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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
------------------- ---------------------
Commission File Number 0-13546
APACHE OFFSHORE INVESTMENT PARTNERSHIP
A Delaware IRS Employer
General Partnership No. 41-1464066
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: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
PARTNERSHIP UNITS
Indicate by check mark whether the Partnership (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
Partnership 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 Partnership'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. X
-----
Indicate by check whether registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). [ ]
Aggregate market value of the voting and non-voting common equity held by
non-affiliates of registrant as of June 28, 2002................ $8,713,894
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Apache Corporation's proxy statement relating to its 2003
annual meeting of stockholders have been incorporated by reference into Part III
hereof.
TABLE OF CONTENTS
DESCRIPTION
ITEM PAGE
- ---- PART I ----
1. BUSINESS...................................................................................... 1
2. PROPERTIES.................................................................................... 5
3. LEGAL PROCEEDINGS............................................................................. 6
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................................... 6
PART II
5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED
SECURITY HOLDER MATTERS.................................................................. 7
6. SELECTED FINANCIAL DATA....................................................................... 7
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS...................................................... 8
7A. MARKET RISK................................................................................... 13
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................... 14
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE...................................................... 32
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP........................................... 33
11. EXECUTIVE COMPENSATION........................................................................ 33
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................................................................... 33
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................................ 33
14. CONTROLS AND PROCEDURES....................................................................... 33
PART IV
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............................... 34
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 (bopd) and thousands of cubic feet of gas per day (Mcfd),
respectively. With respect to information relating to the Partnership's working
interest in wells or acreage, "net" oil and gas wells or acreage is determined
by multiplying gross wells or acreage by the Partnership's working interest
therein. Unless otherwise specified, all references to wells and acres are
gross.
PART I
ITEM 1. BUSINESS
GENERAL
Apache Offshore Investment Partnership (the Investment Partnership), a
Delaware general partnership, was organized in October 1983, with public
investors as Investing Partners and Apache Corporation (Apache), a Delaware
corporation, as Managing Partner. The operations of the Investment Partnership
are conducted by Apache Offshore Petroleum Limited Partnership (the Limited
Partnership), a Delaware limited partnership, of which Apache is the sole
general partner and the Investment Partnership is the sole limited partner.
The Partnership does not maintain a website, so we do not make electronic
access to our reports filed with the SEC available on or through a website. The
Partnership will, however, provide paper copies of these filings, free of
charge, to anyone so requesting. Any such requests should be made by mail to
Apache Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas
77056, Attention: David Higgins, or by telephone at 713-296-6000.
The Investing Partners purchased Units of Partnership Interests (Units) in
the Investment Partnership at $150,000 per Unit, with five percent down and the
balance in payments as called by the Investment Partnership. As of December 31,
2002, a total of $85,000 had been called for each Unit. In 1989, the Investment
Partnership determined that the full $150,000 per Unit was not needed, fixed the
total calls at $85,000 per Unit, and released the Investing Partners from
liability for future calls. The Investment Partnership invested, and will
continue to invest, its entire capital in the Limited Partnership. As used
hereafter, the term "Partnership" refers to either the Investment Partnership or
the Limited Partnership, as the case may be.
The Partnership's business is participation in oil and gas exploration,
development and production activities on federal lease tracts in the Gulf of
Mexico, offshore Louisiana and Texas. Except for the Matagorda Island Block 681
and 682 interests, as described below, the Partnership acquired its oil and gas
interests through the purchase of 85 percent of the working interests held by
Apache as a participant in a venture (the Venture) with Shell Oil Company
(Shell) and certain other companies. The Partnership owns working interests
ranging from 6.29 percent to 9.44 percent in the Venture's properties.
The Venture acquired substantially all of its oil and gas properties
through bidding for leases offered by the federal government. The Venture
members relied on Shell's knowledge and expertise in determining bidding
strategies for the acquisitions. When Shell was successful in obtaining the
properties, it generally billed participating members on a promoted basis
(one-third for one-quarter) for the acquisition of exploratory leases and on a
straight-up basis for the acquisition of leases defined as drainage tracts. All
such billings were proportionately reduced to each member's working interest.
In November 1992, Apache and the Partnership formed a joint venture to
acquire Shell's 92.6 percent working interest in Matagorda Island Blocks 681 and
682 pursuant to a jointly-held contractual preferential right to purchase.
Apache and the Partnership previously owned working interests in the blocks
equal to 1.109 percent and 6.287 percent, respectively, and net revenue
interests of .924 percent and 5.239 percent, respectively. To facilitate the
acquisition, Apache and the Partnership contributed all of their interests in
Matagorda Island Blocks 681 and 682 to a newly formed joint venture, and Apache
contributed $64.6 million ($55.6 million net of purchase price adjustments) to
the joint venture to finance the acquisition. The Partnership had neither the
cash nor additional financing to fund a proportionate share of the acquisition
and participated through an increased net revenue interest in the joint venture.
Under the terms of the joint venture agreement, the Partnership's effective
net revenue interest in the Matagorda Island Block 681 and 682 properties
increased to 13.284 percent as a result of the acquisition, while its working
interest was unchanged. The acquisition added approximately 7.5 Bcf of natural
gas and 16 Mbbls of oil to the Partnership's reserve base without any
incremental expenditures by the Partnership.
Since the Venture is not expected to acquire any additional exploratory
acreage, future acquisitions, if any, will be confined to those leases defined
as drainage tracts. The current Venture members would pay their proportionate
share of acquiring any drainage tracts on a non-promoted basis.
1
Offshore exploration differs from onshore exploration in that production
from a prospect generally will not commence until a sufficient number of
productive wells have been drilled to justify the significant costs associated
with construction of a production platform. Exploratory wells usually are
drilled from mobile platforms until there are sufficient indications of
commercial production to justify construction of a permanent production
platform.
On an ongoing basis, the Partnership reviews the possible sale of lower
value properties prior to incurring associated dismantlement and abandonment
costs.
Apache, as Managing Partner, manages the Partnership's operations. Apache
uses a portion of its staff and facilities for this purpose and is reimbursed
for actual costs paid on behalf of the Partnership, as well as for general,
administrative and overhead costs properly allocable to the Partnership.
2002 RESULTS AND BUSINESS DEVELOPMENT
The Partnership reported net income in 2002 of $3.5 million, or $2,259 per
Investing Partner Unit. Natural gas production averaged 3,353 Mcf per day, while
oil sales averaged 302 barrels per day. Production added through drilling in
2002 partially offset declines from natural depletion and weather-related
downtime.
During 2002, the Partnership participated in drilling six development wells
at South Timbalier 295, with five completed as producing wells. The Partnership
continued to participate in recompletion projects to maintain production and
enhance recoverable reserves. During 2002, the Partnership participated in four
recompletions at South Timbalier 295 and one at Matagorda 681/682.
Since inception, the Partnership has acquired an interest in 49 prospects.
As of December 31, 2002, 42 of those prospects have been surrendered or sold.
As of December 31, 2002, 131 wells have been drilled on the Partnership's
seven remaining developed fields. Of the 131 wells, 104 were productive and of
those, 52 are currently producing. Two of the Partnership's producing wells are
dual completions. The Partnership had, at December 31, 2002, estimated proved
oil and gas reserves of 11.4 Bcfe, of which 55 percent was natural gas.
MARKETING
Apache, on behalf of the Partnership, seeks and negotiates oil and gas
marketing arrangements with various marketers and purchasers. During 2002, the
Partnership's spot market gas was purchased primarily by Cinergy Marketing and
Trading, LLC. The Partnership's oil and condensate production during 2002 was
purchased largely by Apache Crude Oil Marketing, Inc. (ACOM), a wholly-owned
subsidiary of Apache.
In 1998, Apache sold its interest in Producers Energy Marketing LLC
(ProEnergy) (a gas marketing company formed by Apache and other natural gas
producers) to Cinergy Corp., with ProEnergy being renamed Cinergy Marketing &
Trading, LLC (Cinergy). In July 1998, in connection with the sale of its
interest, Apache entered into a gas purchase agreement with Cinergy to market
most of its U.S. natural gas production for a ten-year period, with an option,
after prior notice, to terminate after six years. Apache also sells most of the
Partnership's natural gas production to Cinergy under the gas purchase
agreement. Since 2001, Apache has been involved in an arbitration proceeding
with Cinergy on issues arising from the gas sales agreement. Apache continues to
market most of the Partnership's gas production through Cinergy; however, Apache
is actively discussing with Cinergy its gas marketing relationship with Cinergy
and a resolution of the related disputes. The Partnership does not expect the
final resolution of these disputes to have a material effect on its financial
position or future gas sales. The prices the Partnership receives for its gas
production, in the opinion of Apache, approximate market prices.
During 2002, ACOM purchased oil and condensate from the Partnership which
accounted for approximately 17 percent of the Partnership's total oil and gas
sales. The prices the Partnership received for these sales were based on
third-party pricing indexes and, in the opinion of Apache, were comparable to
prices that would have been received from a non-affiliated party.
See Note (5) "Major Customer and Related Parties Information" to the
Partnership's financial statements under Item 8. Because the Partnership's oil
and gas products are commodities and the prices and terms of its sales reflect
those of the market, the Partnership does not believe that the loss of any
customer would have a material adverse affect
2
on the Partnership's business or results of operations. The Partnership is not
in a position to predict future oil and gas prices.
RISK FACTORS RELATED TO THE PARTNERSHIP'S BUSINESS AND OPERATIONS
VOLATILE PRICES CAN MATERIALLY AFFECT THE PARTNERSHIP
The Partnership continually analyzes forecasts and updates its estimates of
energy prices for its internal use in planning, budgeting, and estimating and
valuing reserves. The Partnership's future financial condition and results of
operations will depend upon the prices received for the Partnership'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 Partnership.
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 Partnership'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 Partnership's oil
and gas properties.
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 Partnership's control. Reserve data
represent only estimates. In addition, the estimates of future net cash flows
from the Partnership'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 Partnership's reserves and future net
cash flows from them being materially different from the estimates. In addition,
the Partnership'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.
SUBSTANTIAL COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS
The Partnership, as an owner or lessee of interests in oil and gas
properties, is subject to various federal, state and local laws and regulations
relating to the 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 Partnership has made and will continue to make expenditures in its
efforts to comply with these requirements. These costs are inextricably
connected to normal operating expenses such that the Partnership is unable to
separate the expenses related to environmental matters; however, the Partnership
does not believe such expenditures are material to its financial position or
results of operations.
The Partnership does not believe that compliance with federal, state or
local 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 and the competitive
position of the Partnership, but 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.
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. Apache, as managing partner, maintains insurance against
certain losses or liabilities arising from the Partnership's operations in
accordance with
3
customary industry practices and in amounts that management believes to be
prudent; however, insurance is not available to the Partnership's against all
operational risks.
COMPETITION WITH OTHER COMPANIES COULD HARM THE PARTNERSHIP
The Partnership is a very minor factor in the oil and gas industry in the
Gulf of Mexico area and faces strong competition from much larger producers for
the marketing of its oil and gas. The Partnership's ability to compete for
purchasers and favorable marketing terms will depend on the general demand for
oil and gas from Gulf of Mexico producers. More particularly, it will depend
largely on the efforts of Apache to find the best markets for the sale of the
Partnership's oil and gas production.
INVESTORS IN THE PARTNERSHIP'S SECURITIES MAY ENCOUNTER DIFFICULTIES IN
OBTAINING, OR MAY BE UNABLE TO OBTAIN, RECOVERIES FROM ARTHUR ANDERSEN WITH
RESPECT TO ITS AUDITS OF OUR FINANCIAL STATEMENTS
On March 14, 2002, the Partnership's previous independent public
accountant, Arthur Andersen LLP, was indicted on federal obstruction of justice
charges arising from the federal government's investigation of Enron Corp. On
June 15, 2002, a jury returned with a guilty verdict against Arthur Andersen
following a trial. We are required to file with the SEC periodic financial
statements audited or reviewed by an independent public accountant. On March 29,
2002, the General Partner decided not to engage Arthur Andersen as the
Partnership's independent auditors, and engaged Ernst & Young LLP to serve as
our new independent auditors for 2002. However, included in this annual report
on Form 10-K are financial data and other information for 2001 and 2000 that
were audited by Arthur Andersen. Investors in the Partnership's securities may
encounter difficulties in obtaining, or be unable to obtain, from Arthur
Andersen with respect to its audits of our financial statements relief that may
be available to investors under the federal securities laws against auditing
firms.
4
ITEM 2. PROPERTIES
ACREAGE
Acreage is held by the Partnership pursuant to the terms of various leases.
The Partnership does not anticipate any difficulty in retaining any of its
desirable leases. A summary of the Partnership's gross and net acreage as of
December 31, 2002, is set forth below:
DEVELOPED ACREAGE
----------------------------------
LEASE BLOCK STATE GROSS ACRES NET ACRES
---------------------------------- ------- ----------- ------------
Ship Shoal 258, 259 LA 10,141 638
South Timbalier 276, 295, 296 LA 15,000 1,063
North Padre Island 969, 976 TX 10,080 714
Matagorda Island 681, 682, 683 TX 15,840 742
South Pass 83 LA 5,000 339
East Cameron 60 LA 5,000 472
Ship Shoal 201, 202 LA 10,000 --
----------- ------------
71,061 3,968
=========== ============
At December 31, 2002, the Partnership did not have an interest in any
undeveloped acreage.
PRODUCTIVE OIL AND GAS WELLS
The number of productive oil and gas wells in which the Partnership had an
interest as of December 31, 2002, is set forth below:
GAS OIL
-------------------- -------------------
LEASE BLOCK STATE GROSS NET GROSS NET
------------------------------- ------- -------------------- -------------------
Ship Shoal 258, 259 LA 5 .31 -- --
South Timbalier 276, 295, 296 LA 1 .07 29 2.05
North Padre Island 969, 976 TX 7 .50 -- --
Matagorda Island 681, 682,683 TX 5 .31 -- --
South Pass 83 LA 4 .27 -- --
East Cameron 60 LA -- -- -- --
Ship Shoal 201, 202 LA -- -- 1 --
--------- ------- --------- -------
22 1.46 30 2.05
========= ======= ========= =======
NET WELLS DRILLED
The following table shows the results of the oil and gas wells drilled and
tested for each of the last three fiscal years:
NET EXPLORATORY NET DEVELOPMENT
--------- --------------------------------------- -------------------------------------------
YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
--------- ------------ ------- --------- ----------- ---------- -----------
2002 -- -- -- .35 .07 .42
2001 -- -- -- .28 -- .28
2000 -- -- -- .28 .06 .34
5
PRODUCTION AND PRICING DATA
The following table describes, for each of the last three fiscal years, oil
and gas production for the Partnership, average production costs (including
gathering and transportation expense) and average sales prices.
PRODUCTION AVERAGE SALES PRICES
------------------------- AVERAGE ----------------------------
YEAR ENDED OIL GAS PRODUCTION OIL GAS
DECEMBER 31, (MBBLS) (MMCF) COST PER MCFE (PER BBL) (PER MCF)
------------- --------- -------- --------------- ----------- ------------
2002 110 1,224 $ .44 $ 25.03 $ 3.36
2001 112 1,705 .33 25.00 4.51
2000 119 2,320 .25 30.18 3.91
See the Supplemental Oil and Gas Disclosures under Item 8 for estimated
proved oil and gas reserves quantities.
ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS
As of December 31, 2002, the Partnership had total estimated proved
reserves of 849,000 barrels of crude oil and condensate and 6.3 Bcf of natural
gas. Combined, these total estimated proved reserves are equivalent to 11.4 Bcf
of gas. Estimated proved developed reserves comprise 99 percent of the
Partnership's total estimated proved reserves on a Bcfe basis.
The Partnership's estimates of proved reserves and proved developed
reserves at December 31, 2002, 2001 and 2000, changes in proved reserves during
the last three years, and estimates of future net cash flows and discounted
future net cash flows from proved reserves are contained in the Supplemental Oil
and Gas Disclosures (Unaudited), in the 2002 Consolidated Financial Statements
under Item 8 of this Form 10-K.
Proved oil and gas reserves are the estimated quantities of natural gas,
crude oil and condensate that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Reserves are considered proved
if economical productibility is supported by either actual production or
conclusive formation tests. Reserves that can be produced economically through
application of improved recovery techniques are included in the "proved"
classification when successful testing by a pilot project or the operation of an
installed program in the reservoir provides support for the engineering analysis
on which the project or program is based. Proved developed oil and gas reserves
can be expected to be recovered through existing wells with existing equipment
and operating methods.
The volumes of reserves are estimates which, by their nature, are subject
to revision. The estimates are made using available geological and reservoir
data, as well as production performance data. These estimates are reviewed
annually and revised, either upward or downward, as warranted by additional
performance data.
The Partnership's estimate of proved oil and gas reserves are prepared by
Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum
engineers, utilizing oil and gas price data and cost estimates provided by
Apache as Managing Partner.
ITEM 3. LEGAL PROCEEDINGS
There are no material legal proceedings pending to which the Partnership is
a party or to which the Partnership's interests are subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 2002.
6
PART II
ITEM 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY HOLDER
MATTERS
As of December 31, 2002, there were 1,084.9 of the Partnership's Units
outstanding held by 899 investors of record. The Partnership has no other class
of security outstanding or authorized. The Units are not traded on any security
market. Cash distributions to Investing Partners totaled approximately $1.1
million, or $1,000 per Unit, during 2002 and approximately $4.5 million, or
$4,000 per Unit, during 2001.
As discussed in Item 7, an amendment to the Partnership Agreement in
February 1994 created a right of presentment under which all Investing Partners
have a limited and voluntary right to offer their Units to the Partnership twice
each year to be purchased for cash.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data for the five years ended December 31,
2002, should be read in conjunction with the Partnership's financial statements
and related notes included under Item 8 below of this Form 10-K. The
Partnership's financial statements for the years 1998 through 2001 were audited
by Arthur Andersen LLP, independent public accountants. For a discussion of the
risks relating to Arthur Andersen's audit of the Partnership's financial
statements, please see "Factors That May Affect Future Results -- Risks Relating
to Arthur Andersen LLP".
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
(In thousands, except per Unit amounts)
Total assets $ 9,834 $ 9,413 $ 8,715 $ 8,722 $ 9,841
============ ============ ============ ============ ============
Partners' capital $ 9,610 $ 8,369 $ 7,728 $ 7,755 $ 9,080
============ ============ ============ ============ ============
Oil and gas sales $ 6,868 $ 10,495 $ 12,641 $ 8,796 $ 8,118
============ ============ ============ ============ ============
Net income $ 3,524 $ 7,264 $ 8,497 $ 4,351 $ 3,621
============ ============ ============ ============ ============
Net income allocated to:
Managing Partner $ 1,036 $ 1,731 $ 2,102 $ 1,269 $ 1,061
Investing Partners 2,488 5,533 6,395 3,082 2,560
------------ ------------ ------------ ------------ ------------
$ 3,524 $ 7,264 $ 8,497 $ 4,351 $ 3,621
============ ============ ============ ============ ============
Net income per Investing
Partner Unit $ 2,259 $ 4,922 $ 5,654 $ 2,707 $ 2,193
============ ============ ============ ============ ============
Cash distributions per
Investing Partner Unit $ 1,000 $ 4,000 $ 5,750 $ 3,500 $ 1,500
============ ============ ============ ============ ============
7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
The Partnership's net income and net income per Investing Partner Unit
decreased in 2002 on lower oil and gas production and lower gas prices. Daily
gas volumes declined 28 percent from a year ago largely as a result of natural
depletion, while daily oil production slid two percent with weather-related
downtime. Distributions per Investing Partner Unit in 2002 also decreased as a
result of the lower production and gas prices. There was only one distribution
made to the Investing Partners in 2002 as a result of lower cash provided by
operating activities during the first half of 2002.
CRITICAL ACCOUNTING POLICIES
The discussion and analysis of the Partnership's financial condition and
results of operations are based upon the consolidated financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States. The preparation of these financial statements
requires the Partnership to make estimates and assumptions that affect the
reported amount of assets, liabilities, revenues and expenses. Certain
accounting policies involve judgments and uncertainties to such an extent that
there is a reasonable likelihood that materially different amounts could have
been reported under different conditions, or if different assumptions had been
used. The Partnership bases its estimates on historical experience and various
other assumptions that are believed to be reasonable under the circumstances.
Actual results may differ from the estimates and assumptions used in preparation
of the financial statements. The following details the more significant
accounting policies, estimates and judgments. Additional accounting policies and
estimates made by management are discussed in Note 2 of Item 8 of this Form
10-K.
Full Cost Method of Accounting for Oil and Gas Operations
The accounting for the Partnership's business is subject to special
accounting rules that are unique to the oil and gas industry. There are two
allowable methods of accounting for oil and gas business activities: the
successful efforts method and the full cost method. There are several
significant differences between these methods. Under the successful efforts
method, cost such as geological and geophysical (G&G), exploratory dry holes and
delay rentals are expensed as incurred, where under the full-cost method these
types of charges would be capitalized to oil and gas properties. In the
measurement of impairment of oil and gas properties, the successful efforts
method of accounting follows the guidance provided in SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets", where the first
measurement for impairment is to compare the net book value of the related asset
to its undiscounted future cash flows using commodity prices consistent with
management expectations. Under the full-cost method the net book value
(full-cost pool) is compared to the future net cash flows discounted at 10%
using commodity prices in effect at the end of the reporting period.
The Partnership has elected to use the full cost method to account for its
investment in oil and gas properties. Under this method, the Partnership
capitalizes all acquisition, exploration and development costs for the purpose
of finding oil and gas reserves. Although some of these costs will ultimately
result in no additional reserves, it expects the benefits of successful wells to
more than offset the costs of any unsuccessful ones. As a result, the
Partnership believes that the full cost method of accounting better reflects the
true economics of exploring for and developing oil and gas reserves. The
Partnership's financial position and results of operations would have been
significantly different had it used the successful efforts method of accounting
for oil and gas investments.
Reserve Estimates
The Partnership's estimate of proved reserves are based on the quantities
of oil and gas which geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known reservoirs
under existing economic and operating conditions. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation, and judgment. For example, engineers must estimate
the amount and timing of future operating costs, severance taxes, development
costs, and workover costs, all of which may in fact vary considerably from
actual results. In addition, as prices and cost levels change from year to year,
the estimate of proved reserves also change. Any significant variance in these
assumptions could materially affect the estimated quantity and value of the
Partnership's reserves.
8
Despite the inherent imprecision in these engineering estimates, the
Partnership's reserves have a significant impact on its financial statements.
For example, the quantity of reserves could significantly impact the
Partnership's DD&A expense. The Partnership's oil and gas properties are also
subject to a "ceiling" limitation based in part on the quantity of our proved
reserves. These reserves are the basis for our supplemental oil and gas
disclosures.
The Partnership's estimate of proved oil and gas reserves are prepared by
Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum
engineers, utilizing oil and gas price data and cost estimates provided by
Apache as Managing Partner.
Asset Retirement Obligation
The Partnership has obligations to remove tangible equipment and restore
land or seabed at the end of oil and gas production operations. These
obligations may be significant in light of the Partnership's limited operations
and estimate of remaining reserves. The Partnership's removal and restoration
obligations are primarily associated with plugging and abandoning wells and
removal and disposal of offshore oil and gas platforms. The estimated
undiscounted costs, net of salvage value, of dismantling and removing these
facilities are accrued over the production life of the oil and gas property.
Estimating the future asset removal costs is difficult and requires management
to make estimates and judgments because most of the removal obligations are many
years in the future and contracts and regulations often have vague descriptions
of what constitutes removal. Asset removal technologies and costs are constantly
changing, as well as regulatory, political, environmental, safety and public
relations considerations.
In 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 143 (SFAS No. 143), "Accounting for Asset
Retirement Obligations." SFAS No. 143 significantly changed the method of
accruing for cost, associated with the retirement of fixed asset an entity is
legally obligated to incur. Primarily, the new statement requires the
Partnership to record a separate liability for asset retirement obligations that
represents the present value of the costs to be incurred. The separate liability
is similar to the Partnership's previous estimates in that the obligations are
based on expected cost estimates and expected economic lives of the asset
retirements that occurs many years in the future, but the new rule now requires
additional discounting assumptions to be considered by management. Revisions to
the asset retirement obligation recorded upon adoption of SFAS No. 143 can
potentially result from changes in the assumptions used to estimate the cash
flows required to settle the obligation. Potential changes include adjustments
in estimated probabilities, amounts, and timing of the settlement, as well as
changes in the legal requirements of an asset retirement obligation. Any such
changes that result in upward and downward revisions in the estimated cash flows
will adjust the liability and the related capitalized asset on a prospective
basis. The Partnership adopted this statement effective January 1, 2003 as
discussed in Note 8 of Item 8 of this Form 10-K.
RESULTS OF OPERATIONS
NET INCOME AND REVENUE
The Partnership reported net income of $3.5 million for 2002 versus $7.3
million in 2001. Net income per Investing Partner Unit declined from $4,922 in
2001 to $2,259 in 2002.
Revenues decreased from $10.6 million in 2001 to $7 million in 2002.
Interest income earned by the Partnership on short-term cash investments
declined from last year as a result of lower interest rates and average
investment balances in 2002. Natural gas sales accounted for 59 percent of the
Partnership's total revenue in 2002, compared to 72 percent during 2001.
9
The Partnership's oil and gas production volume and price information is
summarized in the following table:
FOR THE YEAR ENDED
DECEMBER 31,
----------------------------------- INCREASE
2002 2001 (DECREASE)
------------------------------------------------------
Gas volumes -- Mcf per day 3,353 4,672 (28%)
Average gas price -- per Mcf $ 3.36 $ 4.51 (25%)
Oil volume -- barrels per day 302 307 (2%)
Average oil price -- per barrel $ 25.03 $ 25.00 --
Declines in oil and gas production can be expected in future years as a
result of normal depletion. Given the small number of producing wells owned by
the Partnership, and the fact that offshore wells tend to decline at a faster
rate than onshore wells, the Partnership's future production will be subject to
more volatility than those companies with greater reserves and longer-lived
properties. It is not anticipated that the Partnership will acquire any
additional exploratory leases or that significant exploratory drilling will take
place on leases in which the Partnership currently holds interests.
2002 COMPARED TO 2001
OIL AND GAS SALES
Natural gas sales for 2002 totaled $4.1 million, down 47 percent from 2001
on lower gas prices and production. While natural gas prices improved during the
fourth quarter of 2002, a $1.15 per Mcf drop in the Partnership's average
realized price from a year ago negatively impacted sales by $2 million. Natural
gas production declined by 28 percent from last year, falling to 3,353 Mcf per
day in 2002. The 1,319 Mcf per day decline in volume primarily reflected natural
depletion. The Partnership's North Padre Island 969 production being shut-in for
nearly nine months in 2002 for a dispute with a pipeline company on increased
fees charged for the transportation of natural gas reduced current year sales by
426 Mcf per day, while Hurricane Isidore and Lili reduced 2002 sales by 58 Mcf
per day. The North Padre Island 969 wells returned to production in late
September 2002 after the Federal Energy Regulatory Commission (FERC) issued a
ruling which established an unbundled gathering rate of approximately two cents
per Mcf on the North Padre Island system as opposed to the 12 cents per Mcf rate
demanded by the pipeline. The completion of five successful development wells at
South Timbalier 295 during 2002 largely offset production declines in the field.
The Partnership's crude oil sales for 2002 totaled $2.8 million, even with
the prior year. A slight improvement in average realized oil prices in 2002 was
offset by a two percent decline in production from a year ago. Weather-related
downtime for hurricanes in 2002 drove the five barrel per day decline in
production from last year. Production added through drilling at South Timbalier
295 offset natural depletion for the year.
OTHER REVENUES
During 2002, the Partnership recognized insurance recoveries totaling
$99,300 for the estimated amount of proceeds recoupable under business
interruption insurance policies. The amount reflects expected recoveries, after
applicable deductibles, for the Partnership's share of lost oil and gas
production resulting from hurricanes in 2002.
OPERATING EXPENSES
The Partnership's depreciation, depletion and amortization (DD&A) rate,
expressed as a percentage of oil and gas sales, increased to 32 percent in 2002.
The increase in DD&A rate from prior years reflected higher finding cost in
2002.
Lease operating expense in 2002 increased approximately $96,000 from a year
ago primarily as a result of higher repair and maintenance cost on platforms and
compressors. Administrative expense declined seven percent from last year,
dropping to $447,000.
During 2002, the Partnership adopted Emerging Issues Task Force Issue
00-10, "Accounting for Shipping and Handling Fees and Costs". Prior to adoption,
amounts paid to third parties for transportation had been reported as a
reduction of revenue instead of an operating expense. For comparative purposes,
previously reported transportation
10
costs paid to third parties were reclassified as corresponding increases to oil
and gas production revenues and operating expenses with no impact on net income.
The decline in expense compared to a year ago reflected lower sales volumes in
2002.
2001 COMPARED TO 2000
OIL AND GAS SALES
Natural gas sales for 2001 of $7.7 million declined 15 percent from 2000 as
lower gas production more than offset the impact of higher gas prices. Gas
production in 2001 decreased by 26 percent when compared to 2000, negatively
impacting sales by $2.8 million. Production decreases in 2001 were attributable
to natural production declines impacting all of the Partnership's properties.
These decreases were partially offset by production added from drilling projects
at South Timbalier 295 during 2001. The Partnership's average realized gas price
increased $.60 per Mcf from last year, positively impacting sales by $1.4
million. While the Partnership's average gas price was up from the prior year,
natural gas prices trended upward during most of 2001.
The Partnership's crude oil sales for 2001 totaled $2.8 million, a 22
percent decrease from 2000. The average realized price for 2001 decreased $5.18
per barrel, or 17 percent, when compared to the $30.18 per barrel realized in
2000. Oil production in 2001 declined five percent from the prior year due to
natural depletion.
OPERATING EXPENSES
The Partnership's DD&A rate, expressed as a percentage of oil and gas
sales, was approximately 19 percent during 2001. The DD&A rate decreased from
2000 as a result of reserve additions recognized in 2001.
Lease operating expense during 2001 of $.6 million increased by
approximately $.1 million from the prior year as a result of higher repair and
maintenance costs in 2001. Administrative expense declined 11 percent from 2000,
while transportation cost declined from the prior year with reduced volumes.
CASH FLOW, LIQUIDITY AND CAPITAL RESOURCES
CAPITAL COMMITMENTS
The Partnership's primary needs for cash are for operating expenses,
drilling and recompletion expenditures, future dismantlement and abandonment
costs, distributions to Investing Partners, and the purchase of Units offered by
Investing Partners under the right of presentment. The Partnership had no
outstanding debt, lease commitments or contractual obligations at December 31,
2002.
During 2002, the Partnership's oil and gas property additions totaled $3.2
million. These additions primarily related to drilling projects at South
Timbalier 295 where the Partnership participated in drilling six development
wells of which five were completed as successful wells. The Partnership also
participated in four recompletion projects at South Timbalier 295 and one at
Matagorda 681/682. Capital expenditures during 2001 totaled $3 million as the
Partnership participated in drilling four development wells and recompletions in
South Timbalier 295, Matagorda 681/682 and East Cameron 60. During 2000, capital
expenditures totaled $3.9 million as the Partnership participated in drilling
five wells.
Based on preliminary information provided by the operators of the
properties in which the Partnership owns interests, the Partnership anticipates
capital expenditures will total approximately $1 million in 2003 and will be
directed primarily toward recompletion projects at South Timbalier 295. Such
estimates may change based on realized oil and gas prices, drilling results,
rates charged by drilling contractors or changes by the operator to the
development plan.
During 2002, the Partnership paid distributions to Investing Partners
totaling approximately $1.1 million or $1,000 per Unit. The per Unit
distribution in 2002 declined 75 percent from a year ago due to the decline in
the Partnership's revenues in 2002. The amount of future distributions will be
dependent on actual and expected production levels, realized and expected oil
and gas prices, expected drilling and recompletion expenditures and prudent cash
reserves for future dismantlement and abandonment costs that will be incurred
after the Partnership's reserves are depleted.
11
The Partnership estimates that its share of undiscounted future
dismantlement and abandonment costs for all of its remaining fields will total
approximately $1.2 million. These expenditures will be funded by future cash
flows from operations and cash held by the Partnership. Based on preliminary
information from the operator, the Partnership expects that during 2003 the
remaining wellbore in the East Cameron 60 field will be plugged and abandoned,
and the platform removed from the site. The field has not produced since 2001.
On an ongoing basis, the Partnership reviews the possible sale of lower value
properties prior to incurring associated dismantlement and abandonment costs.
In February 1994, an amendment to the Partnership Agreement created a right
of presentment under which all Investing Partners have a limited and voluntary
right to offer their Units to the Partnership twice each year to be purchased
for cash. In 2002, the first right of presentment offer of $8,686 per Unit, plus
interest to the date of payment, was made to Investing Partners based on a
December 31, 2001 valuation date. The second right of presentment offer of
$7,362 per Unit, plus interest to the date of payment, was made to the Investing
Partners based on a valuation date of June 30, 2002. As a result, the
Partnership acquired 25.4 Units for a total of $213,006 in cash. In 2001 and
2000, Investing Partners were paid $195,221 and $34,831, respectively, for a
total of 22.2 Units.
There will be two rights of presentment in 2003, but the Partnership is not
in a position to predict how many Units will be presented for repurchase and
cannot, at this time, determine if the Partnership will have sufficient funds
available to repurchase Units. The Amended Partnership Agreement contains
limitations on the number of Units that the Partnership can repurchase,
including an annual limit on repurchases of 10 percent of outstanding Units. The
Partnership has no obligation to repurchase any Units presented to the extent
that it determines that it has insufficient funds for such repurchases.
CAPITAL RESOURCES AND LIQUIDITY
The Partnership's primary capital resource is net cash provided by
operating activities, which totaled $4.9 million for 2002. Net cash provided by
operating activities in 2002 decreased $5.3 million, or 52 percent, from a year
ago with declines in oil and gas production and gas prices. Net cash provided by
operating activities in 2001 declined nine percent from 2000 on declines in oil
and gas production and oil prices.
The Partnership's future financial condition, results of operations and
cash from operating activities will largely depend upon prices received for its
oil and natural gas production. A substantial portion of the Partnership'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 factors beyond the Partnership'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.
With natural gas accounting for 65 percent of the Partnership's 2002 production
and 55 percent of total proved reserves, on an energy equivalent basis, the
Partnership is affected more by fluctuations in natural gas prices than in oil
prices. While future oil and gas prices cannot be predicted, prices in early
2003 are up from the comparable period in 2002 as a result of political tensions
and lower average temperatures throughout much of the United States.
The Partnership's oil and gas reserves and production will also
significantly impact future results of operations and cash from operating
activities. The Partnership's production is subject to fluctuations in response
to remaining quantities of oil and gas reserves, weather, pipeline capacity,
consumer demand, mechanical performance and workover, recompletion and drilling
activities. Declines in oil and gas production can be expected in future years
as a result of normal depletion and the Partnership not participating in
acquisition or exploration activities. Based on production estimates from
independent engineers and current market conditions, the Partnership expects it
will be able to meet its liquidity needs for routine operations in the
foreseeable future. The Partnership will reduce capital expenditures and
distributions to partners as cash from operating activities decline.
In the event that future short-term operating cash requirements are greater
than the Partnership's financial resources, the Partnership may seek short-term,
interest-bearing advances from the Managing Partner as needed. The Managing
Partner, however, is not obligated to make loans to the Partnership.
During 2002, the Partnership used available cash to reduce accrued
operating expenses and the payable to Apache. Lower accrued development cost at
December 31, 2002 reflected reduced activity since drilling was completed in
early November at South Timbalier 295.
12
OFF-BALANCE SHEET ARRANGEMENTS
The Partnership does not currently utilize any off-balance sheet
arrangements with unconsolidated entities to enhance liquidity and capital
resource positions, or any other purpose. Any future transactions involving
off-balance sheet arrangements will be fully scrutinized by the Managing Partner
and disclosed by the Partnership.
ITEM 7A. MARKET RISK
COMMODITY RISK
The Partnership'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
natural gas production. Prices received for oil and gas production have been and
remain volatile and unpredictable. During 2002, monthly oil price realizations
ranged from a low of $18.68 per barrel to a high of $28.46 per barrel. Gas price
realizations ranged from a monthly low of $2.25 per Mcf to a monthly high of
$4.35 per Mcf during the same period. Both oil and gas prices trended upward
during most of 2002, with the Partnership realizing its highest prices of the
year in the fourth quarter and its lowest prices in the first quarter. Based on
the Partnership's average daily production for 2002, a $1.00 per barrel change
in the weighted average realized price of oil would have increased or decreased
revenues for the year by approximately $110,000 and a $.10 per Mcf change in the
weighted average realized price of natural gas would have increased or decreased
revenues for the year by approximately $122,000. The Partnership did not use
derivative financial instruments or otherwise engage in hedging activities
during the three-year period ended December 31, 2002. Due to the volatility of
commodity prices, the Partnership is not in a position to predict future oil and
gas prices.
If oil and gas prices decline significantly in the future, even if only for
a short period of time, it is possible that non-cash write-downs of the
Partnership's oil and gas properties could occur under the full cost accounting
rules of the SEC. Under these rules, the Partnership reviews the carrying value
of its proved oil and gas properties each quarter to ensure the capitalized
costs of proved oil and gas properties, net of accumulated depreciation,
depletion and amortization do not exceed the "ceiling". This ceiling is the
present value of estimated future net cash flows from proved oil and gas
reserves, discounted at 10 percent. If capitalized costs exceed this limit, the
excess is charged to additional DD&A expense. The calculation of estimated
future net cash flows is based on the prices for crude oil and natural gas in
effect on the last day of each fiscal quarter except for volumes sold under
long-term contracts. Write-downs required by these rules do not impact cash flow
from operating activities.
FORWARD-LOOKING STATEMENTS AND RISK
Certain statements in this report, including statements of the future
plans, objectives, and expected performance of the Partnership, are
forward-looking statements that are dependent upon certain events, risks and
uncertainties that may be outside the Partnership's control, and which could
cause actual results to differ materially from those anticipated. Some of these
include, but are not limited to, the market prices of oil and gas, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, political and economic uncertainties of foreign
governments, future business decisions, and other uncertainties, all of which
are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of actual future
production may vary significantly from reserves and production estimates. The
drilling of development wells can involve risks, including those related to
timing and cost overruns. Lease and rig availability, complex geology and other
factors can affect these risks. Fluctuations in oil and gas prices, or a
prolonged period of low prices, may substantially adversely affect the
Partnership's financial position, results of operations and cash flows.
13
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
APACHE OFFSHORE INVESTMENT PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS
PAGE
NUMBER
------
Report of Independent Auditors -- 2002................................................................. 15
Report of Independent Public Accountants -- 2001 and 2000.............................................. 16
Statement of Consolidated Income for each of the three years in the period ended December 31, 2002..... 17
Statement of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2002 ................................................................................. 18
Consolidated Balance Sheet as of December 31, 2002 and 2001............................................ 19
Statement of Consolidated Changes in Partners' Capital for each of the three years in the period
ended December 31, 2002............................................................................ 20
Notes to Consolidated Financial Statements............................................................. 21
Supplemental Oil and Gas Disclosures................................................................... 29
Supplemental Quarterly Financial Data................................................................ 31
Schedules --
All financial statement schedules have been omitted because they are either
not required, not applicable or the information required to be presented is
included in the financial statements or related notes thereto.
14
REPORT OF INDEPENDENT AUDITORS
To the Partners of Apache Offshore Investment Partnership:
We have audited the accompanying consolidated balance sheet of Apache
Offshore Investment Partnership (a Delaware general partnership) and subsidiary
as of December 31, 2002, and the related consolidated statements of income, cash
flows and changes in partners' capital for the year then ended. These financial
statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The financial statements of Apache Offshore Investment Partnership as
of December 31, 2001, and for each of the two years in the period then ended,
were audited by other auditors who have ceased operations and whose report,
dated March 1, 2002, expressed an unqualified opinion on those financial
statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Apache
Offshore Investment Partnership as of December 31, 2002, and the results of its
operations and its cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States.
As discussed above, the financial statements of Apache Offshore Investment
Partnership as of December 31, 2001, and for each of the two years in the period
then ended, were audited by other auditors who have ceased operations. As
described in Note 2, these financial statements have been revised to reflect
third party gathering and transportation costs as an operating cost instead of a
reduction of revenues as previously reported. We audited the adjustments
described in Note 2 that were applied to revise the 2001 and 2000 consolidated
statement of operations. In our opinion, such adjustments are appropriate and
have been properly applied. However, we were not engaged to audit, review, or
apply any procedures to the 2001 and 2000 financial statements of Apache
Offshore Investment Partnership other than with respect to such adjustments and,
accordingly, we do not express an opinion or any other form of assurance on the
2001 and 2000 financial statements taken as a whole.
ERNST & YOUNG LLP
Houston, Texas
March 14, 2003
15
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Apache Offshore Investment Partnership:
We have audited the accompanying consolidated balance sheet of Apache
Offshore Investment Partnership (a Delaware general partnership) and subsidiary
as of December 31, 2001 and 2000, and the related consolidated statements of
income, cash flows and changes in partners' capital for each of the three years
in the period ended December 31, 2001. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Apache
Offshore Investment Partnership as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
March 1, 2002
THIS IS A COPY OF AN ACCOUNTANT'S REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN
LLP, AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN. SEE PART II, ITEM 9 FOR
FURTHER INFORMATION.
16
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2002 2001 2000
--------------- --------------- ----------------
REVENUES:
Oil and gas sales $ 6,867,523 $ 10,494,911 $ 12,640,530
Interest income 19,199 75,126 123,820
Other revenue 99,300 -- --
--------------- --------------- ----------------
6,986,022 10,570,037 12,764,350
--------------- --------------- ----------------
OPERATING EXPENSES:
Depreciation, depletion and amortization 2,181,189 2,042,461 2,971,525
Lease operating costs 731,416 635,049 532,433
Gathering and transportation expense 102,698 148,282 223,673
Administrative 447,000 480,000 540,000
--------------- --------------- ----------------
3,462,303 3,305,792 4,267,631
--------------- --------------- ----------------
NET INCOME $ 3,523,719 $ 7,264,245 $ 8,496,719
=============== =============== ===============
NET INCOME ALLOCATED TO:
Managing Partner $ 1,035,747 $ 1,730,985 $ 2,102,310
Investing Partners 2,487,972 5,533,260 6,394,409
--------------- --------------- ----------------
$ 3,523,719 $ 7,264,245 $ 8,496,719
=============== =============== ===============
NET INCOME PER INVESTING PARTNER UNIT $ 2,259 $ 4,922 $ 5,654
=============== =============== ===============
WEIGHTED AVERAGE INVESTING PARTNER
UNITS OUTSTANDING 1,101.5 1,124.1 1,130.9
=============== =============== ===============
The accompanying notes to financial statements are
an integral part of this statement
17
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000
--------------- --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,523,719 $ 7,264,245 $ 8,496,719
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,181,189 2,042,461 2,971,525
Changes in operating assets and liabilities:
(Increase) decrease in accrued revenues receivable (322,209) 731,343 (388,472)
Increase (decrease) in accrued operating
expenses (63,706) 27,400 (87,287)
Increase (decrease) in payable to Apache Corporation (392,810) 125,507 192,624
--------------- --------------- ---------------
Net cash provided by operating activities 4,926,183 10,190,956 11,185,109
--------------- --------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (3,248,104) (3,030,327) (3,882,050)
Proceeds from sales of oil and gas properties -- -- --
Increase (decrease) in accrued development costs (362,745) (96,442) (85,851)
--------------- --------------- ---------------
Net cash used in investing activities (3,610,849) (3,126,769) (3,967,901)
--------------- --------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units (213,006) (195,221) (34,831)
Distributions to Investing Partners (1,095,189) (4,501,620) (6,500,003)
Distributions to Managing Partner, net (974,634) (1,926,838) (1,988,308)
--------------- --------------- ---------------
Net cash used in financing activities (2,282,829) (6,623,679) (8,523,142)
--------------- --------------- ---------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS (967,495) 440,508 (1,305,934)
CASH AND CASH EQUIVALENTS, BEGINNING
OF YEAR 1,883,386 1,442,878 2,748,812
--------------- --------------- ---------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 915,891 $ 1,883,386 $ 1,442,878
=============== =============== ===============
The accompanying notes to financial statements are
an integral part of this statement
18
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
----------------------------------
2002 2001
--------------- ---------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 915,891 $ 1,883,386
Accrued revenues receivable 615,164 292,955
--------------- ---------------
1,531,055 2,176,341
--------------- ---------------
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties 179,656,827 176,408,723
Less -- Accumulated depreciation, depletion and amortization (171,353,743) (169,172,554)
--------------- ---------------
8,303,084 7,236,169
--------------- ---------------
$ 9,834,139 $ 9,412,510
=============== ===============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued development costs $ 51,813 $ 414,558
Accrued operating expenses 48,478 112,184
Payable to Apache Corporation 123,952 516,762
--------------- ---------------
224,243 1,043,504
--------------- ---------------
COMMITMENTS AND CONTINGENCIES (Note 7)
PARTNERS' CAPITAL:
Managing Partner 217,341 156,228
Investing Partners (1,084.9 and 1,110.3 Units
outstanding, respectively) 9,392,555 8,212,778
--------------- ---------------
9,609,896 8,369,006
--------------- ---------------
$ 9,834,139 $ 9,412,510
=============== ===============
The accompanying notes to financial statements are
an integral part of this statement
19
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS' CAPITAL
MANAGING INVESTING
PARTNER PARTNERS TOTAL
-------------- --------------- ---------------
BALANCE, DECEMBER 31, 1999 $ 238,079 $ 7,516,784 $ 7,754,863
Distributions, net (1,988,308) (6,500,003) (8,488,311)
Repurchase of Partnership Units -- (34,831) (34,831)
Net income 2,102,310 6,394,409 8,496,719
-------------- --------------- ---------------
BALANCE, DECEMBER 31, 2000 352,081 7,376,359 7,728,440
Distributions, net (1,926,838) (4,501,620) (6,428,458)
Repurchase of Partnership Units -- (195,221) (195,221)
Net income 1,730,985 5,533,260 7,264,245
-------------- --------------- ---------------
BALANCE, DECEMBER 31, 2001 156,228 8,212,778 8,369,006
Distributions, net (974,634) (1,095,189) (2,069,823)
Repurchase of Partnership Units -- (213,006) (213,006)
Net income 1,035,747 2,487,972 3,523,719
-------------- --------------- ---------------
BALANCE, DECEMBER 31, 2002 $ 217,341 $ 9,392,555 $ 9,609,896
=============== =============== ===============
The accompanying notes to financial statements are
an integral part of this statement
20
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION
NATURE OF OPERATIONS --
Apache Offshore Investment Partnership was formed as a Delaware general
partnership on October 31, 1983, consisting of Apache Corporation (Apache)
as Managing Partner and public investors as Investing Partners. The general
partnership invested its entire capital in Apache Offshore Petroleum
Limited Partnership, a Delaware limited partnership formed to conduct oil
and gas exploration, development and production operations. The
accompanying financial statements include the accounts of both the limited
and general partnerships. Apache is the general partner of both the limited
and general partnerships, and holds slightly less than five percent of the
1,084.9 Investing Partner Units (Units) outstanding at December 31, 2002.
The term "Partnership", as used hereafter, refers to the limited or the
general partnership, as the case may be.
The Partnership purchased, at cost, an 85 percent interest in offshore
leasehold interests acquired by Apache as a co-venturer in a series of oil
and gas exploration, development and production activities on 87 federal
lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The
remaining 15 percent interest was purchased by an affiliated partnership or
retained by Apache. The Partnership acquired an increased net revenue
interest in Matagorda Island Blocks 681 and 682 in November 1992, when the
Partnership and Apache formed a joint venture to acquire a 92.6 percent
working interest in the blocks.
Since inception, the Partnership has participated in 14 federal
offshore lease sales in which 49 prospects were acquired (through the same
date 42 of those prospects have been surrendered/sold). The Partnership's
working interests in the seven remaining venture prospects range from 6.29
percent to 9.44 percent. As of December 31, 2002, the Partnership held a
remaining interest in 12 tracts acquired through federal lease sales and
two tracts obtained through farmout arrangements.
The Partnership's future financial condition and results of operations
will depend largely upon prices received for its oil and natural gas
production and the costs of acquiring, finding, developing and producing
reserves. A substantial portion of the Partnership'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 factors beyond the Partnership'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. With natural gas accounting for 65
percent of the Partnership's 2002 production and 55 percent of total proved
reserves, on an energy equivalent basis, the Partnership is affected more
by fluctuations in natural gas prices than in oil prices.
Under the terms of the Partnership Agreements, the Investing Partners
receive 80 percent and Apache receives 20 percent of revenue. Lease
operating, gathering and transportation and administrative expenses are
allocated to the Investing Partners and Apache in the same proportion as
revenues. The Investing Partners receive 100 percent of the interest income
earned on short-term cash investments. The Investing Partners generally pay
for 90 percent and Apache generally pays for 10 percent of exploration and
development costs and expenses incurred by the Partnership. However,
intangible drilling costs, interest costs and fees or expenses related to
the loans incurred by the Partnership are allocated 99 percent to the
Investing Partners and one percent to Apache until such time as the amount
so allocated to the Investing Partners equals 90 percent of the total
amount of such costs, including such costs incurred by Apache prior to the
formation of the Partnerships.
21
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
RIGHT OF PRESENTMENT --
An amendment to the Partnership Agreements adopted in February 1994,
created a right of presentment under which all Investing Partners have a
limited and voluntary right to offer their Units to the Partnership twice
each year to be purchased for cash. During 2002, the Investing Partners
sold a total of 25.4 Units to the Partnership for a total of $213,006 in
cash. The first right of presentment was based upon a valuation date of
December 31, 2001 for a purchase price of $8,686 per Unit, plus interest to
the date of payment. The second presentment offer was based on a valuation
date of June 30, 2002 for a purchase price of $7,362 per Unit, plus
interest to the payment date. During 2001 and 2000, the Partnership paid
the Investing Partners $195,221 and $34,831, respectively, to acquire a
total of 22.2 Units.
The Partnership is not in a position to predict how many Units will be
presented for repurchase during 2003, however, no more than 10 percent of
the outstanding Units may be purchased under the right of presentment in
any year. The Partnership has no obligation to purchase any Units presented
to the extent that it determines that it has insufficient funds for such
purchases.
The table below sets forth the total repurchase price and the
repurchase price per Unit for all outstanding Units at each presentment
period, based on the right of presentment valuation formula defined in the
amendment to the Partnership Agreement. The right of presentment offers,
made twice annually, are based on a discounted Unit value formula. The
discounted Unit value will be not less than the Investing Partner's share
of: (a) the sum of (i) 70 percent of the discounted estimated future net
revenues from proved reserves, discounted at a rate of 1.5 percent over
prime or First National Bank of Chicago's base rate in effect at the time
the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv)
accounts receivable less a reasonable reserve for doubtful accounts, (v)
oil and gas properties other than proved reserves at cost less any amounts
attributable to drilling and completion costs incurred by the Partnership
and included therein, and (vi) the book value of all other assets of the
Partnership, less the debts, obligations and other liabilities of all kinds
(including accrued expenses) then allocable to such interest in the
Partnership, all determined as of the valuation date, divided by (b) the
number of Units, and fractions thereof, outstanding as of the valuation
date. The discounted Unit value does not purport to be, and may be
substantially different from, the fair market value of a Unit.
RIGHT OF PRESENTMENT TOTAL REPURCHASE REPURCHASE PRICE
VALUATION DATE PRICE PER UNIT
------------------------- ------------------- --------------------
December 31, 1999 $ 12,314,303 $ 8,874
June 30, 2000 10,934,084 6,431
December 31, 2000 13,460,392 9,928
June 30, 2001 13,984,141 10,460
December 31, 2001 9,644,386 8,686
June 30, 2002 9,157,842 7,362
INVESTING PARTNER UNITS OUTSTANDING: 2002 2001 2000
------------- ------------- -------------
Balance, beginning of year 1,110.3 1,128.5 1,132.5
Repurchase of Partnership Units (25.4) (18.2) (4.0)
------------- ------------- -------------
Balance, end of year 1,084.9 1,110.3 1,128.5
============= ============= =============
CAPITAL CONTRIBUTIONS --
A total of $85,000 per Unit, or approximately 57 percent, of investor
subscription had been called through December 31, 2002. The Partnership
determined the full purchase price of $150,000 per Unit was not needed, and
upon completion of the last subscription call in November 1989, released
the Investing Partners from their remaining liability. As a result of
investors defaulting on cash calls and repurchases under the presentment
offer discussed above, the original 1,500 Units have been reduced to
1,084.9 Units at December 31, 2002.
22
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
STATEMENT PRESENTATION --
The accounts of the Partnerships are maintained on a tax basis method
of accounting in accordance with the Articles of Partnership and methods of
reporting allowed for federal income tax purposes.
The consolidated financial statements included in reports that the
Partnership files with the Securities and Exchange Commission (SEC) are
required to be prepared in conformity with generally accepted accounting
principles. Accordingly, the accompanying consolidated financial statements
include adjustments to convert from tax basis to the accrual basis method
in conformity with accounting principles generally accepted in the United
States.
The accompanying consolidated financial statements include the accounts
of Apache Offshore Investment Partnership and Apache Offshore Petroleum
Limited Partnership after elimination of intercompany balances and
transactions.
CASH EQUIVALENTS --
The Partnership considers all highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
These investments are carried at cost which approximates market.
OIL AND GAS PROPERTIES --
The Partnership uses the full cost method of accounting for its
investment in oil and gas properties for financial statement purposes.
Under this method, the Partnership capitalizes all acquisition, exploration
and development costs incurred for the purpose of finding oil and gas
reserves. The amounts capitalized under this method include dry hole costs,
leasehold costs, engineering, geological, exploration, development and
other similar costs. Costs associated with production and administrative
functions are expensed in the period incurred. Unless a significant portion
of the Partnership's reserve volumes are sold (greater than 25 percent),
proceeds from the sale of oil and gas properties are accounted for as
reductions to capitalized costs, and gains or losses are not recognized.
Capitalized costs of oil and gas properties are amortized on the future
gross revenue method whereby depreciation, depletion and amortization
(DD&A) expense is computed quarterly by dividing current period oil and gas
sales by estimated future gross revenue from proved oil and gas reserves
(including current period oil and gas sales) and applying the resulting
rate to the net cost of evaluated oil and gas properties, including
estimated future development costs. The amortizable base includes estimated
dismantlement, restoration and abandonment costs, net of estimated salvage
values. Beginning in 2003, the Partnership changed its method of accounting
for dismantlement, restoration and abandonment cost as described in Note 8.
The Partnership limits the capitalized costs of proved oil and gas
properties, net of accumulated DD&A, to the 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, if any. If capitalized costs exceed this limit, the excess is
charged to DD&A expense. The Partnership has not recorded any write-downs
of capitalized costs for the three years presented.
Given the volatility of oil and gas prices, it is reasonably possible
that the Partnership's estimate of discounted future net cash flows from
proved oil and gas reserves could change in the near term. If oil and gas
prices decline significantly, even if only for a short period of time, it
is possible that write-downs of oil and gas properties could occur in the
future.
23
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
REVENUE RECOGNITION --
The Partnership uses the sales method of accounting for natural gas
revenues. Under this method, revenues are recognized based on actual
volumes of gas sold to purchasers. The volumes of gas sold may differ from
the volumes to which the Partnership is entitled based on its interests in
the properties. These differences create imbalances that are recognized as
a liability only when the estimated remaining reserves will not be
sufficient to enable the underproduced owner to recoup its entitled share
through production. As of December 31, 2002 and 2001, the Partnership did
not have any liabilities for gas imbalances in excess of remaining
reserves. No receivables are recorded for those wells where the Partnership
has taken less than its share of production. Gas imbalances are reflected
as adjustments to proved gas revenues and future cash flows in the
unaudited supplemental oil and gas disclosures. Adjustments for gas
imbalances totaled less than one percent of the Partnership's proved gas
reserves at December 31, 2002, 2001 and 2000.
NET INCOME PER INVESTING UNIT --
The net income per Investing Partner Unit is calculated by dividing the
aggregate Investing Partners' net income for the period by the number of
weighted average Investing Partner Units outstanding for that period.
INCOME TAXES --
The profit or loss of the Partnership for federal income tax reporting
purposes is included in the income tax returns of the partners.
Accordingly, no recognition has been given to income taxes in the
accompanying financial statements.
USE OF ESTIMATES --
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to
make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Certain accounting policies involve
judgments and uncertainties to such an extent that there is a reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been used. The
Partnership bases its estimates on historical experience and various other
assumptions that are believed to be reasonable under the circumstances.
Actual results could differ from those estimates. Significant estimates
with regard to these financial statements include the estimate of proved
oil and gas reserve quantities and the related present value of estimated
future net cash flows therefrom. See unaudited "Supplemental Oil and Gas
Disclosures" below.
PAYABLE TO APACHE --
The payable to Apache represents the net result of the Investing
Partners' revenue and expenditure transactions in the current month.
Generally, this amount will be transferred to Apache in the month after the
Partnership's transactions are processed and the net results from
operations are determined.
MAINTENANCE AND REPAIRS --
Maintenance and repairs are charged to expense as incurred.
RECLASSIFICATIONS --
To comply with the consensus reached on Emerging Issues Task Force
Issue 00-10, "Accounting for Shipping and Handling Fees and Costs", third
party gathering and transportation costs have been reported as an operating
cost instead of a reduction of revenues as previously reported.
Reclassifications have been made to reflect this change in prior period
statements of consolidated income.
24
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(3) COMPENSATION TO APACHE
Apache is entitled to the following types of compensation and
reimbursement for costs and expenses.
TOTAL REIMBURSED BY THE INVESTING
PARTNERS FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(In thousands)
a. Apache is reimbursed for general, administrative and
overhead expenses incurred in connection with the
management and operation of the Partnership's business $ 358 $ 384 $ 432
=========== =========== ===========
b. Apache is reimbursed for development overhead costs
incurred in the Partnership's operations. These costs are
based on development activities and are capitalized to
oil and gas properties $ 129 $ 147 $ 190
=========== =========== ===========
Apache operates certain Partnership properties. Billings to the
Partnership are made on the same basis as to unaffiliated third parties or
at prevailing industry rates.
(4) OIL AND GAS PROPERTIES
The following tables contain direct cost information and changes in the
Partnership's oil and gas properties for each of the years ended December
31. All costs of oil and gas properties are currently being amortized.
2002 2001 2000
------------- ------------- -------------
(In thousands)
Oil and Gas Properties
Balance, beginning of year $ 176,409 $ 173,378 $ 169,496
Costs incurred during the year:
Development --
Investing Partners 3,174 2,962 3,696
Managing Partner 74 69 186
------------- ------------- -------------
Balance, end of year $ 179,657 $ 176,409 $ 173,378
============= ============= =============
25
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
MANAGING INVESTING
PARTNER PARTNERS TOTAL
------------- ------------- -------------
(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 1999 $ 20,298 $ 143,860 $ 164,158
Provision 167 2,805 2,972
------------- ------------- -------------
Balance, December 31, 2000 20,465 146,665 167,130
Provision 116 1,927 2,043
------------- ------------- -------------
Balance, December 31, 2001 20,581 148,592 169,173
Provision 101 2,080 2,181
------------- ------------- -------------
Balance, December 31, 2002 $ 20,682 $ 150,672 $ 171,354
============= ============= =============
The Partnership's aggregate DD&A expense as a percentage of oil and gas
sales for 2002, 2001 and 2000 was 32 percent, 19 percent and 24 percent,
respectively.
(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION
Revenues received from major third party customers that exceeded 10
percent of oil and gas sales are discussed below. No other third party
customers individually accounted for more than ten percent of oil and gas
sales.
Sales to Cinergy Marketing & Trading, LLC (Cinergy) accounted for 60
percent, 73 percent, and 71 percent of the Partnership's oil and gas sales
in 2002, 2001 and 2000, respectively. In 1998, Apache formed a strategic
alliance with Cinergy Corp. to market substantially all of Apache's natural
gas production from North America and sold its 57 percent interest in
Producers Energy Marketing LLC (ProEnergy) to Cinergy Corp. In July 1998,
in connection with the sale of its interest, Apache entered into a gas
purchase agreement with Cinergy to market most of Apache's North American
natural gas production for 10 years, with an option, after prior notice, to
terminate after six years. Apache also sells most of the Partnership's
natural gas production to Cinergy under the gas purchase agreement. Since
2001, Apache has been involved in an arbitration proceeding with Cinergy on
issues arising from the gas sales agreement. Apache continues to market
most of the Partnership's gas production through Cinergy; however, Apache
is actively discussing with Cinergy its gas marketing relationship with
Cinergy and a resolution of the related disputes. The Partnership does not
expect the final resolution of these disputes to have a material effect on
its financial position or future sales. The prices the Partnership receives
for its gas production, in the opinion of Apache, approximate market
prices.
Apache Crude Oil Marketing, Inc., a wholly-owned subsidiary of Apache,
purchased oil and condensate from the Partnership which accounted for
approximately 17 percent, 26 percent and 12 percent of the Partnership's
total oil and gas sales in 2002, 2001 and 2000, respectively. The prices
the Partnership received for these sales were based on third-party pricing
indexes, and in the opinion of Apache, comparable to prices that would have
been received from a non-affiliated party.
Sales of oil and condensate to Chevron Texaco accounted for 21 percent
of the Partnership's oil and gas sales in 2002 and sales to Williams Energy
Marketing & Trading Company accounted for 10 percent of the Partnership's
oil and gas sales in 2000.
Effective November 1992, with Apache's and the Partnership's
acquisition of an additional net revenue interest in Matagorda Island
Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from
Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline
connecting Matagorda Island Block 681 to onshore markets. The Partnership
paid the Apache subsidiary transportation fees totaling $43,785 in 2002,
$45,147 in 2001 and $60,690 in 2000 for the Partnership's share of gas. The
fees were at the same rates and terms as previously paid to Shell.
26
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Partnership's revenues are derived principally from
uncollateralized sales to customers in the oil and gas industry; therefore,
customers may be similarly affected by changes in economic and other
conditions within the industry. The Partnership has not experienced
material credit losses on such sales.
(6) FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents, accrued revenues
receivables and accrued costs included in the accompanying balance sheet
approximated their fair values at December 31, 2002 and 2001 due to their
short maturities. The Partnership did not use derivative financial
instruments or otherwise engage in hedging activities during the three-year
period ended December 31, 2002.
(7) COMMITMENTS AND CONTINGENCIES
Litigation -- The Partnership is involved in litigation and is subject
to governmental and regulatory controls arising in the ordinary course of
business. It is the opinion of the Apache's management that all claims and
litigation involving the Partnership are not likely to have a material
adverse effect on its financial position or results of operations.
Environmental -- The Partnership, as an owner or lessee of interests in
oil and gas properties, is subject to various federal, state, local and
foreign country laws and regulations relating to discharge of materials
into, and protection of, the environment. These laws and regulations may,
among other things, impose liability on the lessee under an oil and gas
lease for the cost of pollution clean-up resulting from operations and
subject the lessee to liability for pollution damages. Apache maintains
insurance coverage on the Partnership's properties, which it believes, is
customary in the industry, although it is not fully insured against all
environmental risks.
(8) NEW ACCOUNTING PRONOUNCEMENTS
In 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 143 "Accounting for Asset
Retirement Obligations." SFAS 143 addresses financial accounting and
reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. This statement
requires companies to record the fair value of legal obligations associated
with the retirement of tangible long-lived assets in the period in which it
is incurred. The liability is capitalized as part of the related long-lived
asset's carrying amount. Over time, accretion of the liability is
recognized as an operating expense and the capitalized cost is depreciated
over the expected useful life of the related asset. The Partnership's asset
retirement obligations relate primarily to the plugging, dismantlement,
removal, site reclamation and similar activities of its oil and gas assets.
Prior to adoption of this statement, such obligations were accrued ratably
over the productive lives of the assets through its depreciation, depletion
and amortization for oil and gas properties without recording a separate
liability for such amounts.
Effective January 1, 2003, the Partnership adopted SFAS 143 which
resulted in an increase to net oil and gas properties of $1.1 million and
additional liabilities related to asset retirement obligations of $.8
million. These entries reflect the asset retirement obligation of the
Partnership had the provisions of SFAS 143 been applied since inception.
This resulted in a cumulative-effect increase in net income of $.3 million.
(9) INSURANCE RECOVERIES
During 2002, the Partnership recognized insurance recoveries totaling
$99,300 for the estimated amount of proceeds recoupable under business
interruption insurance policies. The estimated recoveries are included in
other revenue in the accompanying Statement of Consolidated Income and
reflect expected recoveries for the Partnership's share of lost oil and gas
production resulting from hurricanes in 2002.
27
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(10) TAX-BASIS FINANCIAL INFORMATION
A reconciliation of ordinary income for federal income tax reporting
purposes to net income under accounting principles generally accepted in
the United States is as follows:
2002 2001 2000
------------ ------------ ------------
Net partnership ordinary income for federal income
tax reporting purposes $ 2,426,766 $ 6,199,485 $ 7,106,780
Plus: Items of current (income) expense for tax reporting
purposes only --
Intangible drilling cost 2,638,051 2,457,181 3,358,567
(Gain) on disposition of equipment -- (258,053) --
Tax depreciation 640,091 908,093 1,002,897
------------ ------------ ------------
3,278,142 3,107,221 4,361,464
------------ ------------ ------------
Less: full cost DD&A expense (2,181,189) (2,042,461) (2,971,525)
------------ ------------ ------------
Net income $ 3,523,719 $ 7,264,245 $ 8,496,719
============ ============ ============
The Partnership's tax bases in net oil and gas properties at December
31, 2002 and 2001 was $2,221,960 and $1,074,660, respectively, lower than
carrying value of oil and gas properties under full cost accounting. The
difference reflects the timing deductions for depreciation, depletion and
amortization and intangible drilling costs.
For federal income tax reporting, the Partnership had capitalized
syndication cost of $8,660,878 at December 31, 2002 and 2001. The
Partnership's liabilities for each of the two years ended December 31, 2002
were the same for federal income tax reporting purposes as reported under
accounting principles generally accepted in the United States.
28
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
OIL AND GAS RESERVE INFORMATION --
Proved oil and gas reserve quantities are based on estimates prepared
by Ryder Scott Company, L.P., Petroleum Consultants, independent petroleum
engineers, in accordance with guidelines established by the SEC. These
reserves are subject to revision due to the inherent imprecision in
estimating reserves, and are revised as additional information becomes
available. All the Partnership's reserves are located offshore Texas and
Louisiana.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve data represents estimates
only and should not be construed as being exact.
(Oil in Mbbls and gas in MMcf)
2002 2001 2000
------------------ ----------------- ---------------------
OIL GAS OIL GAS OIL GAS
------- -------- ------- ------- -------- ----------
Proved Reserves
Beginning of year 885 7,075 883 8,080 687 8,992
Extensions, discoveries and other
additions 204 389 155 697 239 747
Revisions of previous estimates (130) 99 (41) 3 76 661
Production (110) (1,224) (112) (1,705) (119) (2,320)
-------- -------- -------- -------- --------- ---------
End of year 849 6,339 885 7,075 883 8,080
======== ======== ======== ======== ========= =========
Proved Developed
Beginning of year 767 6,685 736 7,462 613 8,679
======== ======== ======== ======== ========= =========
End of year 849 6,230 767 6,685 736 7,462
======== ======== ======== ======== ========= =========
29
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES - (CONTINUED)
(UNAUDITED)
FUTURE NET CASH FLOWS --
The following table sets forth unaudited information concerning future
net cash flows from proved oil and gas reserves. Future cash inflows are
based on year-end prices. Operating costs and future development costs are
based on current costs with no escalation. As the Partnership pays no
income taxes, estimated future income tax expenses are omitted. This
information does not purport to present the fair value of the Partnership's
oil and gas assets, but does present a standardized disclosure concerning
possible future net cash flows that would result under the assumptions
used.
Discounted Future Net Cash Flows Relating to Proved Reserves
DECEMBER 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
(In thousands)
Future cash inflows $ 56,471 $ 36,604 $ 104,319
Future production costs (4,623) (4,440) (3,705)
Future development costs (4,115) (4,937) (5,958)
------------- ------------- -------------
Net cash flows 47,733 27,227 94,656
10 percent annual discount rate (16,908) (9,794) (29,333)
------------- ------------- -------------
Discounted future net cash flows $ 30,825 $ 17,433 $ 65,323
============= ============= =============
The following table sets forth the principal sources of change in the
discounted future net cash flows:
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
(In thousands)
Sales, net of production costs $ (6,034) $ (9,712) $ (11,884)
Net change in prices and production costs 14,403 (43,479) 39,718
Extensions, discoveries and other additions 4,548 2,730 7,644
Development costs incurred 680 1,863 933
Revisions of quantities (2,023) (428) 6,016
Accretion of discount 1,743 6,532 2,126
Changes in future development costs 185 174 (1,799)
Changes in production rates and other (110) (5,570) 1,307
------------- ------------- -------------
$ 13,392 $ (47,890) $ 44,061
============= ============= =============
30
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL
------------ ----------- ----------- ----------- -----------
(In thousands, except per Unit amounts)
2002
Revenues $ 1,342 $ 1,787 $ 1,674 $ 2,183 $ 6,986
Expenses 704 896 892 970 3,462
------------ ----------- ----------- ----------- -----------
Net income $ 638 $ 891 $ 782 $ 1,213 $ 3,524
============ =========== =========== =========== ===========
Net income allocated to:
Managing Partner $ 193 $ 260 $ 245 $ 338 $ 1,036
Investing Partners 445 631 537 875 2,488
------------ ----------- ----------- ----------- ------------
$ 638 $ 891 $ 782 $ 1,213 $ 3,524
============ =========== =========== =========== ===========
Net income per Investing
Partner Unit $ 400 $ 570 $ 490 $ 799 $ 2,259
============ =========== =========== =========== ===========
2001
Revenues $ 4,044 $ 2,822 $ 2,090 $ 1,614 $ 10,570
Expenses 1,047 801 739 719 3,306
------------ ----------- ----------- ----------- -----------
Net income $ 2,997 $ 2,021 $ 1,351 $ 895 $ 7,264
============ =========== =========== =========== ===========
Net income allocated to:
Managing Partner $ 699 $ 470 $ 333 $ 229 $ 1,731
Investing Partners 2,298 1,551 1,018 666 5,533
------------ ----------- ----------- ----------- -----------
$ 2,997 $ 2,021 $ 1,351 $ 895 $ 7,264
============ =========== =========== =========== ===========
Net income per Investing
Partner Unit $ 2,036 $ 1,377 $ 907 $ 602 $ 4,922
============ =========== =========== =========== ===========
31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The financial statements for the fiscal year ended December 31, 2002,
included in this report, have been audited by Ernst & Young LLP, independent
public auditors, as stated in their audit report appearing herein. The financial
statements for the fiscal years ended December 31, 2001, and December 31, 2000,
included in this report, were audited by Arthur Andersen LLP, independent public
accountants, as stated in their audit report appearing herein. Arthur Andersen
has not consented to the inclusion of their audit report in this report. For a
discussion of the risks relating to Arthur Andersen's audit of our financial
statements, please see "Risks relating to Arthur Andersen LLP" in Item 1.
Arthur Andersen's reports on the Partnership's consolidated financial
statements for each of the fiscal years ended December 31, 2001 and December 31,
2000, included elsewhere in this report, did not contain an adverse opinion or
disclaimer of opinion, nor were they qualified or modified as to uncertainty,
audit scope or accounting principles.
During the years ended December 31, 2001 and December 31, 2000, and through
the date we dismissed Arthur Andersen LLP, there were no disagreements with
Arthur Andersen on any matter of accounting principle or practice, financial
statement disclosure, or auditing scope or procedure which, if not resolved by
Arthur Andersen's satisfaction, would have caused them to make reference to the
subject matter in connection with their report on the Partnership's consolidated
financial statements for such years; and there were no reportable events as set
forth in applicable SEC regulations.
The General Partner provided Arthur Andersen LLP with a copy of the above
disclosures on April 2, 2002. In a letter dated April 2, 2002, Arthur Andersen
confirmed its agreement with these statements.
32
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP
All management functions are performed by Apache, the Managing Partner of
the Partnership. The Partnership itself has no officers or directors.
Information concerning the officers and directors of Apache set forth under the
captions "Nominees for Election as Directors", "Continuing Directors",
"Executive Officers of the Company", and "Securities Ownership and Principal
Holders" in the proxy statement relating to the 2003 annual meeting of
stockholders of Apache (the Apache Proxy) is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
See Note (3), "Compensation to Apache" of the Partnership's financial
statements, under Item 8 above, for information regarding compensation to Apache
as Managing Partner. The information concerning the compensation paid by Apache
to its officers and directors set forth under the captions "Summary Compensation
Table", "Option/SAR Exercises and Year-End Value Table", "Employment Contracts
and Termination of Employment and Change-in-Control Arrangements", and "Director
Compensation" in the Apache Proxy is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Apache, as an Investing Partner and the General Partner, owns 53 Units, or
4.9 percent of the outstanding Units of the Partnership, as of December 31,
2002. Directors and officers of Apache own four Units, less than one percent of
the Partnership's Units, as of December 31, 2002. Apache owns a one-percent
General Partner interest (15 equivalent Units). To the knowledge of the
Partnership, no Investing Partner owns, of record or beneficially, more than
five percent of the Partnership's outstanding Units.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Note (3), "Compensation to Apache" of the Partnership's financial
statements, under Item 8 above, for information regarding compensation to Apache
as Managing Partner. See Note (5), "Major Customers and Related Parties
Information" of the Partnership's financial statements for amounts paid to
subsidiaries of Apache, and for other related party information.
ITEM 14. CONTROLS AND PROCEDURES
The certifying officers of the general partner evaluated the effectiveness
of the Partnership's disclosure controls and procedures within the last 90 days
preceding the date of this report. Based on that review and as of the date of
that evaluation, these officers found the Partnership's disclosure controls to
be adequate, providing effective means to insure that the Partnership timely and
accurately disclose the information it is required to disclose under applicable
laws and regulations. We also made no significant changes in the Partnership's
internal controls or any other factors that could affect the Partnership's
internal controls since our most recent internal controls evaluation.
33
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
a. (1) Financial Statements -- See accompanying index to financial
statements in Item 8 above.
(2) Financial Statement Schedules -- See accompanying index to
financial statements in Item 8 above.
(3) Exhibits
3.1 Partnership Agreement of Apache Offshore Investment
Partnership (incorporated by reference to Exhibit (3)(i) to
Form 10 filed by Partnership with the Commission on April
30, 1985, Commission File No. 0-13546).
3.2 Amendment No. 1, dated February 11, 1994, to the
Partnership Agreement of Apache Offshore Investment
Partnership (incorporated by reference to Exhibit 3.3 to
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1993, Commission File No. 0-13546).
3.3 Limited Partnership Agreement of Apache Offshore Petroleum
Limited Partnership (incorporated by reference to Exhibit
(3)(ii) to Form 10 filed by Partnership with the Commission
on April 30, 1985, Commission File No. 0-13546).
10.1 Form of Assignment and Assumption Agreement between Apache
Corporation and Apache Offshore Petroleum Limited
Partnership (incorporated by reference to Exhibit 10.2 to
Partnership's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1992, Commission File No. 0-13546).
10.2 Joint Venture Agreement, dated as of November 23, 1992,
between Apache Corporation and Apache Offshore Petroleum
Limited Partnership (incorporated by reference to Exhibit
10.6 to Partnership's Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 0-13546).
10.3 Matagorda Island 681 Field Purchase and Sale Agreement
with Option to Exchange, dated November 24, 1992, between
Apache Corporation, Shell Offshore, Inc. and SOI Royalties,
Inc. (incorporated by reference to Exhibit 10.7 to
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 0-13546).
*23.1 Consent of Ryder Scott Company, L.P., Petroleum
Consultants.
99.1 Consent statement of the Partnership, dated January 7, 1994
(incorporated by reference to Exhibit 99.1 to Partnership's
Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 0-13546).
99.2 Proxy statement to be dated on or about March 31, 2003,
relating to the 2003 annual meeting of stockholders of
Apache Corporation (incorporated by reference to the
document filed by Apache pursuant to Rule 14A, Commission
File No. 1-4300).
*99.3 Certification of Chief Executive Officer and Chief Financial
Officer.
*Filed herewith.
b. Reports filed on Form 8-K.
No reports on Form 8-K were filed during the fiscal quarter ended
December 31, 2002.
34
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
By: Apache Corporation, General Partner
Date: March 24, 2003 By: /s/ G. Steven Farris
----------------------------------------
G. Steven Farris
President, Chief Executive Officer and
Chief Operating Officer
POWER OF ATTORNEY
The officers and directors of Apache Corporation, General Partner of Apache
Offshore Investment Partnership, whose signatures appear below, hereby
constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie and
Eric L. Harry, and each of them (with full power to each of them to act alone),
the true and lawful attorney-in-fact to sign and execute, on behalf of the
undersigned, any amendment(s) to this report and each of the undersigned does
hereby ratify and confirm all that said attorneys shall do or cause to be done
by virtue thereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME TITLE DATE
- --------------------------------------- --------------------------------------- -------------------
/s/ G. Steven Farris Director, President, Chief Executive March 24, 2003
- --------------------------------------- Officer and Chief Operating Officer
G. Steven Farris (Principal Executive Officer)
/s/ Roger B. Plank Executive Vice President and Chief March 24, 2003
- --------------------------------------- Financial Officer (Principal
Roger B. Plank Financial Officer)
/s/ Thomas L. Mitchell Vice President and Controller March 24, 2003
- --------------------------------------- (Principal Accounting Officer)
Thomas L. Mitchell
NAME TITLE DATE
- -------------------------------------------- -------------------------------------- -----------------
/s/ Raymond Plank Chairman of the Board March 24, 2003
- --------------------------------------------
Raymond Plank
/s/ Frederick M. Bohen Director March 24, 2003
- --------------------------------------------
Frederick M. Bohen
/s/ Randolph M. Ferlic Director March 24, 2003
- --------------------------------------------
Randolph M. Ferlic
/s/ Eugene C. Fiedorek Director March 24, 2003
- --------------------------------------------
Eugene C. Fiedorek
/s/ A. D. Frazier, Jr. Director March 24, 2003
- --------------------------------------------
A. D. Frazier, Jr.
/s/ Patricia Albjerg Graham Director March 24, 2003
- --------------------------------------------
Patricia Albjerg Graham
/s/ John A. Kocur Director March 24, 2003
- --------------------------------------------
John A. Kocur
/s/ George D. Lawrence Director March 24, 2003
- --------------------------------------------
George D. Lawrence
/s/ F. H. Merelli Director March 24, 2003
- --------------------------------------------
F. H. Merelli
/s/ Rodman D. Patton Director March 24, 2003
- --------------------------------------------
Rodman D. Patton
/s/ Charles J. Pitman Director March 24, 2003
- --------------------------------------------
Charles J. Pitman
/s/ Jay A. Precourt Director March 24, 2003
- --------------------------------------------
Jay A. Precourt
CERTIFICATIONS
I, Roger B. Plank, certify that:
1. I have reviewed this annual report on Form 10-K of Apache Offshore
Investment Partnership;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
/s/ Roger B. Plank
- -----------------------------------------------------
Roger B. Plank
Executive Vice President and Chief Financial Officer
of Apache Corporation, Managing Partner
Date: March 24, 2003
CERTIFICATIONS
I, G. Steven Farris, certify that:
1. I have reviewed this annual report on Form 10-K of Apache Offshore
Investment Partnership;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
/s/ G. Steven Farris
- -----------------------------------------------------
G. Steven Farris
President, Chief Executive Officer and
Chief Operating Officer of Apache Corporation,
Managing Partner
Date: March 24, 2003
EXHIBIT INDEX
3.1 Partnership Agreement of Apache Offshore Investment
Partnership (incorporated by reference to Exhibit (3)(i) to
Form 10 filed by Partnership with the Commission on April
30, 1985, Commission File No. 0-13546).
3.2 Amendment No. 1, dated February 11, 1994, to the
Partnership Agreement of Apache Offshore Investment
Partnership (incorporated by reference to Exhibit 3.3 to
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1993, Commission File No. 0-13546).
3.3 Limited Partnership Agreement of Apache Offshore Petroleum
Limited Partnership (incorporated by reference to Exhibit
(3)(ii) to Form 10 filed by Partnership with the Commission
on April 30, 1985, Commission File No. 0-13546).
10.1 Form of Assignment and Assumption Agreement between Apache
Corporation and Apache Offshore Petroleum Limited
Partnership (incorporated by reference to Exhibit 10.2 to
Partnership's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1992, Commission File No. 0-13546).
10.2 Joint Venture Agreement, dated as of November 23, 1992,
between Apache Corporation and Apache Offshore Petroleum
Limited Partnership (incorporated by reference to Exhibit
10.6 to Partnership's Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 0-13546).
10.3 Matagorda Island 681 Field Purchase and Sale Agreement
with Option to Exchange, dated November 24, 1992, between
Apache Corporation, Shell Offshore, Inc. and SOI Royalties,
Inc. (incorporated by reference to Exhibit 10.7 to
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 0-13546).
*23.1 Consent of Ryder Scott Company, L.P., Petroleum Consultants.
99.1 Consent statement of the Partnership, dated January 7, 1994
(incorporated by reference to Exhibit 99.1 to Partnership's
Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 0-13546).
99.2 Proxy statement to be dated on or about March 31, 2003,
relating to the 2003 annual meeting of stockholders of
Apache Corporation (incorporated by reference to the
document filed by Apache pursuant to Rule 14A, Commission
File No. 1-4300).
*99.3 Certification of Chief Executive Officer and Chief Financial
Officer.
*Filed herewith.