APACHE CORP - 10-K Annual Report

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

FORM 10-K

(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001,
OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-4300

APACHE CORPORATION
A DELAWARE CORPORATION IRS EMPLOYER NO. 41-0747868

ONE POST OAK CENTRAL
2000 POST OAK BOULEVARD, SUITE 100
HOUSTON, TEXAS 77056-4400
TELEPHONE NUMBER (713) 296-6000

Securities Registered Pursuant to Section 12(b) of the Act:

Securities registered Pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No[ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

Aggregate market value of the voting stock held by
non-affiliates of registrant as of February 28, 2002...... $7,239,122,196
Number of shares of registrant's common stock outstanding as
of February 28, 2002...................................... 137,234,544

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of registrant's proxy statement relating to registrant's 2002
annual meeting of stockholders have been incorporated by reference into Part III
hereof.
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TABLE OF CONTENTS

DESCRIPTION

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

PART I

ITEM 1. BUSINESS

GENERAL

Apache Corporation, a Delaware corporation formed in 1954, is an
independent energy company that explores for, develops and produces natural gas,
crude oil and natural gas liquids. In North America, our exploration and
production interests are focused in the Gulf of Mexico, the Gulf Coast, the
Permian Basin, the Anadarko Basin and the Western Sedimentary Basin of Canada.
Outside of North America we have exploration and production interests offshore
Western Australia, Egypt and Argentina, and exploration interests in Poland and
offshore The People's Republic of China. Our common stock, par value $1.25 per
share, has been listed on the New York Stock Exchange since 1969, and on the
Chicago Stock Exchange since 1960.

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.

2001 RESULTS

Despite the turmoil in the economy, financial markets and the energy
industry, Apache ended the year larger, stronger and in a better position to
continue to meet the challenges of the future. Although commodity prices
weakened through the year, Apache's rising production profile fueled record
income attributable to common stock of $704 million on total revenues of $2.8
billion. Net cash provided by operating activities during 2001 was $1.9 billion,
a 27 percent increase from 2000.

In addition to our financial records, Apache turned in another record year
on many operational fronts. We enjoyed our 24th consecutive year of production
growth (up 32 percent), the largest year-over-year percentage increase in a
decade. Our average daily production for the year was 156.3 Mbbls of oil and
natural gas liquids and 1,127.3 MMcf of natural gas. For the first time, more
than half of Apache's production was derived from operations outside of the
United States - the result of our decision over a decade ago to begin allocating
a portion of our cash flow to international growth.

Production and reserve growth were the result of our strategy to take a
disciplined approach to controlling costs and growing through the most efficient
method given prevailing market conditions. As a result, during 2001 Apache grew
through a combination of successful exploitation of our existing asset base,
exploration activities and prudent acquisitions in core areas worldwide. All
told, Apache spent approximately $2.6 billion on acquisitions, exploration and
development, replacing 314 percent of production at a competitive all-in finding
and acquisition cost. Reserves per share (diluted), an important measure of the
company's strength, increased 16 percent to 8.77 boe per share.

Our balance sheet remained strong despite record capital spending. We
exited the year with debt (including preferred interests of subsidiaries and net
of cash and cash equivalents and short-term investments) at 37 percent of total
capitalization, even with year-end 2000. We also maintained a senior unsecured
long-term debt rating of A3 from Moody's, and A- from Standard and Poor's and
Fitch rating agencies.

Per share results have been adjusted for the 10 percent common stock
dividend declared on September 13, 2001, and paid on January 21, 2002 to our
shareholders of record on December 31, 2001. The stock dividend - as well as an
increase in the quarterly dividend from six cents per common share (seven cents
prior to the 10 percent stock dividend) to 10 cents per share - reflected the
judgment of the board of directors that shareholders should participate more
fully in Apache's progress.

1

OUR GROWTH STRATEGY

Our growth strategy is to increase 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 value, and investing in
high-potential exploration prospects. In order to maximize financial flexibility
during a period of highly volatile natural gas prices coupled with a faltering
U.S. economy, Apache's present plans are to reduce 2002 worldwide capital
expenditures for exploratory and development drilling to approximately $590
million, down from the $1.4 billion we spent in 2001. Any excess cash flow will
be used to reduce debt until such time as we elect either to increase drilling
expenditures should the commodity price environment improve, or to pursue
acquisition opportunities should they become available at reasonable prices.

For our existing assets, we seek to maximize value by increasing production
and reserves while controlling per unit operating costs. Achieving these
objectives requires rigorous pursuit of production enhancement opportunities and
moderate risk drilling, while divesting marginal and non-strategic properties
and pursuing other activities to reduce costs. Given the significant
acquisitions completed over the past two years, our inventory of exploitation
opportunities has never been larger. During 2001, our drilling and production-
enhancement program yielded 828 new gross producing wells out of 939 attempts
and involved 1,350 major North American workover and recompletion projects.

In acquiring new assets, we avoid competitive auctions, choosing instead to
pay appropriate market prices in negotiated deals where we have a higher
likelihood of completing transactions. Our aim is to follow each acquisition
with a cycle of reserve enhancement, property consolidation and cash flow
acceleration, facilitating asset growth and debt reduction. We made acquisitions
totaling $1.2 billion and $1.4 billion in 2001 and 2000, respectively. Recently,
exorbitant acquisition prices have caused Apache to sideline its acquisition
activities until appropriate opportunities arise at more reasonable prices.

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

We prefer to operate our properties so that we can best influence their
development. As a result, we operate properties accounting for over 85 percent
of our production.

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 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. In the U.S., our exploration and
production activities were diversified among three regions: Offshore,
Midcontinent and Southern. In 2002, we consolidated our three U.S. regions into
two regions, Central and Gulf Coast. The new Central region will include the
properties in our Midcontinent region and our interests in the Permian Basin.
The Gulf Coast region will include our onshore Gulf Coast and Gulf of Mexico
properties. Outside the U.S., our exploration and production activities are
focused primarily in Canada, Egypt and Australia. Additionally, we have a
development project underway in China that is expected to commence production in
2003, and have a small production interest in Argentina as a result of
acquisition activity in 2001. We also own exploration acreage in Poland.

2

The table below sets out a brief comparative summary of certain 2001 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 2001, 2000 and 1999 for the core geographic areas is available in
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 of this Form 10-K. In addition, information concerning the
amount of revenue, expenses, operating income (loss) and total assets
attributable to each of the same geographic areas is set forth in Note 15,
Supplemental Oil and Gas Disclosures (Unaudited), and Note 14, Business Segment
Information, both under Item 14 of this Form 10-K.

United States

In the U.S. we had our most active drilling year ever. We completed 369 out
of 419 total wells and replaced 134 percent of our production through drilling.
Our continuing goal is to drill quality prospects in and around our large
domestic reserve and production bases, albeit at an expected slower pace in
2002.

Offshore -- The Offshore region comprises our interests in the Gulf of
Mexico, primarily in the areas offshore Louisiana and Texas. In 2001, the
Offshore region was our leading region for production volumes and revenues. The
Company performed 135 workover and recompletion operations during 2001 in the
Offshore region and completed 47 out of 57 total wells drilled. As of year end
2001, Offshore accounted for 14.8 percent of our estimated proved reserves. In
2002, we currently plan on spending approximately $100 million to drill 17 wells
and to continue our production enhancement program.

Southern -- The Southern region includes assets in the Permian Basin of
western Texas and New Mexico, the San Juan Basin of New Mexico, central Texas
and the Texas and Louisiana coasts. At year-end 2001, the Southern region
accounted for 24 percent of our estimated proved reserves, the second largest in
the company. During 2001, we participated in 230 wells, 210 of which were
completed as productive wells, replacing 225 percent of our production. Apache
performed 695 workovers and recompletions in the region during the year. In
2002, we currently plan to spend approximately $60 million drilling 135 wells
and on our production enhancement programs.

MidContinent -- The Midcontinent region operates in Oklahoma, eastern and
northern Texas, Arkansas and northern Louisiana. The region has focused on its
sizable position in the Anadarko Basin of western Oklahoma. Apache has drilled
and operated in the Anadarko Basin for over four decades, developing an
extensive database of geologic information and a substantial acreage position.
The region accounted for

3

8.6 percent of our estimated proved reserves at year-end. Apache participated in
132 wells during the year, 112 of them were producers. We also performed 65
workover and recompletion operations in the region during 2001. We currently
plan to spend approximately $40 million on an estimated 44 wells and production
exploitation programs in 2002.

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 ten year period, with an option by both parties, after
prior notice, to terminate after six years, and 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 most of 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. The prices received for its gas production under this agreement
approximate market prices. 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, a recent audit. 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.

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 2001 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 our U.S. production 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 are subject
to change due to market conditions.

Canada

Our exploration and development activity in the Canadian region is
concentrated in the Provinces of Alberta, British Columbia and Saskatchewan. The
region comprises 28 percent of our estimated proved reserves, the largest in the
Company. We hold over 3 million net acres in Canada, the largest of the North
American regions and second largest in the Company.

2001 -- In March, we completed the acquisition of subsidiaries of Fletcher
Challenge Energy (Fletcher) which included properties located primarily in
Canada's Western Sedimentary Basin with estimated proved reserves of 120.8 MMboe
as of the acquisition date. We assumed a $103 million liability representing the
fair value of derivative instruments and fixed-price commodity contracts entered
into by Fletcher.

Canada was also our most active region for drilling, with Apache
participating in 447 gross wells, 416 of which were completed as producers. We
also conducted 455 workover and recompletion projects. In fact, we drilled more
wells in Canada in 2001 than we had in all previous years since we entered
Canada. We replaced 242 percent of our Canadian production through drilling and
680 percent of our production from all sources.

2002 -- We currently plan to spend approximately $150 million to drill 39
exploratory and appraisal wells, continue exploitation of properties from our
significant acquisitions over recent years and continue development of our gas
processing infrastructure. At our important Ladyfern development, Apache's share
of production was approximately 100 MMcf per day at the end of 2001, and we
expect further gains in 2002.

Marketing -- Our Canadian natural gas sales include sales to supply
aggregators, to whom we dedicate reserves, and direct sales to brokers and
end-users in the United States and Canada. With the expansion of export capacity
out of Canada in recent years, Canadian prices have strengthened and become
highly
4

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 (6 MMcf/d). 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 5,000 MMbtu/d into
Michigan over a 10-year term. The prices we receive under these contracts are
generally based on market indices.

Oil produced from our Canadian properties is 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 we and our non-governmental co-venturers 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 us and
our co-venturers to recover all our operating and capital costs. The balance of
the production is split with our co-venturers and the Egyptian General Petroleum
Corporation (EGPC) on a contractually defined basis. Apache is the largest
leaseholder in Egypt and the most active driller in the Western Desert. It is
the country with our largest single acreage position and, as of December 31,
2001, we held over 9 million net acres. Total exploratory acreage encompasses 14
concessions (13 operated). Apache is the largest producer of liquid hydrocarbons
and the second largest producer of natural gas in the Western Desert. Apache
operates 10 percent of Egypt's daily oil and gas output.

2001 -- Egypt accounted for 17 percent of our production revenues on 16
percent of our production for the year and accounted for 12.4 percent of our
total estimated proved reserves at December 31, 2001.

The big news in Egypt in 2001 was that we completed two significant
acquisitions. The first was the purchase of approximately 66 MMboe of estimated
proved reserves from Repsol YPF (Repsol), with the main asset in the package
being an additional 50 percent interest and operatorship of the Khalda
concession. This purchase added net production of approximately 60 MMcf/d and
14,000 Bbls/d. Additionally, in November, we completed the acquisition of Novus
Bukha Limited's (Novus) oil and gas concession interests in three Western Desert
concessions including Khalda, where we now own a 100 percent interest. The
acquisition included estimated proved reserves of approximately 11.7 MMboe as of
the acquisition date.

On the exploration front, we had an active drilling year in Egypt,
completing 30 of 43 wells, a success rate of nearly 70 percent, and replacing
129 percent of production through drilling additions. Our drilling finding cost
in Egypt was $4.92/boe. At the Northeast Abu Gharadig Concession in the Western
Desert, the JG-1X, which is operated by Shell Egypt, tested approximately 4,190
b/d and 5 MMcf/d and should be producing in the first half of 2002. Apache has a
48 percent contractor interest in the 2.4-million-acre concession. Apache and
Shell Egypt have identified several potential offset locations. At West
Mediterranean, we developed a gas condensate field onshore, the Akik, which was
discovered in 2000 and is currently producing approximately 8 MMcf/d and 1,400
barrels of condensate per day. In addition to the Akik, we have oil production
of 2,500 Bbls/d in the onshore West Mediterranean area.

2002 -- We made two noteworthy discoveries in Egypt early in 2002 at Khalda
Offset and the South Umbarka development lease. At Khalda Offset, the Ozoris-1X
discovery tested approximately 2,500 b/d. It is six miles from the Khalda Ridge,
a regional high that runs through the area and has estimated reserves of over
200 MMboe discovered to date. We are actively searching for additional
opportunities between Ozoris and the Ridge. At South Umbarka, in which Apache
holds a 100 percent contractor interest, the Khepri 9 discovery tested
approximately 29.5 MMcf/d and 220 barrels of liquids per day. In Egypt, we
currently plan to spend approximately $53 million to drill 29 exploration and
appraisal wells on nine concessions and 27 development wells, primarily in the
Khalda complex. We are also preparing to drill Apache's first deepwater well in
the offshore portion of our West Mediterranean concession. We plan to spend
another estimated $69 million on production enhancements and production
facilities during 2002.

5

Marketing -- In 1996, we and our partners in the Khalda Block in Egypt
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.
Sales of gas under the contract began in 1999 upon completion of a gas pipeline
from the Khalda Block. In late 1997, the same sellers entered into a supplement
to the contract with EGPC to sell an additional 50 MMcf/d. The Repsol
acquisition discussed above transferred operatorship of the Khalda gas
processing plants at Salam and Tarek to us. Gas sales from the contract are
based on a price that is the energy equivalent of 85 percent of the price of
Suez Blend crude oil, FOB Mediterranean port. In 2000, EGPC reduced the price
for certain quantities of gas purchased from other producers. 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 any of our existing gas sales contracts; however, new gas sales contracts
may be impacted.

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 Kherir 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), which is applied to virtually all production from
the area. 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 for
the foreseeable future. Deteriorating economic conditions during 2001 in Egypt
have lessened the availability of U.S. dollars, resulting in a gradual decline
in timeliness of receipts from EGPC.

Australia

In 2001, we produced 15.7 MMboe in Australia (13 percent of our total)
generating $258 million of production revenues. Estimated proved reserves in
Australia were 12.2 percent of our year-end total. We had a very strong
exploration year in Australia, with discoveries at Simpson, Gibson and South
Plato in the first quarter of the year. Production from the Simpson oil field
was brought on line in November and the Gibson and South Plato developments are
expected to begin around mid-2002 at an estimated rate of 10,000 barrels of oil
per day. In total, we completed 12 out of the 24 wells we drilled at a finding
cost of $5.16 per boe. On the development side, we had three discoveries begin
producing in 2001. The Gypsy/North Gypsy (68.5 percent interest) field began
producing late in the first quarter while the Legendre field (31.5 percent
interest) began producing in mid-May. As discussed above, oil production from
the Simpson field (68.5 percent interest) commenced in November of 2001.

In February, 2002, we announced our fourth commercial discovery in the past
12 months in the Carnarvon Basin offshore Western Australia. Apache owns a 68.5
percent working interest in the Double Island discovery and engineering efforts
are underway for the purpose of completing the development in late 2002. For
2002, in Australia, we have budgeted expenditures of approximately $71 million
for 19 exploration wells, three development wells and various production
development and enhancement projects.

Marketing -- In Australia we entered into three gas sales contracts during
2001, bringing our total to 23 contracts. In total, AEL committed a further 26
Bcf for delivery over the next three to 10 years. Our total Australian delivery
rates are expected to average approximately 110 MMcf/d in 2002, excluding spot
sales. As a result of minimum price contracts which escalate at an average of 80
percent of the Australian consumer price index, AEL's natural gas production in
Western Australia is not as subject to price volatility as is our U.S. and
Canadian gas production.

6

Other International

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

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. During 2001, work commenced with the
awarding of contracts for development drilling and the construction of
production facilities in accordance with the approved overall development plan.
First production is expected in 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 in Poland
from FX Energy, Inc. At year-end 2001, we had 735,762 net undeveloped acres in
Poland. In 2002, we will continue our efforts to reach agreement with the Polish
Oil and Gas Company to explore more prospective acreage with them and/or buy
producing or proved undeveloped assets. We will also continue engineering
efforts for commercial development at the Wilga discovery.

In 2001, we recorded an impairment to our properties in China and Poland,
which is described in Item 7 of this Form 10-K.

In 2001, we acquired exploration and production assets of Fletcher and
Anadarko Petroleum in Argentina. As a result of these transactions, 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 was 367,690 acres with 9,510 developed and 358,180
undeveloped at year-end 2001. In 2002, we have tentatively budgeted
approximately $2.6 million of expenditures for Argentina, primarily for drilling
three commitment wells on non-operated blocks and workover activity. Due to the
present uncertainty facing the Argentine economy, Apache will maintain a
defensive posture until improvement is evident. Our staff will concentrate on
identifying opportunities and strategies for growth that can be implemented when
Argentina's political and economic conditions improve.

DRILLING STATISTICS

Worldwide, in 2001, we participated in drilling 939 gross new wells, with
828 (88 percent) completed as producers. Canada was the most active region,
drilling 447 gross new wells with a success rate of 93 percent. We also
performed over 1,350 major workovers and recompletions in North America during
the year. Our drilling activities in the United States generally concentrate on
further development of existing, producing fields rather than exploration. As a
general matter, our international and Canadian drilling activities focus on more
exploration drilling than do our U.S. activities. In addition to our completed
wells, as of the end of the year, we were participating in the drilling of
several wells that had not yet reached completion: two in the U.S. (1.67 net),
six in Canada (5.7 net), three in Egypt (3 net) and one in Australia (.7 net).

7

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

PRODUCTIVE OIL AND GAS WELLS

The number of productive oil and gas wells, operated and non-operated, in
which we had an interest as of December 31, 2001, is set forth below:

8

GROSS AND NET UNDEVELOPED AND DEVELOPED ACREAGE

The following table sets out our gross and net acreage position in each
country where we have operations.

ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS

As of December 31, 2001, Apache had total estimated proved reserves of 599
million barrels of crude oil, condensate and NGLs and 4 Tcf of natural gas.
Combined, these total estimated proved reserves are equivalent to 1.3 billion
barrels of oil or 7.6 Tcf of gas. The company's reserves have grown for the 16th
consecutive year. Estimated proved developed reserves comprise 75 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, 2001, 2000 and 1999, changes in proved reserves during the last
three years, and estimates of future net cash flows and discounted future net
cash flows from proved reserves are contained in Footnote 15, Supplemental Oil
and Gas Disclosures (Unaudited), in the Apache Corporation 2001 Consolidated
Financial Statements under Item 14 of this Form 10-K.

Proved oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and NGLs which 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 which 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.

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.

9

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

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

SUBSTANTIAL COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS

We, as an owner or lessee and operator of oil and gas properties, are
subject to various federal, provincial, state, local and foreign country laws
and regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability on the lessee under an oil and gas lease for the cost of pollution
clean-up resulting from operations, subject the lessee to liability for
pollution damages, and require suspension or cessation of operations in affected
areas.

We maintain insurance coverage, which we believe is customary in the
industry, although we are not fully insured against all environmental risks. We
are not aware of any environmental claims existing as of December 31, 2001,
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, our principal 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

10

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

From time to time we acquire oil and gas properties. Although we perform a
review of the acquired properties that we believe is consistent with industry
practices, such reviews are inherently incomplete. It generally is not feasible
to review in depth every individual property involved in each acquisition.
Ordinarily, we will focus our review efforts on the higher-value properties and
will sample the remainder. However, even a detailed review of records and
properties may not necessarily reveal existing or potential problems, nor will
it permit a buyer to become sufficiently familiar with the properties to assess
fully their deficiencies and potential. Inspections may not always be performed
on every well, and environmental problems, such as ground water contamination,
are not necessarily observable even when an inspection is undertaken. Even when
problems are identified, we often assume certain environmental and other risks
and liabilities in connection with acquired properties. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs with respect to acquired
properties, and actual results may vary substantially from those assumed in the
estimates (see above). In addition, there can be no assurance that acquisitions
will not have an adverse effect upon our operating results, particularly during
the periods in which the operations of acquired businesses are being integrated
into our ongoing operations.

EMPLOYEES

On December 31, 2001, we had 1,915 employees.

OFFICES

Our principal executive offices are located at One Post Oak Central, 2000
Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2001, 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.

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, please 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, please see the
information in Item 1 under Drilling Statistics, Productive Oil and Gas Wells
and Gross and Net Undeveloped Acreage.

11

ITEM 3. LEGAL PROCEEDINGS

The information set forth under the caption "Commitments and Contingencies"
in Note 11 to our financial statements under Item 14 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 2001.

PART II

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

Apache common stock, par value $1.25 per share, is traded on the New York
Stock Exchange and the Chicago Stock Exchange under the symbol APA. The table
below provides certain information regarding our common stock for 2001 and 2000.
Prices were obtained from the New York Stock Exchange Composite Transactions
Reporting System; however, the per share prices and dividends shown in the
following table have been adjusted to reflect the 10-percent stock dividend
described below and have been rounded to the indicated decimal place.

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

(1) We paid dividends of $.25 per share in 2000, of which $.19 was declared in
2000 and $.06 was declared in the fourth quarter of 1999, as a result of
changing our dividend payment schedule from a quarterly basis to an annual
basis.

The closing price per share of our common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for February 28,
2002, was $52.75. At February 28, 2002, there were 137,234,544 shares of our
common stock outstanding held by approximately 9,000 shareholders of record and
approximately 110,000 beneficial owners.

We have paid cash dividends on our common stock for 35 consecutive years
through December 31, 2001. 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, during 2001, we 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 .9 "preferred stock purchase
right" (adjusted for the 10-percent stock dividend) for each outstanding share
of common stock 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

12

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 are traded on the New York Stock Exchange and the Chicago Stock Exchange.
The Series C Preferred Stock is not subject to a sinking fund or mandatory
redemption. On May 15, 2002, each depositary share will automatically convert,
subject to adjustments, into not more than 1.099 shares and not less than 0.9016
of a share of our common stock, depending on the market price of the common
stock at that time. In 2000, we 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. At any time prior to May 15, 2002, holders of the depositary shares
may elect to convert each of their shares, subject to adjustments, into not less
than 0.9016 of a share of our common stock (6,242,769 common shares). Holders of
the depositary shares are entitled to receive cumulative cash dividends at an
annual rate of $2.015 per depositary share when, and if, declared by our board
of directors.

On September 13, 2001, our board of directors declared a 10-percent
dividend on our shares of common stock payable in common stock on January 21,
2002 to shareholders of record on December 31, 2001. Pursuant to the terms of
the declared stock dividend, we issued 12,447,684 shares of our common stock on
January 21, 2002 to the holders of the 124,655,495 shares 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.

The following updated financial information concerning the 10-percent stock
dividend is as of December 31, 2001, and is provided as required under the
regulations of The New York Stock Exchange, Inc.:

Amount capitalized in the aggregate (in thousands).......... $544,871
Amount capitalized per share................................ 42.51
Relation of aggregate amount to current earnings............ 77%
Relation of aggregate amount to retained earnings........... 29%
Accounts to which aggregate amount was charged and credited:
Decrease in retained earnings (in thousands).............. $544,871
Increase in common stock (in thousands)................... 16,022
Increase in additional paid-in capital (in thousands)..... 528,849

Although this 10-percent stock dividend increased the outstanding shares of
our common stock by 12,447,684 shares, it does not change any shareholder's
proportionate equity interest in Apache. However, a sale by a shareholder of all
or part of the shares received for this stock dividend will reduce such
shareholder's proportionate equity in us.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and
its consolidated subsidiaries for each of the years in the five-year period
ended December 31, 2001, which information has been derived from the Company's
audited financial statements. 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 under Item 14 below.

For a discussion of significant acquisitions, refer to Note 3 to the
Company's consolidated financial statements under Item 14 below. During 1998,
the Company recorded $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 due to ceiling test limitations.

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

OVERVIEW

In 2001, Apache turned in another record year on many operational and
financial fronts, the result of our strategy of pursuing growth through a
combination of drilling and acquisition activities in core areas worldwide. The
results were achieved in a year marked with turmoil in the economy, financial
markets and the energy industry. In January, natural gas prices neared $10 per
thousand cubic feet (Mcf), only to fall below $2 per Mcf in October. Although
commodity prices weakened through the year, Apache's rising production profile
fueled record income attributable to common stock and record cash from operating
activities of $704 million and $1.9 billion, respectively.

Throughout the year, we remained focused on increasing our production and
building our reserves at reasonable costs. Our production grew for the 24th
consecutive year, rising 32 percent, to 344,130 barrels of oil equivalent per
day (boe/d), the largest year-over-year percentage increase in a decade. Our
fourth quarter average daily production exceeded 362,000 boe/d, pointing to a
strong start for 2002. Our strategy put in place over a decade ago to seek
opportunities outside the U.S., is paying off for shareholders; for the first
time in our history, over half of our equivalent production came from outside
the U.S., adding to the Company's stability. Additionally, our record reserves
increased for the 16th consecutive year (by 17 percent) to 1.3 billion boe.

Production and reserve growth was driven by successful drilling activities
in Canada and Australia, and strategic acquisitions in Canada and Egypt.
Development activities at the Ladyfern field in Canada, which was discovered on
acreage acquired from Shell Canada in 1999, contributed 12 percent of the
company-wide

14

increase in gas production. In Australia, drilling and development activity at
the Legendre, Gipsy/North Gipsy and Simpson fields accounted for approximately
one-third of our worldwide oil production increase. Worldwide, we spent
approximately $1.4 billion on exploration and development and completed over
$1.2 billion of acquisitions. Our acquisitions were dominated by two
transactions; the acquisition of the Fletcher Challenge Energy properties,
primarily located in Canada, and the acquisition of substantially all of Repsol
YPF's concession interests in Egypt. Including the related goodwill, our
acquisition cost totaled $5.07 per Boe in 2001.

All told, Apache spent approximately $2.6 billion on acquisitions,
exploration and development, replacing 314 percent of production at a
competitive all-in finding and acquisition cost of $5.64 per boe, the outcome of
our long-term strategy to take a disciplined approach to controlling costs and
growing through the most cost effective method given market conditions. Both
acquisitions and drilling are important; a barrel is a barrel no matter how you
obtain it. What matters are its underlying economics. Our strategy is also
reflected in our balance sheet, which remained strong despite a record year of
spending. We exited the year with debt (including preferred interests of
subsidiaries and net of cash and cash equivalents and short-term investments) at
37 percent of total capitalization, even with year-end 2000. We also maintained
a senior unsecured long-term debt rating of A3 from Moody's, and A- from the
Standard and Poor's and Fitch rating agencies.

In September 2001, to recognize Apache's transformation to a stronger, more
profitable Company, we declared a 10-percent common stock dividend paid on
January 21, 2002, to shareholders of record on December 31, 2001. In conjunction
with our stock dividend, we increased our quarterly dividend from six cents per
common share to 10 cents per share. Together, these actions are expected to
result in a 57 percent increase in the dividends you will receive. All of the
share and per share information included in this discussion have been adjusted
for the stock dividend.

RESULTS OF OPERATIONS

Acquisitions and Divestitures

In each of the past three years, Apache has made significant acquisitions
that affect the comparability of our financial results. We acquired 213, 254 and
246 million barrels of oil equivalent (MMboe) of proved reserves for
approximately $0.9, $1.3 and $1.4 billion during 2001, 2000, and 1999,
respectively. In addition, the acquisitions added $197 million of goodwill and
$146 million of production, processing and transportation facilities in 2001,
and $94 million of such facilities in 2000. These acquisitions helped strengthen
our position in our 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.

In connection with some of these acquisitions, 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
implications of our acquisitions. These, as well as the gas price swaps
associated with advances from gas purchasers, increased the Company's average
natural gas price by $.09 per Mcf during 2001 and $.05 per Mcf during 2000. They
reduced our average crude oil price by $.42 per bbl during 2001 and $1.62 per
bbl during 2000. Driven by the uncertainty of how the collapse of Enron Corp.
would impact the derivatives markets, we closed all of these positions in
October and November 2001, and recognized a net gain of $10 million. An
additional $21 million net gain will be recognized over the next two years as
the original hedged production occurs.

We continuously evaluate our portfolio of properties and divest those that
are marginal or do not strategically fit into our growth program. We divested
$348, $26 and $155 million of properties during 2001, 2000, and 1999,
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

15

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.

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

16

Natural Gas Revenues

A 36 percent increase in our natural gas production contributed $390
million to our 2001 revenues. Canada's increase was primarily driven by our
acquisition of producing properties from Phillips Petroleum Company (Phillips)
(December 2000) and Fletcher (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)
(August 2000) and Collins & Ware, Inc. (Collins & Ware) (June 2000) helped to
boost our domestic production by 13 percent, while properties acquired from
Repsol helped double our Egyptian production.

During 2000, our natural gas revenues more than doubled. About 60 percent
of this increase was the result of significantly higher natural gas prices.
Recognizing the opportunities that these strong natural gas prices provided, we
acquired numerous properties at reasonable prices and accelerated our drilling
program. Together, these helped increase our production by 27 percent.
Properties acquired from a subsidiary of Repsol (January 2000), Collins & Ware
(June 2000) and Occidental (August 2000) enabled us to increase our domestic
production by 18 percent. Increased developmental activities on the properties
acquired from Shell Canada Limited (Shell Canada) (November 1999) added 31
percent to our Canadian production. The completion of a second pipeline in
Australia helped us tap our existing capacity and increase production by 42
percent in 2000. Similarly, Egyptian gas production nearly tripled in 2000
reflecting a full year of deliveries into the northern portion of the Western
Desert Gas Pipeline.

We have used long-term, fixed-price physical contracts to lock in a portion
of our domestic future natural gas production at fixed prices. These contracts
represented approximately 11 and 10 percent of our 2001 and 2000 domestic
natural gas production, respectively. The contracts provide protection to the
Company in the event of decreasing natural gas prices. The historically high
prices for natural gas during 2001 and 2000, however, resulted in losses under
these contracts, negatively impacting our average realized prices by $.06 per
Mcf in 2001 and $.17 per Mcf in 2000. In addition, due to the availability of
long-term contracts in Australia, substantially all of our Australian natural
gas production is subject to fixed prices.

Crude Oil Revenues

Our crude oil revenues increased in 2001 despite a 16 percent drop in the
average realized price. This was due to a 29 percent increase in our crude oil
production. With the acquisition and subsequent exploitation of properties
acquired from Repsol (March 2001), we increased our Egyptian production by 41
percent. Strong results on properties we acquired from Fletcher (March 2001) and
Phillips (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.

Our crude oil revenues during 2000 nearly doubled, driven by substantially
higher oil prices and significant production growth. During 2000, demand for oil
increased, helping boost oil prices by nearly 50 percent. Apache was in prime
position to take advantage of this pricing environment. We increased our overall
oil production by 26 percent. Our acquisition of properties from Shell Offshore
Inc. and affiliated Shell entities (Shell Offshore) (May 1999), Collins & Ware
(June 2000), and Occidental (August 2000) helped drive domestic oil production
up 24 percent. The acquisition of properties from Shell Canada (November 1999)
significantly expanded our position in Canada and was a major factor in the 382
percent increase in production in that country. Successful drilling in the Stag
field enabled us to increase our Australian production by 46 percent. Our
Egyptian oil production decreased 13 percent as a result of the price-driven
dynamics of certain production sharing contracts.

17

Operating Expenses

The table below presents a detail of our expenses.

Depreciation, Depletion and Amortization

Apache's full cost DD&A expense is driven by many factors including certain
costs incurred in the exploration, development, and acquisition of producing
reserves, production levels, and estimates of proved reserve quantities and
future developmental costs. During 2001, our DD&A per boe increased by $.30 to
$6.05. This was primarily the result of higher drilling and finding costs and
negative reserve revisions associated with declining prices. During 2000, full
cost DD&A expense increased by $.18 to $5.75 per boe due primarily to the cost
of oil producing properties acquired from Occidental ($6.74 per boe).

Depreciation on other assets increased $25 million in 2001 due to
additional facilities acquired from Fletcher (March 2001) and Repsol (March
2001) and the amortization of goodwill. In connection with the adoption of a new
accounting principle effective January 1, 2002, we will no longer amortize our
goodwill. Instead, it will be assessed for periodic impairment, as discussed in
the impairment section below.

Impairments

We periodically assess all of our unproved properties for possible
impairment. 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). We are continuing to evaluate our operations in Poland, which may
result in additional impairments in 2002.

As discussed in Note 2 of Item 14 of this Form 10-K, beginning in 2002,
goodwill will be subject to a periodic fair-value-based impairment assessment.
The Company has not yet determined whether or the extent to which the impairment
test will affect the consolidated financial statements.

Lease Operating Costs

Lease operating costs are driven in part by the type of commodity produced
and the level of workovers performed. 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, such as the one we
had during the first half of 2001. During 2001, these costs were $3.24 per boe,
a $.56 increase from 2000. The increase was primarily driven by three factors.
First, our acquisition of Canadian and offshore Gulf of Mexico oil properties
carry higher production costs than our other operations. Second, although high
commodity prices are beneficial to us overall, they can drive up some of our
production costs. Domestically, we had to pay more for service, power and lease
fuel costs

18

than we did in 2000. Finally, workover activity was up in the U.S. and Canada.
Increases in these two countries were the primary driver of the $.12 increase in
LOE per boe in 2000 over 1999 costs.

Severance and Other Taxes

Severance and other taxes, which generally are based on a percentage of oil
and gas production revenues, increased in 2001 and 2000 due to higher oil and
gas revenues. Also contributing to the increases were higher effective
production tax rates resulting from a loss of available incentives in Oklahoma
due to higher commodity prices and an increase in Canadian Large Corporation Tax
from the added production of the properties acquired from Fletcher (March 2001).

Administrative, Selling and Other Expenses

G&A is influenced by the size of our business. As a result of our active
acquisition program, especially in Canada, G&A increased during 2001 and 2000.
On an equivalent barrel basis, however, expensed G&A fell 10 percent during 2001
to $.71. This was the result of a significant increase in our production while
controlling our costs. During 2000, G&A per boe increased 10 percent to $.79.
This was primarily the result of higher incentive compensation driven by
Apache's then record performance.

Financing Costs, Net

Net financing costs increased by 11 percent in 2001 and 30 percent in 2000
due to higher average outstanding borrowings resulting from increased capital
expenditures and acquisitions. At year-end 2001, approximately 31 percent of our
borrowings were subject to fluctuations in short-term rates. As a result of the
decline in these rates, our weighted average cost of borrowing decreased to 5.9
percent in 2001 from 7.5 percent in 2000.

OIL AND GAS CAPITAL EXPENDITURES

Apache's 2001 acquisition and drilling program added 394.1 MMboe of proved
reserves (including revisions) and replaced 314 percent of production.

The capital expenditure budget for 2002 is approximately $590 million
(excluding acquisitions), including $350 million for North America. Preliminary
North American exploration and development expenditures include $60 million in
the Southern region, $40 million in the Midcontinent region, $100 million in the
Offshore region and $150 million in Canada. The Company has estimated its other
international

19

exploration and development expenditures in 2002, exclusive of facilities, to
total approximately $240 million. Capital expenditures will be reviewed and
possibly adjusted throughout the year in light of changing industry conditions.

Cash Dividend Payments

Apache paid a total of $20 million in dividends during 2001 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 will be paid through May 15,
2002, when the shares will automatically convert to common stock (see Note 9
under Item 14 below). Common dividends paid during 2001 totaled $35 million, up
five percent from 2000, due to increased common shares outstanding. The Company
has paid cash dividends on its common stock for 35 consecutive years through
2001. Future dividend payments will depend on the Company's level of earnings,
financial requirements and other relevant factors. The Company has increased its
annual common stock dividend to $.40 per share beginning in 2002.

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. Apache
budgets capital expenditures based upon projected cash flows. The Company
routinely adjusts its capital expenditures in response to changes in oil and
natural gas prices and cash flow. The Company cannot accurately predict future
oil and gas prices.

Net Cash Provided by Operating Activities

Apache's net cash provided by operating activities during 2001 totaled $1.9
billion, an increase of 27 percent over the $1.5 billion in 2000. This increase
was due primarily to higher oil and gas production revenue as a result of
full-year production from 2000 property acquisitions and properties acquired in
2001. Net cash provided by operating activities during 2000 increased $891
million from 1999 due primarily to higher oil and gas production and prices in
2000.

Debt

At December 31, 2001, Apache had outstanding debt of $663 million under its
credit and commercial paper facilities and a total of $1.6 billion of other
debt. This other debt included notes and debentures maturing in the years 2002
through 2096. The 9.25 percent notes totaling $100 million mature on June 1,
2002. These notes and the outstanding debt under credit and commercial paper
facilities are classified as long-term debt because the Company has the ability
and intent to refinance them on a long-term basis through rollover of commercial
paper or availability under the U.S. portion of the global credit facility and
364-day revolving credit facility. The global credit facility is scheduled to
mature in June 2003. The Company is planning to negotiate new credit facilities
in the first half of 2002. The Company's debt, including preferred interests of
subsidiaries and net of cash and cash equivalents and short-term investments,
was 37 percent of total capitalization at December 31, 2001 and 2000. Based on
our current plan for capital spending and projections of debt and interest
rates, interest payments on the Company's debt for 2002 are projected to be $154
million (using weighted average balances for floating rate obligations).

Apache has a $500 million, 364-day revolving credit agreement with a group
of banks. The terms of this facility are substantially the same as those of
Apache's global credit facility. The 364-day credit facility will be used, along
with the U.S. portion of the global credit facility, to support Apache's
commercial paper program, which was increased from $700 million to $1.2 billion
in late July 2000. Refer to Note 6 under Item 14 of this Form 10-K for
discussion of our debt instruments and related covenants.

20

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 $441 million
reflected as preferred interests of subsidiaries on the balance sheet.

Stock Transactions

On September 13, 2001, the Company's 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.

During 2001, the Company repurchased 962,600 shares of common stock to be
held in treasury at an average price of $45.09 per share.

On August 2, 2000, the Company completed the public offering of 10.1
million shares of Apache common stock, including 1.3 million shares for the
underwriters' over-allotment option, at $44.55 per share and total net proceeds
of approximately $434 million. The proceeds were used to fund a portion of the
acquisitions made during 2000 and repay indebtedness under Apache's commercial
paper program.

In the first quarter of 2000, the Company bought back 75,900 depository
shares, each representing one-fiftieth (1/50) of a share of Series C Preferred
Stock, at an average price of $34.42 per share. The excess of the purchase price
to reacquire the depository shares over the original issuance price is reflected
as a preferred stock dividend in the accompanying statement of consolidated
operations.

LIQUIDITY

The Company had $36 million in cash and cash equivalents on hand at
December 31, 2001, slightly down from $37 million at December 31, 2000. Apache's
ratio of current assets to current liabilities increased from 1.14 at December
31, 2000, to 1.34 at December 31, 2001.

The Company had $103 million in short-term securities (U.S. Government
Agency Notes) at December 31, 2001, a portion of which is currently available to
fund operating and exploration activities, and will be available to reduce
long-term debt after August, 2002.

Apache believes that cash on hand, net cash generated from operations,
short-term investments, and unused committed borrowing capacity under its global
credit facility and 364-day credit facility will be adequate to satisfy the
Company's financial obligations to meet liquidity needs for the foreseeable
future. As of December 31, 2001, Apache's available borrowing capacity under its
global credit facility and 364-day revolving credit facility was $839 million.

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The Company's contractual obligations relate primarily to long-term debt,
preferred interests of subsidiaries, operating leases, pipeline transportation
commitments and international commitments. The following table summarizes the
Company's contractual obligations as of December 31, 2001. Refer to the
indicated footnote to the Company's consolidated financial statements under Item
14 of this Form 10-K for further information regarding these obligations. The
Company expects to fund these contractual obligations with cash generated from
operations.

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

(a) Note that this table does not include the liability for dismantlement,
abandonment and restoration costs of offshore drilling platforms. The
Company currently includes such costs in the amortizable base of its oil
and gas properties. Effective with the adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations" on January 1, 2003, the
Company will record a liability for the fair value of this asset retirement
obligation, which will be capitalized as part of the oil and gas
properties' carrying amount. See Note 2 to the accompanying financial
statements for further discussion.

Our liquidity could be impacted by a downgrade of the credit rating for our
senior unsecured long-term debt by Standard & 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 described in Note 12 to the
accompanying financial statements could be in violation of their covenants which
may require them to redeem some of the preferred interests as described in that
Note.

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.

In order to maximize financial flexibility during a period of highly
volatile natural gas prices coupled with a faltering U.S. economy, Apache's
present plans are to reduce 2002 worldwide capital expenditures for exploratory
and development drilling to approximately $590 million from $1.4 billion in
2001. Any excess cash flow will be used to reduce debt until such time that we
elect either to increase drilling expenditures should the commodity price
environment improve, or to pursue acquisition opportunities should they become
available at reasonable prices.

22

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. Given the significant acquisitions completed over the last two
years, Apache's inventory of exploitation opportunities has never been larger.

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. Recently exorbitant acquisition prices have caused Apache to sideline
its acquisition activities until appropriate opportunities arise at reasonable
prices.

Investing in High-Potential Exploration Prospects

Apache seeks to concentrate our exploratory investments in a select number
of international areas and to become the dominant operator in those regions. We
believe that these investments, although 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. Rating upgrades on Apache's
senior unsecured long-term debt received from Moody's and Standard & Poor's
illustrate our commitment to preserving a strong balance sheet and 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 Company's major market risk exposure is in the pricing applicable to
its oil and gas production. Realized pricing is primarily driven by the
prevailing worldwide price for crude oil and spot prices applicable to its
United States and Canadian natural gas production. Historically, prices received
for oil and gas production have been volatile and unpredictable and price
volatility is expected to continue. Monthly oil price realizations ranged from a
low of $17.35 per barrel to a high of $27.67 per barrel during 2001. Average gas
price realizations ranged from a monthly low of $2.24 per Mcf to a monthly high
of $7.33 per Mcf during the same period. Based on the Company's 2001 worldwide
oil production levels, a $1.00 per barrel change in the weighted average price
of oil would increase or decrease revenues by $54 million. Based on the
Company's 2001 worldwide gas production levels, a $.10 per Mcf change in the
weighted average price of gas would increase or decrease revenues by $41
million.

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

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The Company periodically enters into hedging activities on a portion of its
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 its exposure to oil and gas price fluctuations. Apache may
use futures contracts, swaps, options and fixed-price physical contracts to
hedge its commodity prices. Realized gains or losses from the Company's price
risk management activities are recognized in oil and gas production revenues
when the associated production occurs. Apache does not generally hold or issue
derivative instruments for trading purposes. As indicated in Note 4 under Item
14 below, the Company terminated all of its derivative instruments in October
and November 2001.

Apache sells all of its Egyptian crude oil and natural gas to the EGPC for
U.S. dollars. Deteriorating economic conditions during 2001 in Egypt have
lessened the availability of U.S. dollars resulting in a gradual decline in
timeliness of receipts from EGPC.

INTEREST RATE RISK

The Company considers its interest rate risk exposure to be minimal as a
result of fixing interest rates on approximately 69 percent of the Company's
debt. At December 31, 2001, total debt included $700 million of floating-rate
debt. As a result, Apache's annual interest costs in 2002 will fluctuate based
on short-term interest rates on approximately 31 percent of its total debt
outstanding at December 31, 2001. Additionally, our preferred interests of
subsidiaries of $441 million is subject to fluctuations in short-term interest
rates. The impact on annual cash flow of a 10 percent change in the floating
interest rate, including our preferred interests in subsidiaries, (approximately
22 basis points) would be approximately $2 million. The Company did not have any
open derivative contracts relating to interest rates at December 31, 2001 or
2000.

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. Reported cash flow from Canadian operations is 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.
A portion of Apache's debt in Canada is denominated in U.S. dollars and, as
such, is adjusted for differences in exchange rates at each period-end. This
unrealized adjustment is recorded as other revenues (losses). Substantially all
of the Company's international transactions, outside of Canada and Australia,
are denominated in U.S. dollars. A 10 percent weakening of each of the Canadian
dollar, Polish zloty or Australian dollar will result in a foreign currency loss
of approximately $17 million. The Company did not have any open derivative
contracts relating to foreign currencies at December 31, 2001 or 2000.

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

24

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-48 of this Form
10-K, and are incorporated herein by reference.

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information set forth under the captions "Nominees for Election as
Directors", "Continuing Directors", "Executive Officers of the Company", and
"Securities Ownership and Principal Holders" in the proxy statement relating to
the Company's 2002 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 Grants 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 caption "Securities Ownership and
Principal Holders" 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.

25

PART IV

ITEM 14. 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 public accountants.................... F-2
Statement of consolidated operations for each of the three
years in the period ended December 31, 2001............... F-3
Statement of consolidated cash flows for each of the three
years in the period ended December 31, 2001............... F-4
Consolidated balance sheet as of December 31, 2001 and
2000...................................................... F-5
Statement of consolidated shareholders' equity for each of
the three years in the period ended December 31, 2001..... F-6
Notes to consolidated financial statements.................. F-7

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