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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, 2004
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, 2004.................................................. $13,044,372
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Apache Corporation's proxy statement relating to its 2005
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.............................................................. 14
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.............................. 15
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE................................... 33
9A. CONTROLS AND PROCEDURES.................................................. 33
9B. OTHER INFORMATION........................................................ 33
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP...................... 34
11. EXECUTIVE COMPENSATION................................................... 34
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................................................ 34
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................... 34
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES................................... 34
PART IV
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.......... 35
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 Securities and Exchange Commission (SEC)
available on or through a website. The Partnership will, however, provide paper
copies of these filings, free of charge, to anyone so requesting. Included in
the Partnership's annual reports on Form 10-K and quarterly reports on Form 10-Q
are the certifications of the Managing Partners' chief executive officer and
chief financial officer that are required by applicable laws and regulations.
Any requests for copies of filing with the SEC should be made by mail to Apache
Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas 77056,
Attention: David Higgins, or by telephone at 713-296-6690.
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,
2004, 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.
1
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.
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.
2004 RESULTS AND BUSINESS DEVELOPMENT
The Partnership reported net income in 2004 of $9.6 million, or $6,786 per
Investing Partner Unit. Earnings were up from $8.0 million in 2003 on the
strength of higher oil and gas prices in 2004. Natural gas production averaged
3,820 Mcf per day, while oil sales averaged 301 barrels per day. Production
added through drilling in 2004 partially offset declines from natural depletion.
During 2004, the Partnership participated in drilling four new wells at
Ship Shoal 258/259. The Partnership completed the Ship Shoal 258 JB-6 well in
mid-April, the Ship Shoal 259 JA-3 well in late May, the Ship Shoal 259 JA-7 in
late July and the Ship Shoal 259 JA-8 well in late September. While the JB-6
well produced for only three months before watering out, the other Ship Shoal
completions were still producing at the end of 2004 and each are projected to
produce from their current zones for two or more years. During 2004, the
Partnership participated in one recompletion at South Timbalier 295 and one
recompletion at Ship Shoal 258 to maintain production and enhance recoverable
reserves.
Since inception, the Partnership has acquired an interest in 49 prospects.
As of December 31, 2004, 43 of those prospects have been surrendered or sold.
As of December 31, 2004, the Partnership had 54 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, 2004, estimated
proved oil and gas reserves of 9.1 Bcfe, of which 57 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 2004 was purchased largely by Plains
Marketing LP 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. 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
2
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.
RISK FACTORS RELATED TO THE PARTNERSHIP'S BUSINESS AND OPERATIONS
The Partnership's business activities are subject to significant hazards
and risks, including those described below. If any of such events should occur,
the Partnership's business, financial condition, liquidity and/or results of
operations could be materially harmed, and holders of the Partnership Units
could lose part or all of their investments.
PARTNERSHIP'S PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES OF CRUDE OIL,
NATURAL GAS AND NATURAL GAS LIQUIDS, WHICH HAVE HISTORICALLY BEEN VERY VOLATILE
The Partnership's revenues, profitability, operating cash flows and future
rate of growth are highly dependent on the prices of crude oil, natural gas and
natural gas liquids, which are affected by numerous factors beyond its control.
Historically these prices have been very volatile. A significant downward trend
in commodity prices would have a material adverse effect on our revenues,
profitability and cash flow and could result in a reduction in the carrying
value of our oil and gas properties and the amounts of our proved oil and gas
reserves.
DRILLING ACTIVITIES MAY NOT BE PRODUCTIVE
Drilling for oil and gas involves numerous risks, including the risk that
we will not encounter commercially productive oil or gas reservoirs. The costs
of drilling, completing and operating wells are often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors including, but not limited to:
- unexpected drilling conditions;
- pressure or irregularities in formations;
- equipment failures or accidents;
- fires, explosions, blow-outs and surface cratering;
- marine risks such as capsizing, collisions and hurricanes;
- other adverse weather conditions; and
- shortages or delays in the delivery of equipment.
Certain of the Partnership's future drilling activities may not be
successful and, if unsuccessful, this failure could have an adverse effect on
our future results of operations and financial condition.
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.
3
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 customary industry practices and in amounts that management
believes to be prudent; however, insurance is not available to the Partnership
against all operational risks.
INDUSTRY COMPETITION
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 and 2004. However, included in this
annual report on Form 10-K are financial data and other information for 2000 and
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, 2004, 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, 2004, 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, 2004, is set forth below:
GAS OIL
------------ ------------
LEASE BLOCK STATE GROSS NET GROSS NET
- ------------------------------ ----- ----- ---- ----- -----
Ship Shoal 258, 259 LA 7 .44 -- --
South Timbalier 276, 295, 296 LA 1 .07 33 2.34
North Padre Island 969, 976 TX 5 .35 -- --
Matagorda Island 681, 682, 683 TX 5 .32 -- --
South Pass 83 LA 1 .07 -- --
Ship Shoal 201, 202 LA 1 -- 1 --
--- ---- --- ----
20 1.25 34 2.34
=== ==== === ====
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
- ---- ---------- --- ----- ---------- --- -----
2004 -- -- -- .30 -- .30
2003 -- -- -- -- -- --
2002 -- -- -- .35 .07 .42
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 SALES PRICES
-------------------------- AVERAGE ---------------------------------
YEAR ENDED OIL GAS NGLS PRODUCTION OIL GAS NGLS
DECEMBER 31, (MBBLS) (MMCF) (MBBLS) COST PER MCFE (PER BBL) (PER MCF) (PER BBL)
- ------------ ------- ------ ------- ------------- --------- --------- ---------
2004 110 1,398 26 $.48 $40.62 $6.23 $26.84
2003 125 1,432 6 .42 30.73 5.56 23.92
2002 110 1,224 -- .44 25.03 3.36 --
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, 2004, the Partnership had total estimated proved
reserves of 648,201 barrels of crude oil, condensate and NGLs and 5.2 Bcf of
natural gas. Combined, these total estimated proved reserves are equivalent to
9.1 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, 2004, 2003 and 2002, changes in estimated 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 2004 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. Estimated 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 2004.
6
PART II
ITEM 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY HOLDER
MATTERS
As of December 31, 2004, there were 1,055.7 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 $6.4
million, or $6,000 per Unit, during 2004 and approximately $4.8 million, or
$4,500 per Unit, during 2003.
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,
2004, 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 2000 and 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 "Risk Factors Related to the Partnership's Business and
Operations".
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------
2004 2003 2002 2001 2000
------- ------- ------ ------- -------
(In thousands, except per Unit amounts)
Total assets $12,215 $11,674 $9,834 $ 9,413 $ 8,715
======= ======= ====== ======= =======
Partners' capital $11,293 $10,475 $9,610 $ 8,369 $ 7,728
======= ======= ====== ======= =======
Oil and gas sales $13,874 $11,951 $6,868 $10,495 $12,641
======= ======= ====== ======= =======
Net income $ 9,591 $ 8,037 $3,524 $ 7,264 $ 8,497
======= ======= ====== ======= =======
Net income allocated to:
Managing Partner $ 2,407 $ 2,037 $1,036 $ 1,731 $ 2,102
Investing Partners 7,184 6,000 2,488 5,533 6,395
------- ------- ------ ------- -------
$ 9,591 $ 8,037 $3,524 $ 7,264 $ 8,497
======= ======= ====== ======= =======
Net income per Investing
Partner Unit $ 6,786 $ 5,598 $2,259 $ 4,922 $ 5,654
======= ======= ====== ======= =======
Cash distributions per
Investing Partner Unit $ 6,000 $ 4,500 $1,000 $ 4,000 $ 5,750
======= ======= ====== ======= =======
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 2004. 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. During 2004, the Partnership participated in drilling four development
wells at Ship Shoal 258/259. All four wells were completed as producers although
one well was subsequently taken off production as a result of excess water
production.
Generally, the Partnership has used its remaining available cash to fund
distributions to its Partners. Distributions to Investing Partners increased to
$6,000 per Unit in 2004, up 33 percent from 2003. Reflecting the significant
impact of oil and gas prices on net income and cash from operating activities,
distributions to Investing Partners had increased from $1,000 per Unit in 2002
to $4,500 per Unit in 2003.
RESULTS OF OPERATIONS
This section includes a discussion of the Partnership's 2004 and 2003
results of operations, and items contributing to changes in revenues and
expenses during those periods.
NET INCOME AND REVENUE
The Partnership reported net income of $9.6 million for 2004, up 19 percent
from 2003 on the strength of higher commodity prices. Net income per Investing
Partner Unit increased in 2004 to $6,786, up from $5,598 in 2003. The
Partnership reported earnings in 2003 of $8.0 million, more than double the 2002
earnings on higher production and prices.
Total revenues increased to $14.0 million in 2004 with higher prices. The
Partnership's total revenue in 2003 of $12.0 million was up 72 percent from 2002
on higher oil and gas production and prices. Interest income earned by the
Partnership on short-term cash investments in 2004 increased from 2003 as a
result of higher average investment balances in 2004. Interest income in 2003
increased 41 percent from $19,199 in 2002 on higher interest rates and average
investment balances to $27,081 in 2003.
8
The Partnership's oil and gas production volume and price information is
summarized in the following table:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2004 2003 2002
------ ------ ------
Gas volumes - Mcf per day 3,820 3,924 3,353
Average gas price - per Mcf $ 6.23 $ 5.56 $ 3.36
Oil volumes - barrels per day 301 342 302
Average oil price - per barrel $40.62 $30.73 $25.03
NGL volumes - barrels per day 71 16 --
Average NGL price - per barrel $26.84 $23.92 --
The Partnership's revenues are sensitive to changes in prices received for
its products. A substantial portion of the Partnership's production is sold at
prevailing market prices, which fluctuate in response to many factors that are
outside of our control. Imbalances in the supply and demand for oil and natural
gas can have dramatic effects on the prices we receive for our production.
Political instability and availability of alternative fuels could impact
worldwide supply, while other economic factors could impact demand.
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 2004 totaled $8.7 million, up nine percent from 2003
on higher prices. The Partnership's average realized natural gas price for 2004
improved 12 percent from 2003. The $.67 per Mcf increase in gas price from a
year ago boosted sales by approximately $1.0 million. Daily gas production for
2004 decreased three percent from 2003, decreasing sales by $.2 million.
Production added through drilling successes at Ship Shoal 258/259 and
recompletions at South Timbalier 295 and Ship Shoal 259 in 2004 partially offset
natural depletion for the year. The Partnership completed the Ship Shoal 258
JB-6 well in mid-April, the Ship Shoal 259 JA-3 in late May, the Ship Shoal 259
JA-7 in late July and the Ship Shoal 258 JA-8 in late September.
Natural gas sales for 2003 totaled $8 million, up 94 percent from 2002 on
higher prices and production. The Partnership's average realized natural gas
price for 2003 improved 65 percent from 2002. The $2.20 per Mcf increase in gas
price from 2002 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.
CRUDE OIL SALES
The Partnership's crude oil sales in 2004 totaled $4.5 million, up 17
percent from 2003. A $9.89 per barrel, or 32 percent, increase in the
Partnership's average realized oil price in 2004 increased oil revenues by $1.2
million from 2003. Oil production decreased 12 percent from 2003 as a result of
declines at South Timbalier 295.
9
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.
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 20 percent in 2004.
The decrease in DD&A rate as a percentage of sales reflected higher oil and gas
prices in 2004. The Partnership's DD&A rate, expressed as a percentage of oil
and gas sales, decreased to 24 percent in 2003 from 32 percent in 2002 as a
result of higher oil and gas prices in 2003. DD&A expense declined slightly in
2004 on an absolute basis as a result of the decline in the Partnership's
production from 2003, and as a result of reserve additions from drilling at Ship
Shoal 258/259. DD&A expense had increased on an absolute basis in 2003 with the
increase in oil and gas production compared to 2002.
Lease operating costs in 2004 increased approximately $100,000 from a year
ago primarily as result of higher repair and maintenance costs. The increase
also reflected generally higher service costs, chemical costs and fuel and power
costs impacting all oil and gas producers. Repair cost in 2004 included cost to
repair damage to the South Pass 83 platform resulting from Hurricane Ivan.
Administrative expense declined slightly from last year, dropping to $403,000 in
2004.
Lease operating costs in 2003 increased approximately $87,000 from the
prior year primarily as a 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 2002, dropping to $405,000.
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. In this case,
the Partnership records sales at the price received from the purchaser which is
net of transportation costs. 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. In this case, the Partnership records the transportation cost as
gathering and transportation costs. The Partnership's treatment of
transportation costs is pursuant to Emerging Issues Task Force Issue 00-10,
"Accounting or Shipping and Handling Fees and Costs" and as a result a portion
of our transporting costs are reflected in sales prices and a portion is
reflected as Transportation and Gathering expense.
CAPITAL RESOURCES AND LIQUIDITY
The Partnership's primary capital resource is net cash provided by
operating activities, which totaled $11.7 million for 2004. Benefiting from
strong commodity prices throughout 2004, the Partnership's 2004 net cash
provided by operating activities increased $1.6 million, or 16 percent, from a
year ago. Net cash provided by operating activities in 2003 increased 106
percent from 2002 on increases in both oil and gas production and prices.
The Partnership's future financial condition, results of operations and
cash from operating activities will largely depend upon prices received for its
oil and natural gas production. A substantial portion of the Partnership's
production is sold under market-sensitive contracts. Prices for oil and natural
gas are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of factors beyond the Partnership's control. These
factors include worldwide political instability (especially in the Middle East),
the foreign supply of oil and natural gas, the price of foreign imports, the
level of consumer demand, and the price and availability of alternative fuels.
With natural gas accounting for 63 percent of the Partnership's 2004 production
and 57 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.
10
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 is projected to
decline in the future.
Approximately 67 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 will have to be spent to
access these reserves and that the estimated reserves from these projects are
based on prices at December 31, 2004. The Partnership's liquidity may be
negatively impacted if the actual quantity of reserves that are ultimately
produced are materially different from current estimates. Also, if prices
decline significantly from current levels, the Partnership may not be able to
fund the necessary capital investment, or development of the remaining reserves
may not be economical for the Partnership.
The Partnership may reduce capital expenditures or distributions to
partners, or both, 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.
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, 2004. The Partnership did
not have any contractual obligations as of December 31, 2004, other than the
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 2004, the Partnership's oil and gas property additions totaled $1.9
million. These additions primarily related to the Partnership's participation in
drilling four wells at Ship Shoal 258/259. The Partnership also participated in
one recompletion at South Timbalier 295 and another at Ship Shoal 259 during
2004. Capital expenditures during 2003 totaled $1.6 million, exclusive of
ARO-related costs. During 2003, the partnership participated in nine
recompletions at South Timbalier 295 and one recompletion at Ship Shoal 259.
There were no new drilling wells in 2003 for the Partnership. 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.
Based on preliminary information provided by the operators of the
properties in which the Partnership owns interests, the Partnership anticipates
capital expenditures will total approximately $1 million in 2005. The
Partnership currently plans to participate with the operator in drilling two
wells at Ship Shoal 258/259 during 2005. 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. The Partnership
did not have any drilling in progress at the end of 2004.
Distributions of $6.4 million, or $6,000 per Unit, were made to Partners
during 2004. Favorable oil and gas prices allowed for the increase in the per
Unit distributions in 2004. During 2003, the Partnership paid distributions to
Investing Partners totaling approximately $4.8 million or $4,500 per Unit. The
amount of future distributions will be dependent on actual and expected
production levels, realized and expected oil and gas prices, expected drilling
and recompletion expenditures, and prudent cash reserves for future
dismantlement and abandonment costs that will be incurred after the
Partnership's reserves are depleted.
11
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 2004, the first right of presentment offer of $11,518 per Unit,
plus interest to the date of payment, was made to Investing Partners based on a
December 31, 2003 valuation date. The second right of presentment offer of
$8,988 per Unit, plus interest to the date of payment, was made to the Investing
Partners based on a valuation date of June 30, 2004. As a result, the
Partnership acquired 5.0 Units for a total of $55,881 in cash. In 2003 and 2002,
Investing Partners were paid $295,734 and $213,006, respectively, for a total of
49.5 Units.
There will be two rights of presentment in 2005, 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.
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.
CRITICAL ACCOUNTING POLICIES
The following details the more significant accounting policies, estimates
and judgments of the Partnership. 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 percent using commodity prices in effect at the
end of the reporting period. If the full cost pool is in excess of the ceiling
limitation, the excess amount is charged through income.
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. In addition, gains or
losses on the sale or other disposition of oil and gas properties are not
recognized. Unless the gain or loss would significantly alter the relationship
between capitalized cost and the proved oil and gas reserves of the Company. 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. Generally, the application of the
full-cost method of accounting for oil and gas property results in higher
capitalized costs and higher depletion, depreciation and amortization rates
compared to similar companies applying the successful efforts method of
accounting.
12
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 depreciation, depletion and amortization (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
the 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 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. As such, beginning in 2003, the Partnership's depletion
expense is reduced since it will deplete a discounted ARO rather than the
undiscounted value previously depleted in our oil and gas property base. The
lower depletion expense under SFAS No. 143 is offset, however, by accretion
expense, which reflects increases in the discounted asset retirement obligation
over time.
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.
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 of this 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.
In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106
to provide new guidance on how asset retirement obligations should impact the
calculation of the "ceiling test" or limitation on the amount of
13
properties that can be capitalized on the balance sheet under the full cost
method of accounting for oil and gas companies. The new guidance dictates that
since the asset retirement obligation is now reported on the balance sheet,
related costs in the future net cash flow calculation should be omitted to avoid
double-counting these costs. Based on this guidance, the Company changed its
method of calculating the ceiling test limitation as of year end and there was
no material impact.
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 2004, monthly oil price realizations
ranged from a low of $33.34 per barrel to a high of $52.55 per barrel. Gas price
realizations ranged from a monthly low of $5.19 per Mcf to a monthly high of
$7.77 per Mcf during the same period. While remaining strong compared to
historical levels, gas prices trended upward during most of 2004. Based on the
Partnership's average daily production for 2004, a $1.00 per barrel change in
the weighted average realized oil price would have increased or decreased
revenues for the year by approximately $110,000 and a $.10 per Mcf change in the
weighted average realized price of natural gas would have increased or decreased
revenues for the year by approximately $139,800. The Partnership did not use
derivative financial instruments or otherwise engage in hedging activities
during the three-year period ended December 31, 2004. 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, capital expenditure projections, 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.
14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
APACHE OFFSHORE INVESTMENT PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS
PAGE
NUMBER
------
Report of Independent Registered Public Accounting Firm ............................... 16
Statement of Consolidated Income for each of the three years in the period ended
December 31, 2004 .................................................................. 17
Statement of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2004 .................................................................. 18
Consolidated Balance Sheet as of December 31, 2004 and 2003 ........................... 19
Statement of Consolidated Changes in Partners' Capital for each of the three years
in the period ended December 31, 2004 .............................................. 20
Notes to Consolidated Financial Statements ............................................ 21
Supplemental Oil and Gas Disclosures .................................................. 30
Supplemental Quarterly Financial Data ................................................. 32
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.
15
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004 and 2003, 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, 2004. 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 the standards of the Public
Company Accounting Oversight Board (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
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the
Partnership's internal control over financial reporting. Accordingly, we express
no such opinion. An audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
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, 2004 and 2003, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States.
ERNST & YOUNG LLP
Houston, Texas
March 11, 2005
16
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
2004 2003 2002
----------- ----------- ----------
REVENUES:
Oil and gas sales $13,873,998 $11,950,908 $6,867,523
Interest income 39,087 27,081 19,199
Other revenue -- 14,567 99,300
----------- ----------- ----------
13,913,085 11,992,556 6,986,022
----------- ----------- ----------
OPERATING EXPENSES:
Depreciation, depletion and amortization 2,816,528 2,875,896 2,181,189
Asset retirement obligation accretion 48,744 37,605 --
Lease operating costs 918,337 818,636 731,416
Gathering and transportation expense 135,263 121,067 102,698
Administrative 403,000 405,000 447,000
----------- ----------- ----------
4,321,872 4,258,204 3,462,303
----------- ----------- ----------
Operating income before cumulative effect of
change in accounting principle $ 9,591,213 $ 7,734,352 $3,523,719
Cumulative effect of change in accounting principle -- 302,407 --
----------- ----------- ----------
NET INCOME $ 9,591,213 $ 8,036,759 $3,523,719
=========== =========== ==========
NET INCOME ALLOCATED TO:
Managing Partner $ 2,407,360 $ 2,036,681 $1,035,747
Investing Partners 7,183,853 6,000,078 2,487,972
----------- ----------- ----------
$ 9,591,213 $ 8,036,759 $3,523,719
=========== =========== ==========
NET INCOME PER INVESTING PARTNER UNIT $ 6,786 $ 5,598 $ 2,259
=========== =========== ==========
WEIGHTED AVERAGE INVESTING PARTNER
UNITS OUTSTANDING 1,058.6 1,071.9 1,101.5
=========== =========== ==========
The accompanying notes to financial statements are
an integral part of this statement.
17
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------
2004 2003 2002
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 9,591,213 $ 8,036,759 $ 3,523,719
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,816,528 2,875,896 2,181,189
Asset retirement obligation accretion 48,744 37,605 --
Cumulative effect of change in accounting principle -- (302,407) --
Dismantlement and abandonment cost (323,966) (254,134) --
Changes in operating assets and liabilities:
(Increase) decrease in accrued revenues receivable (324,111) (26,046) (322,209)
Increase (decrease) in accrued operating
expenses 11,693 3,598 (63,706)
Increase (decrease) in payable to Apache Corporation (79,257) (210,169) (392,810)
----------- ----------- -----------
Net cash provided by operating activities 11,740,844 10,161,102 4,926,183
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (1,570,794) (1,916,566) (3,248,104)
Increase (decrease) in accrued development costs (334,740) 282,927 (362,745)
----------- ----------- -----------
Net cash used in investing activities (1,905,534) (1,633,639) (3,610,849)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units (55,881) (295,734) (213,006)
Distributions to Investing Partners (6,350,335) (4,789,313) (1,095,189)
Distributions to Managing Partner (2,366,949) (2,086,812) (974,634)
----------- ----------- -----------
Net cash used in financing activities (8,773,165) (7,171,859) (2,282,829)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 1,062,145 1,355,604 (967,495)
CASH AND CASH EQUIVALENTS, BEGINNING
OF YEAR 2,271,495 915,891 1,883,386
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 3,333,640 $ 2,271,495 $ 915,891
=========== =========== ===========
The accompanying notes to financial statements are
an integral part of this statement.
18
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-----------------------------
2004 2003
------------- -------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 3,333,640 $ 2,271,495
Accrued revenues receivable 965,321 641,210
Receivable from Apache Corporation 165,474 86,217
------------- -------------
4,464,435 2,998,922
------------- -------------
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties 184,065,602 182,173,899
Less - Accumulated depreciation, depletion and amortization (176,315,217) (173,498,689)
------------- -------------
7,750,385 8,675,210
------------- -------------
$ 12,214,820 $ 11,674,132
============= =============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued development costs $ -- $ 334,740
Accrued operating expenses 63,769 52,076
------------- -------------
63,769 386,816
------------- -------------
COMMITMENTS AND CONTINGENCIES (Note 7)
ASSET RETIREMENT OBLIGATION 858,207 812,520
------------- -------------
PARTNERS' CAPITAL:
Managing Partner 207,621 167,210
Investing Partners (1,055.7 and 1,060.7 Units
outstanding, respectively) 11,085,223 10,307,586
------------- -------------
11,292,844 10,474,796
------------- -------------
$ 12,214,820 $ 11,674,132
============= =============
The accompanying notes to financial statements are
an integral part of this statement.
19
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS' CAPITAL
MANAGING INVESTING
PARTNER PARTNERS TOTAL
----------- ----------- -----------
BALANCE, DECEMBER 31, 2001 $ 156,228 $ 8,212,778 $ 8,369,006
Distributions (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 (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
Distributions (2,366,949) (6,350,335) (8,717,284)
Repurchase of Partnership Units -- (55,881) (55,881)
Net income 2,407,360 7,183,853 9,591,213
----------- ----------- -----------
BALANCE, DECEMBER 31, 2004 $ 207,621 $11,085,223 $11,292,844
=========== =========== ===========
The accompanying notes to financial statements are
an integral part of this statement.
20
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION
NATURE OF OPERATIONS -
Apache Offshore Investment Partnership was formed as a Delaware
general partnership on October 31, 1983, consisting of Apache Corporation
(Apache) as Managing Partner and public investors as Investing Partners.
The general partnership invested its entire capital in Apache Offshore
Petroleum Limited Partnership, a Delaware limited partnership formed to
conduct oil and gas exploration, development and production operations. The
accompanying financial statements include the accounts of both the limited
and general partnerships. Apache is the general partner of both the limited
and general partnerships, and held approximately five percent of the
1,055.7 Investing Partner Units (Units) outstanding at December 31, 2004.
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, 2004, 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 63
percent of the Partnership's 2004 production and 57 percent of total proved
reserves, on an energy equivalent basis, the Partnership is affected more
by fluctuations in natural gas prices than in oil prices.
Under the terms of the Partnership Agreements, the Investing Partners
receive 80 percent and Apache receives 20 percent of revenue. Lease
operating, gathering and transportation and administrative expenses are
allocated to the Investing Partners and Apache in the same proportion as
revenues. The Investing Partners receive 100 percent of the interest income
earned on short-term cash investments. The Investing Partners generally pay
for 90 percent and Apache generally pays for 10 percent of exploration and
development costs and expenses incurred by the Partnership. However,
intangible drilling costs, interest costs and fees or expenses related to
the loans incurred by the Partnership are allocated 99 percent to the
Investing Partners and one percent to Apache until such time as the amount
so allocated to the Investing Partners equals 90 percent of the total
amount of such costs, including such costs incurred by Apache prior to the
formation of the Partnerships.
21
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
RIGHT OF PRESENTMENT -
An amendment to the Partnership Agreements adopted in February 1994,
created a right of presentment under which all Investing Partners have a
limited and voluntary right to offer their Units to the Partnership twice
each year to be purchased for cash. In 2004, the first right of presentment
offer of $11,518 per Unit, plus interest to the date of payment, was made
to Investing Partners based on a December 31, 2003 valuation date. The
second right of presentment offer of $8,988 per Unit, plus interest to the
date of payment, was made to the Investing Partners based on a valuation
date of June 30, 2004. As a result, the Partnership acquired 5.0 Units for
a total of $55,881 in cash. In 2003 and 2002, Investing Partners were paid
$295,734 and $213,006, respectively, for a total of 49.5 Units.
The Partnership is not in a position to predict how many Units will be
presented for repurchase during 2005, 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, 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
December 31, 2003 14,338,941 11,518
June 30, 2004 13,730,918 8,988
INVESTING PARTNER UNITS OUTSTANDING:
2004 2003 2002
------- ------- -------
Balance, beginning of year 1,060.7 1,084.9 1,110.3
Repurchase of Partnership Units (5.0) (24.2) (25.4)
------- ------- -------
Balance, end of year 1,055.7 1,060.7 1,084.9
======= ======= =======
CAPITAL CONTRIBUTIONS -
A total of $85,000 per Unit, or approximately 57 percent, of investor
subscription had been called through December 31, 2004. 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
1,055.7 Units at December 31, 2004.
22
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
STATEMENT PRESENTATION -
The accounts of the Partnerships are maintained on a tax basis method
of accounting in accordance with the Articles of Partnership and methods of
reporting allowed for federal income tax purposes.
The consolidated financial statements included in reports that the
Partnership files with the Securities and Exchange Commission (SEC) are
required to be prepared in conformity with generally accepted accounting
principles. Accordingly, the accompanying consolidated financial statements
include adjustments to convert from tax basis to the accrual basis method
in conformity with accounting principles generally accepted in the United
States.
The accompanying consolidated financial statements include the
accounts of Apache Offshore Investment Partnership and Apache Offshore
Petroleum Limited Partnership after elimination of intercompany balances
and transactions.
CASH EQUIVALENTS -
The Partnership considers all highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
These investments are carried at cost which approximates market.
OIL AND GAS PROPERTIES -
The Partnership uses the full cost method of accounting for its
investment in oil and gas properties for financial statement purposes.
Under this method, the Partnership capitalizes all acquisition, exploration
and development costs incurred for the purpose of finding oil and gas
reserves. The amounts capitalized under this method include dry hole costs,
leasehold costs, engineering, geological, exploration, development and
other similar costs. Costs associated with production and administrative
functions are expensed in the period incurred. Unless a significant portion
of the Partnership's reserve volumes are sold (greater than 25 percent),
proceeds from the sale of oil and gas properties are accounted for as
reductions to capitalized costs, and gains or losses are not recognized.
Capitalized costs of oil and gas properties are amortized on the
future gross revenue method whereby depreciation, depletion and
amortization (DD&A) expense is computed quarterly by dividing current
period oil and gas sales by estimated future gross revenue from proved oil
and gas reserves (including current period oil and gas sales) and applying
the resulting rate to the net cost of evaluated oil and gas properties,
including estimated future development costs. The amortizable base included
estimated dismantlement, restoration and abandonment costs, net of
estimated salvage values, in 2002. Beginning in 2003, the Partnership
changed its method of accounting for dismantlement, restoration and
abandonment cost as described in Note 8. The Partnership now includes the
present value of its dismantlement, restoration and abandonment costs
within the capitalized oil and gas property balance and, therefore, no
longer reflects the recognized abandonment obligations within the future
development costs added to the amortizable base.
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.
In September 2004, the SEC issued Staff Accounting Bulletin No. 106
("SAB 106") to provide new guidance on how asset retirement obligations
should impact the calculation of the "ceiling test" or limitation on
23
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the amount of properties that can be capitalized on the balance sheet under
the full cost method of accounting for oil and gas companies. The new
guidance dictates that since the asset retirement obligation is now
reported on the balance sheet, related costs in the future net cash flow
calculation should be omitted to avoid double-counting these costs. The
Partnership's adoption of SAB 106 did not have a material impact on its
financial results.
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.
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, 2004 and 2003, the Partnership did
not have any liabilities for gas imbalances in excess of remaining
reserves. No receivables are recorded for those wells where the Partnership
has taken less than its share of production. Gas imbalances are reflected
as adjustments to proved gas revenues and future cash flows in the
unaudited supplemental oil and gas disclosures. Adjustments for gas
imbalances totaled less than one percent of the Partnership's proved gas
reserves at December 31, 2004, 2003 and 2002.
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 APACHE -
The receivable from 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
24
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
SHIPPING AND HANDLING COSTS -
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.
(3) COMPENSATION TO APACHE
Apache is entitled to the following types of compensation and
reimbursement for costs and expenses.
TOTAL REIMBURSED BY THE INVESTING PARTNERS
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------
2004 2003 2002
---- ---- ----
(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 $322 $324 $358
==== ==== ====
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 $ 71 $ 86 $129
==== ==== ====
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.
2004 2003 2002
-------- -------- --------
(In thousands)
Oil and Gas Properties
Balance, beginning of year $182,174 $179,657 $176,409
Asset retirement cost from adoption of
SFAS No. 143 -
Investing Partners -- 323 --
Managing Partner -- 3 --
Costs incurred during the year:
Development -
Investing Partners 1,841 2,154 3,174
Managing Partner 51 37 74
-------- -------- --------
Balance, end of year $184,066 $182,174 $179,657
======== ======== ========
25
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
MANAGING INVESTING
PARTNER PARTNERS TOTAL
-------- --------- --------
(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 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
Provision 75 2,741 2,816
------- -------- --------
Balance, December 31, 2004 $20,840 $155,475 $176,315
======= ======== ========
The Partnership's aggregate DD&A expense as a percentage of oil and
gas sales for 2004, 2003 and 2002 was 20 percent, 24 percent and 32
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 accounted for 37 percent and 60 percent of the
Partnership's oil and gas sales in 2003 and 2002, 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.
Apache Crude Oil Marketing, Inc., a wholly-owned subsidiary of Apache,
purchased oil and condensate from the Partnership which accounted for
approximately 17 percent of the Partnership's total oil and gas sales in
2002. 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 Plains Marketing LP accounted for 32 percent of the
Partnership's oil and gas sales in 2004. 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 onshore markets. The Partnership
paid the Apache subsidiary transportation fees totaling $31,008 in 2004,
$43,606 in 2003 and $43,785 in 2002 for the Partnership's share of gas. The
fees were at the same rates and terms as previously paid to Shell.
26
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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, 2004 and 2003 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, 2004.
(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) ASSET RETIREMENT OBLIGATION
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 and
recorded an increase to net oil and gas properties of $1.1 million and
associated 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 is offset, however, by accretion
expense, which is recognized over time as the discounted liability is
accreted to its expected settlement value.
27
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
The following table is a reconciliation of the asset retirement
obligation liability since adoption:
2004 2003
-------- ---------
Asset retirement obligation at beginning of period $812,520 $ 754,351
Liabilities settled (6,101) (575,553)
Accretion expense 48,744 37,605
Revisions in estimated liabilities 3,044 596,117
-------- ---------
Asset retirement obligation at December 31 $858,207 $ 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 East Cameron 60 Field was plugged and
abandoned in late 2003.
(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.
28
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(10) TAX-BASIS FINANCIAL INFORMATION
A reconciliation of ordinary income for federal income tax reporting
purposes to net income under accounting principles generally accepted in
the United States is as follows:
2004 2003 2002
----------- ----------- -----------
Net partnership ordinary income for federal income
tax reporting purposes $ 9,993,343 $ 7,846,759 $ 2,426,766
Plus: Items of current (income) expense for tax reporting
purposes only -
Intangible drilling cost 1,457,967 1,358,245 2,638,051
Dismantlement and abandonment cost 6,101 575,553 --
Tax depreciation 999,074 867,296 640,091
----------- ----------- -----------
2,463,142 2,801,094 3,278,142
----------- ----------- -----------
Less: full cost DD&A expense (2,816,528) (2,875,896) (2,181,189)
Less: asset retirement obligation accretion (48,744) (37,605) --
Plus: cumulative effect of change in accounting principle -- 302,407 --
----------- ----------- -----------
Net income $ 9,591,213 $ 8,036,759 $ 3,523,719
=========== =========== ===========
The Partnership's tax bases in net oil and gas properties at December
31, 2004 and 2003 was $4,351,881 and $3,303,730, 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, 2004 and 2003.
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,
---------------------
2004 2003
-------- ----------
Liabilities for federal income tax purposes $ 63,769 $ 386,816
Asset retirement liability 858,207 812,520
-------- ----------
Liabilities under accounting principles generally
accepted in the United States $921,976 $1,199,336
======== ==========
Asset retirement liabilities for future dismantlement and abandonment
costs are not recognized for federal income tax reporting purposes until
settled.
29
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)
2004 2003 2002
------------- ------------- -------------
OIL GAS OIL GAS OIL GAS
---- ------ ---- ------ ---- ------
Proved Reserves
Beginning of year 618 5,992 849 6,339 885 7,075
Extensions, discoveries and other additions 32 1,027 12 161 204 389
Revisions of previous estimates 134 (377) (112) 924 (130) 99
Production (136) (1,398) (131) (1,432) (110) (1,224)
---- ------ ---- ------ ---- ------
End of year 648 5,244 618 5,992 849 6,339
==== ====== ==== ====== ==== ======
Proved Developed
Beginning of year 618 5,883 849 6,230 767 6,685
==== ====== ==== ====== ==== ======
End of year 648 5,140 618 5,883 849 6,230
==== ====== ==== ====== ==== ======
Oil includes crude oil, condensate and natural gas liquids.
Approximately 67 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 will 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.
30
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,
------------------------------
2004 2003 2002
-------- -------- --------
(In thousands)
Future cash inflows $ 58,854 $ 55,014 $ 56,471
Future production costs (5,943) (5,645) (4,623)
Future development costs (3,571) (3,789) (4,115)
-------- -------- --------
Net cash flows 49,340 45,580 47,733
10 percent annual discount rate (17,590) (14,995) (16,908)
-------- -------- --------
Discounted future net cash flows $ 31,750 $ 30,585 $ 30,825
======== ======== ========
The following table sets forth the principal sources of change in the
discounted future net cash flows:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2004 2003 2002
-------- -------- -------
(In thousands)
Sales, net of production costs $(12,820) $(11,011) $(6,034)
Net change in prices and production costs 4,435 3,731 14,403
Extensions, discoveries and other additions 6,331 1,247 4,548
Development costs incurred 233 490 680
Revisions of quantities 1,644 813 (2,023)
Accretion of discount 3,059 3,083 1,743
Changes in future development costs -- -- 185
Changes in production rates and other (1,717) 1,407 (110)
-------- -------- -------
$ 1,165 $ (240) $13,392
======== ======== =======
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.
31
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL
------ ------ ------ ------ -------
(In thousands, except per Unit amounts)
2004
Revenues $3,257 $3,180 $3,454 $4,022 $13,913
Expenses 1,037 1,052 1,098 1,135 4,322
------ ------ ------ ------ -------
Income before change in
accounting principle 2,220 2,128 2,356 2,887 9,591
------ ------ ------ ------ -------
Net income $2,220 $2,128 $2,356 $2,887 $ 9,591
====== ====== ====== ====== =======
Net income allocated to:
Managing Partner $ 564 $ 545 $ 604 $ 694 $ 2,407
Investing Partners 1,656 1,583 1,752 2,193 7,184
------ ------ ------ ------ -------
$2,220 $2,128 $2,356 $2,887 $ 9,591
====== ====== ====== ====== =======
Net income per Investing
Partner Unit (1) $1,561 $1,494 $1,657 $2,075 $ 6,786
====== ====== ====== ====== =======
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
====== ====== ====== ====== =======
(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.
32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Control 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, 2004 that have
materially affected, or are reasonably likely to materially affect, the
Partnership's internal control over financial reporting.
Report on Internal Control Over Financial Reporting
On February 24, 2004, the SEC approved an extension of the original
compliance dates related to the internal control reporting pursuant to Section
404 of the Sarbanes-Oxley Act of 2002, as they pertain to companies with less
than $75 million in market value of outstanding securities. The effective date
for these non-accelerated filers was extended until fiscal years ending on or
after July 15, 2005. On March 2, 2005, the SEC further extended the compliance
date for non-accelerated filers until fiscal years ending on or after July 15,
2006. The Partnership has not issued a report on its internal control over
financial reporting, nor had an assessment made by its independent registered
public accounting firm, as they were not required for the year ended December
31, 2004.
ITEM 9B. OTHER INFORMATION
None.
33
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 2005 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 Apache'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 Apache'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", "Long-Term Incentive
Plan Awards 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,
2004. Directors and officers of Apache own four Units, less than one percent of
the Partnership's Units, as of December 31, 2004. 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 5.0 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 Accountants" in
Apache's 2005 proxy statement.
34
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 28, 2005,
relating to the 2005 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, 2004.
35
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, 2005 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,
Thomas L. Mitchell and Jeffrey B. King, 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, 2005
- ----------------------------- Officer and Chief Operating Officer
G. Steven Farris (Principal Executive Officer)
/s/ Roger B. Plank Executive Vice President and Chief March 11, 2005
- ----------------------------- Financial Officer (Principal
Roger B. Plank Financial Officer)
/s/ Thomas L. Mitchell Vice President and Controller March 11, 2005
- ----------------------------- (Principal Accounting Officer)
Thomas L. Mitchell
NAME TITLE DATE
---- ----- ----
/s/ Raymond Plank Chairman of the Board March 11, 2005
- -----------------------------
Raymond Plank
/s/ Frederick M. Bohen Director March 11, 2005
- -----------------------------
Frederick M. Bohen
/s/ Randolph M. Ferlic Director March 11, 2005
- -----------------------------
Randolph M. Ferlic
/s/ Eugene C. Fiedorek Director March 11, 2005
- -----------------------------
Eugene C. Fiedorek
/s/ A. D. Frazier, Jr. Director March 11, 2005
- -----------------------------
A. D. Frazier, Jr.
/s/ Patricia Albjerg Graham Director March 11, 2005
- -----------------------------
Patricia Albjerg Graham
/s/ John A. Kocur Director March 11, 2005
- -----------------------------
John A. Kocur
/s/ George D. Lawrence Director March 11, 2005
- -----------------------------
George D. Lawrence
/s/ F. H. Merelli Director March 11, 2005
- -----------------------------
F. H. Merelli
/s/ Rodman D. Patton Director March 11, 2005
- -----------------------------
Rodman D. Patton
/s/ Charles J. Pitman Director March 11, 2005
- -----------------------------
Charles J. Pitman
/s/ Jay A. Precourt Director March 11, 2005
- -----------------------------
Jay A. Precourt
Index to Exhibits
Exhibits 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 28, 2005, relating to
the 2005 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.