected lives
of 4.5 years for 2002 and five years for 2001 and 2000 for the Stock Option
Plans; (iii) expected volatility of 37.17, 41.39 and 37.42 percent; and (iv)
expected dividend yields of .68, .51 and .57 percent.

The following table summarizes information about stock options covered by
the plans described above that are outstanding at December 31, 2002 (shares in
thousands):

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------ ----------------------
NUMBER OF WEIGHTED NUMBER OF
SHARES AVERAGE WEIGHTED SHARES WEIGHTED
UNDER REMAINING AVERAGE UNDER AVERAGE
OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES OPTIONS LIFE PRICE OPTIONS PRICE
------------------------ ----------- ----------- -------- ----------- --------

$ 7.36 - $14.72................ 2,562 4.55 $12.91 2,284 $12.80
14.78 - 15.59................ 2,596 4.48 15.25 982 15.15
15.75 - 23.10................ 2,280 7.06 20.10 1,392 19.95
23.81 - 28.05................ 3,890 8.77 26.41 1,072 25.13
------ -----
11,328 5,730
====== =====

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

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

expense over the 24-month vesting period equal to the value of the stock on the
date the particular goal is achieved. The shares of Apache common stock
contingently issuable under the Share Appreciation Plan will be excluded from
the computation of income per common share until the stated goals are met.

The Share Price Goals were based on achieving a share price of $87, $104,
and $156 per share before January 1, 2005 (subject to a meeting of the stock
option plan committee of the board of directors in February 2004 to take into
consideration an adjustment for the two-for-one stock split). A summary of the
number of shares contingently issuable under the Share Price Goals as of
December 31, 2002, 2001 and 2000 is presented in the table below (shares in
thousands):

SHARES SUBJECT TO
CONDITIONAL GRANTS
------------------------
2002 2001 2000
------ ------ ------

Outstanding, beginning of year............................. 6,390 5,764 --
Granted.................................................... 436 1,294 5,764
Forfeited.................................................. (592) (668) --
------ ------ ------
Outstanding, end of year(1)................................ 6,234 6,390 5,764
====== ====== ======
Exercisable, end of year................................... -- -- --
====== ====== ======
Weighted average fair value of conditional grants --
Share Price Goals(2)..................................... $ 7.98 $ 9.31 $17.43
====== ====== ======

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

(1) Represents shares issuable upon attainment of the per share price goals
(assuming an adjustment by the stock option plan committee to approximately
$43.50, $52, and $78 per share) of 1,351,792 shares, 3,381,050 shares and
1,501,398 shares, respectively, in 2002 and 1,386,268 shares, 3,464,788
shares and 1,539,794 shares, respectively, in 2001 and 1,252,020 shares,
3,125,430 shares and 1,388,310 shares, respectively, in 2000.

(2) The fair value of each Share Price Goal conditional grant is estimated as of
the date of grant using a Monte Carlo simulation with the following
weighted-average assumptions used for grants in 2002, 2001 and 2000,
respectively: (i) risk-free interest rate of 2.90, 4.16 and 5.95 percent;
(ii) expected volatility of 38.77, 46.27 and 44.69 percent; and (iii)
expected dividend yield of .70, .77 and .44 percent.

The Production Goal will be attained if and when the Company's average
daily production equals or exceeds .6666 barrels of oil equivalent per diluted
share (calculated on an annualized basis) during any fiscal quarter ending
before January 1, 2005. Such level of production was approximately twice the
Company's level of production at the time the Share Appreciation Plan was
adopted. Shares issuable in connection with the Production Goal will be a number
of shares of the Company's common stock equal to (a) 37.5 percent, 75 percent or
150 percent of a participant's annual base salary (at the time of attainment),
as applicable, divided by (b) the average daily per share closing price of the
Company's common stock for the fiscal quarter during which the Production Goal
is attained.

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

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

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

PREFERRED STOCK

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

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

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

Series C Preferred Stock -- In May 1999, Apache issued 140,000 shares ($217
million) of Series C Preferred Stock in the form of seven million depositary
shares each representing one-fiftieth (1/50) of a share

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of Series C Preferred Stock, for net proceeds of $211 million. Holders of the
shares were entitled to receive cumulative cash dividends at an annual rate of
6.5 percent, or $2.015 per depositary share when, and if, declared by Apache's
board of directors.

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

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

FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
--------- --------- --------
(IN THOUSANDS)

Currency translation adjustments................... $(108,750) $(114,078) $(40,050)
Unrealized gain (loss) on available for sale
securities....................................... -- 125 (182)
Unrealized gain (loss) on derivatives.............. (4,186) 12,136 --
--------- --------- --------
Accumulated other comprehensive loss............... $(112,936) $(101,817) $(40,232)
========= ========= ========

The unrealized gain (loss) on available for sale securities at December 31,
2001 and 2000 is net of income tax expense (benefit) of $67,000 and $(94,000),
respectively. The currency translation adjustments are not adjusted for income
taxes as they relate to a permanent investment in non-U.S. subsidiaries.

A rollforward of the unrealized gain on derivatives is presented in the
table below:

GROSS AFTER-TAX
------- ---------
(IN THOUSANDS)

Unrealized gain on derivatives at December 31, 2001......... $20,559 $12,136
Reclassification of net realized losses into earnings....... (24,193) (14,128)
Net change in derivative fair value......................... (3,507) (2,194)
------- -------
Unrealized loss on derivatives at December 31, 2002......... $(7,141) $(4,186)
======= =======

Based on commodity prices as of December 31, 2002, the Company expects to
reclassify losses of $5 million ($3 million after tax) to earnings from the
balance in accumulated other comprehensive income during the next twelve months.
The remaining balance in other comprehensive income is expected to be
reclassified to future earnings, contemporaneously with the related sales of
natural gas production as applicable to specific hedges. The actual amounts that
will be reclassified to earnings over the next year and beyond could vary
materially from this estimated amount as a result of changes in market
conditions.

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 2002 and 2001. See Note 4
for a discussion of the Company's derivative instruments.

2002 2001
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN THOUSANDS)

Short-term investments..................... $ -- $ -- $102,950 $103,967
Long-term debt:
Apache
Money market lines of credit.......... 8,900 8,900 1,600 1,600
Global credit facility -- U.S. ....... -- -- 100,000 100,000
Commercial paper...................... 271,400 271,400 530,700 530,700
6.25-percent debentures............... 397,307 448,880 -- --
9.25-percent notes.................... -- -- 99,974 102,560
7-percent notes....................... 148,446 179,445 148,391 148,845
7.625-percent notes................... 149,134 180,990 149,109 157,350
7.7-percent notes..................... 99,660 122,890 99,655 105,130
7.95-percent notes.................... 178,614 226,926 178,595 194,454
7.375-percent debentures.............. 148,009 177,090 148,003 152,415
7.625-percent debentures.............. 149,175 179,205 149,175 157,380
Subsidiary and other obligations
Money market lines of credit.......... -- -- 1,196 1,196
Global credit facility -- Canada...... -- -- 30,000 30,000
Fletcher notes........................ 5,356 6,065 5,356 5,716
Apache Finance Australia 6.5-percent
notes............................... 169,260 193,936 169,137 172,822
Apache Finance Australia 7-percent
notes............................... 99,535 116,430 99,478 104,230
Apache Finance Canada 7.75-percent
notes............................... 297,019 380,280 296,988 320,880
Apache Clearwater notes............... 37,000 37,000 37,000 37,000

The following methods and assumptions were used to estimate the fair value
of the financial instruments summarized in the table above. The Company's trade
receivables and trade payables are by their very nature short-term. The carrying
values included in the accompanying consolidated balance sheet approximate fair
value at December 31, 2002 and December 31, 2001.

Short-Term Investments -- The fair value of the Company's short-term
investments are estimates provided to the Company by independent investment
banking firms.

Long-Term Debt -- The 2002 fair value of the notes and debentures is based
upon an estimate provided to the Company by an independent investment banking
firm. The fair value of the notes and debentures for 2001 is based on quoted
market prices and in the case of the 7.625-percent debentures, an estimate
provided by an independent banking firm. The carrying amount of the global
credit facility, commercial paper, money market lines of credit and Apache
Clearwater notes approximated fair value because the interest rates are variable
and reflective of market rates.

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. COMMITMENTS AND CONTINGENCIES

LITIGATION

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

On February 5, 2003, the Bankruptcy Court for the Western District of
Louisiana entered an order confirming Debtor XCL-China Ltd.'s most recently
filed plan of arrangement. XCL-China is a participant in certain of our
concessions in the Zhao Dong Block in the Bohai Bay of China. We understand that
XCL Ltd. will now have one percent or less ownership interest, if any, in
XCL-China with any remaining ownership interest being held by the bondholders of
XCL Ltd. In connection with the order, Apache China has agreed to waive its
approval and preferential purchase rights of the XCL-China interest in the Zhao
Dong Block for the event of the confirmation and reorganization of the Debtor
only, without waiver of any rights concerning future events. All agreements
approved in 2001 by Apache China, XCL-China and the various Chinese parties,
which resolved the funding and subsequent repayment of XCL-China's share of
development costs, remain in place.

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

Cinergy -- Cinergy Marketing & Trading, LLC (Cinergy) purchases most of the
Company's United States natural gas production (see Note 13 Transactions with
Related Parties and Major Customers.) Disputes have arisen between Cinergy and
Apache concerning various matters, including Cinergy's claim to market Apache's
Canadian gas production. In response to these disputes, Cinergy commenced an
arbitration proceeding in September 2001 seeking, among other things, specific
performance to require the Company to sell its Canadian gas production to
Cinergy or pay damages. The Company is 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. Management does not believe the outcome of the
arbitration will be material to our financial position or results of operations.
The Company continues to market most of its U.S. gas production through Cinergy,
although the Company is actively discussing its gas marketing arrangements and a
resolution of the disputes with Cinergy.

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

Environmental -- The Company, as an owner or lessee and operator of oil and
gas properties, is subject to various federal, provincial, state, local and
foreign country laws and regulations relating to discharge of

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

Apache manages its exposure to environmental liabilities on properties to
be acquired by identifying existing problems and assessing the potential
liability. The Company also conducts periodic reviews, on a company-wide basis,
to identify changes in its environmental risk profile. These reviews evaluate
whether there is a probable liability, its amount, and the likelihood that the
liability will be incurred. The amount of any potential liability is determined
by considering, among other matters, incremental direct costs of any likely
remediation and the proportionate cost of employees who are expected to devote a
significant amount of time directly to any possible remediation effort. As it
relates to evaluations of purchased properties, depending on the extent of an
identified environmental problem, the Company may exclude a property from the
acquisition, require the seller to remediate the property to Apache's
satisfaction, or agree to assume liability for the remediation of the property.
The Company's general policy is to limit any reserve additions to any incidents
or sites that are considered probable to result in an expected remediation cost
exceeding $100,000. Any environmental costs and liabilities that are not
reserved for are treated as an expense when actually incurred. In our
estimation, neither these expenses nor expenses related to training and
compliance programs, are likely to have a material impact on our financial
condition. As of December 31, 2002, the Company had an undiscounted reserve for
environmental remediation of approximately $10 million. Apache is not aware of
any environmental claims existing as of December 31, 2002, which have not been
provided for or would otherwise have a material impact on its financial position
or results of operations. There can be no assurance, however, that current
regulatory requirements will not change, or past non-compliance with
environmental laws will not be discovered on the Company's properties.

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

International Lease Concessions -- The Company, through its subsidiaries,
has acquired or has been conditionally or unconditionally granted exploration
rights in Australia, Egypt, China and Poland. In order to comply with the
contracts and agreements granting these rights, the Company, through various
wholly-owned subsidiaries, is committed to expend approximately $71 million
through 2006.

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

For certain eligible employees, the Company also provides a non-qualified
retirement/savings plan which allows the deferral of up to 50 percent of each
such employee's salary, and which accepts employee contributions and the
Company's matching contributions in excess of the above-referenced restrictions
on the

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

401(k) savings plan and money purchase retirement plan. Additionally, Apache
Energy Limited and Apache Canada Ltd. maintain separate retirement plans, as
required under the laws of Australia and Canada, respectively.

Vesting in the Company's contributions to the 401(k) savings plan, the
money purchase retirement plan and the non-qualified retirement/savings plan
occurs at the rate of 20 percent per year. Upon a change in control of
ownership, vesting is immediate. Total costs under all plans were $18 million,
$16 million and $9 million for 2002, 2001 and 2000, respectively. The unfunded
liability for all plans as of December 31, 2002 and 2001 has been recorded in
other accrued expenses.

In connection with the pending acquisition of U.K. North Sea assets from
BP, Apache will establish a defined benefit pension plan for certain employees
acquired in the transaction. BP will contribute amounts to the new plan related
to past service for the transferred employees.

Operating Lease and Other Commitments -- The Company has leases for
buildings, facilities and equipment with varying expiration dates through 2008.
Net rental expense was $16 million, $18 million and $16 million for 2002, 2001
and 2000, respectively.

As of December 31, 2002, minimum rental commitments under long-term
operating leases, net of sublease rentals; and long-term pipeline transportation
commitments, ranging from one to 21 years, are as follows:

NET MINIMUM COMMITMENTS
-------------------------------------------------
PIPELINE
TOTAL LEASES DRILLING RIGS TRANSMISSION
-------- ------- ------------- ------------
(IN THOUSANDS)

2003..................................... $107,234 $13,213 $68,234 $ 25,787
2004..................................... 49,735 13,404 14,182 22,149
2005..................................... 33,769 11,969 2,957 18,843
2006..................................... 31,158 11,543 2,957 16,658
2007..................................... 23,096 4,137 2,957 16,002
Thereafter............................... 65,151 319 478 64,354
-------- ------- ------- --------
$310,143 $54,585 $91,765 $163,793
======== ======= ======= ========

12. PREFERRED INTERESTS OF SUBSIDIARIES

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

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

F-36

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The limited partnership is scheduled to terminate as of August 9, 2021.
However, the general partner, an Apache subsidiary, may elect to retire all or
part of the limited partner's interest at any time without penalty. In addition,
the limited partnership agreement requires that the limited and general partners
reset the partners' rate of return over LIBOR every five years beginning in
2006. If the partners fail to mutually agree on new rates of return, the general
partner must either dissolve the partnership or purchase the limited partner's
interest. Upon dissolution of the partnership, retirement of the limited
partner's interest, or purchase of the limited partner's interest by the general
partner, the limited partner will receive the unrecouped balance of its initial
$361 million capital investment.

If Apache's senior unsecured long-term debt ratings from Standard & Poor's
and Moody's fall to BBB- or lower and Baa3 or lower, respectively, or if either
rating is withdrawn, our subsidiaries that issued the preferred stock and
limited partnership interests may need to obtain additional cash or cash
equivalents or redeem part of the preferred interests to remain in compliance
with certain covenants. Also, if Apache's rating falls to BB or lower or Ba2 or
lower, the limited partner has the right to cause the dissolution of the
partnership, though Apache can avoid this by exercising its right to retire the
limited partnership interests without penalty.

The preferred stock certificates require that the Apache subsidiaries and
their preferred shareholders reset the preferred stock dividend rate every five
years beginning in 2006. If they fail to mutually agree on a new rate, the
Apache subsidiaries must either register the stock for public sale, or redeem
all of the outstanding preferred stock. The Apache subsidiaries may elect to
redeem all or part of the preferred stock at any time without penalty.

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

13. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

Cinergy Corp. -- In June 1998, Apache contracted with Cinergy Corp. to
market substantially all the Company's natural gas production from the United
States and agreed to develop terms for the marketing of most of Apache's
Canadian production under an amended and restated gas purchase agreement
effective July 1, 1998. Apache sold its 57 percent interest in ProEnergy for
771,258 shares of Cinergy Corp. common stock, which the Company subsequently
sold for $26 million. In December 1998, Apache and Cinergy Corp. agreed to
postpone the negotiation of terms to market most of Apache's Canadian
production. Pursuant to the gas purchase agreement, ProEnergy, renamed Cinergy
Marketing and Trading LLC (Cinergy), will continue to market Apache's North
American natural gas production until June 30, 2008, with an option, following
prior notice, to terminate on June 30, 2004. During this period, Apache is
generally obligated to deliver most of its United States gas production to
Cinergy and, under certain circumstances, reimburse Cinergy if certain gas
throughput thresholds are not met. All throughput thresholds have been met. The
prices received for its gas production under this agreement approximate market
prices. Apache and Cinergy are parties to arbitration (see Note 11 Commitments
and Contingencies). Apache continues to market most of its U.S. gas production
through Cinergy, although the Company is actively discussing with Cinergy its
gas marketing arrangements and a resolution of its disputes.

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

F-37

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Apache's board of directors through December 19, 2003, is president, chief
executive officer and the sole stockholder of Maralo.

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

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

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

All transactions with related parties were consummated at fair value.

Major Customers -- In 2002, purchases by Cinergy and EGPC accounted for 19
percent and 22 percent of the Company's oil and gas production revenues,
respectively. In 2001, purchases by Cinergy and EGPC accounted for 35 percent
and 17 percent of the Company's oil and gas production revenues, respectively.
In 2000, purchases by Cinergy and EGPC accounted for 26 percent and 16 percent
of the Company's oil and gas production revenues, respectively. No other
purchaser has accounted for more than 10 percent of revenues for 2002, 2001 or
2000.

Concentration of Credit Risk -- The Company's revenues are derived
principally from uncollateralized sales to customers in the oil and gas
industry; therefore, customers may be similarly affected by changes in economic
and other conditions within the industry. Apache has not experienced significant
credit losses on such sales. Sales of natural gas by Apache to Cinergy are
similarly uncollateralized. Apache sells all of its Egyptian crude oil and
natural gas to the EGPC for U.S. dollars. Deteriorating economic conditions
during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars,
resulting in a 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.

F-38

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. BUSINESS SEGMENT INFORMATION

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

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- ---------- ---------- --------- ------------- ----------
(IN THOUSANDS)

2002
Oil and Gas Production Revenues..... $1,101,388 $ 557,720 $ 560,099 $334,039 $ 6,502 $2,559,748
Operating Expenses:
Depreciation, depletion and
amortization.................... 387,187 182,584 163,648 107,993 2,467 843,879
International impairments......... -- -- -- -- 19,600 19,600
Lease operating costs............. 239,837 114,299 69,160 37,107 1,721 462,124
Gathering and transportation
costs........................... 17,311 21,256 -- -- -- 38,567
Severance and other taxes......... 34,792 5,489 -- 22,807 -- 63,088
---------- ---------- ---------- -------- -------- ----------
Operating Income (Loss)............. $ 422,261 $ 234,092 $ 327,291 $166,132 $(17,286) 1,132,490
========== ========== ========== ======== ========
Other Income (Expense):
Other revenues.................... 125
Administrative, selling and
other........................... (104,588)
Financing costs, net.............. (112,833)
Preferred interests of
subsidiaries.................... (16,224)
----------
Income Before Income Taxes.......... $ 898,970
==========
Net Property and Equipment.......... $4,068,362 $2,190,029 $1,263,560 $807,332 $136,302 $8,465,585
========== ========== ========== ======== ======== ==========
Total Assets........................ $4,309,736 $2,401,319 $1,713,267 $883,704 $151,825 $9,459,851
========== ========== ========== ======== ======== ==========
Additions to Net Property and
Equipment......................... $ 597,954 $ 379,413 $ 196,975 $100,761 $ 37,767 $1,312,870
========== ========== ========== ======== ======== ==========

F-39

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- ---------- ---------- --------- ------------- ----------
(IN THOUSANDS)

2001
Oil and Gas Production Revenues..... $1,474,628 $ 628,967 $ 460,910 $257,407 $ 1,047 $2,822,959
Operating Expenses:
Depreciation, depletion and
amortization.................... 423,727 178,770 135,225 82,686 423 820,831
International impairments......... -- -- -- -- 65,000 65,000
Lease operating costs............. 227,418 95,833 49,449 31,728 386 404,814
Gathering and transportation
costs........................... 15,790 18,794 -- -- -- 34,584
Severance and other taxes......... 49,555 8,483 -- 11,789 -- 69,827
---------- ---------- ---------- -------- -------- ----------
Operating Income (Loss)............. $ 758,138 $ 327,087 $ 276,236 $131,204 $(64,762) 1,427,903
========== ========== ========== ======== ========
Other Income (Expense):
Other revenues (losses)........... (13,568)
Administrative, selling and
other........................... (88,710)
Financing costs, net.............. (118,762)
Preferred interests of
subsidiaries.................... (7,609)
----------
Income Before Income Taxes.......... $1,199,254
==========
Net Property and Equipment.......... $3,855,674 $1,984,147 $1,238,234 $814,423 $120,594 $8,013,072
========== ========== ========== ======== ======== ==========
Total Assets........................ $4,172,551 $2,163,615 $1,564,474 $882,141 $150,875 $8,933,656
========== ========== ========== ======== ======== ==========
Additions to Net Property and
Equipment......................... $ 834,581 $1,015,184 $ 515,551 $113,171 $ 34,048 $2,512,535
========== ========== ========== ======== ======== ==========
2000
Oil and Gas Production Revenues..... $1,386,642 $ 337,876 $ 360,772 $223,543 $ -- $2,308,833
Operating Expenses:
Depreciation, depletion and
amortization.................... 356,998 79,892 84,425 62,183 48 583,546
Lease operating costs............. 167,986 32,945 28,328 24,450 -- 253,709
Gathering and transportation
costs........................... 11,701 7,915 -- -- -- 19,616
Severance and other taxes......... 48,015 5,072 -- 6,086 -- 59,173
---------- ---------- ---------- -------- -------- ----------
Operating Income (Loss)............. $ 801,942 $ 212,052 $ 248,019 $130,824 $ (48) 1,392,789
========== ========== ========== ======== ========
Other Income (Expense):
Other revenues (losses)........... (6,855)
Administrative, selling and
other........................... (75,615)
Financing costs, net.............. (106,638)
----------
Income Before Income Taxes.......... $1,203,681
==========
Net Property and Equipment.......... $3,643,439 $1,378,639 $ 854,531 $783,884 $151,969 $6,812,462
========== ========== ========== ======== ======== ==========
Total Assets........................ $4,022,749 $1,463,306 $ 965,733 $856,575 $173,587 $7,481,950
========== ========== ========== ======== ======== ==========
Additions to Net Property and
Equipment......................... $1,461,479 $ 649,804 $ 93,083 $117,248 $ 20,865 $2,342,479
========== ========== ========== ======== ======== ==========

F-40

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

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

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- -------- -------- --------- ------------- ----------
(IN THOUSANDS)

2002
Oil and gas production revenues........ $1,101,388 $557,720 $560,099 $334,039 $ 6,502 $2,559,748
---------- -------- -------- -------- -------- ----------
Operating costs:
Depreciation, depletion and
amortization(1).................... 369,864 181,087 163,648 107,194 2,455 824,248
International impairments............ -- -- -- -- 19,600 19,600
Lease operating expenses............. 239,837 114,299 69,160 37,107 1,721 462,124
Gathering and transportation costs... 17,311 21,256 -- -- -- 38,567
Production taxes(2).................. 33,336 -- -- 18,659 -- 51,995
Income tax........................... 165,390 104,869 157,100 58,167 (6,536) 478,990
---------- -------- -------- -------- -------- ----------
825,738 421,511 389,908 221,127 17,240 1,875,524
---------- -------- -------- -------- -------- ----------
Results of operations.................. $ 275,650 $136,209 $170,191 $112,912 $(10,738) $ 684,224
========== ======== ======== ======== ======== ==========
Amortization rate per boe.............. $ 7.06 $ 5.71 $ 6.10 $ 5.36 $ 3.68 $ 6.29
========== ======== ======== ======== ======== ==========
2001
Oil and gas production revenues........ $1,474,628 $628,967 $460,910 $257,407 $ 1,047 $2,822,959
---------- -------- -------- -------- -------- ----------
Operating costs:
Depreciation, depletion and
amortization(1).................... 409,096 177,159 135,086 81,930 388 803,659
International impairments............ -- -- -- -- 65,000 65,000
Lease operating expenses............. 227,418 95,833 49,449 31,728 386 404,814
Gathering and transportation costs... 15,790 18,794 -- -- -- 34,584
Production taxes(2).................. 47,462 -- -- 11,789 -- 59,251
Income tax........................... 290,573 150,450 132,660 44,866 (24,279) 594,270
---------- -------- -------- -------- -------- ----------
990,339 442,236 317,195 170,313 41,495 1,961,578
---------- -------- -------- -------- -------- ----------
Results of operations.................. $ 484,289 $186,731 $143,715 $ 87,094 $(40,448) $ 861,381
========== ======== ======== ======== ======== ==========
Amortization rate per boe.............. $ 6.64 $ 5.80 $ 5.66 $ 4.70 $ 4.72 $ 6.05
========== ======== ======== ======== ======== ==========

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- -------- -------- --------- ------------- ----------
(IN THOUSANDS)

2000
Oil and gas production revenues........ $1,386,642 $337,876 $360,772 $223,543 $ -- $2,308,833
---------- -------- -------- -------- -------- ----------
Operating costs:
Depreciation, depletion and
amortization(1).................... 345,624 76,286 84,302 61,358 -- 567,570
Lease operating expenses............. 167,985 32,945 28,328 24,451 -- 253,709
Gathering and transportation costs... 11,701 7,915 -- -- -- 19,616
Production taxes(2).................. 46,509 -- -- 6,086 -- 52,595
Income tax........................... 305,559 98,489 119,108 44,760 -- 567,916
---------- -------- -------- -------- -------- ----------
877,378 215,635 231,738 136,655 -- 1,461,406
---------- -------- -------- -------- -------- ----------
Results of operations.................. $ 509,264 $122,241 $129,034 $ 86,888 $ -- $ 847,427
========== ======== ======== ======== ======== ==========
Amortization rate per boe.............. $ 6.16 $ 5.53 $ 5.46 $ 4.42 $ -- $ 5.75
========== ======== ======== ======== ======== ==========

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

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

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

Costs Not Being Amortized -- The following table sets forth a summary of
oil and gas property costs not being amortized at December 31, 2002, by the year
in which such costs were incurred. There are no individually significant
properties or significant development projects included in costs not being
amortized. The majority of the evaluation activities are expected to be
completed within five to ten years.

1999
TOTAL 2002 2001 2000 AND PRIOR
-------- -------- -------- ------- ---------
(IN THOUSANDS)

Property acquisition costs....... $393,426 $150,855 $ 38,658 $70,622 $133,291
Exploration and development...... 214,519 119,901 48,764 21,000 24,854
Capitalized interest............. 48,327 19,130 14,427 3,041 11,729
-------- -------- -------- ------- --------
Total.......................... $656,272 $289,886 $101,849 $94,663 $169,874
======== ======== ======== ======= ========

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- -------- -------- --------- ------------- ----------
(IN THOUSANDS)

2002
Acquisitions(1)................. $ 267,537 $ 84,170 $ -- $ -- $ -- $ 351,707
Purchase of non-producing
leases........................ 2,264 20,150 -- -- -- 22,414
Exploration..................... 19,805 2,833 55,580 50,327 2,330 130,875
Development..................... 280,542 235,208 115,580 39,486 36,079 706,895
Capitalized interest............ 13,200 14,392 8,875 4,224 -- 40,691
Property sales.................. 873 84 (8,000) -- -- (7,043)
---------- -------- -------- ------- ------- ----------
$ 584,221 $356,837 $172,035 $94,037 $38,409 $1,245,539
========== ======== ======== ======= ======= ==========
2001
Acquisitions (1)................ $ 65,395 $561,700 $240,255 $ -- $12,936 $ 880,286
Purchase of non-producing
leases........................ 14,004 27,941 -- -- -- 41,945
Exploration..................... 47,688 64,172 39,806 38,727 12,536 202,929
Development..................... 637,488 318,232 87,798 46,441 8,302 1,098,261
Capitalized interest............ 24,500 13,920 11,293 7,036 -- 56,749
Property sales.................. (200,445) (147,851) -- -- -- (348,296)
---------- -------- -------- ------- ------- ----------
$ 588,630 $838,114 $379,152 $92,204 $33,774 $1,931,874
========== ======== ======== ======= ======= ==========
2000
Acquisitions (1)................ $ 922,523 $401,904 $ -- $ -- $ -- $1,324,427
Purchase of non-producing
leases........................ 10,712 11,548 -- -- -- 22,260
Exploration..................... 26,045 16,331 51,819 40,917 18,077 153,189
Development..................... 459,046 107,748 33,130 32,918 -- 632,842
Capitalized interest............ 27,185 10,063 12,194 9,908 2,650 62,000
Property sales.................. (10,853) (15,418) -- -- -- (26,271)
---------- -------- -------- ------- ------- ----------
$1,434,658 $532,176 $ 97,143 $83,743 $20,727 $2,168,447
========== ======== ======== ======= ======= ==========

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

(1) Acquisitions include unproved costs of $70 million, $77 million and $125
million for transactions completed in 2002, 2001 and 2000, respectively.

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

OTHER
UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- ---------- ---------- ---------- ------------- -----------
(IN THOUSANDS)

2002
Proved properties........ $7,906,966 $2,478,623 $1,232,119 $ 970,386 $239,365 $12,827,459
Unproved properties...... 203,366 204,059 174,925 39,962 33,960 656,272
---------- ---------- ---------- ---------- -------- -----------
8,110,332 2,682,682 1,407,044 1,010,348 273,325 13,483,731
Accumulated DD&A......... (4,121,751) (637,546) (502,658) (357,271) (137,668) (5,756,894)
---------- ---------- ---------- ---------- -------- -----------
$3,988,581 $2,045,136 $ 904,386 $ 653,077 $135,657 $ 7,726,837
========== ========== ========== ========== ======== ===========
2001
Proved properties........ $7,314,153 $2,103,263 $1,037,431 $ 816,620 $119,225 $11,390,692
Unproved properties...... 211,958 215,003 197,578 99,691 115,691 839,921
---------- ---------- ---------- ---------- -------- -----------
7,526,111 2,318,266 1,235,009 916,311 234,916 12,230,613
Accumulated DD&A......... (3,751,887) (466,703) (359,792) (259,373) (115,613) (4,953,368)
---------- ---------- ---------- ---------- -------- -----------
$3,774,224 $1,851,563 $ 875,217 $ 656,938 $119,303 $ 7,277,245
========== ========== ========== ========== ======== ===========

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Oil and Gas Reserve Information -- Proved oil and gas reserve quantities are
based on estimates prepared by the Company's engineers in accordance with Rule
4-10 of Regulation S-X. The Company's estimates of proved reserve quantities of
its U.S., Canadian and international properties are subject to review by Ryder
Scott Company, L.P. Petroleum Consultants, independent petroleum engineers.
During 2002, 2001 and 2000, their review covered 68 percent, 61 percent and 72
percent of the reserve value, respectively.

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

CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS
---------------------------------------------------------- -------------------------------
(THOUSANDS OF BARRELS) (MILLIONS OF CUBIC FEET)
UNITED OTHER UNITED
STATES CANADA EGYPT AUSTRALIA INT'L TOTAL STATES CANADA EGYPT
------- ------- ------- --------- ------ ------- --------- --------- -------

PROVED DEVELOPED RESERVES:
December 31, 1999............. 186,962 50,401 30,719 33,887 -- 301,969 1,004,844 397,704 106,830
December 31, 2000............. 232,361 66,484 26,028 29,124 -- 353,997 1,579,865 660,334 93,205
December 31, 2001............. 230,017 76,250 59,188 45,628 699 411,782 1,407,561 1,148,516 338,707
December 31, 2002............. 240,880 89,554 51,162 31,746 1,033 414,375 1,444,677 1,255,068 246,529
TOTAL PROVED RESERVES:
Balance December 31,1999........ 238,657 83,043 39,076 54,466 -- 415,242 1,214,887 407,053 156,049
Extensions, discoveries and
other additions............. 36,681 6,589 9,168 6,074 -- 58,512 154,489 94,792 32,967
Purchases of minerals
in-place.................... 60,519 29,514 -- -- -- 90,033 736,079 246,360 --
Revisions of previous
estimates................... 2,655 159 1,012 429 -- 4,255 32,414 (8,397) 2,966
Production.................... (22,894) (5,828) (10,155) (5,691) -- (44,568) (199,362) (47,758) (17,371)
Sales of properties........... (914) (87) -- -- -- (1,001) (10,454) (333) --
------- ------- ------- ------- ------ ------- --------- --------- -------
Balance December 31, 2000....... 314,704 113,390 39,101 55,278 -- 522,473 1,928,053 691,717 174,611
Extensions, discoveries and
other additions............. 54,533 21,121 17,121 12,320 -- 105,095 166,307 281,037 52,938
Purchases of minerals
in-place.................... 6,728 35,298 36,465 -- 1,099 79,590 34,827 512,927 247,302
Revisions of previous
estimates................... (7,943) 814 2,621 -- -- (4,508) (61,522) 8,391 13,392
Production.................... (24,157) (9,916) (14,322) (8,595) (42) (57,032) (224,600) (108,925) (35,010)
Sales of properties........... (22,428) (23,802) -- -- -- (46,230) (167,271) (83,265) --
------- ------- ------- ------- ------ ------- --------- --------- -------
Balance December 31, 2001....... 321,437 136,905 80,986 59,003 1,057 599,388 1,675,794 1,301,882 453,233
Extensions, discoveries and
other additions............. 20,082 31,366 18,227 4,221 11,793 85,689 102,050 70,066 6,123
Purchases of minerals
in-place.................... 7,109 5,055 -- -- -- 12,164 154,459 66,113 --
Revisions of previous
estimates................... 6,630 159 (8,140) 106 40 (1,205) 37,944 20,900 (37,480)
Production.................... (21,790) (9,846) (15,977) (11,082) (225) (58,920) (183,708) (120,210) (44,769)
Sales of properties........... (46) -- (305) -- -- (351) (2,446) -- (6,440)
------- ------- ------- ------- ------ ------- --------- --------- -------
Balance December 31, 2002....... 333,422 163,639 74,791 52,248 12,665 636,765 1,784,093 1,338,751 370,667
======= ======= ======= ======= ====== ======= ========= ========= =======

NATURAL GAS TOTAL
------------------------------ -----------
(MILLIONS OF CUBIC FEET) (THOUSAND
OTHER BARRELS OF
AUSTRALIA INT'L TOTAL OIL
--------- ------ --------- EQUIVALENT)

PROVED DEVELOPED RESERVES:
December 31, 1999............. 364,369 -- 1,873,747 614,260
December 31, 2000............. 331,390 -- 2,664,794 798,129
December 31, 2001............. 307,509 1,524 3,203,817 945,751
December 31, 2002............. 256,790 3,469 3,206,533 948,797
TOTAL PROVED RESERVES:
Balance December 31,1999........ 573,589 -- 2,351,578 807,172
Extensions, discoveries and
other additions............. 55,195 -- 337,443 114,752
Purchases of minerals
in-place.................... -- -- 982,439 253,773
Revisions of previous
estimates................... (6) -- 26,977 8,751
Production.................... (39,489) -- (303,980) (95,231)
Sales of properties........... -- -- (10,787) (2,799)
------- ------ --------- ---------
Balance December 31, 2000....... 589,289 -- 3,383,670 1,086,418
Extensions, discoveries and
other additions............. 25,084 -- 525,366 192,656
Purchases of minerals
in-place.................... -- 2,969 798,025 212,594
Revisions of previous
estimates................... -- -- (39,739) (11,131)
Production.................... (42,684) (236) (411,455) (125,608)
Sales of properties........... -- -- (250,536) (87,986)
------- ------ --------- ---------
Balance December 31, 2001....... 571,689 2,733 4,005,331 1,266,943
Extensions, discoveries and
other additions............. 28,943 3,355 210,537 120,779
Purchases of minerals
in-place.................... -- -- 220,572 48,926
Revisions of previous
estimates................... 22 37 21,423 2,366
Production.................... (42,998) (2,656) (394,341) (124,644)
Sales of properties........... -- -- (8,886) (1,832)
------- ------ --------- ---------
Balance December 31, 2002....... 557,656 3,469 4,054,636 1,312,538
======= ====== ========= =========

As of December 31, 2002, 2001 and 2000, on a barrel of equivalent basis 28,
25 and 27 percent of our worldwide reserves, respectively, were classified as
proved undeveloped. Approximately 19.2 percent of our proved developed reserves
are classified as proved not producing. These reserves relate to zones that are
either behind pipe, or that have been completed but not yet produced or zones
that have been produced in the past but are not now producing due to mechanical
reasons. These reserves may be regarded as less certain than producing reserves
because they are frequently based on volumetric calculations rather than
performance data. Future production associated with behind pipe reserves is
scheduled to follow depletion of the currently producing zones in the same
wellbores. It should be noted that additional capital may have to be spent to
access these reserves. The capital and economic impact of production timing are
reflected in our standardized measure Note 15.

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

OTHER
UNITED STATES CANADA(1) EGYPT AUSTRALIA INTERNATIONAL TOTAL
------------- ----------- ---------- ---------- ------------- ------------
(IN THOUSANDS)

2002
Cash inflows.................... $17,550,514 $ 9,597,042 $3,820,016 $2,436,477 $402,311 $ 33,806,360
Production costs................ (4,442,214) (1,955,401) (501,511) (463,282) (61,905) (7,424,313)
Development costs............... (662,686) (312,194) (421,454) (235,318) (19,600) (1,651,252)
Income tax expense.............. (3,875,478) (2,288,073) (963,906) (482,883) (59,164) (7,669,504)
----------- ----------- ---------- ---------- -------- ------------
Net cash flows.................. 8,570,136 5,041,374 1,933,145 1,254,994 261,642 17,061,291
10 percent discount rate........ (4,170,620) (2,633,601) (651,524) (373,032) (80,894) (7,909,671)
----------- ----------- ---------- ---------- -------- ------------
Discounted future net cash
flows(2)...................... $ 4,399,516 $ 2,407,773 $1,281,621 $ 881,962 $180,748 $ 9,151,620
=========== =========== ========== ========== ======== ============
2001
Cash inflows.................... $10,424,737 $ 5,468,028 $2,831,285 $1,838,437 $ 22,381 $ 20,584,868
Production costs................ (3,457,430) (1,538,797) (564,714) (383,171) (13,789) (5,957,901)
Development costs............... (613,594) (333,043) (306,543) (188,017) (3,532) (1,444,729)
Income tax expense.............. (1,417,677) (851,971) (683,856) (345,392) -- (3,298,896)
----------- ----------- ---------- ---------- -------- ------------
Net cash flows.................. 4,936,036 2,744,217 1,276,172 921,857 5,060 9,883,342
10 percent discount rate........ (2,286,959) (1,337,536) (427,744) (286,696) (946) (4,339,881)
----------- ----------- ---------- ---------- -------- ------------
Discounted future net cash
flows(2)...................... $ 2,649,077 $ 1,406,681 $ 848,428 $ 635,161 $ 4,114 $ 5,543,461
=========== =========== ========== ========== ======== ============
2000
Cash inflows.................... $26,652,689 $ 8,865,939 $1,430,178 $2,133,073 $ -- $ 39,081,879
Production costs................ (4,909,091) (996,123) (214,686) (453,153) -- (6,573,053)
Development costs............... (640,218) (347,708) (84,025) (197,998) -- (1,269,949)
Income tax expense.............. (7,132,257) (2,194,511) (375,112) (385,953) -- (10,087,833)
----------- ----------- ---------- ---------- -------- ------------
Net cash flows.................. 13,971,123 5,327,597 756,355 1,095,969 -- 21,151,044
10 percent discount rate........ (6,148,566) (2,478,102) (238,985) (337,741) -- (9,203,394)
----------- ----------- ---------- ---------- -------- ------------
Discounted future net cash
flows(2)...................... $ 7,822,557 $ 2,849,495 $ 517,370 $ 758,228 $ -- $ 11,947,650
=========== =========== ========== ========== ======== ============

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

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

(2) Estimated future net cash flows before income tax expense, discounted at 10
percent per annum, totaled approximately $13.2 billion, $7.4 billion and
$17.7 billion as of December 31, 2002, 2001 and 2000, respectively.

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------
2002 2001 2000
----------- ------------ -----------
(IN THOUSANDS)

Sales, net of production costs............... $(1,994,631) $ (2,327,679) $(2,064,471)
Net change in prices and production costs.... 4,767,785 (10,125,666) 4,693,840
Discoveries and improved recovery, net of
related costs.............................. 1,885,266 1,760,299 2,703,195
Change in future development costs........... 222,160 182,816 67,442
Revision of quantities....................... (15,400) (79,138) 135,669
Purchases of minerals in-place............... 603,608 1,332,244 5,796,278
Accretion of discount........................ 737,112 1,772,520 606,801
Change in income taxes....................... (2,200,925) 3,949,890 (4,284,904)
Sales of properties.......................... (14,502) (1,306,042) (25,585)
Change in production rates and other......... (382,314) (1,563,433) (255,976)
----------- ------------ -----------
$ 3,608,159 $ (6,404,189) $ 7,372,289
=========== ============ ===========

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

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

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

FIRST SECOND THIRD FOURTH TOTAL
-------- -------- -------- -------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

2002
Revenues............................... $527,996 $656,315 $645,189 $730,373 $2,559,873
Expenses, net.......................... 447,324 510,005 498,661 549,554 2,005,544
-------- -------- -------- -------- ----------
Net income............................. $ 80,672 $146,310 $146,528 $180,819 $ 554,329
======== ======== ======== ======== ==========
Income attributable to common stock.... $ 75,764 $143,229 $145,122 $179,399 $ 543,514
======== ======== ======== ======== ==========
Net income per common share (1)(2):
Basic................................ $ .26 $ .48 $ .48 $ .59 $ 1.83
======== ======== ======== ======== ==========
Diluted.............................. $ .26 $ .48 $ .48 $ .59 $ 1.80
======== ======== ======== ======== ==========
2001
Revenues............................... $803,515 $808,681 $659,917 $537,278 $2,809,391
Expenses, net.......................... 521,314 602,936 503,084 458,658 2,085,992
-------- -------- -------- -------- ----------
Net income............................. $282,201 $205,745 $156,833 $ 78,620 $ 723,399
======== ======== ======== ======== ==========
Income attributable to common stock.... $277,293 $200,868 $151,925 $ 73,712 $ 703,798
======== ======== ======== ======== ==========
Net income per common share (1)(2):
Basic................................ $ .97 $ .69 $ .53 $ .26 $ 2.44
======== ======== ======== ======== ==========
Diluted.............................. $ .93 $ .67 $ .51 $ .25 $ 2.37
======== ======== ======== ======== ==========

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

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

(2) Earnings per share have been restated to reflect the 10 percent stock
dividend declared September 13, 2001, paid January 21, 2002 to shareholders
of record on December 31, 2001, the five percent stock dividend declared
December 18, 2002, payable April 2, 2003 to shareholders of record on March
12, 2003, and the two-for-one stock split declared September 11, 2003,
distributed January 14, 2004 to shareholders of record on December 31, 2003.

17. SUPPLEMENTAL GUARANTOR INFORMATION

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

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

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

ALL OTHER
APACHE SUBSIDIARIES
APACHE APACHE FINANCE APACHE OF APACHE
CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION
----------- ------------- --------- -------------- ------------
(IN THOUSANDS)

REVENUES AND OTHER:
Oil and gas production
revenues....................... $ 814,225 $ -- $ -- $ -- $1,906,009
Equity in net income of
affiliates..................... 391,295 20,976 32,905 76,707 (37,036)
Other............................ 7,909 -- (25) -- (7,759)
---------- ------- ------- -------- ----------
1,213,429 20,976 32,880 76,707 1,861,214
---------- ------- ------- -------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... 211,291 -- -- -- 632,588
International impairments........ -- -- -- -- 19,600
Lease operating costs............ 198,052 -- -- -- 424,558
Gathering and transportation
costs.......................... 15,896 -- -- -- 22,671
Severance and other taxes........ 34,015 -- -- 270 28,803
Administrative, selling and
other.......................... 87,860 -- -- -- 16,728
Financing costs, net............. 72,721 -- 18,050 41,058 (18,996)
---------- ------- ------- -------- ----------
619,835 -- 18,050 41,328 1,125,952
---------- ------- ------- -------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- -- -- -- 16,224
---------- ------- ------- -------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ 593,594 20,976 14,830 35,379 719,038
Provision (benefit) for income
taxes.......................... 39,265 -- (6,146) (16,221) 327,743
---------- ------- ------- -------- ----------
NET INCOME......................... 554,329 20,976 20,976 51,600 391,295
Preferred stock dividends........ 10,815 -- -- -- --
---------- ------- ------- -------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $ 543,514 $20,976 $20,976 $ 51,600 $ 391,295
========== ======= ======= ======== ==========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

REVENUES AND OTHER:
Oil and gas production
revenues....................... $(160,486) $2,559,748
Equity in net income of
affiliates..................... (484,847) --
Other............................ -- 125
--------- ----------
(645,333) 2,559,873
--------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... -- 843,879
International impairments........ -- 19,600
Lease operating costs............ (160,486) 462,124
Gathering and transportation
costs.......................... -- 38,567
Severance and other taxes........ -- 63,088
Administrative, selling and
other.......................... -- 104,588
Financing costs, net............. -- 112,833
--------- ----------
(160,486) 1,644,679
--------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- 16,224
--------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ (484,847) 898,970
Provision (benefit) for income
taxes.......................... -- 344,641
--------- ----------
NET INCOME......................... (484,847) 554,329
Preferred stock dividends........ -- 10,815
--------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $(484,847) $ 543,514
========= ==========

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

REVENUES AND OTHER:
Oil and gas production
revenues....................... $1,388,017 $ -- $ -- $ -- $1,897,305
Equity in net income of
affiliates..................... 202,137 16,227 26,170 88,243 (31,085)
Other............................ (3,064) -- 3,053 -- (13,557)
---------- ------- ------- -------- ----------
1,587,090 16,227 29,223 88,243 1,852,663
---------- ------- ------- -------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... 170,854 -- -- -- 649,977
International impairments........ -- -- -- -- 65,000
Lease operating costs............ 214,075 -- -- -- 653,102
Gathering and transportation
costs.......................... 15,337 -- -- -- 19,247
Severance and other taxes........ 49,201 -- -- 36 20,590
Administrative, selling and
other.......................... 78,440 -- -- -- 10,270
Financing costs, net............. 71,150 -- 18,119 37,450 (7,957)
---------- ------- ------- -------- ----------
599,057 -- 18,119 37,486 1,410,229
---------- ------- ------- -------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- -- -- -- 7,609
---------- ------- ------- -------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ 988,033 16,227 11,104 50,757 434,825
Provision (benefit) for income
taxes.......................... 264,634 -- (5,123) (16,344) 232,688
---------- ------- ------- -------- ----------
NET INCOME......................... 723,399 16,227 16,227 67,101 202,137
Preferred stock dividends........ 19,601 -- -- -- --
---------- ------- ------- -------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $ 703,798 $16,227 $16,227 $ 67,101 $ 202,137
========== ======= ======= ======== ==========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

REVENUES AND OTHER:
Oil and gas production
revenues....................... $(462,363) $2,822,959
Equity in net income of
affiliates..................... (301,692) --
Other............................ -- (13,568)
--------- ----------
(764,055) 2,809,391
--------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... -- 820,831
International impairments........ -- 65,000
Lease operating costs............ (462,363) 404,814
Gathering and transportation
costs.......................... -- 34,584
Severance and other taxes........ -- 69,827
Administrative, selling and
other.......................... -- 88,710
Financing costs, net............. -- 118,762
--------- ----------
(462,363) 1,602,528
--------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- 7,609
--------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ (301,692) 1,199,254
Provision (benefit) for income
taxes.......................... -- 475,855
--------- ----------
NET INCOME......................... (301,692) 723,399
Preferred stock dividends........ -- 19,601
--------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $(301,692) $ 703,798
========= ==========

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000

REVENUES AND OTHER:
Oil and gas production
revenues....................... $1,409,724 $ -- $ -- $ -- $1,281,209
Equity in net income of
affiliates..................... 290,644 -- -- 21,417 (10,884)
Other............................ (4,323) -- -- -- (3,394)
---------- ----- ----- ------- ----------
1,696,045 -- -- 21,417 1,266,931
---------- ----- ----- ------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... 356,998 -- -- -- 226,548
Lease operating costs............ 168,336 -- -- -- 467,473
Gathering and transportation
costs.......................... 11,701 -- -- -- 7,915
Severance and other taxes........ 48,014 -- -- -- 11,159
Administrative, selling and
other.......................... 63,418 -- -- -- 12,197
Financing costs, net............. 80,066 -- -- 19,297 7,275
---------- ----- ----- ------- ----------
728,533 -- -- 19,297 732,567
---------- ----- ----- ------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ 967,512 -- -- 2,120 534,364
Provision (benefit) for income
taxes.......................... 246,917 -- -- (8,413) 244,582
---------- ----- ----- ------- ----------
INCOME (LOSS) BEFORE CHANGE IN
ACCOUNTING PRINCIPLE............. 720,595 -- -- 10,533 289,782
Cumulative effect of change in
accounting principle, net of
income tax..................... (7,539) -- -- -- (4,831)
---------- ----- ----- ------- ----------
NET INCOME......................... 713,056 -- -- 10,533 284,951
Preferred stock dividends........ 19,988 -- -- -- --
---------- ----- ----- ------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $ 693,068 $ -- $ -- $10,533 $ 284,951
========== ===== ===== ======= ==========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

REVENUES AND OTHER:
Oil and gas production
revenues....................... $(382,100) $2,308,833
Equity in net income of
affiliates..................... (300,315) 862
Other............................ -- (7,717)
--------- ----------
(682,415) 2,301,978
--------- ----------
OPERATING EXPENSES:
Depreciation, depletion and
amortization................... -- 583,546
Lease operating costs............ (382,100) 253,709
Gathering and transportation
costs.......................... -- 19,616
Severance and other taxes........ -- 59,173
Administrative, selling and
other.......................... -- 75,615
Financing costs, net............. -- 106,638
--------- ----------
(382,100) 1,098,297
--------- ----------
INCOME (LOSS) BEFORE INCOME
TAXES............................ (300,315) 1,203,681
Provision (benefit) for income
taxes.......................... -- 483,086
--------- ----------
INCOME (LOSS) BEFORE CHANGE IN
ACCOUNTING PRINCIPLE............. (300,315) 720,595
Cumulative effect of change in
accounting principle, net of
income tax..................... 4,831 (7,539)
--------- ----------
NET INCOME......................... (295,484) 713,056
Preferred stock dividends........ -- 19,988
--------- ----------
INCOME ATTRIBUTABLE TO COMMON
STOCK............................ $(295,484) $ 693,068
========= ==========

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

ALL OTHER
APACHE SUBSIDIARIES OF
APACHE APACHE FINANCE APACHE APACHE
CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION
----------- ------------- --------- -------------- ---------------
(IN THOUSANDS)

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES...... $ 39,727 $ -- $(18,687) $(43,819) $ 1,403,497
----------- -------- -------- -------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment................ (249,971) -- -- -- (787,397)
Acquisitions....................................... (269,885) -- -- -- --
Proceeds from sales of oil and gas properties...... -- -- -- -- 7,043
Purchase of U.S. Government Agency Notes........... -- -- -- -- 101,723
Investment in and advances to subsidiaries, net.... (168,481) (18,050) -- -- (843,894)
Other, net......................................... (15,105) -- -- -- (22,415)
----------- -------- -------- -------- -----------
NET CASH USED IN INVESTING ACTIVITIES................ (703,442) (18,050) -- -- (1,544,940)
----------- -------- -------- -------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings............................... 2,063,264 -- 637 2,826 225,518
Payments on long-term debt......................... (1,362,800) -- -- -- (190,671)
Dividends paid..................................... (68,879) -- -- -- --
Common stock activity.............................. 30,708 18,050 18,050 41,120 128,889
Treasury stock activity, net....................... 1,991 -- -- -- --
Cost of debt and equity transactions............... (6,728) -- -- -- --
----------- -------- -------- -------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES............ 657,556 18,050 18,687 43,946 163,736
----------- -------- -------- -------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS........................................ (6,159) -- -- 127 22,293
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR....... 6,383 -- 2 -- 29,240
----------- -------- -------- -------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR............. $ 224 $ -- $ 2 $ 127 $ 51,533
=========== ======== ======== ======== ===========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES...... $ -- $ 1,380,718
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment................ -- (1,037,368)
Acquisitions....................................... -- (269,885)
Proceeds from sales of oil and gas properties...... -- 7,043
Purchase of U.S. Government Agency Notes........... -- 101,723
Investment in and advances to subsidiaries, net.... 1,030,425 --
Other, net......................................... -- (37,520)
----------- -----------
NET CASH USED IN INVESTING ACTIVITIES................ 1,030,425 (1,236,007)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings............................... (824,316) 1,467,929
Payments on long-term debt......................... -- (1,553,471)
Dividends paid..................................... -- (68,879)
Common stock activity.............................. (206,109) 30,708
Treasury stock activity, net....................... -- 1,991
Cost of debt and equity transactions............... -- (6,728)
----------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES............ (1,030,425) (128,450)
----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS........................................ -- 16,261
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR....... -- 35,625
----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR............. $ -- $ 51,886
=========== ===========

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES............. $1,149,273 $ -- $(1,575) $ (29) $ 757,331
---------- ------- ------- --------- -----------
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to property and
equipment...................... (708,139) -- -- -- (820,845)
Acquisitions..................... (11,000) -- -- -- (911,951)
Proceeds from sales of oil and
gas properties................. 200,445 -- -- -- 147,851
Purchase of U.S. Government
Agency Notes................... -- -- -- -- (103,863)
Investment in and advances to
subsidiaries, net.............. (1,055,334) (5,568) (5,568) (250,849) (652,967)
Other, net....................... (17,564) -- -- -- (59,271)
---------- ------- ------- --------- -----------
NET CASH USED IN INVESTING
ACTIVITIES....................... (1,591,592) (5,568) (5,568) (250,849) (2,401,046)
---------- ------- ------- --------- -----------
CASH FLOWS FROM FINANCING
ACTIVITIES:
Long-term borrowings............. 2,783,409 -- 1,577 250,878 1,151,428
Payments on long-term debt....... (2,251,000) -- -- -- (482,641)
Dividends paid................... (54,492) -- -- -- --
Common stock activity............ 10,205 5,568 5,568 -- 531,598
Treasury stock activity, net..... (42,959) -- -- -- --
Cost of debt and equity
transactions................... (1,718) -- -- -- --
Proceeds from preferred interests
of subsidiaries................ -- -- -- -- 440,654
---------- ------- ------- --------- -----------
NET CASH PROVIDED BY FINANCING
ACTIVITIES....................... 443,445 5,568 7,145 250,878 1,641,039
---------- ------- ------- --------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................. 1,126 -- 2 -- (2,676)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR................ 5,257 -- -- -- 31,916
---------- ------- ------- --------- -----------
CASH AND CASH EQUIVALENTS AT END OF
YEAR............................. $ 6,383 $ -- $ 2 $ -- $ 29,240
========== ======= ======= ========= ===========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES............. $ -- $ 1,905,000
----------- -----------
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to property and
equipment...................... -- (1,528,984)
Acquisitions..................... -- (922,951)
Proceeds from sales of oil and
gas properties................. -- 348,296
Purchase of U.S. Government
Agency Notes................... -- (103,863)
Investment in and advances to
subsidiaries, net.............. 1,970,286 --
Other, net....................... -- (76,835)
----------- -----------
NET CASH USED IN INVESTING
ACTIVITIES....................... 1,970,286 (2,284,337)
----------- -----------
CASH FLOWS FROM FINANCING
ACTIVITIES:
Long-term borrowings............. (1,427,552) 2,759,740
Payments on long-term debt....... -- (2,733,641)
Dividends paid................... -- (54,492)
Common stock activity............ (542,734) 10,205
Treasury stock activity, net..... -- (42,959)
Cost of debt and equity
transactions................... -- (1,718)
Proceeds from preferred interests
of subsidiaries................ -- 440,654
----------- -----------
NET CASH PROVIDED BY FINANCING
ACTIVITIES....................... (1,970,286) 377,789
----------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................. -- (1,548)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR................ -- 37,173
----------- -----------
CASH AND CASH EQUIVALENTS AT END OF
YEAR............................. $ -- $ 35,625
=========== ===========

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2000

CASH PROVIDED BY (USED IN)
OPERATING
ACTIVITIES....................... $ 899,872 $ -- $ 250 $ 1,721 $ 615,525
---------- ------ ----- -------- ---------
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to property and
equipment...................... (579,856) -- -- -- (375,720)
Acquisitions..................... (760,566) -- -- -- (490,250)
Proceeds from sales of oil and
gas properties................. 10,853 -- -- -- 15,418
Investment in and advances to
subsidiaries, net.............. (472,778) -- (406) (27,084) (25,337)
Other, net....................... (15,380) -- -- -- (21,495)
---------- ------ ----- -------- ---------
NET CASH USED IN INVESTING
ACTIVITIES....................... (1,817,727) -- (406) (27,084) (897,384)
---------- ------ ----- -------- ---------
CASH FLOWS FROM FINANCING
ACTIVITIES:
Long-term borrowings............. 892,315 -- 156 202 712,347
Payments on long-term debt....... (361,925) -- -- -- (431,606)
Dividends paid................... (52,945) -- -- -- --
Issuance (repurchase) of
preferred stock................ (2,613) -- -- -- --
Common stock activity............ 465,306 -- -- 25,161 21,405
Treasury stock activity, net..... (17,730) -- -- -- --
Cost of debt and equity
transactions................... (838) -- -- -- --
---------- ------ ----- -------- ---------
NET CASH PROVIDED BY FINANCING
ACTIVITIES....................... 921,570 -- 156 25,363 302,146
---------- ------ ----- -------- ---------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................. 3,715 -- -- -- 20,287
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR................ 1,542 -- -- -- 11,629
---------- ------ ----- -------- ---------
CASH AND CASH EQUIVALENTS AT END OF
YEAR............................. $ 5,257 $ -- $ -- $ -- $ 31,916
========== ====== ===== ======== =========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

CASH PROVIDED BY (USED IN)
OPERATING
ACTIVITIES....................... $ -- $ 1,517,368
--------- -----------
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to property and
equipment...................... -- (955,576)
Acquisitions..................... -- (1,250,816)
Proceeds from sales of oil and
gas properties................. -- 26,271
Investment in and advances to
subsidiaries, net.............. 525,605 --
Other, net....................... -- (36,875)
--------- -----------
NET CASH USED IN INVESTING
ACTIVITIES....................... 525,605 (2,216,996)
--------- -----------
CASH FLOWS FROM FINANCING
ACTIVITIES:
Long-term borrowings............. (479,039) 1,125,981
Payments on long-term debt....... -- (793,531)
Dividends paid................... -- (52,945)
Issuance (repurchase) of
preferred stock................ -- (2,613)
Common stock activity............ (46,566) 465,306
Treasury stock activity, net..... -- (17,730)
Cost of debt and equity
transactions................... -- (838)
--------- -----------
NET CASH PROVIDED BY FINANCING
ACTIVITIES....................... (525,605) 723,630
--------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................. -- 24,002
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR................ -- 13,171
--------- -----------
CASH AND CASH EQUIVALENTS AT END OF
YEAR............................. $ -- $ 37,173
========= ===========

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

ASSETS
CURRENT ASSETS:
Cash and cash equivalents........ $ 224 $ -- $ 2 $ 127 $ 51,533
Receivables, net of allowance.... 121,410 -- -- -- 406,277
Inventories...................... 15,509 -- -- -- 93,695
Advances to oil and gas ventures
and others..................... 19,468 -- -- -- 58,536
Short-term investments........... -- -- -- -- --
---------- -------- -------- --------- ----------
156,611 -- 2 127 610,041
---------- -------- -------- --------- ----------
PROPERTY AND EQUIPMENT, NET........ 3,403,716 -- -- -- 5,061,869
---------- -------- -------- --------- ----------
OTHER ASSETS:
Intercompany receivable, net..... 1,146,086 -- (662) (253,851) (891,573)
Goodwill, net.................... -- -- -- -- 189,252
Equity in affiliates............. 2,994,954 142,422 402,596 958,382 (808,503)
Deferred charges and other....... 31,804 -- -- 2,472 3,957
---------- -------- -------- --------- ----------
$7,733,171 $142,422 $401,936 $ 707,130 $4,165,043
========== ======== ======== ========= ==========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable................. $ 124,152 $ -- $ -- $ -- $ 90,136
Other accrued expenses........... 134,191 -- 2,229 1,263 180,264
---------- -------- -------- --------- ----------
258,343 -- 2,229 1,263 270,400
---------- -------- -------- --------- ----------
LONG-TERM DEBT..................... 1,550,645 -- 268,795 297,019 42,356
---------- -------- -------- --------- ----------
DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Income taxes................... 736,661 -- (11,510) (1,205) 396,663
Advances from gas purchasers... 125,453 -- -- -- --
Oil and gas derivative
instruments.................. 3,507 -- -- -- --
Other.......................... 134,282 -- -- -- 24,044
---------- -------- -------- --------- ----------
999,903 -- (11,510) (1,205) 420,707
---------- -------- -------- --------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- -- -- -- 436,626
---------- -------- -------- --------- ----------
COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY............... 4,924,280 142,422 142,422 410,053 2,994,954
---------- -------- -------- --------- ----------
$7,733,171 $142,422 $401,936 $ 707,130 $4,165,043
========== ======== ======== ========= ==========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents........ $ -- $ 51,886
Receivables, net of allowance.... -- 527,687
Inventories...................... -- 109,204
Advances to oil and gas ventures
and others..................... -- 78,004
Short-term investments........... -- --
----------- ----------
-- 766,781
----------- ----------
PROPERTY AND EQUIPMENT, NET........ -- 8,465,585
----------- ----------
OTHER ASSETS:
Intercompany receivable, net..... -- --
Goodwill, net.................... -- 189,252
Equity in affiliates............. (3,689,851) --
Deferred charges and other....... -- 38,233
----------- ----------
$(3,689,851) $9,459,851
=========== ==========

LIABILITIES AND SHAREHOLDERS' EQUIT
CURRENT LIABILITIES:
Accounts payable................. $ -- $ 214,288
Other accrued expenses........... -- 317,947
----------- ----------
-- 532,235
----------- ----------
LONG-TERM DEBT..................... -- 2,158,815
----------- ----------
DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Income taxes................... -- 1,120,609
Advances from gas purchasers... -- 125,453
Oil and gas derivative
instruments.................. -- 3,507
Other.......................... -- 158,326
----------- ----------
-- 1,407,895
----------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- 436,626
----------- ----------
COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY............... (3,689,851) 4,924,280
----------- ----------
$(3,689,851) $9,459,851
=========== ==========

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
FOR THE YEAR ENDED DECEMBER 31, 2001

ASSETS
CURRENT ASSETS:
Cash and cash equivalents........ $ 6,383 $ -- $ 2 $ -- $ 29,240
Receivables, net of allowance.... 94,881 -- -- -- 309,912
Inventories...................... 17,024 -- -- -- 85,512
Advances to oil and gas ventures
and others..................... 24,644 -- -- -- 27,201
Short-term investments........... -- -- -- -- 102,950
---------- -------- -------- ---------- -----------
142,932 -- 2 -- 554,815
---------- -------- -------- ---------- -----------
PROPERTY AND EQUIPMENT, NET........ 3,098,485 -- -- -- 4,914,587
---------- -------- -------- ---------- -----------
OTHER ASSETS:
Intercompany receivable, net..... 1,426,455 -- (25) (251,025) (1,175,405)
Goodwill, net.................... -- -- -- -- 188,812
Equity in affiliates............. 2,566,969 103,577 369,691 1,082,328 (812,827)
Deferred charges and other....... 27,688 -- -- 2,564 3,771
---------- -------- -------- ---------- -----------
$7,262,529 $103,577 $369,668 $ 833,867 $ 3,673,753
========== ======== ======== ========== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable................. $ 75,164 $ -- $ -- $ -- $ 104,614
Other accrued expenses........... 165,858 -- 2,599 1,246 172,977
---------- -------- -------- ---------- -----------
241,022 -- 2,599 1,246 277,591
---------- -------- -------- ---------- -----------
LONG-TERM DEBT..................... 1,605,201 -- 268,615 296,988 73,553
---------- -------- -------- ---------- -----------
DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Income taxes................... 696,441 -- (5,123) 18 300,387
Advances from gas purchasers... 140,027 -- -- -- --
Other.......................... 161,355 -- -- -- 14,570
---------- -------- -------- ---------- -----------
997,823 -- (5,123) 18 314,957
---------- -------- -------- ---------- -----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- -- -- -- 440,683
---------- -------- -------- ---------- -----------
COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY............... 4,418,483 103,577 103,577 535,615 2,566,969
---------- -------- -------- ---------- -----------
$7,262,529 $103,577 $369,668 $ 833,867 $ 3,673,753
========== ======== ======== ========== ===========

RECLASSIFICATIONS
& ELIMINATIONS CONSOLIDATED
----------------- ------------
(IN THOUSANDS)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents........ $ -- $ 35,625
Receivables, net of allowance.... -- 404,793
Inventories...................... -- 102,536
Advances to oil and gas ventures
and others..................... -- 51,845
Short-term investments........... -- 102,950
----------- ----------
-- 697,749
----------- ----------
PROPERTY AND EQUIPMENT, NET........ -- 8,013,072
----------- ----------
OTHER ASSETS:
Intercompany receivable, net..... -- --
Goodwill, net.................... -- 188,812
Equity in affiliates............. (3,309,738) --
Deferred charges and other....... -- 34,023
----------- ----------
$(3,309,738) $8,933,656
=========== ==========

LIABILITIES AND SHAREHOLDERS' EQUIT
CURRENT LIABILITIES:
Accounts payable................. $ -- $ 179,778
Other accrued expenses........... -- 342,680
----------- ----------
-- 522,458
----------- ----------
LONG-TERM DEBT..................... -- 2,244,357
----------- ----------
DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Income taxes................... -- 991,723
Advances from gas purchasers... -- 140,027
Other.......................... -- 175,925
----------- ----------
-- 1,307,675
----------- ----------
PREFERRED INTERESTS OF
SUBSIDIARIES..................... -- 440,683
----------- ----------
COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY............... (3,309,738) 4,418,483
----------- ----------
$(3,309,738) $8,933,656
=========== ==========

F-57

BOARD OF DIRECTORS

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

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

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

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

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

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

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

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

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

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

CHARLES J. PITMAN(4)

Former Regional President -- Middle East/Caspian/ Egypt/India, BP Amoco plc;

Sole Member, Shaker Mountain Energy Associates, LLC

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

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

OFFICERS

RAYMOND PLANK
Chairman of the Board

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

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

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

RODNEY J. EICHLER
Executive Vice President

ROGER B. PLANK
Executive Vice President and Chief Financial Officer

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

LISA A. STEWART
Executive Vice President
Business Development and E&P Services

JON A. JEPPESEN
Senior Vice President

JEFFREY M. BENDER
Vice President -- Human Resources

MICHAEL J. BENSON
Vice President -- Security

THOMAS P. CHAMBERS
Vice President -- Corporate Planning

MATTHEW W. DUNDREA
Vice President and Treasurer

ROBERT J. DYE
Vice President -- Investor Relations

ERIC L. HARRY
Vice President and Associate General Counsel

P. ANTHONY LANNIE
Vice President and General Counsel

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

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

THOMAS L. MITCHELL
Vice President and Controller

JON W. SAUER
Vice President -- Tax

CHERI L. PEPER
Corporate Secretary

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(1) Executive Committee
(2) Audit Committee
(3) Management, Development & Compensation Committee
(4) Nominating Committee
(5) Stock Option Plan Committee

SHAREHOLDER INFORMATION

STOCK DATA

DIVIDENDS
PRICE RANGE* PER SHARE**
--------------- -----------------
HIGH LOW DECLARED PAID
------ ------ -------- ------

2002
First Quarter..................................... $27.72 $21.13 $.0475 $.0475
Second Quarter.................................... 28.62 25.04 .0475 .0475
Third Quarter..................................... 28.57 21.46 .0475 .0475
Fourth Quarter.................................... 28.88 23.55 .0475 .0475
2001
First Quarter..................................... $31.55 $23.47 $ -- $ --
Second Quarter.................................... 28.92 20.80 -- --
Third Quarter..................................... 23.55 16.56 .121 --
Fourth Quarter.................................... 23.87 17.57 .0475 .121

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

* Per share prices have been adjusted to reflect the effects of the ten percent
stock dividend in 2001, the five percent stock dividend in 2002 and the
two-for-one stock split in 2003.

** The amounts in the chart have been adjusted to reflect the ten percent stock
dividend in 2001, the five percent stock dividend in 2002 and the two-for-one
stock split in 2003.

The Company has paid cash dividends on its common stock for 36 consecutive
years through December 31, 2002. During 2000, the Company changed the dividend
payment schedule on its common stock from a quarterly basis to an annual basis;
however, during 2001, the Company implemented a return to a quarterly dividend
payment schedule beginning in 2002. Future dividend payments will depend upon
the Company's level of earnings, financial requirements and other relevant
factors.

Apache common stock is listed on the New York and Chicago stock exchanges
(symbol APA). At December 31, 2002, the Company's shares of common stock
outstanding were held by approximately 8,000 shareholders of record and 104,000
beneficial owners. Also listed on the New York Stock Exchange are:

- the Company's 9.25% notes, due 2002 (symbol APA 02)

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

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

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

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

Communications concerning the transfer of shares, lost certificates,
dividend checks, duplicate mailings or change of address should be directed to
the stock transfer agent.

DIVIDEND REINVESTMENT PLAN

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

ANNUAL MEETING

Apache will hold its annual meeting of shareholders on Thursday, May 1,
2003, at 10 a.m. in the Ballroom, Doubletree Hotel at Post Oak, 2001 Post Oak
Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live;
connect through the Apache web site: http://www.apachecorp.com.

STOCK HELD IN "STREET NAME"

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

FORM 10-K REQUEST

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

INVESTOR RELATIONS

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

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

WEB SITE: http://www.apachecorp.com

EXHIBIT INDEX

EXHIBIT
NO. DESCRIPTION
------- -----------

10.4 -- Credit Agreement, dated June 12, 1997, among Apache Canada
Ltd., a wholly-owned subsidiary of the Registrant, the
Lenders named therein, Morgan Guaranty Trust Company, as
Global Documentation Agent, Royal Bank of Canada, as
Canadian Documentation Agent, The Chase Manhattan Bank of
Canada, as Canadian Syndication Agent, Bank of Montreal, as
Canadian Administrative Agent, and The Chase Manhattan Bank,
as Global Administrative Agent (incorporated by reference to
Exhibit 10.2 to Registrant's Current Report on Form 8-K,
filed June 25, 1997, SEC File No. 1-4300).
10.5 -- Form of Credit Agreement, dated as of June 3, 2002, among
Apache Canada Ltd, a wholly-owned subsidiary of Registrant,
the Lenders named therein, JPMorgan Chase Bank, as Global
Administrative Agent, Bank of America, N.A., as Global
Syndication Agent, Citibank, N.A., as Global Documentation
Agent, Royal Bank of Canada, as Canadian Administrative
Agent, The Bank of Nova Scotia and The Toronto-Dominion
Bank, as Canadian Co-Syndication Agents, and BNP Paribas
(Canada) and Bayerische Landesbank Girozentrale, as Canadian
Co-Documentation Agents (excluding exhibits and schedules)
(incorporated by reference to Exhibit 10.4 to Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2002, SEC File No. 1-4300).
10.6 -- Credit Agreement, dated June 12, 1997, among Apache Energy
Limited and Apache Oil Australia Pty Limited, wholly-owned
subsidiaries of the Registrant, the Lenders named therein,
Morgan Guaranty Trust Company, as Global Documentation
Agent, Bank of America National Trust and Savings
Association, Sydney Branch, as Australian Documentation
Agent, The Chase Manhattan Bank, as Australian Syndication
Agent, Citisecurities Limited, as Australian Admin-
istrative Agent, and The Chase Manhattan Bank, as Global
Administrative Agent (incorporated by reference to Exhibit
10.3 to Registrant's Current Report on Form 8-K, filed June
25, 1997, SEC File No. 1-4300).
10.7 -- Form of Credit Agreement, dated as of June 3, 2002, among
Apache Energy Limited, a wholly-owned subsidiary of
Registrant, the Lenders named therein, JPMorgan Chase Bank,
as Global Administrative Agent, Bank of America, N.A., as
Global Syndication Agent, Citibank, N.A., as Global
Documentation Agent, Citisecurities Limited, as Australian
Administrative Agent, Bank of America, N.A., Sydney Branch,
and Deutsche Bank AG, Sydney Branch, as Australian Co-
Syndication Agents, and Royal Bank of Canada and Bank One,
NA, Australia Branch, as Australian Co-Documentation Agents
(excluding exhibits and schedules) (incorporated by
reference to Exhibit 10.5 to Registrant's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2002, SEC File
No. 1-4300).
10.8 -- Concession Agreement for Petroleum Exploration and
Exploitation in the Khalda Area in Western Desert of Egypt
by and among Arab Republic of Egypt, the Egyptian General
Petroleum Corporation and Phoenix Resources Company of
Egypt, dated April 6, 1981 (incorporated by reference to
Exhibit 19(g) to Phoenix's Annual Report on Form 10-K for
year ended December 31, 1984, SEC File No. 1-547).
10.9 -- Amendment, dated July 10, 1989, to Concession Agreement for
Petroleum Exploration and Exploitation in the Khalda Area in
Western Desert of Egypt by and among Arab Republic of Egypt,
the Egyptian General Petroleum Corporation and Phoenix
Resources Company of Egypt incorporated by reference to
Exhibit 10(d)(4) to Phoenix's Quarterly Report on Form 10-Q
for quarter ended June 30, 1989, SEC File No. 1-547).
10.10 -- Farmout Agreement, dated September 13, 1985 and relating to
the Khalda Area Concession, by and between Phoenix Resources
Company of Egypt and Conoco Khalda Inc (incorporated by
reference to Exhibit 10.1 to Phoenix's Registration
Statement on Form S-1, Registration No. 33-1069, filed
October 23, 1985).
10.11 -- Amendment, dated March 30, 1989, to Farmout Agreement
relating to the Khalda Area Concession, by and between
Phoenix Resources Company of Egypt and Conoco Khalda Inc
(incorporated by reference to Exhibit 10(d)(5) to Phoenix's
Quarterly Report on Form 10-Q for quarter ended June 30,
1989, SEC File No. 1-547).

EXHIBIT
NO. DESCRIPTION
------- -----------

10.12 -- Amendment, dated May 21, 1995, to Concession Agreement for
Petroleum Exploration and Exploitation in the Khalda Area in
Western Desert of Egypt between Arab Republic of Egypt, the
Egyptian General Petroleum Corporation, Repsol Exploracion
Egipto S.A., Phoenix Resources Company of Egypt and Samsung
Corporation (incorporated by reference to exhibit 10.12 to
Registrant's Annual Report on Form 10-K for year ended
December 31, 1997, SEC File No. 1-4300).
10.13 -- Concession Agreement for Petroleum Exploration and
Exploitation in the Qarun Area in Western Desert of Egypt,
between Arab Republic of Egypt, the Egyptian General
Petroleum Corporation, Phoenix Resources Company of Qarun
and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated
by reference to Exhibit 10(b) to Phoenix's Annual Report on
Form 10-K for year ended December 31, 1993, SEC File No.
1-547).
10.14 -- Agreement for Amending the Gas Pricing Provisions under the
Concession Agreement for Petroleum Exploration and
Exploitation in the Qarun Area, effective June 16, 1994
(incorporated by reference to Exhibit 10.18 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1996,
SEC File No. 1-4300).
+10.15 -- Apache Corporation Corporate Incentive Compensation Plan A
(Senior Officers' Plan), dated July 16, 1998 (incorporated
by reference to Exhibit 10.13 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1998, SEC File No.
1-4300).
+10.16 -- Apache Corporation Corporate Incentive Compensation Plan B
(Strategic Objectives Format), dated July 16, 1998
(incorporated by reference to Exhibit 10.14 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.17 -- Apache Corporation 401(k) Savings Plan, dated August 1, 2002
(incorporated by reference to Exhibit 10.1 to Registrant's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002, SEC File No. 1-4300).
+**10.18 -- Amendment to Apache Corporation 401(k) Savings Plan, dated
January 27, 2003, effective as January 1, 2003.
+10.19 -- Apache Corporation Money Purchase Retirement Plan, dated
August 1, 2002 (incorporated by reference to Exhibit 10.2 to
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2002, SEC File No. 1-4300).
+**10.20 -- Amendment to Apache Corporation Money Purchase Retirement
Plan, dated January 27, 2003, effective as of January 1,
2003.
+10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation,
restated as of January 1, 1997, and amendments effective as
of January 1, 1997, January 1, 1998 and January 1, 1999
(incorporated by reference to Exhibit 10.17 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache
Corporation, dated February 22, 2000, effective as of
January 1, 1999 (incorporated by reference to Exhibit 4.7 to
Registrant's Registration Statement on Form S-8,
Registration No. 333-31092, filed February 25, 2000); and
Amendment dated July 27, 2000 (incorporated by reference to
Exhibit 4.8 to Post-Effective Amendment No. 1 to
Registrant's Registration Statement on Form S-8,
Registration No. 333-31092, filed August 18, 2000).
+10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache
Corporation, dated August 3, 2001, effective as of September
1, 2000 and July 1, 2001 (incorporated by reference to
Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended June 30,
2001, SEC File No. 1-4300).
+10.24 -- Apache Corporation 1990 Stock Incentive Plan, as amended and
restated September 13, 2001, (incorporated by reference to
Exhibit 10.01 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).
+10.25 -- Apache Corporation 1995 Stock Option Plan, as amended and
restated September 13, 2001, (incorporated by reference to
Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).

EXHIBIT
NO. DESCRIPTION
------- -----------

+**10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended
and restated February 5, 2003, effective as of March 12,
2003.
+10.27 -- Apache Corporation 1996 Performance Stock Option Plan, as
amended and restated September 13, 2001 (incorporated by
reference to Exhibit 10.03 to Registrant's Quarterly Report
on Form 10-Q, as amended by Form 10-Q/A, for the quarter
ended September 30, 2001, SEC File No. 1-4300).
+10.28 -- Apache Corporation 1998 Stock Option Plan, as amended and
restated September 13, 2001 (incorporated by reference to
Exhibit 10.04 to Registrant's Quarterly Report on Form 10-Q,
as amended by Form 10-Q/A, for the quarter ended September
30, 2001, SEC File No. 1-4300).
+10.29 -- Apache Corporation 2000 Stock Option Plan, as amended and
restated March 5, 2003 (incorporated by reference to Exhibit
4.5 to Registrant's Registration Statement on Form S-8,
Registration No. 333-103758, filed March 12, 2003).
+10.30 -- 1990 Employee Stock Option Plan of The Phoenix Resource
Companies, Inc., as amended through September 29, 1995,
effective April 9, 1990 (incorporated by reference to
Exhibit 10.33 to Registrant's Annual Report on Form 10-K for
year ended December 31, 1996, SEC File No. 1-4300).
+10.31 -- Apache Corporation Income Continuance Plan, as amended and
restated May 3, 2001 (incorporated by reference to Exhibit
10.30 to Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, SEC File No. 1-4300).
+10.32 -- Apache Corporation Deferred Delivery Plan, as amended and
restated December 18, 2002, effective as of May 2, 2002
(incorporated by reference o Exhibit 4.5 to Post-Effective
Amendment No. 2 to Registrant's Registration Statement on
Form S-8, Registration No. 333-31092, filed March 11, 2003).
+10.33 -- Apache Corporation Executive Restricted Stock Plan, as
amended and restated December 18, 2002, effective as of May
2, 2002 (incorporated by reference to Exhibit 4.5 to
Post-Effective Amendment No. 1 to Registrant's Registration
Statement on Form S-8, Registration No. 333-97403, filed
December 30, 2002).
+10.34 -- Apache Corporation Non-Employee Directors' Compensation
Plan, as amended and restated December 17, 1998
(incorporated by reference to Exhibit 10.26 to Registrant's
Annual Report on Form 10-K for year ended December 31, 1998,
SEC File No. 1-4300).
+10.35 -- Apache Corporation Outside Directors' Retirement Plan, as
amended and restated May 3, 2001 (incorporated by reference
to Exhibit 10.08 to Registrant's Quarterly Report on Form
10-Q, as amended by Form 10-Q/A, for the quarter ended June
30, 2001, SEC File No. 1-4300).
+10.36 -- Apache Corporation Equity Compensation Plan for Non-Employee
Directors, as amended and restated May 3, 2001 (incorporated
by reference to Exhibit 10.09 to Registrant's Quarterly
Report on Form 10-Q, as amended by Form 10-Q/A, for the
quarter ended June 30, 2001, SEC File No. 1-4300).
+10.37 -- Amended and Restated Employment Agreement, dated December 5,
1990, between Registrant and Raymond Plank (incorporated by
reference to Exhibit 10.39 to Registrant's Annual Report on
Form 10-K for year ended December 31, 1996, SEC File No.
1-4300).
+10.38 -- First Amendment, dated April 4, 1996, to Restated Employment
Agreement between Registrant and Raymond Plank (incorporated
by reference to Exhibit 10.40 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1996, SEC File No.
1-4300).
+10.39 -- Amended and Restated Employment Agreement, dated December
20, 1990, between Registrant and John A. Kocur (incorporated
by reference to Exhibit 10.10 to Registrant's Annual Report
on Form 10-K for year ended December 31, 1990, SEC File No.
1-4300).
+10.40 -- Employment Agreement, dated June 6, 1988, between Registrant
and G. Steven Farris (incorporated by reference to Exhibit
10.6 to Registrant's Annual Report on Form 10-K for year
ended December 31, 1989, SEC File No. 1-4300).
+10.41 -- Amended and Restated Conditional Stock Grant Agreement,
dated June 6, 2001, between Registrant and G. Steven Farris
(incorporated by reference to Exhibit 10.10 to Registrant's
Quarterly Report by Form 10-Q, as amended on Form 10-Q/A,
for the quarter ended June 30, 2001, SEC File No. 1-4300).

EXHIBIT
NO. DESCRIPTION
------- -----------

10.42 -- Amended and Restated Gas Purchase Agreement, effective July
1, 1998, by and among Registrant and MW Petroleum
Corporation, as seller, and Producers Energy Marketing, LLC,
as buyer (incorporated by reference to Exhibit 10.1 to
Registrant's Current Report on Form 8-K, filed June 23,
1998, SEC File No. 1-4300).
10.43 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made
by Registrant in favor of BP Exploration Operating Company
Limited (incorporated by reference to Exhibit 10.1 to Regis-
trant's Current Report on Form 8-K, filed January 13, 2003,
SEC File No. 1-4300).
**12.1 -- Statement of Computation of Ratios of Earnings to Fixed
Charges and Combined Fixed Charges and Preferred Stock
Dividends
**21.1 -- Subsidiaries of Registrant
*23.1 -- Consent of Ernst & Young LLP
**23.2 -- Consent of Ryder Scott Company L.P., Petroleum Consultants
**24.1 -- Power of Attorney (included as a part of the signature pages
to this report)
*31.1 -- Certification of Chief Executive Officer
*31.2 -- Certification of Chief Financial Officer
*32.1 -- Certification of Chief Executive Officer and Chief Financial
Officer

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

* Filed herewith.

**Previously filed.

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