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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, 1999,
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:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $1.25 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, 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. [ ]
Aggregate market value of the voting stock held by
non-affiliates of registrant as of February 29, 1999...... $4,147,883,616
Number of shares of registrant's common stock outstanding as
of February 29, 1999...................................... 113,640,647
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of registrant's proxy statement relating to registrant's 2000
annual meeting of stockholders have been incorporated by reference into Part III
hereof.
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TABLE OF CONTENTS
DESCRIPTION
ITEM PAGE
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PART I
1. BUSINESS.................................................... 1
2. PROPERTIES.................................................. 11
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................................... 18
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 28
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.................................... 28
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 29
11. EXECUTIVE COMPENSATION...................................... 29
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 29
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 29
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K......................................................... 29
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) or billion cubic feet (Bcf). 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), respectively. 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 the Company's working interest in wells
or acreage, "net" oil and gas wells or acreage is determined by multiplying
gross wells or acreage by the Company's working interest therein. Unless
otherwise specified, all references to wells and acres are gross.
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PART I
ITEM 1. BUSINESS
GENERAL
Apache Corporation (Apache or the Company), 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,
Apache's exploration and production interests are focused on the Gulf of Mexico,
the Anadarko Basin, the Permian Basin, the Gulf Coast and the Western
Sedimentary Basin of Canada. Outside of North America, Apache has exploration
and production interests offshore Western Australia and in Egypt and exploration
interests in Poland and offshore The People's Republic of China (China). Apache
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.
Apache holds interests in many of its U.S., Canadian and international
properties through operating subsidiaries, such as Apache Canada Ltd., DEK
Energy Company (DEKALB, formerly known as DEKALB Energy Company), Apache Energy
Limited (formerly known as Hadson Energy Limited), Apache International, Inc.,
and Apache Overseas, Inc. Properties referred to in this document may be held by
those subsidiaries. Apache treats all operations as one line of business.
1999 RESULTS
In 1999, Apache had record net income attributable to common stock of
$186.4 million, or $1.73 per share, on total revenues of $1.3 billion. Net cash
provided by operating activities during 1999 was $638.2 million, a 35 percent
increase from 1998.
Apache reported its 22nd consecutive year of production growth (up 17
percent) and 12th consecutive year of oil and gas reserves growth (up 32
percent) in 1999. Apache's average daily production was 95 Mbbls of oil and
natural gas liquids and 656 MMcf of natural gas for the year. Giving effect to
1999 production, acquisitions, dispositions, revisions and drilling activity,
the Company's estimated proved reserves increased by 194 MMboe in 1999 over the
prior year to 807 MMboe, of which approximately 49 percent was natural gas.
Based on 613 MMboe reported at year-end 1998, Apache's reserve additions
(including revisions) during the year reflect replacement of 416 percent of the
Company's 1999 production. Apache's drilling and production-enhancement program
yielded 190 new producing wells out of 252 attempts and involved 579 major North
American workover and recompletion projects during the year.
At December 31, 1999, Apache held interests in approximately 4,307 net oil
and gas wells and 2,148,620 net developed acres of oil and gas properties
worldwide. In addition, the Company had approximately 977,292 net undeveloped
acres under North American leases and 18,755,419 net undeveloped acres under
international exploration and production rights.
APACHE'S GROWTH STRATEGY
Apache's growth strategy is to increase oil and gas reserves, production,
cash flow and earnings through a combination of exploratory drilling,
development of its inventory of existing projects, and property acquisitions
meeting defined financial parameters. The Company's drilling program emphasizes
reserve additions through low to moderate-risk drilling primarily on its North
American interests, and exploratory and subsequent development drilling
primarily on its international interests. The Company also emphasizes reducing
operating costs per unit produced and selling marginal and non-strategic
properties in order to enhance its profit margins.
Apache's international exploration activities are an emerging component of
its long-term growth strategy. In addition to active, low to moderate-risk
drilling and exploration activities in Apache's North American focus areas,
higher-risk international exploration offers potential for greater rewards and
significant reserve additions. Apache directed its international efforts in 1999
toward development of certain discoveries offshore Western Australia and in
Egypt and toward further exploration efforts in those areas and on its
concessions in
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Poland. Apache believes that reserve additions in these international areas are
likely to continue through higher-risk exploration and through appraisal and
development drilling of prior exploratory discoveries.
For Apache, property acquisition is only one phase in a continuing cycle of
business growth. Apache's aim is to follow each acquisition with a cycle of
reserve enhancement, property consolidation and cash flow acceleration,
facilitating asset growth and debt reduction. This approach requires a well
planned and carefully executed property development program and, where
appropriate, a selective program of property dispositions. It motivates Apache
to target acquisitions that have ascertainable additional reserve potential and
to apply an active drilling, workover and recompletion program to realize the
potential of the acquired undeveloped and partially developed properties. Apache
prefers to operate its properties so that it can best influence their
development; as a result, the Company operates properties accounting for 82
percent of its production.
1999 ACQUISITIONS AND DISPOSITIONS
On February 1, 1999, the Company acquired oil and gas properties located in
the Gulf of Mexico from Petsec Energy Inc. (Petsec) for an adjusted purchase
price of $67.7 million. The Petsec transaction included estimated proved
reserves of approximately 10.2 MMboe as of the acquisition date.
On May 18, 1999, Apache acquired from Shell Offshore Inc. and affiliated
Shell entities (Shell Offshore) its interest in 22 producing fields and 16
undeveloped blocks located in the Gulf of Mexico. The transaction also included
certain production-related assets and proprietary 2-D and 3-D seismic data
covering approximately 1,000 blocks in the Gulf of Mexico. The purchase price
was $687.7 million in cash and one million shares of Apache common stock (valued
at $28.125 million). The Shell Offshore acquisition included approximately 123.2
MMboe of proved reserves as of the acquisition date.
On June 18, 1999, Apache acquired a 10 percent interest in the East Spar
Joint Venture and an 8.4 percent interest in the Harriet Joint Venture, both
located in the Carnarvon Basin (offshore Western Australia), from British-Borneo
Oil and Gas Plc (British-Borneo) for $83.6 million cash and working interests in
11 leases in the Gulf of Mexico. The British-Borneo transaction included
approximately 16.8 MMboe of proved reserves as of the acquisition date.
On November 30, 1999, Apache acquired from Shell Canada Limited (Shell
Canada) producing properties and other assets for C$761 million (US$517.8
million). The producing properties consisted of 150,400 net acres and comprised
20 fields with an average working interest of 55 percent and proved reserves of
87.2 MMboe as of the acquisition date. Apache also acquired 294,294 net acres of
undeveloped leaseholdings, a 100 percent interest in a gas processing plant with
a potential throughput capacity of 160 MMcf per day, and 52,700 square miles of
2-D seismic and 884 square miles of 3-D seismic.
In 1999, the Company also completed tactical regional acquisitions for cash
consideration totaling $17.7 million. These acquisitions added approximately 8.8
MMboe to the Company's proved reserves.
On September 3, 1999, Apache sold its holdings in the Ivory Coast by
selling its wholly owned subsidiary, Apache Cote d'Ivoire Petroleum LDC, for a
total sales price of $46.1 million to a consortium consisting of Mondoil Cote
d'Ivoire LLC and Saur Energie Cote d'Ivoire. The sale consisted of 13.7 MMboe of
proved reserves and a gain was recorded to other revenues in the accompanying
statement of consolidated operations. Also, during 1999, Apache sold 27.9 MMboe
of proved reserves in several transactions from largely marginal North American
properties for $110 million.
EXPLORATION AND PRODUCTION
The Company's North American exploration and production activities are
diversified among four operating regions: Offshore, Midcontinent, Southern and
Canada. In July 1999, the Company combined its former Western region and the
onshore properties from its former Gulf region to form the new Southern region,
leaving its offshore properties in the renamed Offshore region. Approximately 73
percent of the Company's proved reserves are located in these North American
regions. Egypt and Australia are the Company's most important international
regions. The Company's Egyptian operations are headquartered in Cairo, and
Apache conducts its Australian exploration and production operations from Perth.
Information concerning the amount of revenue, operating income (loss) and total
assets attributable to U.S., Canadian and
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international operations is set forth in Note 12 to the Company's consolidated
financial statements under Item 8 below.
Offshore. The Offshore region comprises the Company's interests in the Gulf
of Mexico, offshore Louisiana and Texas. In 1999, the Offshore region was
Apache's leading region for production and production revenues contributing
approximately $346.2 million in revenues from production of 21.3 MMboe for the
year. The Company performed 110 workover and recompletion operations during 1999
in the offshore region and participated in drilling 24 wells, 16 of which were
completed as producers. As of December 31, 1999, the region encompassed 482,204
net acres, and accounted for 146.8 MMboe, or 18 percent, of the Company's
year-end 1999 total estimated proved reserves.
Midcontinent. Apache's Midcontinent region operates in Oklahoma, eastern
and northern Texas, Arkansas and northern Louisiana. The region has focused
operations 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. In 1999, the Midcontinent region had approximately 10.5 MMboe
of production generating $143.7 million in revenue for the Company.
At December 31, 1999, Apache held an interest in 391,935 net acres in the
region, which accounted for approximately 88.1 MMboe, or 11 percent, of Apache's
total estimated proved reserves. Apache participated in drilling 48 wells in the
Midcontinent region during the year, 40 of which were completed as producing
wells. The Company performed 50 workover and recompletion operations in the
region during 1999.
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. In 1999, the Southern region produced
approximately 14.1 MMboe and generated $212.3 million in production revenue. At
December 31, 1999, the Company held 626,241 net acres in the region, which
accounted for 206.3 MMboe, or 26 percent, of the Company's total estimated
proved reserves. Apache participated in drilling 58 wells in the Southern
region, 52 of which were productive wells. Apache performed 350 workovers and
recompletions in the Southern region during the year.
Canada. Exploration and development activity in the Canadian region is
concentrated in the Provinces of Alberta and British Columbia. The region
produced approximately 7.4 MMboe and generated $86.9 million in production
revenue in 1999. Apache participated in drilling 49 wells in this region during
the year, 32 of which were completed as producers. The Company performed 69
workovers and recompletions on operated wells during 1999. At December 31, 1999,
the region encompassed approximately 896,701 net acres, and accounted for 150.9
MMboe, or 19 percent, of the Company's year-end 1999 total estimated proved
reserves.
Egypt. At year end, Apache held 11,803,569 net acres in Egypt with 65.1
MMboe of estimated proved reserves or eight percent of Apache's total estimated
proved reserves. In 1999, Apache had 12.6 MMboe of production in Egypt, which
generated $235.9 million in production revenues. Apache owns a 75 percent
interest in the Qarun Block and a 40 percent interest in the Khalda Block, both
located in the Western Desert of Egypt. Production of gas from Khalda is
delivered for sale to the Egyptian General Petroleum Corporation (EGPC) at a
point west of Alexandria, Egypt, via a 34-inch gas pipeline, construction of
which commenced in 1997 and was completed in August 1999. Additional gas will be
delivered via a southern line expected to be completed mid-year 2000. The costs
of building the pipeline were borne by Apache, the other Khalda participants,
and the owners of a neighboring block and are recoverable from oil and gas
production from the Khalda Block.
In addition to the Qarun and Khalda Blocks, Apache holds interests in the
East Beni Suef and Asyout Blocks to the south of the Qarun Block, and three
other blocks in the Western Desert of Egypt, the North East Abu Gharadig Block,
the East Bahariya Block, and the West Mediterranean Block No. 1 (partly onshore
and partly offshore). Apache also acquired interests in the Ras El Hekma and Ras
Kanayes concessions from Repsol Exploracion Egipto S.A. in December 1997.
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On November 30, 1999 Apache acquired from Amoco Egypt 100 percent of the
working interest in the WD-19 area in the Western Desert. This area has produced
oil in the past, but is currently inactive. Apache intends to drill additional
wells and, if successful, to tie them into adjoining Qarun facilities.
Both the Khalda and Qarun Concession Agreements provide that Apache and its
partners in the concessions will pay all of the operating and capital costs for
developing the concessions, while the production will be split between EGPC and
the partners. Up to 40 percent of the oil and gas produced from each of the
concessions is available to the Company and its partners to recover operating
and capital costs for the applicable concession. To the extent eligible costs
exceed 40 percent of the oil and gas produced and sold from a concession in any
given quarter, such excess costs may be carried into future quarters without
limit. The remaining 60 percent of all oil and gas produced from the concessions
is divided between EGPC and Apache and its partners, with the percentage
received by Apache and its partners reducing as the gross daily average of oil
and gas produced on a quarterly basis increases. Under the Khalda Agreement,
capital costs are amortized over four years, while the Qarun agreement provides
for a five-year amortization.
Australia. Western Australia became an important region for Apache after
the 1993 acquisition of Hadson Energy Resources Corporation (subsequently known
as Apache Energy Resources Corporation). In 1999, natural gas production in the
region increased by 51 percent from the prior year to approximately 76 MMcf/d.
Apache acts as operator for most of its Western Australian properties through
its wholly-owned subsidiary, Apache Energy Limited (AEL). During 1999, Apache
had 8.5 MMboe of production generating $118.5 million of production revenue.
Estimated proved reserves in Australia increased by 13 percent to 150.1 MMboe,
or 19 percent of the Company's year-end total estimated proved reserves. The
increase reflects, among other matters, the 1999 acquisition from British-Borneo
of holdings in the East Spar and Harriet fields. As of December 31, 1999, Apache
held 259,240 net developed acres and 1,664,440 net undeveloped acres offshore
Western Australia. Through AEL and its subsidiaries, Apache also operates the
Varanus Island gas hub with a throughput capacity of 240 MMcf/d and two 60-mile
(12-inch and 16-inch) pipelines from Varanus Island to connections with the
Dampier to Bunbury and Goldfields Gas Transmission pipelines. See "1999
Acquisitions and Dispositions" and "Oil and Natural Gas Marketing."
Other International Operations. Outside of Canada, Egypt and Australia,
Apache currently has exploration interests in Poland and offshore China.
Apache obtained its first properties in Poland on April 16, 1997, when the
Company assumed operatorship and a 50 percent interest in over 5.5 million acres
in Poland located near Lublin, southeast of Warsaw, from FX Energy, Inc. (FX
Energy). The Company has since acquired additional acreage in Poland, including
approximately 1.8 million acres in the Carpathian area near the southern border
of Poland and participation in a further 2.275 million acres in the Pomeranian
area of northwest Poland, giving Apache interests in 11,468,335 total gross
undeveloped acres and 5,734,169 net undeveloped acres as of December 31, 1999.
Apache is obligated to drill at least ten wells and to shoot at least 1,250
miles of seismic data in Poland. At year end, drilling operations on the first
five exploratory wells had been completed, and all were determined to be
exploratory dry holes. Subsequent to year end, a sixth well, known as the Wilga
well, tested at a combined rate of 16.9 MMcf of gas and 570 barrels of
condensate per day. The well is located on Block 255 of the Vistula Concession
in the Lublin basin. Apache and FX Energy plan to enter into further exploration
and production agreements with the Polish Oil and Gas Company (POGC), the
national oil company of Poland. Apache's operations in Poland are headquartered
in Warsaw.
Apache is also the operator, with a 50 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. The Company elected to proceed with
the second exploration phase, commencing in May 1996, which involved a
commitment to drill two additional exploratory wells. 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 submitted to Chinese authorities in late 1997 and is awaiting approval.
On May 28, 1999, Apache China Corporation LDC (Apache China, an indirect
wholly owned subsidiary of the Company) sent a notice of default to XCL-China,
Ltd. (XCL-China), a participant with Apache China in the Zhao Dong Block
offshore the People's Republic of China, and its parent company, XCL, Ltd.,
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for the failure to pay approximately $10 million of costs pursuant to the
agreements governing the project. Prior to the expiration of the cure period,
XCL-China and XCL, Ltd. filed petitions initiating arbitration proceedings
against Apache China. The actions seek to disallow approximately $17 million in
costs expended by Apache China related to developing the Zhao Dong Block,
including the $10 million in costs billed by Apache China to XCL-China that have
not been paid. In addition, XCL-China has advised Apache China of XCL-China's
intent to seek the removal of Apache China as operator of the Block. Apache
China has denied the allegations made by XCL-China in its petition and is
vigorously contesting them. On November 30, 1999 the arbitration proceedings
were stayed in connection with the bankruptcy proceeding described below.
On June 25, 1999, Apache China filed a petition in U.S. Bankruptcy Court in
Opelousas, Louisiana, to place XCL-China into involuntary bankruptcy under
Chapter 7 of the Bankruptcy Code on account of XCL-China's failure to pay its
share of costs related to development of the Zhao Dong Block. On December 21,
1999, the holders of XCL, Ltd.'s senior secured notes, acting through their
Trustee, exercised their remedial rights under their indenture and removed the
existing Board of Directors of XCL-China, electing a new Board. The new Board of
Directors of XCL-China voted to withdraw XCL-China's opposition to Apache
China's Chapter 7 bankruptcy petition filed against XCL-China and on December
22, 1999 obtained an order of the Court converting the proceeding into a
voluntary Chapter 11 bankruptcy proceeding.
Apache China has entered into negotiations with the Chinese authorities
concerning the terms and conditions of the development of the Zhao Dong Block
including, among other things the portion of XCL-China's future development
costs to be paid by the Chinese. Apache China is prepared to move forward as
soon as these negotiations are satisfactorily concluded.
In September 1999, Apache sold its interests in the Ivory Coast as detailed
in "1999 Acquisitions and Dispositions" above.
OIL AND NATURAL GAS MARKETING
On October 27, 1995, wholly owned affiliates of each of Apache, Oryx Energy
Company and Parker & Parsley Petroleum Company (Parker & Parsley) formed
Producers Energy Marketing LLC (ProEnergy), a Delaware limited liability
company. ProEnergy became fully operational on April 1, 1996, and marketed
substantially all of its members' domestic natural gas pursuant to member gas
purchase agreements having an initial term of 10 years, subject to early
termination following specified events. The price of gas purchased by ProEnergy
from its members was based upon agreed to published indexes. Effective January
1, 1998, Parker & Parsley withdrew from ProEnergy. In June 1998, Apache sold its
interest in ProEnergy to Cinergy Corp. (Cinergy) and formed a strategic alliance
with Cinergy to market substantially all the Company's natural gas production
from North America. ProEnergy, renamed Cinergy Marketing & Trading, LLC in June
1999, will continue to market Apache's North American natural gas production for
10 years, with an option to terminate after six years, under an amended and
restated gas purchase agreement effective July 1, 1998. During this period,
Apache is generally obligated to deliver most of its North American gas
production to Cinergy and, under certain circumstances, may have to make
payments to Cinergy if certain gas throughput thresholds are not met.
Separate from its arrangements with Cinergy, Apache is also delivering
natural gas under several long-term supply agreements with terms greater than
one year.
Apache assumed its own U.S. crude oil marketing operations in 1992. Most of
Apache's U.S. crude oil production is sold through lease-level marketing to
refiners, traders and transporters, generally under 30 day contracts that renew
automatically until canceled. Oil produced from 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. Natural gas produced
from Canadian properties is sold to major aggregators of natural gas, gas
marketers and direct users under long-term and short-term contracts. The oil and
gas contracts provide for sales at specified prices, or at prices that are
subject to change due to market conditions.
The Company diversifies the markets for its Canadian gas production not
presently committed to Cinergy by selling directly or indirectly to customers
through aggregators and brokers in the United States and Canada.
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Apache transports natural gas via the Company's firm transportation contracts to
California (12 MMcf/d) and to the Province of Ontario, Canada (four MMcf/d)
through end-users' firm transportation contracts. Pursuant to an agreement
entered into in 1994, the Company is also selling five MMcf/d of natural gas to
the Hermiston Cogeneration Project, located in the Pacific Northwest of the
United States. In 1996, the Company entered into an agreement with Westcoast Gas
Services, Inc. for the sale of 5,000 MMBtu/d for delivery in the United States
for a 10 year term.
In Australia, the Company entered into two gas sales contracts during 1999,
bringing its total to 18 contracts, with terms of four to 12 years to deliver
323 Bcf of AEL's gas from its Harriet and East Spar fields for mining, power
generation, nickel refining, ammonia production and other industrial and
domestic uses. Under these contracts AEL is required to deliver its gas at
contract rates of approximately 111 MMcf/day increasing to 135 MMcf/d by mid
2000, with take or pay provisions, net to AEL, of approximately 28 Bcf/year
increasing to 49 Bcf/year by the end of 2001. Apache operates both the Harriet
and East Spar Joint Ventures, holding a 68.5 percent interest in Harriet and a
55 percent interest in East Spar.
In Egypt, oil from the Qarun Block is delivered by pipeline to tanks owned
by the Company and its partners in the Qarun Concession at the Dashour pumping
station northeast of the Qarun Block or by truck to the Tebbin refinery south of
Alexandria, Egypt. At the discretion of the operator of the pipelines, oil from
the Qarun Block is put into the two 42-inch diameter SUMED pipelines, which
transport significant quantities of Egyptian and other crude oil from the Gulf
of Suez to Sidi Kherir, west of Alexandria, Egypt, on the Mediterranean Coast.
All Qarun and Khalda crude oil is currently sold to EGPC. In 1996, the Company
and its 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. 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 through a southern gas line being constructed by the
Company and its partners from the Khalda Block to a point near the Qarun Block
to tie into an existing gas pipeline. This southern line is expected to complete
tie-in in mid-year 2000.
OIL AND NATURAL GAS PRICES
Natural gas prices remained volatile during 1999, with Apache's realized
prices ranging from $1.60 per Mcf in March to $2.74 per Mcf in November.
Fluctuations are largely due to market perceptions about natural gas supply and
demand. Apache's average realized gas price of $2.16 per Mcf for 1999 was up 13
percent from the prior-year average of $1.92 per Mcf, and its 1998 average
realized natural gas price was 16 percent lower than the 1997 average price of
$2.28 per Mcf.
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 subject to price volatility as is Apache's U.S. and
Canadian gas production; however, natural gas sales under such Australian
minimum price contracts represented approximately 10.3 percent of the Company's
total natural gas sales at the end of 1999. Total Australian gas sales in 1999,
including long-term contracts and spot sales averaged $1.51 per Mcf, equal to
the 1998 average.
In Egypt, all oil production from the East Beni Suef, Khalda, West
Mediterranean and Qarun Blocks is currently sold to EGPC on a spot basis at a
"Western Desert" price, which is applied to virtually all production from the
area and is announced periodically by EGPC. In 1999, the average price was
$18.63 per barrel. Discussions with EGPC regarding the possibility of exporting
Qarun oil production are continuing. Gas sales from the Khalda Block commenced
in 1999 based on a contract price that is equivalent to 85 percent of the price
of Suez Blend crude oil, FOB Mediterranean.
Oil prices remained subject to unpredictable political and economic forces
during 1999 and experienced fluctuations similar to those seen in natural gas
prices for the year, but showing a significant upward trend. Apache believes
that oil prices will continue to fluctuate in response to changes in the
policies of the Organization of Petroleum Exporting Countries (OPEC), demand
from Asian countries, events in the Middle East and other factors associated
with the world political and economic environment. As a result of the many
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uncertainties associated with levels of production maintained by OPEC and other
oil producing countries, the availabilities of worldwide energy supplies and the
competitive relationships and consumer perceptions of various energy sources,
the Company is unable to predict what changes will occur in crude oil and
natural gas prices.
In 1999, Apache's realized worldwide crude oil price ranged from $10.09 per
barrel in February to $24.11 per barrel in December. The average crude oil price
of $18.43 per barrel in 1999 was up 46 percent from the average price of $12.66
per barrel in 1998, and four percent lower than the average price of $19.20 per
barrel in 1997. The Company's average crude oil price for its Australian
production was $19.70 per barrel in 1999, 51 percent more than the average price
in 1998.
From time to time, Apache buys or sells contracts to hedge a limited
portion of its future oil and gas production against exposure to spot market
price changes. See Note 9 to the Company's consolidated financial statements
under Item 8 below.
The Company's business has been and will continue to be affected by future
worldwide changes in oil and gas prices and the relationship between the prices
of oil and gas. No assurance can be given as to the trend in, or level of,
future oil and gas prices.
WRITE-DOWNS UNDER THE FULL COST CEILING TEST RULES
Under the full cost accounting rules of the Securities and Exchange
Commission (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
depreciation, depletion and amortization, 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. These rules generally require pricing future oil and gas production at
the unescalated oil and gas prices in effect at the end of each fiscal quarter
and require a write-down if the "ceiling" is exceeded, even if prices declined
for only a short period of time. The Company recorded a write-down in 1998, but
had no write-downs due to ceiling test limitations in 1999. 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 in the future,
even if only for a short period of time, it is possible that additional
write-downs of oil and gas properties could occur. Write-downs required by these
rules do not impact cash flow from operating activities.
VOLATILE PRICES CAN MATERIALLY AFFECT THE COMPANY
The Company continually analyzes, forecasts and updates its estimates of
energy prices for its internal use in planning, budgeting, and estimating and
valuing reserves. The Company's future financial condition and results of
operations will depend upon the prices received for the Company's oil and
natural gas production and the costs of acquiring, finding, developing and
producing reserves. Prices for oil and natural gas are subject to fluctuations
in response to relatively minor changes in supply, market uncertainty and a
variety of additional factors that are beyond the control of the Company. These
factors include worldwide political instability (especially in the Middle East
and other oil-producing regions), the foreign supply of oil and gas, the price
of foreign imports, the level of drilling activity, the level of consumer
product demand, government regulations and taxes, the price and availability of
alternative fuels and the overall economic environment. A substantial or
extended decline in oil and gas prices would have a material adverse effect on
the Company's financial position, results of operations, quantities of oil and
gas that may be economically produced, and access to capital. Oil and natural
gas prices have historically been and are likely to continue to be volatile.
This volatility makes it difficult to estimate with precision the value of
producing properties in acquisitions and to budget and project the return on
exploration and development projects involving the Company's oil and gas
properties. In addition, unusually volatile prices often disrupt the market for
oil and gas properties, as buyers and sellers have more difficulty agreeing on
the purchase price of properties.
7
10
UNCERTAINTY IN CALCULATING RESERVES; RATES OF PRODUCTION; DEVELOPMENT
EXPENDITURES; CASH FLOWS
There are numerous uncertainties inherent in estimating quantities of oil
and natural gas reserves of any category and in projecting future rates of
production and timing of development expenditures, which underlie the reserve
estimates, including many factors beyond the Company's control. Reserve data
represent only estimates. In addition, the estimates of future net cash flows
from the Company's proved reserves and their present value are based upon
various assumptions about future production levels, prices and costs that may
prove to be incorrect over time. Any significant variance from the assumptions
could result in the actual quantity of the Company's reserves and future net
cash flows from them being materially different from the estimates. In addition,
the Company's estimated reserves may be subject to downward or upward revision
based upon production history, results of future exploration and development,
prevailing oil and gas prices, operating and development costs and other
factors.
ACQUISITION OR DISCOVERIES OF ADDITIONAL RESERVES IS 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 the Company acquires additional
properties containing proved reserves, conducts successful exploration and
development activities or, through engineering studies, identifies additional
behind-pipe zones or secondary recovery reserves, the Company's proved reserves
will decline materially as reserves are produced. Future oil and gas production
is, therefore, highly dependent upon the Company's level of success in acquiring
or finding additional reserves.
SUBSTANTIAL COSTS INCURRED TO CONFORM TO GOVERNMENT REGULATION OF THE OIL AND
GAS INDUSTRY
The Company's exploration, production and marketing operations are
regulated extensively at the federal, state and local levels, as well as by
other countries in which the Company does business. The Company has made and
will continue to make large expenditures in its 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 the Company's
operations and limit the quantity of hydrocarbons the Company 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
The Company, as an owner or lessee and operator of oil and gas properties,
is subject to various federal, provincial, state, local and foreign country laws
and regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liability on the lessee under an oil and gas lease for the cost of pollution
clean-up resulting from operations, subject the lessee to liability for
pollution damages, and require suspension or cessation of operations in affected
areas.
The Company maintains insurance coverage, which it believes is customary in
the industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of December 31,
1999, which would have a material impact upon the Company's financial position
or results of operations.
The Company has made and will continue to make expenditures in its efforts
to comply with these requirements, which it believes are necessary business
costs in the oil and gas industry. The Company has established policies for
continuing compliance with environmental laws and regulations, including
regulations applicable to its operations in Canada, Australia and other
countries. Apache also has established operational procedures and training
programs designed to minimize the environmental impact of its field facilities.
The costs incurred by these policies and procedures are inextricably connected
to normal operating expenses such
8
11
that the Company is unable to separate the expenses related to environmental
matters; however, the Company does not believe any such additional expenses are
material to its 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 Apache any
differently, or to any greater or lesser extent, than other companies in the
industry. The Company does 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 the Company 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 THE COMPANY
The oil and gas industry is highly competitive. The Company's business
could be harmed by competition with other companies. Because oil and gas are
fungible commodities, the Company's principal form of competition is price
competition. The Company strives to maintain the lowest finding and production
costs possible to maximize profits. In addition, as an independent oil and gas
company, the Company frequently competes for reserve acquisitions, exploration
leases, licenses, concessions and marketing agreements against companies with
financial and other resources substantially larger than the Company possesses.
Many of the Company's competitors have established strategic long-term positions
and maintain strong governmental relationships in countries in which the Company
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. The Company maintains insurance against certain losses or
liabilities arising from its operations in accordance with customary industry
practices and in amounts that management believes to be prudent; however,
insurance is not available to the Company against all operational risks.
HEDGING MAY PREVENT THE COMPANY FROM FULLY BENEFITING FROM PRICE INCREASES
To the extent that the Company engages in hedging activities, it may be
prevented from realizing the benefits of price increases above the levels of the
hedges. In addition, the Company is subject to basis risk when it engages in
hedging transactions, particularly where transportation constraints restrict the
Company's ability to deliver oil and gas volumes at the delivery point to which
the hedging transaction is indexed.
RISKS ARISING FROM THE FAILURE TO FULLY IDENTIFY POTENTIAL PROBLEMS RELATED TO
ACQUIRED RESERVES OR TO PROPERLY ESTIMATE THOSE RESERVES
The Company from time to time acquires oil and gas properties. Although the
Company performs a review of the acquired properties that it believes 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 the Company will focus its 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, the
Company often assumes 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
9
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upon the Company's operating results, particularly during the periods in which
the operations of acquired businesses are being integrated into the Company's
ongoing operations.
GENERAL ECONOMIC CONDITIONS
Virtually all of the Company's operations are subject to the risks and
uncertainties of adverse changes in general economic conditions (domestically,
in specific regions of the United States and Canada, and internationally), the
outcome of pending and/or potential legal or regulatory proceedings, changes in
environmental, tax, labor and other laws and regulations to which the Company is
subject, and the condition of the capital markets utilized by the Company to
finance its operations.
RISKS OF NON-U.S. OPERATIONS
The Company's non-U.S. oil and natural gas exploration, development and
production activities are subject to: political and economic uncertainties,
including, among others, changes, sometimes frequent or marked, in governmental
energy policies or the personnel administering them; expropriation of property;
cancellation or modification of contract rights; foreign exchange restrictions;
currency fluctuations; risks of loss due to civil strife, acts of war, guerrilla
activities and insurrection; royalty and tax increases; and other risks arising
out of foreign governmental sovereignty over the areas in which the Company's
operations are conducted. These risks may be higher in the developing countries
in which the Company conducts these activities. Consequently, the Company's
non-U.S. exploration, development and production activities may be substantially
affected by factors beyond the Company's control, any of which could materially
adversely affect the Company's financial position or results of operations.
Furthermore, in the event of a dispute arising from non-U.S. operations, the
Company may be subject to the exclusive jurisdiction of courts outside the
United States or may not be successful in subjecting non-U.S. persons to the
jurisdiction of the courts in the United States, which could adversely affect
the outcome of the dispute.
EFFECT OF CHANGES IN FOREIGN EXCHANGE RATES ON THE COMPANY'S CASH FLOW
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 on the
transaction date. Reported cash flow relating to Canadian operations is based on
cash flows measured in Canadian dollars converted to the U.S. dollar equivalent
based on the average of the Canadian and U.S. dollar exchange rates for the
period reported. Substantially all of the Company's international transactions,
outside of Canada and Australia, are denominated in U.S. dollars. The Company's
Polish and Australian subsidiaries have net financial assets that are
denominated in a currency other than the functional reporting currency of the
subsidiaries. The Company considers its current risk exposure to exchange rate
movements, based on net cash flows, to be immaterial.
EMPLOYEES
On December 31, 1999, Apache had 1,429 employees.
OFFICES
Apache's principal executive offices are located at One Post Oak Central,
2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 1999,
the Company maintained regional exploration and/or production offices in Tulsa,
Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western
Australia; Beijing, China; and Warsaw, Poland.
10
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ITEM 2. PROPERTIES
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
Acreage
The undeveloped and developed acreage including both domestic leases and
international production and exploration rights that Apache held as of December
31, 1999, are as follows:
UNDEVELOPED ACREAGE DEVELOPED ACREAGE
----------------------- ---------------------
GROSS NET GROSS NET
ACRES ACRES ACRES ACRES
---------- ---------- --------- ---------
OFFSHORE
Louisiana.............................. 190,259 138,863 378,885 245,075
Texas.................................. 46,992 22,301 151,200 75,965
---------- ---------- --------- ---------
Total........................ 237,251 161,164 530,085 321,040
---------- ---------- --------- ---------
MIDCONTINENT
Arkansas............................... 3,004 2,122 4,299 3,190
Kansas................................. 200 93 -- --
Louisiana.............................. 8,600 5,922 38,088 26,254
Michigan............................... 4,937 4,262 -- --
Oklahoma............................... 148,562 54,032 477,622 185,449
Pennsylvania........................... -- -- 796 38
Texas.................................. 60,939 39,605 132,854 70,968
---------- ---------- --------- ---------
Total........................ 226,242 106,036 653,659 285,899
---------- ---------- --------- ---------
SOUTHERN
Alaska................................. 14,262 -- -- --
Colorado............................... 13,974 12,228 10,979 10,715
Illinois............................... 140 56 -- --
Louisiana.............................. 75,352 71,120 86,722 66,196
New Mexico............................. 79,704 44,465 84,818 43,593
Texas.................................. 188,819 85,660 418,429 270,162
Utah................................... 140 35 60 15
Wyoming................................ 29,076 21,769 680 227
---------- ---------- --------- ---------
Total........................ 401,467 235,333 601,688 390,908
---------- ---------- --------- ---------
Total United States.......... 864,960 502,533 1,785,432 997,847
---------- ---------- --------- ---------
INTERNATIONAL
Australia.............................. 3,234,060 1,664,440 445,050 259,240
Canada................................. 785,189 474,759 604,083 421,942
China.................................. 42,678 21,384 5,911 1,448
Egypt.................................. 22,821,527 11,335,426 842,863 468,143
Ivory Coast............................ -- -- -- --
Poland................................. 11,468,335 5,734,169 -- --
---------- ---------- --------- ---------
Total International.......... 38,351,789 19,230,178 1,897,907 1,150,773
---------- ---------- --------- ---------
Total Company................ 39,216,749 19,732,711 3,683,339 2,148,620
========== ========== ========= =========
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Productive Oil and Gas Wells
The number of productive oil and gas wells, operated and non-operated, in
which Apache had an interest as of December 31, 1999, is set forth below:
GAS OIL
------------- -------------
GROSS NET GROSS NET
----- ----- ----- -----
Offshore............................................... 209 111 316 230
Midcontinent........................................... 1,692 571 532 141
Southern............................................... 417 230 3,518 1,895
Canada................................................. 654 468 851 562
Egypt.................................................. 20 8 150 75
Australia.............................................. 8 5 20 11
----- ----- ----- -----
Total........................................ 3,000 1,393 5,387 2,914
===== ===== ===== =====
Gross Wells Drilled
The following table sets forth the number of gross exploratory and gross
development wells drilled in the last three fiscal years in which the Company
participated. The number of wells drilled refers to the number of wells
commenced at any time during the respective fiscal year. "Productive" wells are
either producing wells or wells capable of commercial production. At December
31, 1999, the Company was participating in 27 wells in the U.S., 23 Canadian
wells, seven Egyptian wells, one Australian well and one Polish well in the
process of drilling.
EXPLORATORY DEVELOPMENTAL
------------------------ ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
1999
United States................................ 11 13 24 97 9 106
Canada....................................... 2 3 5 30 14 44
Australia.................................... 2 12 14 5 1 6
Egypt........................................ 3 2 5 38 3 41
Other International.......................... -- 5 5 2 -- 2
-- -- --- --- -- ---
Total.............................. 18 35 53 172 27 199
== == === === == ===
1998
United States................................ 20 16 36 163 34 197
Canada....................................... 17 12 29 30 7 37
Egypt........................................ 11 24 35 27 5 32
Australia.................................... 7 8 15 -- -- --
Other International.......................... -- 1 1 1 -- 1
-- -- --- --- -- ---
Total.............................. 55 61 116 221 46 267
== == === === == ===
1997
United States................................ 27 25 52 234 32 266
Canada....................................... 19 14 33 41 7 48
Egypt........................................ 7 19 26 23 4 27
Australia.................................... 3 6 9 6 1 7
Other International.......................... 1 2 3 1 -- 1
-- -- --- --- -- ---
Total.............................. 57 66 123 305 44 349
== == === === == ===
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Net Wells Drilled
The following table sets forth, for each of the last three fiscal years,
the number of net exploratory and net developmental wells drilled by Apache:
EXPLORATORY DEVELOPMENTAL
------------------------- -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- ---- ----- ---------- ---- -----
1999
United States..................................... 4.1 8.2 12.3 59.1 4.8 63.9
Canada............................................ 1.3 2.3 3.6 26.2 12.1 38.3
Australia......................................... 2.0 5.4 7.4 2.6 .2 2.8
Egypt............................................. 1.6 1.2 2.8 15.6 1.2 16.8
Other International............................... -- 1.6 1.6 .5 -- .5
---- ---- ---- ----- ---- -----
Total................................... 9.0 18.7 27.7 104.0 18.3 122.3
==== ==== ==== ===== ==== =====
1998
United States..................................... 9.9 11.1 21.0 64.0 18.8 82.8
Canada............................................ 16.2 11.0 27.2 28.3 6.1 34.4
Egypt............................................. 5.6 13.5 19.1 11.9 2.8 14.7
Australia......................................... 3.5 3.4 6.9 -- -- --
Other International............................... -- .2 .2 .2 -- .2
---- ---- ---- ----- ---- -----
Total................................... 35.2 39.2 74.4 104.4 27.7 132.1
==== ==== ==== ===== ==== =====
1997
United States..................................... 11.5 11.9 23.4 107.5 19.0 126.5
Canada............................................ 14.5 10.1 24.6 29.0 6.0 35.0
Egypt............................................. 3.7 12.3 16.0 14.4 2.0 16.4
Australia......................................... 1.0 1.0 2.0 1.8 .2 2.0
Other International............................... .5 1.4 1.9 .5 -- .5
---- ---- ---- ----- ---- -----
Total................................... 31.2 36.7 67.9 153.2 27.2 180.4
==== ==== ==== ===== ==== =====
Production and Pricing Data
The following table describes, for each of the last three fiscal years,
oil, natural gas liquids (NGL) and gas production for the Company, average
production costs (excluding severance taxes) and average sales prices.
PRODUCTION AVERAGE SALES PRICE
--------------------------- AVERAGE ---------------------------------
OIL NGL GAS PRODUCTION OIL NGL GAS
YEAR ENDED DECEMBER 31, (MBBLS) (MBBLS) (MMCF) COST PER BOE (PER BBL) (PER BBL) (PER MCF)
- ----------------------- ------- ------- ------- ------------ --------- --------- ---------
1999..................... 33,223 1,437 239,484 $2.56 $18.43 $9.42 $2.16
1998..................... 26,611 1,052 215,389 2.88 12.66 7.94 1.92
1997..................... 24,291 843 222,237 3.07 19.20 14.08 2.28
Estimated Reserves and Reserve Value Information
The following information relating to estimated reserve quantities, reserve
values and discounted future net revenues is derived from, and qualified in its
entirety by reference to, the more complete reserve and revenue information and
assumptions included in the Company's Supplemental Oil and Gas Disclosures under
Item 8 below. The Company's estimates of proved reserve quantities of its U.S.,
Canadian and international properties have been subject to review by Ryder Scott
Company, L.P. Petroleum Consultants. 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
information represents estimates only and should not be construed as being
exact.
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The following table sets forth the Company's estimated proved developed and
undeveloped reserves as of December 31, 1999, 1998 and 1997:
OIL, NGL
NATURAL AND
GAS CONDENSATE
(BCF) (MMBBLS)
------- ----------
1999
Developed................................................... 1,873.7 302.0
Undeveloped................................................. 477.9 113.2
------- -----
Total............................................. 2,351.6 415.2
======= =====
1998
Developed................................................... 1,450.1 178.0
Undeveloped................................................. 722.1 73.0
------- -----
Total............................................. 2,172.2 251.0
======= =====
1997
Developed................................................... 1,554.3 203.1
Undeveloped................................................. 317.5 70.7
------- -----
Total............................................. 1,871.8 273.8
======= =====
The following table sets forth the estimated future value of all the
Company's proved reserves, and proved developed reserves, as of December 31,
1999, 1998 and 1997. Future reserve values are based on year-end prices except
in those instances where the sale of gas and oil is covered by contract terms
providing for determinable escalations. Operating costs, production and ad
valorem taxes, and future development costs are based on current costs with no
escalations.
PRESENT VALUE OF ESTIMATED
FUTURE NET REVENUES
ESTIMATED FUTURE BEFORE INCOME TAXES
NET REVENUES (DISCOUNTED AT 10 PERCENT)
------------------------ ---------------------------
PROVED PROVED
DECEMBER 31, PROVED DEVELOPED PROVED DEVELOPED
- ------------ ----------- ---------- ------------ ------------
(IN THOUSANDS)
1999................................ $10,392,116 $8,638,015 $6,068,013 $4,890,340
1998................................ 3,994,612 2,793,698 2,395,888 1,764,887
1997................................ 5,347,892 4,301,768 3,272,618 2,728,747
At December 31, 1999, estimated future net revenues expected to be received
from all the Company's proved reserves and proved developed reserves were as
follows:
PROVED
DECEMBER 31, PROVED DEVELOPED
------------ ----------- ----------
(IN THOUSANDS)
2000........................................................ $ 1,128,516 $1,178,935
2001........................................................ 1,136,113 1,081,851
2002........................................................ 1,077,281 902,930
Thereafter.................................................. 7,050,206 5,474,299
----------- ----------
Total............................................. $10,392,116 $8,638,015
=========== ==========
The Company believes that no major discovery or other favorable or adverse
event has occurred since December 31, 1999, which would cause a significant
change in the estimated proved reserves reported herein. The estimates above are
based on year-end pricing in accordance with the SEC guidelines and do not
reflect current prices. Since January 1, 2000, no oil or gas reserve information
has been filed with, or included in any report to, any U.S. authority or agency
other than the SEC and the Energy Information Administration
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(EIA). The basis of reporting reserves to the EIA for the Company's reserves is
identical to that set forth in the foregoing table.
Title to Interests
The Company believes that its 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 the Company's operations. The interests owned by the Company
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 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 the Company's operations.
ITEM 3. LEGAL PROCEEDINGS
The information set forth under the caption "Litigation" in Note 10 to the
Company's financial statements under Item 8 below is incorporated herein by
reference.
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 1999.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Apache's 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 Apache common stock for 1999 and
1998. Prices shown are from the New York Stock Exchange Composite Transactions
Reporting System.
1999 1998
----------------------------- -----------------------------
PRICE RANGE PRICE RANGE
---------------- DIVIDENDS ---------------- DIVIDENDS
HIGH LOW PER SHARE HIGH LOW PER SHARE
------ ------ --------- ------ ------ ---------
First Quarter......................... $28 9/16 $17 5/8 $.07 $38 3/4 $31 3/16 $.07
Second Quarter........................ 39 7/8 25 1/16 .07 38 1/8 30 3/8 .07
Third Quarter......................... 49 15/16 37 .07 32 3/8 22 1/2 .07
Fourth Quarter........................ 44 30 .07 29 5/16 21 3/8 .07
The closing price per share of Apache common stock, as reported on the New
York Stock Exchange Composite Transactions Reporting System for February 29,
2000, was $36 1/2. At December 31, 1999, there were 113,996,464 shares of Apache
common stock outstanding, held by approximately 10,000 shareholders of record
and 45,000 beneficial owners.
The Company has paid cash dividends on its common stock for 132 consecutive
quarters through December 31, 1999, and expects to continue the payment of
dividends at current levels. During 2000, the Company will implement a change in
the payment dates for the dividends on its common stock from a quarterly basis
to an annual basis. When, and if, declared by the Company's board of directors,
future dividend payments will depend upon the Company's level of earnings,
financial requirements and other relevant factors.
In December 1995, the Company declared a dividend of one right (a Right)
for each share of Apache common stock outstanding on January 31, 1996. Each
Right entitles the registered holder to purchase from
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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. The Company may 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.
In August 1998, the Company issued 100,000 shares of 5.68 percent Series B
Cumulative Preferred Stock (the 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. Neither the shares of Series B Preferred Stock nor the
depositary shares are traded on any stock exchange. The shares of Series B
Preferred Stock are not convertible into common equity. Holders of the
depositary shares are entitled to receive cumulative cash dividends at an annual
rate of $5.68 per depositary share when, and if, declared by the Company's board
of directors.
In May 1999, the Company issued 14,950,000 shares of its common stock and
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 one share
and not less than 0.8197 of a share of the Company's common stock, depending on
the market price of the common stock at that time. 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 0.8197 of a share of the
Company's common stock (5,737,900 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 the Company's board of
directors.
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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, 1999, 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 8 below.
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1999(1) 1998(2) 1997(3) 1996(4) 1995(5)
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA
Total revenues....................... $1,300,505 $ 875,715 $1,176,273 $ 977,151 $ 750,702
Net income (loss).................... 200,855 (129,387) 154,896 121,427 20,207
Income (loss) attributable to common
stock.............................. 186,406 (131,391) 154,896 121,427 20,207
Net income (loss) per common share:
Basic.............................. 1.73 (1.34) 1.71 1.42 .28
Diluted............................ 1.72 (1.34) 1.65 1.38 .28
Cash dividends per common share...... .28 .28 .28 .28 .28
BALANCE SHEET DATA
Working capital (deficit)............ $ 6,290 $ (78,804) $ 4,546 $ (41,501) $ (22,013)
Total assets......................... 5,502,543 3,996,062 4,138,633 3,432,430 2,681,450
Long-term debt....................... 1,879,650 1,343,258 1,501,380 1,235,706 1,072,076
Shareholders' equity................. 2,669,427 1,801,833 1,729,177 1,518,516 1,091,805
Common shares outstanding at end of
year............................... 113,996 97,769 93,305 90,059 77,379
For a discussion of significant acquisitions, reference is made to Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and to Note 2 to the Company's consolidated financial statements
under Item 8 below.
- ---------------
(1) Includes the results of the acquisitions of certain oil and gas properties
from Petsec, Shell Offshore, British-Borneo and Shell Canada after February
1, 1999, May 18, 1999, June 18, 1999 and November 30, 1999, respectively.
(2) Includes the results of the acquisitions of certain subsidiaries and oil and
gas properties from Novus Petroleum Limited (Novus) after December 18, 1998.
Also includes a $243.2 million pre-tax ($158.1 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.
(3) Includes financial data after November 20, 1997, relating to the acquisition
from Mobil Exploration & Producing Australia Pty Ltd (Mobil) of three
companies owning interests in certain oil and gas properties and production
facilities offshore Western Australia (the Ampolex Group Transaction).
(4) Includes financial data after May 20, 1996, for Apache PHN Company, Inc.
(Phoenix, formerly known as The Phoenix Resource Companies, Inc.).
(5) Includes the results of the acquisitions of certain oil and gas properties
from Texaco Exploration and Production, Inc. and Aquila Energy Resources
Corporation after March 1, 1995 and September 1995, respectively, and the
sale of a substantial portion of the Company's Rocky Mountain properties in
September 1995.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Apache's considerable progress in 1999 and favorable outlook for continued
growth were not fully reflected in the Company's stock price at year-end. While
Wall Street turned its attention to technology stocks, Apache recorded its best
year ever, paving the way for its 23rd consecutive year of production growth in
2000.
1999 performance highlights include record:
- Production of 204.3 thousand barrels of oil equivalent per day, up 17
percent.
- Proved reserves of 807.2 MMboe, up 32 percent.
- Net cash provided by operating activities of $638.2 million, up 35
percent.
- Net income attributable to common stock of $186.4 million, up $31.5
million over our 1997 record.
More important than these milestones is the position they have left Apache
for continued progress ahead.
- $1.8 billion of capital expenditures brought into our fold quality assets
with low operating costs and high margins. The two acquisitions from
Shell coupled with first production from major development projects in
Egypt and Australia contributed to a $.32 per boe decline in Apache's
lease operating expense per equivalent barrel produced.
- Record 1999 earnings coupled with $654.8 million of equity offerings
reduced Apache's debt to 41.4 percent of capitalization, among the
strongest in our sector and capable of funding substantial growth
opportunities.
- Rising production will generate substantial cash flow. While prices are
always a wildcard, should they approximate levels indicated by the
current New York Mercantile Exchange, Apache has the potential to achieve
$1 billion of cash flow in 2000, adding fuel with which to act on
opportunities that many of Apache's competitors are unable to capture.
In short, despite only partial recognition in our stock price, Apache's
progress in 1999 puts the company in its strongest financial position ever to
carry out its business strategy and continue to build lasting shareholder value.
Apache's results of operations and financial position for 1999 were also
significantly impacted by the following factors:
Commodity Prices -- Apache's average realized oil price increased $5.77 per
barrel from $12.66 per barrel in 1998 to $18.43 per barrel in 1999, increasing
revenues by $153.6 million. The average realized price for natural gas increased
$.24 per Mcf from $1.92 per Mcf in 1998 to $2.16 per Mcf in 1999, positively
impacting revenues by $50.7 million.
Operations -- Oil production increased 25 percent in 1999 compared to the
prior year. The increase was primarily due to the acquisition of certain blocks
in the Gulf of Mexico from Shell Offshore, included since mid-May of 1999, the
full-period impact of the acquisition of certain oil and gas interests in the
Carnarvon Basin, offshore Western Australia, from Novus in November 1998 and
production from Australia's Stag field which began in May 1998. The increase in
oil production positively impacted revenues by $121.9 million. Gas production
increased 11 percent, which increased revenues by $52.0 million. As with oil,
gas increased in the U.S. due to the Shell Offshore acquisition. In Egypt, the
Western Desert Gas Pipeline in the Khalda concession was completed and first
sales commenced in August 1999.
RESULTS OF OPERATIONS
Apache reported 1999 income attributable to common stock of $186.4 million,
up from a loss attributable to common stock of $131.4 million in 1998. A
significant increase in oil and gas production revenues was
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partially offset by higher recurring depreciation, depletion and amortization
(DD&A) expense, operating costs, preferred stock dividends, and administrative,
selling and other (G&A) expense. Basic net income (loss) per common share was
$1.73 for 1999, as compared to $(1.34) in 1998. A loss attributable to common
stock of $131.4 million was reported in 1998 as opposed to income attributable
to common stock of $154.9 million in 1997. The 1998 loss resulted from a
full-cost ceiling write-down at year end. Results for 1998 were further hampered
by sharp declines in oil and gas prices. Basic net income (loss) per common
share was $(1.34) for 1998, as compared to basic net income per share of $1.71
in 1997.
Oil and gas production revenues increased 50 percent in 1999 to $1.1
billion as compared to $759.0 million in 1998. The increase resulted from a 46
percent increase in the average realized oil price, a 13 percent increase in the
average realized natural gas price, a 25 percent increase in oil production and
an 11 percent increase in natural gas production. Crude oil, including natural
gas liquids, contributed 55 percent and natural gas contributed 45 percent of
total oil and gas production revenues during 1999. Oil and gas production
revenues decreased 23 percent in 1998 to $759.0 million as compared to $983.8
million in 1997. The decrease resulted from a 34 percent decrease in the average
realized oil price, a 16 percent decrease in the average realized price for
natural gas and a three percent decrease in gas production. Crude oil, including
natural gas liquids, contributed 45 percent and natural gas contributed 55
percent of oil and gas production revenues during 1998.
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The table below presents, for the years indicated, the 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,
--------------------------------
1999 1998 1997
---------- -------- --------
Revenues (in thousands):
Natural gas............................................... $ 516,503 $413,870 $505,604
Oil....................................................... 612,298 336,813 466,291
Natural gas liquids....................................... 13,535 8,355 11,878
---------- -------- --------
Total............................................. $1,142,336 $759,038 $983,773
========== ======== ========
Natural Gas Volume -- Mcf per day:
United States............................................. 461,444 432,059 492,594
Canada.................................................... 99,791 105,871 89,699
Egypt..................................................... 15,916 1,554 563
Australia................................................. 76,220 50,624 26,016
Ivory Coast............................................... 2,749 -- --
---------- -------- --------
Total............................................. 656,120 590,108 608,872
========== ======== ========
Average Natural Gas Price -- Per Mcf:
United States............................................. $ 2.31 $ 2.11 $ 2.47
Canada.................................................... 1.73 1.36 1.33
Egypt..................................................... 3.45 1.91 2.94
Australia................................................. 1.51 1.51 1.78
Ivory Coast............................................... 1.72 -- --
Total............................................. 2.16 1.92 2.28
Oil Volume -- Barrels per day:
United States............................................. 45,556 34,067 40,638
Canada.................................................... 3,053 2,090 2,120
Egypt..................................................... 31,751 27,911 19,372
Australia................................................. 10,624 8,838 4,417
Ivory Coast............................................... 37 -- --
---------- -------- --------
Total............................................. 91,021 72,906 66,547
========== ======== ========
Average Oil Price -- Per barrel:
United States............................................. $ 17.94 $ 12.63 $ 19.31
Canada.................................................... 19.35 12.55 19.27
Egypt..................................................... 18.63 12.57 18.65
Australia................................................. 19.70 13.07 20.51
Ivory Coast............................................... 15.68 -- --
Total............................................. 18.43 12.66 19.20
NGL Volume -- Barrels per day:
United States............................................. 3,308 2,267 1,684
Canada.................................................... 630 616 627
---------- -------- --------
Total............................................. 3,938 2,883 2,311
========== ======== ========
Average NGL Price -- Per barrel:
United States............................................. $ 9.37 $ 8.38 $ 14.50
Canada.................................................... 9.64 6.32 12.98
Total............................................. 9.42 7.94 14.08
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
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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.
Natural gas revenues increased by 25 percent from 1998 to 1999 as a result
of increased production volumes and realized prices. The average realized gas
price increased 13 percent in 1999 positively affecting revenues by $50.7
million. U.S. natural gas production, which comprised 70 percent of the
Company's worldwide gas production, sold at an average price of $2.31 per Mcf,
nine percent higher than in 1998, positively impacting natural gas sales by
$32.4 million. The Company periodically engages in hedging activities, including
fixed-price physical contracts and financial contracts. Gains under long-term
fixed-price physical contracts increased the gas price by $.02 per Mcf in 1999
while realized losses from open hedging positions negatively impacted the gas
price by $.01 per Mcf in 1999.
Natural gas production increased 66 million cubic feet per day (MMcf/d), or
11 percent, on a worldwide basis, favorably impacting revenue by $52.0 million
in 1999. In the United States, gas production increased 29.4 MMcf/d due to
acquisition activities, primarily the Shell Offshore acquisition in 1999.
Development activities and the impact of producing property acquisitions during
late 1998 increased natural gas production in Australia by 25.6 MMcf/d. Egyptian
gas production increased ten fold in 1999 as a result of the completion of the
northern portion of the Western Desert Gas Pipeline in the Khalda concession,
with first sales commencing in August.
Natural gas revenues decreased by 18 percent from 1997 to 1998 due to lower
natural gas prices and production. The average realized gas price received in
1998 was $1.92 per Mcf, 16 percent lower than 1997, negatively affecting revenue
by $78.6 million. The Company periodically engages in hedging activities,
including fixed-price physical contracts and financial contracts. Apache
realized gains from open hedging positions favorably impacting the gas price by
$.01 per Mcf in 1998. Gains under long-term fixed-price physical contracts
increased the gas price by $.05 per Mcf in 1998. Prices declined in the United
States due to unfavorable market conditions. Natural gas prices in Australia
declined 15 percent from 1997 resulting from the devaluation of the Australian
dollar.
Natural gas production for the United States decreased 12 percent from 1997
to 1998 due to the impact of property sales in the Southern and Midcontinent
regions, tropical storms in the Gulf of Mexico and natural depletion. In
Australia, natural gas production increased 95 percent driven by a full year of
incremental production from properties acquired in the year-end 1997 Ampolex
Group Transaction. The 18 percent uplift in Canadian production resulted from
development activity and Alberta royalty recoupments received for 1998. Alberta
allows reduction in royalty for costs to build processing and transportation
facilities.
Crude oil revenues totaled $612.3 million in 1999, an 82 percent increase
from 1998 due to higher average realized oil prices and production increases. On
a worldwide basis, average oil prices increased 46 percent to $18.43 per barrel
positively impacting oil sales by $153.6 million. Realized losses from open
hedging positions negatively impacted the oil price by $.16 per barrel in 1999.
Oil production increased 18,115 barrels per day, or 25 percent, in 1999 due
primarily to increases in the United States. Domestic oil production increased
11,489 barrels per day, or 34 percent, primarily due to the Shell Offshore
acquisition. Australian oil production increased 1,786 barrels per day, or 20
percent, over 1998 with additional full-year production from the Stag field.
Egyptian oil production increased 3,840 barrels per day, or 14 percent, as a
result of the price-driven dynamics of certain production sharing contracts and
development activity.
Crude oil revenues totaled $336.8 million in 1998, a 28 percent decrease
from 1997 due to lower average realized oil prices, which were partially offset
by production increases. On a worldwide basis, average oil prices decreased 34
percent to $12.66 per barrel negatively impacting oil revenues by $158.9
million. Oil production increased 6,359 barrels per day (approximately 10
percent), in 1998 due to increases in Egypt and Australia. Australian oil
production increased 4,421 barrels per day over 1997 with additional production
from the Ampolex Group Transaction and initial sales from the Stag field.
Egyptian oil production increased 8,539 barrels per day, or 44 percent, as a
result of the price-driven dynamics of certain production sharing
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contracts and to a lesser extent, drilling and development activity. U.S. oil
production decreased by 6,571 barrels per day, or 16 percent, primarily due to
marginal property sales in the first half of 1998 and natural reservoir
depletion of mature fields.
Natural gas liquids revenues in 1999 increased 62 percent from 1998.
Natural gas liquids production increased 1,055 barrels per day, or 37 percent
and natural gas liquids prices increased by $1.48 per barrel, or 19 percent, due
to improved market conditions. Natural gas liquids revenues decreased 30 percent
in 1998. Natural gas liquids production increased 572 barrels per day, or 25
percent, while natural gas liquids prices declined by $6.14 per barrel, or 44
percent, due to deteriorating market conditions.
Other Revenues and Operating Expenses
Gas gathering, processing and marketing revenues increased 33 percent to
$155.6 million in 1999 from 1998. Higher gas prices in 1999 contributed to the
increase. Gas gathering, processing and marketing costs increased by 34 percent
to $153.4 million resulting in a slight decrease to 1999 margins. During 1998,
gas gathering, processing and marketing revenues decreased 40 percent to $117.4
million. Slightly higher margins were realized in 1998 as compared to 1997.
Recurring DD&A expense increased to $442.8 million in 1999 from $382.8
million in 1998. On an equivalent barrel basis, recurring full cost DD&A expense
decreased $.09 per boe, from $5.66 per boe in 1998 to $5.57 per boe in 1999. The
decrease in the overall DD&A rate was the result of substantial increases in
United States production volumes during 1999 and the ceiling test write-down in
1998, which lowered the carrying amount of those properties being depleted. The
Company's recurring DD&A expense increased to $382.8 million in 1998 from $381.4
million in 1997. On an equivalent barrel basis, recurring full cost DD&A expense
decreased $.11 per boe, from $5.77 per boe in 1997 to $5.66 per boe in 1998.
Apache limits, on a country-by-country basis, the capitalized cost of oil
and gas properties, net of accumulated DD&A and deferred income taxes, to
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. As a result of low
oil and gas prices in the United States at December 31, 1998, Apache's
capitalized costs of oil and gas properties exceeded the ceiling limitation and
the Company reported a $243.2 million pre-tax ($158.1 million net of tax)
non-cash write-down as additional DD&A expense. No additional DD&A expense was
recorded during 1999 or 1997. Write-downs required by these rules do not impact
cash flow from operating activities.
Apache's operating costs increased six percent in 1999 to $223.6 million
from $211.6 in 1998. Lease operating expense (LOE), excluding severance taxes,
increased from $182.9 million in 1998 to $191.2 million in 1999. On an
equivalent barrel basis, LOE for 1999 averaged $2.56 per boe, a $.32 decline
from $2.88 per boe in 1998. Domestic per unit costs were significantly reduced
due to lower Southern region repairs, maintenance, power and fuel costs
resulting from the sale of marginal properties partially offset by increases in
the Offshore region due to workover costs associated with acquired properties
located in the Gulf of Mexico from Petsec and Shell Offshore. Operating costs
decreased nine percent to $211.6 million in 1998 from $231.4 million in 1997.
LOE, excluding severance taxes, decreased from $190.8 million in 1997 to $182.9
million in 1998. On an equivalent barrel basis, LOE for 1998 averaged $2.88 per
boe, a $.19 decline from $3.07 per boe in 1997. Domestic per unit costs were
significantly reduced from the sale of marginal North American properties, and
by lower Southern region repairs and maintenance costs.
G&A expense increased $13.2 million, or 32 percent, from 1998 to 1999. The
Company's overall infrastructure was enlarged to properly handle increased
responsibilities associated with 1999 North American producing property
acquisitions. On an equivalent barrel basis, G&A expense increased to $.72 per
boe in 1999 compared to $.64 per boe in 1998. G&A expense increased $2.5
million, or seven percent from 1997 to 1998. On an equivalent barrel basis, G&A
expense increased to $.64 per boe in 1998 compared to $.62 per boe in 1997. The
increase in G&A expense was primarily the result of employee separation payments
associated with the sale of marginal North American properties.
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Net financing costs for 1999 increased $11.7 million, or 17 percent, from
1998 primarily due to higher interest expense and lower interest income,
partially offset by higher capitalized interest. Gross interest expense
increased $13.3 million resulting from higher average outstanding debt in 1999.
The weighted average interest rate on outstanding debt increased to 7.5 percent
at December 31, 1999 from 7.2 percent at December 31, 1998. The increase in
capitalized interest is associated with Egyptian pipeline projects under
construction. The decrease in interest income was due to a lower average cash
balance during 1999. Net financing costs for 1998 decreased $1.8 million, or two
percent, from 1997 primarily due to higher capitalized interest. Gross interest
expense increased $14.6 million due to a slightly higher interest rate on
average outstanding debt in 1998 compared to 1997 and higher imputed interest on
advances from gas purchasers. This was offset by an increase in capitalized
interest, interest income and lower amortization of deferred loan costs. The
Company's weighted average interest rate on outstanding debt was 7.2 percent at
December 31, 1998 compared to 7.1 percent at December 31, 1997.
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 $10.09 per barrel to a high of $24.11 per barrel during 1999. Gas price
realizations ranged from a monthly low of $1.60 per Mcf to a monthly high of
$2.74 per Mcf during the same period.
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 hold or issue derivative
instruments for trading purposes. In 1999, Apache recognized a net loss of $3.1
million from hedging activities that decreased oil and gas production revenues.
The net loss in 1999 includes $6.7 million in derivatives losses and $3.6
million in gains from fixed-price physical gas contracts. Gains or losses on
derivative contracts are expected to be offset by sales at the spot market price
or to preserve the margin on existing physical gas contracts.
At December 31,1999, the Company had open natural gas price swap positions
with a positive fair value of $11.1 million. A 10 percent increase in natural
gas prices would increase the fair value by $19.7 million. A 10 percent decrease
in prices would decrease the fair value by $19.7 million. The Company also had
open oil price swap positions at December 31, 1999 with a negative fair value of
$(9.4) million. A 10 percent increase in oil prices would decrease the fair
value by $18.3 million. A 10 percent decrease in oil prices would increase the
fair value by $18.3 million. Discount rates used in arriving at fair values
range from 6.5 percent for 2000 to 7.3 percent for 2008.
At December 31, 1999, the Company also had natural gas commodity collars
with a fair value of $.8 million and oil commodity collars with a fair value of
$(4.9) million. A 10 percent increase in oil and gas prices would change the
fair values of the gas collars and the oil collars by $(.9) million and $(5.2)
million, respectively. A 10 percent decrease in oil and gas prices would change
the fair values of the gas collars and the oil collars by $1.6 million and $3.9
million, respectively. The model used to arrive at the fair values for the
commodity collars is based on the Black commodity pricing model. Changes in fair
value, assuming 10 percent price changes, assume non-constant volatility with
volatility based on prevailing market parameters at December 31,1999.
Notional volumes associated with the Company's derivative contracts are
shown in Note 9 to the Company's consolidated financial statements.
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Interest Rate Risk
The Company considers its interest rate risk exposure to be minimal as a
result of fixing interest rates on approximately 83 percent of the Company's
debt. Total debt at December 31, 1999, included $318.7 million of floating-rate
debt. As a result, Apache's annual interest costs in 2000 will fluctuate based
on short-term interest rates on approximately 17 percent of its total debt
outstanding at December 31, 1999. The impact on annual cash flow of a 10 percent
change in the floating rate (approximately 69 basis points) would be
approximately $2.2 million. The Company did not have any open derivative
contracts relating to interest rates at December 31, 1999.
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 on the
transaction date. Reported cash flow relating to Canadian operations is based on
cash flows measured in Canadian dollars converted to the U.S. dollar equivalent
based on the average of the Canadian and U.S. dollar exchange rates for the
period reported. Substantially all of the Company's international transactions,
outside of Canada and Australia, are denominated in U.S. dollars.
The Company's Polish and Australian subsidiaries have net financial assets
that are denominated in a currency other than the functional reporting currency
of the subsidiaries. A decrease in value of 10 percent in the Australian dollar
and Polish zloty relative to the U.S. dollar from the year-end exchange rates
would result in a foreign currency loss of approximately $.7 million, based on
December 31, 1999 amounts. The Company considers its current risk exposure to
exchange rate movements, based on net cash flows, to be immaterial. The Company
did not have any open derivative contracts relating to foreign currencies at
December 31, 1999.
CASH FLOW, LIQUIDITY AND CAPITAL RESOURCES
Capital Commitments
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, payment of dividends, and capital obligations for affiliated
ventures. 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.
Capital Expenditures -- Apache's oil and gas capital expenditures over the
last three years are summarized below:
1999 1998 1997
---------- -------------- --------
(IN THOUSANDS)
Exploration and Development:
United States.................................. $ 217,476 $222,750 $359,272
Canada......................................... 45,691 69,757 56,263
Egypt.......................................... 59,808 105,431 139,938
Australia...................................... 60,976 80,099 68,563
Ivory Coast.................................... 2,553 23,527 556
Other International............................ 18,835 39,856 24,335
---------- -------- --------
405,339 541,420 648,927
Capitalized Interest........................... 45,722 49,279 36,493
---------- -------- --------
Total.................................. $ 451,061 $590,699 $685,420
========== ======== ========
Acquisitions of Oil and Gas Properties........... $1,391,206 $ 58,402 $225,934
========== ======== ========
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27
Expenditures for exploration and development totaled $405.3 million in 1999
compared to $541.4 million in 1998. Apache's drilling program in 1999 added 64.1
MMboe of proved reserves (including revisions) and replaced 86 percent of
production. In the United States, Apache completed 108 gross wells as producers
out of 130 gross wells drilled during the year, compared with 183 gross
producers out of 233 gross wells drilled in 1998. In Canada, Apache completed 32
gross wells as producers out of 49 gross wells drilled during the year, compared
with 47 gross producers out of 66 gross wells drilled in 1998.
Internationally, the Company completed 50 gross producers out of 73 gross
wells drilled in 1999, compared to 46 gross producers out of 84 gross wells in
1998. Successful international wells drilled in 1999 included 41 in Egypt and
seven in Australia.
The total capital expenditures budget for 2000 is $597.5 million, including
$384.9 million for North America. Estimated North American exploration and
development expenditures include $56.4 million in the Southern region, $67.1
million in the Midcontinent region, $151.5 million in the Offshore region and
$109.9 million in Canada. The Company has estimated its other international
exploration and development expenditures in 2000, exclusive of facilities, to
total approximately $212.6 million. Capital expenditures will be reviewed and
possibly adjusted throughout the year in light of changing industry conditions.
On February 1, 1999, the Company acquired oil and gas properties located in
the Gulf of Mexico from Petsec for an adjusted purchase price of $67.7 million.
The Petsec transaction included estimated proved reserves of approximately 10.2
MMboe as of the acquisition date.
On May 18, 1999, Apache acquired from Shell Offshore its interest in 22
producing fields and 16 undeveloped blocks located in the Gulf of Mexico. The
Shell Offshore acquisition also included certain production-related assets and
proprietary 2D and 3D seismic data covering approximately 1,000 blocks in the
Gulf of Mexico. The purchase price was $687.7 million in cash and one million
shares of Apache common stock (valued at $28.125 per share). The Shell Offshore
acquisition included approximately 123.2 MMboe of proved reserves as of the
acquisition date.
On June 18, 1999, the Company acquired a 10 percent interest in the East
Spar Joint Venture and an 8.4 percent interest in the Harriet Joint Venture,
both located in the Carnarvon Basin (offshore Western Australia), from
British-Borneo in exchange for $83.6 million cash and working interests in 11
leases in the Gulf of Mexico. The British-Borneo transaction included
approximately 16.8 MMboe of proved reserves as of the acquisition date.
On November 30, 1999, Apache acquired from Shell Canada producing
properties and other assets for C$761 million (US$517.8 million). The producing
properties consist of 150,400 net acres and comprise 20 fields with an average
working interest of 55 percent and proved reserves of 87.2 MMboe as of the
acquisition date. Apache also acquired 294,294 net acres of undeveloped
leaseholdings, 100 percent interest in a gas processing plant with a potential
throughput capacity of 160 million cubic feet (MMcf) per day, and 52,700 square
miles of 2D seismic and 884 square miles of 3D seismic.
In 1999, the Company also completed tactical regional acquisitions for cash
consideration totaling $17.7 million. These acquisitions added approximately 8.8
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 YPF, for approximately $119 million, plus assumed liabilities of
approximately $30 million. The acquisition included estimated proved reserves of
206 Bcfe as of the acquisition date.
In November 1998, the Company entered into agreements to acquire certain
oil and gas interests and companies holding oil and gas interests in the
Carnarvon Basin, offshore Western Australia, from subsidiaries of Novus for
approximately $55 million. The interests have proved reserves of approximately
5.8 MMboe and daily production of 2,400 barrels of oil equivalent. They are
within the Apache-operated Harriet Joint Venture (which includes production,
processing and pipeline infrastructure associated with the Varanus Island hub),
the Airlie Joint Venture (in which the Company held a prior interest and became
operator) and three other
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exploration permit areas. The transaction closed in two stages, in December 1998
for approximately $49 million and in January 1999 for approximately $6 million.
In 1998, the Company also completed tactical regional acquisitions for cash
consideration totaling $19.4 million. These acquisitions added approximately 9.1
MMboe to the Company's reserves.
In November 1997, the Company acquired, in the Ampolex Group Transaction,
all the capital stock of three companies owning interests in certain oil and gas
properties (including 31.9 MMboe of proved oil and natural gas reserves) and
production facilities offshore Western Australia for approximately $300 million
pursuant to three agreements with subsidiaries of Mobil. The Ampolex Group
Transaction acquisition, net of the sale of certain properties to Hardy
Petroleum Limited (Hardy), increased the Company's interest to 47.5 percent from
22.5 percent in the Carnarvon Basin's Harriet area, which included the Varanus
Island pipeline, processing and production complex and eight existing oil and
gas fields. In addition, the Company's interest in the East Spar field, which
produces through the Varanus Island facilities, increas