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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, 2003
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 30, 2003................... $13,628,508
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Apache Corporation's proxy statement relating to its 2004
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................................................................................... 15
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................... 16
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE...................................................... 37
9A. CONTROLS AND PROCEDURES....................................................................... 37
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP........................................... 38
11. EXECUTIVE COMPENSATION........................................................................ 38
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................................................................... 38
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................................ 38
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES........................................................ 38
PART IV
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............................... 39
All defined terms under Rule 4-10(a) of Regulation S-X shall have their
statutorily-prescribed meanings when used in this report. Quantities of natural
gas are expressed in this report in terms of thousand cubic feet (Mcf), million
cubic feet (MMcf) 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,
2003, 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 7.08 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.
2003 RESULTS AND BUSINESS DEVELOPMENT
The Partnership reported net income in 2003 of $8.0 million, or $5,598 per
Investing Partner Unit including the cumulative effect of a change in accounting
principle. Earnings before the cumulative effect of the change in accounting
principles totaled $7.7 million, or more than twice the Partnership's 2002
earnings. The change in accounting principle reflects the Partnership's adoption
of Statement of Financial Accounting Standard (SFAS) No. 143, Accounting for
Asset Retirement Obligations. Natural gas production averaged 3,924 Mcf per day,
while oil sales averaged 342 barrels per day. Production added through
successful recompletions in 2003 and a full year's production from North Padre
Island 969 more than offset declines from natural depletion.
During 2003, the Partnership did not participate in drilling any new wells,
but continued to participate in recompletion projects to maintain production and
enhance recoverable reserves. During 2003, the Partnership participated in nine
recompletions at South Timbalier 295 and one at Ship Shoal 259.
Since inception, the Partnership has acquired an interest in 49 prospects.
As of December 31, 2003, 43 of those prospects have been surrendered or sold.
As of December 31, 2003, the Partnership had 52 producing wells on the
Partnership's six remaining developed fields. Two of the Partnership's producing
wells are dual completions. The Partnership had, at December 31, 2003, estimated
proved oil and gas reserves of 9.7 Bcfe, of which 62 percent was natural gas.
MARKETING
Apache, on behalf of the Partnership, seeks and negotiates oil and gas
marketing arrangements with various marketers and purchasers. The Partnership's
oil and condensate production during 2003 was purchased largely by Chevron
Texaco at market prices.
Effective with July 2003 production, the Managing Partner began directly
marketing the Partnership's and its own U.S. natural gas production. Most of the
Partnership's natural gas production was previously marketed through Cinergy
Marketing and Trading, LLC (Cinergy) under a gas sales agreement between the
Managing Partner and Cinergy. The Partnership believes that the sales prices it
receives for natural gas sales are comparable to prices that would have been
received from Cinergy.
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 sold most of the
Partnership's natural gas production to Cinergy under the gas purchase
agreement.
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 on the Partnership's business or
results of operations. The Partnership is not in a position to predict future
oil and gas prices.
2
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.
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 had not incurred any material
environmental remediation costs in any of the periods presented and is not aware
of any future environmental remediation matters that would be 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. Ernst & Young also served as the
Partnership's independent auditors in 2003. However, included in this annual
report on Form 10-K are financial data and other information for 2001 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, 2003, 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
Ship Shoal 201, 202 LA 10,000 -
----------- -----------
66,061 3,496
=========== ===========
At December 31, 2003, 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, 2003, is set forth below:
GAS OIL
---------------------- ----------------------
LEASE BLOCK STATE GROSS NET GROSS NET
------------------------------ -------- ---------- --------- ----------- ----------
Ship Shoal 258, 259 LA 4 .25 - -
South Timbalier 276, 295, 296 LA 1 .07 32 2.27
North Padre Island 969, 976 TX 5 .35 - -
Matagorda Island 681, 682, TX 7 .44 - -
683
South Pass 83 LA 1 .07 - -
Ship Shoal 201, 202 LA 1 - 1 -
-------- ------- --------- --------
19 1.18 33 2.27
======== ======= ========= ========
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
------------ ------------- ---------- ------------ ------------ ------------- ------------
2003 - - - - - -
2002 - - - .35 .07 .42
2001 - - - .28 - .28
5
PRODUCTION AND PRICING DATA
The following table describes, for each of the last three fiscal years,
oil, natural gas liquids (NGLs) and gas production for the Partnership, average
production costs (including gathering and transportation expense) and average
sales prices.
PRODUCTION AVERAGE AVERAGE SALES PRICES
------------------------------------ -------------------------------------
YEAR ENDED OIL GAS NGLS PRODUCTION OIL GAS NGLS
DECEMBER 31, (MBBLS) (MMCF) (MBBLS) COST PER MCFE (PER BBL) (PER MCF) (PER BBL)
- ---------------- ----------- ----------- ---------- --------------- ----------- ----------- ----------
2003 125 1,432 6 $ .42 $ 30.73 $ 5.56 $ 23.92
2002 110 1,224 - .44 25.03 3.36 -
2001 112 1,705 - .33 25.00 4.51 -
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, 2003, the Partnership had total estimated proved
reserves of 618,000 barrels of crude oil, condensate and NGLs and 6 Bcf of
natural gas. Combined, these total estimated proved reserves are equivalent to
9.7 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, 2003, 2002 and 2001, 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 2003 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, condensate and NGLs that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Reserves are
considered proved if economical producibility is supported by either actual
production or conclusive formation tests. Reserves that can be produced
economically through application of improved recovery techniques are included in
the "proved" classification when successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program is based. Proved developed
oil and gas reserves can be expected to be recovered through existing wells with
existing equipment and operating methods.
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 2003.
6
PART II
ITEM 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY
HOLDER MATTERS
As of December 31, 2003, there were 1,060.7 of the Partnership's Units
outstanding held by 879 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 $4.8
million, or $4,500 per Unit, during 2003 and approximately $1.1 million, or
$1,000 per Unit, during 2002.
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,
2003, 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 1999 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,
----------------------------------------------------------------------------
2003 2002 2001 2000 1999
------------ ------------ ------------ ------------- -------------
(In thousands, except per Unit amounts)
Total assets $ 11,674 $ 9,834 $ 9,413 $ 8,715 $ 8,722
=========== ========== =========== =========== ===========
Partners' capital $ 10,475 $ 9,610 $ 8,369 $ 7,728 $ 7,755
=========== ========== =========== =========== ===========
Oil and gas sales $ 11,951 $ 6,868 $ 10,495 $ 12,641 $ 8,796
=========== ========== =========== =========== ===========
Net income $ 8,037 $ 3,524 $ 7,264 $ 8,497 $ 4,351
=========== ========== =========== =========== ===========
Net income allocated to:
Managing Partner $ 2,037 $ 1,036 $ 1,731 $ 2,102 $ 1,269
Investing Partners 6,000 2,488 5,533 6,395 3,082
----------- ----------- ----------- ----------- -----------
$ 8,037 $ 3,524 $ 7,264 $ 8,497 $ 4,351
=========== ========== =========== =========== ===========
Net income per Investing
Partner Unit $ 5,598 $ 2,259 $ 4,922 $ 5,654 $ 2,707
=========== ========== =========== =========== ===========
Cash distributions per
Investing Partner Unit $ 4,500 $ 1,000 $ 4,000 $ 5,750 $ 3,500
=========== ========== =========== =========== ===========
7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
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. The Partnership is a very minor factor in
the oil and gas industry and faces strong competition in all aspects of its
business. With a relatively small amount of capital invested in the Partnership
and management's decision to avoid incurring debt, the Partnership has not
engaged in acquisition or exploration activities in recent years. The
Partnership has not carried any debt since January 1997. The limited amount of
capital and the Partnership's modest reserve base have contributed to the
Partnership focusing on production activities and developing existing leases.
As with other independent energy companies, the Partnership derives its
revenue from the production and sale of crude oil, natural gas and natural gas
liquids. The Partnership sells its production at market prices and has not used
derivative financial instruments or otherwise engaged in hedging activities.
With tight supplies of natural gas in the United States and political concerns
impacting world oil markets, the Partnership benefited from high oil and gas
prices throughout 2003. Commodity prices, however, have historically been
volatile. This volatility has caused the Partnership's revenues and resulting
cash flow from operating activities to fluctuate widely over the years.
The Partnership participates in development drilling and recompletion
activities as recommended by outside operators and the Partnership's Managing
Partner. These activities have helped stem the decline in the Partnership's
production in recent years and even contributed to an increase in production in
2003. Generally, the Partnership has used remaining available cash to fund
distributions to its partners.
The Partnership's net income and net income per Investing Partner Unit
increased in 2003 on higher oil and gas production and prices. Daily oil and gas
volumes increased 13 percent and 17 percent, respectively, from a year ago as a
result of successful recompletions in 2003 and a full year's production from
North Padre Island 969. Distributions per Investing Partner Unit in 2003 also
increased as a result of the higher production and gas prices. There were two
distributions made to the Investing Partners in 2003 for a total per unit
distribution of $4,500.
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, costs 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 Statement of Financial
Accounting Standards (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.
8
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.
The Partnership has taken note of a July 2003 inquiry to the Financial
Accounting Standards Board (FASB) regarding whether or not contract-based oil
and gas mineral rights held by lease or contract ("mineral rights") should be
recorded or disclosed as intangible assets. The inquiry presents a view that
these mineral rights are intangible assets as defined in SFAS No. 141, "Business
Combinations," and, therefore, should be classified separately on the balance
sheet as intangible assets. SFAS No. 141, and SFAS No. 142, "Goodwill and Other
Intangible Assets," became effective for transactions subsequent to June 30,
2001 with the disclosure requirements of SFAS No. 142 required as of January 1,
2002. SFAS No. 141 requires that all business combinations initiated after June
30, 2001 be accounted for using the purchase method and that intangible assets
be disaggregated and reported separately from goodwill. SFAS No. 142 established
new accounting guidelines for both finite lived intangible assets and indefinite
lived intangible assets. Under the statement, intangible assets should be
separately reported on the face of the balance sheet and accompanied by
disclosure in the notes to financial statements. SFAS No. 142 scopes out
accounting utilized by the oil and gas industry as prescribed by SFAS No. 19,
and is silent about whether or not its disclosure provisions apply to oil and
gas companies. The Partnership does not believe that SFAS No. 141 or 142 change
the classification of oil and gas mineral rights and the Partnership continues
to classify these assets as part of oil and gas properties. Also, the
Partnership has not participated in any business combinations or major asset
acquisition since the June 30, 2001 effective date of SFAS No. 141 and SFAS No.
142. The Emerging Issues Task Force (EITF) has added the treatment of oil and
gas mineral rights to an upcoming agenda, which may result in a change in how
the Partnership classifies these assets.
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.
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
removing and disposing of offshore oil and gas platforms. Estimating the future
restoration and 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 are regulatory, political, environmental, safety and public
relations considerations. Prior to 2003, under the full-cost method of
accounting, as described in the preceding critical accounting policy sections,
the estimated undiscounted costs of the
9
abandonment obligations, net of the value of salvage, were currently included as
a component of the Partnership's depletion base and expensed over the production
life of the oil and gas properties.
In 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement
Obligations." The Partnership adopted this statement effective January 1, 2003,
as discussed in Note 8 of this Form 10-K. SFAS No. 143 significantly changed the
method of accruing for costs an entity is legally obligated to incur related to
the retirement of fixed assets ("asset retirement obligations" or "ARO").
Primarily, the new statement requires the Partnership to record a separate
liability for the discounted present value of the Partnership's asset retirement
obligations, with an offsetting increase to the related oil and gas properties
on the balance sheet.
Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance. In addition, increases in the discounted ARO liability resulting from
the passage of time will be reflected as accretion expense in the statement of
consolidated income.
SFAS No. 143 requires a cumulative adjustment to reflect the impact of
implementing the statement had the rule been in effect since inception. The
Partnership, therefore, calculated the cumulative accretion expense on the ARO
liability and the cumulative depletion expense on the corresponding property
balance. The sum of these cumulative expenses was compared to the depletion
expense originally recorded. Because the historically recorded depletion expense
was higher than the cumulative expense calculated under SFAS No. 143, the
difference resulted in a gain which the Partnership recorded as cumulative
effect of change in accounting principle on January 1, 2003.
Upon implementation, the Partnership also had to determine if the statement
required us to recalculate our historical full-cost ceiling tests (see Note 1 of
this Form 10-K). The Partnership chose not to re-calculate its historical
full-cost ceiling tests even though its historical oil and gas property balances
would have been higher had we applied the statement from inception. We believe
this approach is appropriate because SFAS No. 143 is silent on this issue and
was not effective during the prior impairment test periods. Had a recalculation
of the historical full-cost ceiling test resulted in impairment, the charge
would have reduced the gain recorded upon adoption.
Going forward, the Partnership's depletion expense will be reduced since it
will deplete a discounted ARO rather than the undiscounted value previously
depleted. The lower depletion expense under SFAS No. 143 is offset, however, by
higher accretion expense, which reflects increases in the discounted asset
retirement obligation over time.
Also, the Partnership had to determine how to incorporate the asset
retirement obligations into the quarterly calculation of its full-cost ceiling
tests (see Note 1 Form 10-K). SFAS No. 143 is silent with respect to this issue
and, although there are various views, the Partnership elected to continue
including the undiscounted ARO as part of future development costs, essentially
reducing the present value of its future net revenues and full-cost ceiling
limit. To compare the property balance, which included the ARO component, to the
full-cost ceiling limit, which has been reduced by a similar abandonment cost,
we netted the ARO liability against the property balance. The Partnership
believes its view is appropriate since there must be a comparable basis between
the net book value of the properties and the full-cost ceiling limitation.
Another widely contemplated view is to exclude the ARO from future development
costs when calculating the full-cost ceiling limitation and not reduce the
carrying amount of capitalized costs by the related liability. This approach
would result in a higher full-cost ceiling limitation and a higher net oil and
gas property balance.
RESULTS OF OPERATIONS
NET INCOME AND REVENUE
The Partnership reported net income of $8.0 million for 2003, more than
double the net income reported in 2002 on the strength of higher prices and
production. Net income per Investing Partner Unit increased in 2003 to $5,598,
up from $2,259 in 2002. The Partnership reported earnings of $3.5 million in
2002 versus $7.3 million in 2001. Net income fell in 2002 on lower gas prices
and a dip in gas production resulting from natural depletion and the impact of
shutting-in production from North Padre Island 969 for nine months in 2002.
10
Total revenues increased to $12 million in 2003 with higher prices and
production. The Partnership's total revenue in 2002 of $7 million was down
one-third from 2001 on lower gas prices and production. Interest income earned
by the Partnership on short-term cash investments in 2003 increased from 2002 as
a result of higher average investment balances in 2003. Interest income in 2002
had declined from $75,000 in 2001 on lower interest rates and average investment
balances.
The Partnership's oil and gas production volume and price information is
summarized in the following table:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2003 2002 2001
---------------- ---------------- ----------------
Gas volumes - Mcf per day 3,924 3,353 4,672
Average gas price - per Mcf $ 5.56 $ 3.36 $ 4.51
Oil volumes - barrels per day 342 302 307
Average oil price - per barrel $ 30.73 $ 25.03 $ 25.00
NGL volumes - barrels per day 16 - -
Average NGL price - per barrel $ 23.92 - -
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.
NATURAL GAS SALES
Natural gas sales for 2003 totaled $8 million, up 94% from 2002 on higher
prices and production. The Partnership's average realized natural gas price for
2003 improved 65% from 2002. The $2.20 per Mcf increase in gas price from a year
ago boosted sales by approximately $2.7 million. Daily gas production for 2003
increased 17 percent from 2002, increasing sales by $1.2 million. Production
added through recompletions at South Timbalier 295 and Ship Shoal 259 in 2003
more than offset natural depletion for the year. Also, production at North Padre
Island 969 was shut-in for the first nine months of 2002 for a dispute with a
pipeline company on increased fees charged for the transportation of natural
gas. 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.
Effective with July 2003 production, the Managing Partner began directly
marketing the Partnership's and its own U.S. natural gas production. Most of the
Partnership's natural gas production was previously marketed through Cinergy
Marketing and Trading, LLC (Cinergy) under a gas sales agreement between the
Managing Partner and Cinergy. The Partnership believes that the prices it
receives for natural gas are comparable to the prices it would have received
from Cinergy. During the fourth quarter of 2003, the Partnership began
processing a portion of its natural gas production through on-shore plants
operated by third parties.
The Partnership's 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 2001 negatively impacted sales by $2
million. Natural gas production declined by 28 percent from 2001, 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 nine months in 2002 for a dispute with a pipeline company
reduced 2002 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 FERC issued its ruling on the
systems transportation rates. The completion of five successful development
wells at South Timbalier 295 during 2002 largely offset production declines in
the field.
11
CRUDE OIL SALES
During 2003, the Partnership's crude oil sales increased 39 percent from
2002 to $3.8 million. A $5.70 per barrel, or 23 percent, increase in the
Partnership's average realized oil price in 2003 increased oil revenues by $.6
million from 2002. Oil production increased 13 percent from 2002 as a result of
recompletions at South Timbalier 295.
The Partnership's crude oil sales for 2002 totaled $2.8 million, even with
2001. A slight improvement in average realized oil prices in 2002 was offset by
a two percent decline in production from 2001. Weather-related downtime for
hurricanes in 2002 drove the five barrel per day decline in production from the
prior year. Production added through drilling at South Timbalier 295 during 2002
offset natural depletion for the year.
OTHER REVENUES
The Partnership recognized insurance recoveries in 2003 and 2002 totaling
$14,567 and $99,300, respectively, for the amount of proceeds recoupable under
business interruption insurance policies. The amount reflects 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, decreased to 24 percent in 2003.
The decrease in DD&A rate as a percentage of sales reflected higher oil and gas
prices in 2003. 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 from 19 percent in 2001 as a result of higher finding cost and
lower oil and gas prices in 2002. On an equivalent Mcf basis, the Partnership's
DD&A rate increased in both 2003 and 2002 due to higher finding costs in those
years.
Lease operating expense in 2003 increased approximately $87,000 from a year
ago primarily as result of higher workover and maintenance costs and higher cost
at the North Padre Island 969 compared to 2002. Operations and costs at North
Padre Island 969 were sustained at a reduced level in 2002 while shut-in during
the dispute between the producers and a pipeline company as noted under the
discussion of natural gas sales. Administrative expense declined slightly from
last year, dropping to $405,000.
Lease operating expense in 2002 increased approximately $96,000 from 2001
primarily as a result of higher repair and maintenance cost on platforms and
compressors. Administrative expense declined seven percent from 2001, dropping
to $447,000.
The Partnership sells oil and natural gas under two types of transactions,
both of which include a transportation charge. One is a netback arrangement,
under which the Partnership sells oil or natural gas at the wellhead and
collects a price, net of transportation incurred by the purchaser. Under the
other arrangement, the Partnership sells oil or natural gas at a specific
delivery point, pays transportation to a carrier and receives from the purchaser
a price with no transportation deduction.
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 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 increase in transportation cost paid
to third parties in 2003 reflected higher sales volumes and a modest increase in
transportation rates at North Padre Island 969. The decline in expense in 2002
compared to 2001 reflected lower sales volumes in 2002.
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 or lease commitments at December 31, 2003. The Partnership did
not have any contractual obligations as of December 31, 2003, other than the
12
liability for dismantlement and abandonment costs of its oil and gas properties.
The Partnership has recorded a separate liability for the fair value of this
asset retirement obligation as discussed under the discussion of critical
accounting policies noted above.
During 2003, the Partnership's oil and gas property additions, exclusive of
ARO-related costs, totaled $1.6 million. These additions primarily related to
the Partnership's participation in nine recompletions at South Timbalier 295 and
one recompletion at Ship Shoal 259. The Partnership did not participate in
drilling any new wells during 2003. Capital expenditures during 2002 totaled
$3.2 million as the Partnership participated in drilling six development wells
at South Timbalier 295 and Matagorda 681/682. Capital expenditures during 2001
totaled $3 million as the Partnership participated in drilling four development
wells at South Timbalier 295 and recompletions at Matagorda Island 681/682 and
South Timbalier 295.
As noted above, the Partnership accrues and funds expenditures for future
dismantlement and abandonment costs associated with its oil and gas properties.
These expenditures will be funded by future cash flows from operations and cash
held by the Partnership. At December 31, 2003, the Partnership held $.8 million
in short-term cash investments to fund future dismantlement and abandonment
costs, approximately the net present value of the Partnership's ARO liability at
year-end. These funds are not legally restricted to funding ARO-related cost.
During 2003, the Partnership plugged and abandoned the remaining wellbore in the
East Cameron 60 field, and removed the platform from the site. The field had 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.
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 $.6 million in 2004 directed
primarily toward recompletion projects. 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 2003, the Partnership paid distributions to Investing Partners
totaling approximately $4.8 million or $4,500 per Unit; more than four times the
2002 distributions as a result of higher oil and gas prices and production in
2003. The per Unit distribution in 2002 declined 75 percent from 2001 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.
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 2003, the first right of presentment offer of $12,047 per Unit,
plus interest to the date of payment, was made to Investing Partners based on a
December 31, 2002 valuation date. The second right of presentment offer of
$9,512 per Unit, plus interest to the date of payment, was made to the Investing
Partners based on a valuation date of June 30, 2003. As a result, the
Partnership acquired 24.2 Units for a total of $295,734 in cash. In 2002 and
2001, Investing Partners were paid $213,006 and $195,221, respectively, for a
total of 43.6 Units.
There will be two rights of presentment in 2004, 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 $10.2 million for 2003. Net cash provided by
operating activities in 2003 increased $5.2 million, or 106 percent, from a year
ago resulting from increase in oil and gas production and prices. Net cash
provided by operating activities in 2002 declined 52 percent from 2001 on
declines in oil and gas production and gas 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
13
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 2003 production and 62 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.
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's oil and gas production on an equivalent
Mcf basis is projected to decline by approximately 16 percent in each of the
next two years. While the rate of decline will not be as significant in
following years, the Partnership's production will generally decline each year
thereafter. 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.
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.
14
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 2003, monthly oil price realizations
ranged from a low of $27.38 per barrel to a high of $34.62 per barrel. Gas price
realizations ranged from a monthly low of $4.59 per Mcf to a monthly high of
$9.13 per Mcf during the same period. While remaining strong compared to
historical levels, gas prices trended downward during most of 2003. Based on the
Partnership's average daily production for 2003, a $1.00 per barrel change in
the weighted average realized oil price would have increased or decreased
revenues for the year by approximately $125,000 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 $143,000. The Partnership did not use
derivative financial instruments or otherwise engage in hedging activities
during the three-year period ended December 31, 2003. 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, however, as discussed above, sustained low prices
would have a material adverse effect on future cash flows.
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.
15
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
APACHE OFFSHORE INVESTMENT PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS
PAGE
NUMBER
Report of Independent Auditors - 2003 and 2002......................................................... 17
Report of Independent Public Accountants - 2001........................................................ 18
Statement of Consolidated Income for each of the three years in the period ended December 31, 2003..... 19
Statement of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2003 ................................................................................. 20
Consolidated Balance Sheet as of December 31, 2003 and 2002............................................ 21
Statement of Consolidated Changes in Partners' Capital for each of the three years in the period
ended December 31, 2003............................................................................ 22
Notes to Consolidated Financial Statements............................................................. 23
Supplemental Oil and Gas Disclosures................................................................... 34
Supplemental Quarterly Financial Data................................................................ 36
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.
16
REPORT OF INDEPENDENT AUDITORS
To the Partners of Apache Offshore Investment Partnership:
We have audited the accompanying consolidated balance sheets of Apache
Offshore Investment Partnership (a Delaware general partnership) and subsidiary
as of December 31, 2003 and 2002, and the related consolidated statements of
income, cash flows and changes in partners' capital for each of the two years in
the period ended December 31, 2003. 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. The financial
statements of Apache Offshore Investment Partnership as of December 31, 2001,
and for the year 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 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, 2003 and 2002, and the
results of its operations and its cash flows for each of the two years in the
period ended December 31, 2003 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 the year 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 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 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 financial statements taken as a whole.
As discussed in Note 8 to the consolidated financial statements, effective
January 1, 2003, the Partnership changed its method of accounting for Asset
Retirement Obligations.
ERNST & YOUNG LLP
Houston, Texas
March 11, 2004
17
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.
18
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2003 2002 2001
---------------- ---------------- ----------------
REVENUES:
Oil and gas sales $ 11,950,908 $ 6,867,523 $ 10,494,911
Interest income 27,081 19,199 75,126
Other revenue 14,567 99,300 -
--------------- --------------- ---------------
11,992,556 6,986,022 10,570,037
--------------- --------------- ---------------
OPERATING EXPENSES:
Depreciation, depletion and amortization 2,875,896 2,181,189 2,042,461
Asset retirement obligation accretion 37,605 - -
Lease operating costs 818,636 731,416 635,049
Gathering and transportation expense 121,067 102,698 148,282
Administrative 405,000 447,000 480,000
--------------- --------------- ---------------
4,258,204 3,462,303 3,305,792
--------------- --------------- ---------------
Operating income before cumulative effect of
change in accounting principle $ 7,734,352 $ 3,523,719 $ 7,264,245
Cumulative effect of change in accounting principle 302,407 - -
--------------- --------------- ---------------
NET INCOME $ 8,036,759 $ 3,523,719 $ 7,264,245
=============== =============== ===============
NET INCOME ALLOCATED TO:
Managing Partner $ 2,036,681 $ 1,035,747 $ 1,730,985
Investing Partners 6,000,078 2,487,972 5,533,260
--------------- --------------- ---------------
$ 8,036,759 $ 3,523,719 $ 7,264,245
=============== =============== ===============
NET INCOME PER INVESTING PARTNER UNIT $ 5,598 $ 2,259 $ 4,922
=============== =============== ===============
WEIGHTED AVERAGE INVESTING PARTNER
UNITS OUTSTANDING 1,071.9 1,101.5 1,124.1
=============== =============== ===============
The accompanying notes to financial statements are
an integral part of this statement.
19
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2003 2002 2001
---------------- ---------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 8,036,759 $ 3,523,719 $ 7,264,245
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,875,896 2,181,189 2,042,461
Asset retirement obligation accretion 37,605 - -
Cumulative effect of change in accounting principle (302,407) - -
Dismantlement and abandonment cost (254,134) - -
Changes in operating assets and liabilities:
(Increase) decrease in accrued revenues receivable (26,046) (322,209) 731,343
Increase (decrease) in accrued operating
expenses 3,598 (63,706) 27,400
Increase (decrease) in payable to Apache Corporation (210,169) (392,810) 125,507
-------------- -------------- --------------
Net cash provided by operating activities 10,161,102 4,926,183 10,190,956
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (1,916,566) (3,248,104) (3,030,327)
Increase (decrease) in accrued development costs 282,927 (362,745) (96,442)
-------------- -------------- --------------
Net cash used in investing activities (1,633,639) (3,610,849) (3,126,769)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units (295,734) (213,006) (195,221)
Distributions to Investing Partners (4,789,313) (1,095,189) (4,501,620)
Distributions to Managing Partner, net (2,086,812) (974,634) (1,926,838)
-------------- -------------- --------------
Net cash used in financing activities (7,171,859) (2,282,829) (6,623,679)
-------------- -------------- --------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 1,355,604 (967,495) 440,508
CASH AND CASH EQUIVALENTS, BEGINNING
OF YEAR 915,891 1,883,386 1,442,878
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 2,271,495 $ 915,891 $ 1,883,386
============== ============== ==============
The accompanying notes to financial statements are
an integral part of this statement.
20
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-----------------------------------
2003 2002
---------------- ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,271,495 $ 915,891
Accrued revenues receivable 641,210 615,164
Receivable from Apache Corporation 86,217 -
-------------- --------------
2,998,922 1,531,055
-------------- --------------
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties 182,173,899 179,656,827
Less - Accumulated depreciation, depletion and amortization (173,498,689) (171,353,743)
-------------- --------------
8,675,210 8,303,084
-------------- --------------
$ 11,674,132 $ 9,834,139
============== ==============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued development costs $ 334,740 $ 51,813
Accrued operating expenses 52,076 48,478
Payable to Apache Corporation - 123,952
-------------- --------------
386,816 224,243
-------------- --------------
COMMITMENTS AND CONTINGENCIES (Note 7)
ASSET RETIREMENT OBLIGATION 812,520 -
-------------- --------------
PARTNERS' CAPITAL:
Managing Partner 167,210 217,341
Investing Partners (1,060.7 and 1,084.9 Units
outstanding, respectively) 10,307,586 9,392,555
-------------- --------------
10,474,796 9,609,896
-------------- --------------
$ 11,674,132 $ 9,834,139
============== ==============
The accompanying notes to financial statements are
an integral part of this statement.
21
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS' CAPITAL
MANAGING INVESTING
PARTNER PARTNERS TOTAL
-------------- -------------- --------------
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
Distributions, net (2,086,812) (4,789,313) (6,876,125)
Repurchase of Partnership Units - (295,734) (295,734)
Net income 2,036,681 6,000,078 8,036,759
-------------- -------------- --------------
BALANCE, DECEMBER 31, 2003 $ 167,210 $ 10,307,586 $ 10,474,796
============== ============== ==============
The accompanying notes to financial statements are
an integral part of this statement.
22
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 held approximately five percent of the
1,060.7 Investing Partner Units (Units) outstanding at December 31, 2003.
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 43 of those prospects have been surrendered/sold). The Partnership's
working interests in the six remaining venture prospects range from 6.29
percent to 7.08 percent. As of December 31, 2003, the Partnership held a
remaining interest in 11 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 2003 production and 62 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.
23
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 2003, the Investing Partners
sold a total of 24.2 Units to the Partnership for a total of $295,734 in
cash. The first right of presentment was based upon a valuation date of
December 31, 2002 for a purchase price of $12,047 per Unit, plus interest
to the date of payment. The second presentment offer was based on a
valuation date of June 30, 2003 for a purchase price of $9,512 per Unit,
plus interest to the payment date. During 2002 and 2001, the Partnership
paid the Investing Partners $213,006 and $195,221, respectively, to acquire
a total of 43.6 Units.
The Partnership is not in a position to predict how many Units will be
presented for repurchase during 2004, 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, 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
December 31, 2002 13,612,220 12,047
June 30, 2003 14,345,895 9,512
INVESTING PARTNER UNITS OUTSTANDING: 2003 2002 2001
------------- ------------- -------------
Balance, beginning of year 1,084.9 1,110.3 1,128.5
Repurchase of Partnership Units (24.2) (25.4) (18.2)
----------- ----------- -----------
Balance, end of year 1,060.7 1,084.9 1,110.3
=========== =========== ===========
CAPITAL CONTRIBUTIONS -
A total of $85,000 per Unit, or approximately 57 percent, of investor
subscription had been called through December 31, 2003. 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
1,060.7 Units at December 31, 2003.
24
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.
In performing its quarterly ceiling test, 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. Please see "Future Net Cash Flows" in the
Supplemental Oil and Gas Disclosures included in this Form 10-K for a
discussion on calculation of estimated future net cash flows.
Given the volatility of oil and gas prices, it is reasonably possible
that the 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.
25
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Partnership has taken note of a July 2003 inquiry to the Financial
Accounting Standards Board (FASB) regarding whether or not contract-based
oil and gas mineral rights held by lease or contract ("mineral rights")
should be recorded or disclosed as intangible assets. The inquiry presents
a view that these mineral rights are intangible assets as defined in
Statement of Financial Accounting Standards (SFAS) No. 141, "Business
Combinations," and, therefore, should be classified separately on the
balance sheet as intangible assets. SFAS No. 141, and SFAS No. 142,
"Goodwill and Other Intangible Assets," became effective for transactions
subsequent to June 30, 2001 with the disclosure requirements of SFAS No.
142 required as of January 1, 2002. SFAS No. 141 requires that all business
combinations initiated after June 30, 2001 be accounted for using the
purchase method and that intangible assets be disaggregated and reported
separately from goodwill. SFAS No. 142 established new accounting
guidelines for both finite lived intangible assets and indefinite lived
intangible assets. Under the statement, intangible assets should be
separately reported on the face of the balance sheet and accompanied by
disclosure in the notes to financial statements. SFAS No. 142 scopes out
accounting utilized by the oil and gas industry as prescribed by SFAS No.
19, and is silent about whether or not its disclosure provisions apply to
oil and gas companies. The Partnership does not believe that SFAS No. 141
or 142 change the classification of oil and gas mineral rights and the
Partnership continues to classify these assets as part of oil and gas
properties. The Emerging Issues Task Force (EITF) has added the treatment
of oil and gas mineral rights to an upcoming agenda, which may result in a
change in how the Partnership classifies these assets.
The Partnership has not participated in any business combinations or
major asset purchases since the June 30, 2001 effective date of SFAS No.
141 and SFAS No. 142, and believes it will not be impacted by the EITF's
decisions regarding the accounting treatment for oil and gas mineral
interests. The Partnership has not historically tracked the amount of
mineral rights in the proved property balance related to producing leases
or relinquished leases.
Based on the Partnership's understanding of the issue before the EITF,
if all mineral rights associated with unevaluated property and producing
reserves were deemed to be intangible assets:
- mineral rights with proved reserves that were acquired after June
30, 2001 and mineral rights with no proved reserves would be
classified as intangible assets and would not be included in oil
and gas properties on our consolidated balance sheet;
- results of operations and cash flows would not be materially
affected because mineral rights would continue to be amortized in
accordance with full cost accounting rules; and
- disclosures required by SFAS Nos. 141 and 142 relative to
intangibles would be included in the notes to our financial
statements.
If the accounting for mineral rights is ultimately changed,
transitional guidance for intangible assets permits the reclassification of
only amounts acquired after the effective date of SFAS Nos. 141 and 142 if
records were not previously maintained to track acquisition costs based on
their intangible or tangible nature. Lack of these records prior to the
effective date could result in the loss of comparability between historical
balances of tangible and intangible asset balances and among companies in
the industry.
REVENUE RECOGNITION -
Oil and gas revenues are recognized when production is sold to a
purchaser at a fixed or determinable price, when delivery has occurred and
title has transferred, and if collectibility of the revenue is probable.
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, 2003 and 2002, 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
26
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
supplemental oil and gas disclosures. Adjustments for gas imbalances
totaled less than one percent of the Partnership's proved gas reserves at
December 31, 2003, 2002 and 2001.
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.
RECEIVABLE FROM/PAYABLE TO APACHE -
The receivable from/payable to Apache represents the net result of the
Investing Partners' revenue and expenditure transactions in the current
month. Generally, cash in this amount will be paid by Apache to the
Partnership or 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.
27
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
-------------------------------------------
2003 2002 2001
----------- ----------- ------------
(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 $ 324 $ 358 $ 384
========== ========== ==========
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 $ 86 $ 129 $ 147
========== ========== ==========
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.
2003 2002 2001
------------- ------------- -------------
(In thousands)
Oil and Gas Properties
Balance, beginning of year $ 179,657 $ 176,409 $ 173,378
Asset retirement cost from adoption of
SFAS No. 143 -
Investing Partners 323 - -
Managing Partner 3 - -
Costs incurred during the year:
Development -
Investing Partners 2,154 3,174 2,962
Managing Partner 37 74 69
------------ ------------ ------------
Balance, end of year $ 182,174 $ 179,657 $ 176,409
============ ============ ============
28
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, 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
Adoption of SFAS No. 143 (7) (724) (731)
Provision 90 2,786 2,876
------------ ------------ ------------
Balance, December 31, 2003 $ 20,765 $ 152,734 $ 173,499
============ ============ ============
The Partnership's aggregate DD&A expense as a percentage of oil and gas
sales for 2003, 2002 and 2001 was 24 percent, 32 percent and 19 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.
Effective with July 2003 production, the Managing Partner began
directly marketing the Partnership's and its own U.S. natural gas
production. Most of the Partnership's natural gas production was previously
marketed through Cinergy Marketing and Trading, LLC (Cinergy) under a gas
sales agreement between the Managing Partner and Cinergy. The Partnership
believes that the prices it receives for natural gas are comparable to the
prices it would have received from Cinergy.
Sales to Cinergy Marketing & Trading, LLC (Cinergy) accounted for 37
percent, 60 percent and 73 percent of the Partnership's oil and gas sales
in 2003, 2002 and 2001, 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 sold most of the Partnership's
natural gas production to Cinergy under the gas purchase agreement. Since
2001, Apache had been involved in an arbitration proceeding with Cinergy on
issues arising from the gas sales agreement. Apache's resolution of these
disputes with Cinergy in mid-2003 did not have a material effect on the
Partnership's financial position or sales.
Apache Crude Oil Marketing, Inc., a wholly-owned subsidiary of Apache,
purchased oil and condensate from the Partnership which accounted for
approximately 17 percent and 26 percent of the Partnership's total oil and
gas sales in 2002 and 2001, 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 to Chevron Texaco accounted for 32 percent and 21 percent of the
Partnership's oil and gas sales in 2003 and 2002, respectively.
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
29
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
onshore markets. The Partnership paid the Apache subsidiary transportation
fees totaling $43,606 in 2003, $43,785 in 2002 and $45,147 in 2001 for the
Partnership's share of gas. The fees were at the same rates and terms as
previously paid to Shell.
All transactions with related parties were consumated at fair value.
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, 2003 and 2002 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, 2003.
(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 PRONOUCEMENTS
In June 2001 the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires that an asset retirement
obligation (ARO) associated with the retirement of a tangible long-lived
asset be recognized as a liability in the period in which a legal
obligation is incurred and becomes determinable, with an offsetting
increase in the carrying amount of the associated asset. The cost of the
tangible asset, including the initially recognized ARO, is depleted such
that the cost of the ARO is recognized over the useful life of the asset.
The ARO is recorded at fair value, and accretion expense will be recognized
over time as the discounted liability is accreted to its expected
settlement value. The fair value of the ARO is measured using expected
future cash outflows discounted at the company's credit-adjusted risk-free
interest rate.
Effective January 1, 2003, the Partnership adopted SFAS No. 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 amounts reflect the ARO of the Partnership had the
provisions of SFAS No. 143 been applied since inception and resulted in a
non-cash cumulative-effect increase in net income of $.3 million. In
accordance with the provisions of SFAS No. 143, the Partnership records an
abandonment liability associated with its oil and gas wells and platforms
when those assets are placed in service, rather than its past practice of
accruing the expected abandonment costs over the productive life of the
associated full-cost pool. Under SFAS No. 143 depletion expense is reduced
since a discounted ARO is depleted in the property balance rather than the
undiscounted value previously depleted under the old rules. The lower
depletion expense under SFAS No. 143
30
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
is offset, however, by accretion expense, which is recognized over time as
the discounted liability is accreted to its expected settlement value.
Inherent in the fair value calculation of ARO are numerous assumptions
and judgments including the ultimate settlement amounts, inflation factors,
credit adjusted discount rates, timing of settlement, and changes in the
legal, regulatory, environmental and political environments. To the extent
future revisions to these assumptions impact the fair value of the existing
ARO liability, a corresponding adjustment is made to the oil and gas
property balance.
The $.3 million cumulative increase to earnings upon adoption did not
take into consideration potential impacts of adopting SFAS No. 143 on
previous full-cost property impairment tests. The Partnership chose not to
re-calculate historical full-cost impairment tests ("ceiling test") upon
adoption even though historical oil and gas property balances would have
been higher had the Partnership applied the provisions of the statement.
Management believes this approach is appropriate because SFAS No. 143 is
silent on this issue and was not effective during the prior ceiling test
periods. Had the Partnership re-calculated the historical full-cost ceiling
tests and included the impact as a component of the cumulative effect of
adoption, the ultimate gain recognized would have potentially been reduced.
A ceiling test calculation was performed upon adoption and at the end of
each reporting period subsequent to adoption and no impairment was
necessary. In calculating ceiling limitations, the Partnership includes the
undiscounted ARO as part of future development costs, essentially reducing
the present value of its future net revenues and full-cost ceiling limit.
To compare the property balance, which included the ARO component, to the
full-cost ceiling limit, which has been reduced by a similar abandonment
cost, the Partnership nets the ARO liability against the property balance.
The Partnership believes this is appropriate since there must be a
comparable basis between the net book value of the properties and the
full-cost ceiling limitation.
The following table is a reconciliation of the asset retirement
obligation liability since adoption (in thousands):
Asset retirement obligation upon adoption on January 1, 2003 $ 754,351
Liabilities settled (575,553)
Accretion expense 37,605
Revisions in estimated liabilities 596,117
------------
Asset retirement obligation at December 31, 2003 $ 812,520
============
The upward revision in estimated liabilities during 2003 resulted from
new information provided by outside operators on the East Cameron 60 and
Ship Shoal 258/259 Fields.
The pro forma asset retirement obligation would have been approximately
$.7 million at January 1, 2002 had the Company adopted the provisions of
SFAS No. 143 on January 1, 2002. If the Partnership had not adopted SFAS
No. 143 in 2003, the Partnership's operating income before the cumulative
effect of the change in accounting principle would not have been materially
different then the amount reported for 2003. The following table shows the
pro forma effect of the implementation on the Partnership's net income had
SFAS No. 143 been adopted by the Company on January 1, 2001.
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------
2002 2001
------------- -------------
(IN THOUSANDS)
Net income, as reported $ 3,524 $ 7,264
Effect on net income had SFAS No. 143 been applied (35) (33)
----------- -----------
Net income, as adjusted $ 3,489 $ 7,231
=========== ===========
In January 2003, the FASB issued Interpretation No. 46 "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research
Bulletin No. 51." Interpretation No. 46 requires a company to consolidate a
variable interest entity (VIE) if the company has a variable interest (or
combination of variable
31
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
interests) that is exposed to a majority of the entity's expected losses if
they occur, receive a majority of the entity's expected residual returns if
they occur, or both. In addition, more extensive disclosure requirements
apply to the primary and other significant variable interest owners of the
VIE. This interpretation applies immediately to VIEs created after January
31, 2003, and to VIEs in which an enterprise obtains an interest after that
date. It is also effective for the first fiscal year or interim period
beginning after December 31, 2003, to VIEs in which a company holds a
variable interest that is acquired before February 1, 2003. This
interpretation did not affect the Partnership's consolidated financial
statements.
(9) INSURANCE RECOVERIES
During 2003, the Partnership recognized insurance recoveries totaling
$14,567 for the final amount of proceeds recoupable under business
interruption insurance policies. The recoveries are included in other
revenue in the accompanying Statement of Consolidated Income and reflect
recoveries for the Partnership's share of lost oil and gas production
resulting from hurricanes in 2002. The Partnership recognized $99,300 in
2002 for amounts recoupable under business interruption insurance policies.
(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:
2003 2002 2001
------------- ------------- -------------
Net partnership ordinary income for federal income
tax reporting purposes $ 7,846,759 $ 2,426,766 $ 6,199,485
Plus: Items of current (income) expense for tax reporting
purposes only -
Intangible drilling cost 1,358,245 2,638,051 2,457,181
Dismantlement and abandonment cost 575,553 - -
(Gain) on disposition of equipment - - (258,053)
Tax depreciation 867,296 640,091 908,093
----------- ----------- -----------
2,801,094 3,278,142 3,107,221
----------- ----------- -----------
Less: full cost DD&A expense (2,875,896) (2,181,189) (2,042,461)
Less: asset retirement obligation accretion (37,605) - -
Plus: cumulative effect of change in accounting principle 302,407 - -
----------- ----------- -----------
Net income $ 8,036,759 $ 3,523,719 $ 7,264,245
=========== =========== ===========
The Partnership's tax bases in net oil and gas properties at December
31, 2003 and 2002 was $3,303,730 and $2,221,960, 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, intangible drilling costs and dismantlement and abandonment
costs. For federal income tax reporting, the Partnership had capitalized
syndication cost of $8,660,878 at December 31, 2003 and 2002.
32
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
A reconciliation of liabilities for federal income tax reporting
purposes to liabilities under accounting principles generally accepted in
the United States is as follows:
DECEMBER 31,
----------------------------------
2003 2002
---------------- ----------------
Liabilities for federal income tax purposes $ 386,816 $ 224,243
Asset retirement liability 812,520 -
-------------- --------------
Liabilities under accounting principles generally
accepted in the United States $ 1,199,336 $ 224,243
============== ==============
Asset retirement liabilities for future dismantlement and abandonment
costs are not recognized for federal income tax reporting purposes.
33
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)
2003 2002 2001
------------------ -------------------- --------------------
OIL GAS OIL GAS OIL GAS
-------- ------- ------- --------- --------- ---------
Proved Reserves
Beginning of year 849 6,339 885 7,075 883 8,080
Extensions, discoveries and other
additions 12 161 204 389 155 697
Revisions of previous estimates (112) 924 (130) 99 (41) 3
Production (131) (1,432) (110) (1,224) (112) (1,705)
-------- ------- ------- ------- -------- -------
End of year 618 5,992 849 6,339 885 7,075
======== ======= ======= ======= ======== =======
Proved Developed
Beginning of year 849 6,230 767 6,685 736 7,462
======== ======= ======= ======= ======== =======
End of year 618 5,883 849 6,230 767 6,685
======== ======= ======= ======= ======== =======
Oil includes crude oil, condensate and natural gas liquids.
Approximately 62 percent of the Partnership's proved developed reserves
are classified as proved not producing. These reserves relate to zones that
are either behind pipe, or that have been completed but not yet produced or
zones that have been produced in the past, but are not now producing due to
mechanical reasons. These reserves may be regarded as less certain than
producing reserves because they are frequently based on volumetric
calculations rather than performance data. Future production associated
with behind pipe reserves is scheduled to follow depletion of the currently
producing zones in the same wellbores. It should be noted that additional
capital may have to be spent to access these reserves. The capital and
economic impact of production timing are reflected in the Partnership's
standardized measure under Future Net Cash Flows.
34
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,
------------------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands)
Future cash inflows $ 55,014 $ 56,471 $ 36,604
Future production costs (5,645) (4,623) (4,440)
Future development costs (3,789) (4,115) (4,937)
------------ ------------ ------------
Net cash flows 45,580 47,733 27,227
10 percent annual discount rate (14,995) (16,908) (9,794)
------------ ------------ ------------
Discounted future net cash flows $ 30,585 $ 30,825 $ 17,433
============ ============ ============
The following table sets forth the principal sources of change in the
discounted future net cash flows:
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands)
Sales, net of production costs $ (11,011) $ (6,034) $ (9,712)
Net change in prices and production costs 3,731 14,403 (43,479)
Extensions, discoveries and other additions 1,247 4,548 2,730
Development costs incurred 490 680 1,863
Revisions of quantities 813 (2,023) (428)
Accretion of discount 3,083 1,743 6,532
Changes in future development costs - 185 174
Changes in production rates and other 1,407 (110) (5,570)
------------ ------------ ------------
$ (240) $ 13,392 $ (47,890)
============ ============ ============
Impact of Pricing - The estimates of cash flows and reserve quantities
shown above are based on year-end oil and gas prices. Forward price
volatility is largely attributable to supply and demand perceptions for
natural gas and oil.
Under full-cost accounting rules, the Partnership reviews the carrying
value of its proved oil and gas properties each quarter. Under these rules,
capitalized costs of proved oil and gas properties, net of accumulated
DD&A, may not exceed the present value of estimated future net cash flows
from proved oil and gas reserves, discounted at 10 percent (the "ceiling").
These rules generally require pricing future oil and gas production at the
unescalated oil and gas prices at the end of each fiscal quarter and
require a write-down if the "ceiling" is exceeded. Given the volatility of
oil and gas prices, it is reasonably possible that the 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.
35
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL
--------- --------- --------- --------- ---------
(In thousands, except per Unit amounts)
2003
Revenues $ 3,195 $ 3,021 $ 2,962 $ 2,815 $ 11,993
Expenses 1,151 1,061 1,051 995 4,258
--------- --------- --------- --------- ---------
Income before change in
accounting principle 2,044 1,960 1,911 1,820 7,735
Cumulative effect of change
in accounting principle 302 - - - 302
--------- --------- --------- --------- ---------
Net income $ 2,346 $ 1,960 $ 1,911 $ 1,820 $ 8,037
========= ========= ========= ========= =========
Net income allocated to:
Managing Partner $ 536 $ 505 $ 509 $ 487 $ 2,037
Investing Partners 1,810 1,455 1,402 1,333 6,000
--------- --------- --------- --------- ---------
$ 2,346 $ 1,960 $ 1,911 $ 1,820 $ 8,037
========= ========= ========= ========= =========
Net income per Investing
Partner Unit (1) $ 1,668 $ 1,348 $ 1,321 $ 1,256 $ 5,598
========= ========= ========= ========= =========
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
========= ========= ========= ========= =========
(1) The sum of the individual net income per Investing Partner Unit may
not agree with the year-to-date net income per Investing Partner Unit
as each quarterly computation is based on the weighted average number
of Investing Partner Units during that period.
36
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The financial statements for the fiscal year ended December 31, 2003 and
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 year ended December 31, 2001 and the
year then ended, 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 report on the Partnership's consolidated financial
statements for the year ended December 31, 2001 and the year then ended,
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 year ended December 31, 2001, 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.
ITEM 9A. CONTROLS AND PROCEDURES
G. Steven Farris, the Managing Partner's President, Chief Executive Officer
and Chief Operating Officer, and Roger B. Plank, the Managing Partner's
Executive Vice President and Chief Financial Officer, evaluated the
effectiveness of the Partnership's disclosure controls and procedures as of the
end of the period covered by this report. Based on that evaluation and as of the
date of that evaluation, these officers concluded that the Partnership's
disclosure controls to be effective, providing effective means to insure that
information it is required to disclose under applicable laws and regulations is
recorded, processed, summarized and reported in a timely manner. We also made no
significant changes in the Partnership's internal controls over financial
reporting during the fiscal quarter ending December 31, 2003 that have
materially affected, or are reasonably likely to materially affect, the
Partnership's internal control over financial reporting.
37
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 2004 annual meeting of
stockholders of Apache (the Apache Proxy) is incorporated herein by reference.
Code of Business Conduct
Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, Apache
was required to adopt a code of business conduct and ethics for its directors,
officers and employees. In February 2004, Apache's Board of Directors adopted a
Code of Business Conduct (the "Code of Conduct"), which also meets the
requirements of a code of ethics under Item 406 of Regulation S-K. You can
access Apache's Code of Conduct on the Investor Relations page of the company's
website at www.apachecorp.com. Changes in and waivers to the Code of Conduct for
Apache's directors, chief executive officer and certain senior financial
officers will be posted on the company's website within five business days and
maintained for at least twelve months.
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
5.0 percent of the outstanding Units of the Partnership, as of December 31,
2003. Directors and officers of Apache own four Units, less than one percent of
the Partnership's Units, as of December 31, 2003. 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, except for Apache as
General Partner which owns 53 Units or five percent of the 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. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Accountant fees and services paid to Ernst & Young LLP, the Partnership's
independent auditors, are included in amounts paid by the Partnership's Managing
Partner. Information on the Managing Partner's principal accountant fees and
services is set forth under the caption "Independent Public Auditors" in
Apache's 2004 proxy statement.
38
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.
*31.1 Certification of Chief Executive Officer.
*31.2 Certification of Chief Financial Officer.
*32.1 Certification of Chief Executive Officer and Chief Financial
Officer.
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, 2004,
relating to the 2004 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).
*Filed herewith.
b. Reports filed on Form 8-K.
No reports on Form 8-K were filed during the fiscal quarter ended
December 31, 2003.
39
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 11, 2004 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 11, 2004
- -------------------------------------------- Officer and Chief Operating Officer
G. Steven Farris (Principal Executive Officer)
/s/ Roger B. Plank Executive Vice President and Chief March 11, 2004
- -------------------------------------------- Financial Officer (Principal
Roger B. Plank Financial Officer)
/s/ Thomas L. Mitchell Vice President and Controller March 11, 2004
- -------------------------------------------- (Principal Accounting Officer)
Thomas L. Mitchell
NAME TITLE DATE
- -------------------------------------------- ------------------------------------ ---------------
/s/ Raymond Plank Chairman of the Board March 11, 2004
- --------------------------------------------
Raymond Plank
/s/ Frederick M. Bohen Director March 11, 2004
- --------------------------------------------
Frederick M. Bohen
/s/ Randolph M. Ferlic Director March 11, 2004
- --------------------------------------------
Randolph M. Ferlic
/s/ Eugene C. Fiedorek Director March 11, 2004
- --------------------------------------------
Eugene C. Fiedorek
/s/ A. D. Frazier, Jr. Director March 11, 2004
- --------------------------------------------
A. D. Frazier, Jr.
/s/ Patricia Albjerg Graham Director March 11, 2004
- --------------------------------------------
Patricia Albjerg Graham
/s/ John A. Kocur Director March 11, 2004
- --------------------------------------------
John A. Kocur
/s/ George D. Lawrence Director March 11, 2004
- --------------------------------------------
George D. Lawrence
/s/ F. H. Merelli Director March 11, 2004
- --------------------------------------------
F. H. Merelli
/s/ Rodman D. Patton Director March 11, 2004
- --------------------------------------------
Rodman D. Patton
/s/ Charles J. Pitman Director March 11, 2004
- --------------------------------------------
Charles J. Pitman
/s/ Jay A. Precourt Director March 11, 2004
- --------------------------------------------
Jay A. Precourt
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
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.
*31.1 Certification of Chief Executive Officer.
*31.2 Certification of Chief Financial Officer.
*32.1 Certification of Chief Executive Officer and Chief Financial
Officer.
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, 2004,
relating to the 2004 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).
*Filed herewith.