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, 2005
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 if the registrant is a well-known seasoned issuer,
as defined in Rule 405 of the Securities Act of 1933. Yes [ ] No [X ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X ]
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the Registrant is a large accelerated
filer, an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange
Act
Large accelerated filer ( ) Accelerated filer ( ) Non-accelerated filer (x)
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act): Yes ( ) No (x)
Aggregate market value of the voting and non-voting common equity held by non-affiliates of
registrant as of June 30, 2005............................................................. $14,375,129
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Apache Corporation's proxy statement relating to its 2006
annual meeting of stockholders have been incorporated by reference into Part III
hereof.
TABLE OF CONTENTS
DESCRIPTION
ITEM PAGE
PART I
1. BUSINESS...................................................................................... 1
1A. RISK FACTORS.................................................................................. 3
1B. UNRESOLVED STAFF COMMENTS..................................................................... 4
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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.................................... 13
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 Investment 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 Investment Partnership
will, however, provide paper copies of these filings, free of charge, to anyone
so requesting. Included in the Investment 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,
2005, 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.
2005 RESULTS AND BUSINESS DEVELOPMENT
The Partnership reported net income in 2005 of $11.0 million, or $8,048
per Investing Partner Unit. Earnings were up $1.5 million from 2004 on the
strength of higher oil and gas prices in 2005. Natural gas production averaged
3,172 Mcf per day in 2005, while oil sales averaged 203 barrels per day.
Production added through drilling in 2005 partially offset declines from natural
depletion.
During 2005, the Partnership participated in drilling three new wells at
Ship Shoal 258/259. The Ship Shoal 259 JA-9 was completed as a producer in
August, while the Ship Shoal 258 JB-7 was completed as a producer in late
November. The Ship Shoal 259 JA-10 well was a dry hole. Also during 2005, the
Partnership sold its interest in the South Pass 83 Field for $134,060. The
purchaser also assumed all dismantlement and abandonment obligations for the
property.
Since inception, the Partnership has acquired an interest in 49 prospects.
As of December 31, 2005, 44 of those prospects have been surrendered or sold.
As of December 31, 2005, the Partnership had 52 producing wells on the
Partnership's five remaining developed fields. Two of the Partnership's
producing wells are dual completions. The Partnership had, at December 31, 2005,
estimated proved oil and gas reserves of 8.4 Bcfe, of which 54 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 2005 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
those of the market, the Partnership does not believe that the loss of any
customer would have a material adverse affect
2
on the Partnership's business or results of operations. The Partnership is not
in a position to predict future oil and gas prices.
ITEM 1A. RISK FACTORS
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
the Partnership's new independent auditors for 2002. Ernst & Young also served
as the Partnership's independent auditors in 2003, 2004 and 2005. However,
included in this annual report on Form 10-K are financial data and other
information for 2001 that were audited by Arthur Andersen. Investors in the
Partnership's securities may encounter difficulties in obtaining, or be unable
to obtain, from Arthur Andersen with respect to its audits of the Partnership's
financial statements relief that may be available to investors under the federal
securities laws against auditing firms.
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of the date of filing of this report, the Partnership had no material
comments from the staff of the SEC that were unresolved for more than 180 days
as of December 31, 2005.
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, 2005, 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
Ship Shoal 201, 202 LA 10,000 -
------ -----
61,061 3,157
====== =====
At December 31, 2005, 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, 2005, is set forth below:
GAS OIL
----------------- -----------------
LEASE BLOCK STATE GROSS NET GROSS NET
----------- ----- ----- --- ----- ---
Ship Shoal 258, 259 LA 9 .57 - -
South Timbalier 276, 295, 296 LA 1 .07 33 2.34
North Padre Island 969, 976 TX 4 .28 - -
Matagorda Island 681, 682, 683 TX 3 .19 - -
Ship Shoal 201, 202 LA 1 - 1 -
-- ---- -- ----
18 1.11 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
- ---- ---------- --- ----- ---------- --- -----
2005 - - - .13 .06 .19
2004 - - - .30 - .30
2003 - - - - - -
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)
- ------------- ------- ------ ------- ------------- --------- --------- ---------
2005 74 1,158 18 $ .78 $ 53.91 $ 8.78 $33.98
2004 110 1,398 26 .48 40.62 6.23 26.84
2003 125 1,432 6 .42 30.73 5.56 23.92
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, 2005, the Partnership had total estimated proved
reserves of 643,081 barrels of crude oil, condensate and NGLs and 4.5 Bcf of
natural gas. Combined, these total estimated proved reserves are equivalent to
8.4 Bcf of gas. Estimated proved developed reserves comprise 99 percent of the
Partnership's total estimated proved reserves on a Bcfe basis.
The Partnership's estimates of proved reserves and proved developed
reserves at December 31, 2005, 2004 and 2003, 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 2005 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 2005.
6
PART II
ITEM 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY HOLDER
MATTERS
As of December 31, 2005, there were 1,053.4 of the Partnership's Units
outstanding held by 886 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 $9.5
million, or $9,000 per Unit, during 2005 and approximately $6.4 million, or
$6,000 per Unit, during 2004.
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, 2005, 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 year 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,
---------------------------------------------------
2005 2004 2003 2002 2001
------- ------- ------- ------- -------
(In thousands, except per Unit amounts)
Total assets $11,624 $12,215 $11,674 $ 9,834 $ 9,413
======= ======= ======= ======= =======
Partners' capital $10,311 $11,293 $10,475 $ 9,610 $ 8,369
======= ======= ======= ======= =======
Oil and gas sales $14,779 $13,874 $11,951 $ 6,868 $10,495
======= ======= ======= ======= =======
Net income $11,048 $ 9,591 $ 8,037 $ 3,524 $ 7,264
======= ======= ======= ======= =======
Net income allocated to:
Managing Partner $ 2,555 $ 2,407 $ 2,037 $ 1,036 $ 1,731
Investing Partners 8,493 7,184 6,000 2,488 5,533
------- ------- ------- ------- -------
$11,048 $ 9,591 $ 8,037 $ 3,524 $ 7,264
======= ======= ======= ======= =======
Net income per Investing
Partner Unit $ 8,048 $ 6,786 $ 5,598 $ 2,259 $ 4,922
======= ======= ======= ======= =======
Cash distributions per
Investing Partner Unit $ 9,000 $ 6,000 $ 4,500 $ 1,000 $ 4,000
======= ======= ======= ======= =======
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 2005. 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's oil and gas production has declined in each of the last two years
and is expected to continue to decline with Partnership's limited capital
expenditures.
Since all of the Partnership's properties are located in the Gulf of
Mexico, its operations and cash flow can be significantly impacted by hurricanes
and other inclement weather. These events may also have detrimental impact on
third-party pipelines and processing facilities, which the Partnership relies
upon to transport and process the crude oil and natural gas it produces. During
the third quarter of 2005, four hurricanes struck the Gulf of Mexico that
impacted the Partnership's operations. Two of these storms, Hurricanes Denis and
Emily, only required temporary curtailment of production while the operators'
personnel were evacuated for safety purposes. The other two storms, Hurricanes
Katrina and Rita, caused lengthier production curtailments as the storms damaged
third-party pipelines and disrupted the operations of crews which could assess
and repair damage to the Partnership's or other's facilities. While the
Partnership's platforms avoided major damage, the Partnership's production was
curtailed approximately 22 percent during the third quarter of 2005 as a result
of hurricanes. The Partnership's production was restored to pre-hurricane levels
early in the fourth quarter.
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. During 2005, the Partnership participated in
drilling three development wells at Ship Shoal 258/259, of which two wells were
completed as producing gas wells and one well was dry. The Partnership currently
anticipates that future development cost will largely be directed to
recompletion projects in the Ship Shoal 258/259 and South Timbalier 295 fields.
Generally, the Partnership has used its remaining available cash to fund
distributions to its Partners. Reflecting the significant impact of oil and gas
prices on net income and cash from operating activities, distributions to
Investing Partners increased to $9,000 per Unit in 2005, up 50 percent from
2004. Distributions to Investing Partners increased to $6,000 per Unit in 2004
from $4,500 in 2003.
RESULTS OF OPERATIONS
This section includes a discussion of the Partnership's 2005 and 2004
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 $11.0 million for 2005, up 15
percent from 2004 on the strength of higher commodity prices. Net income per
Investing Partner Unit increased in 2005 to $8,048, up from $6,786 in 2004. The
Partnership reported earnings in 2004 of $9.6 million.
8
Total revenues increased to $14.9 million in 2005 on higher prices.
Interest income earned by the Partnership on short-term cash investments in 2005
more than doubled from 2004 as a result of higher average investment balances
and higher interest rates in 2005. Interest income in 2004 increased 44 percent
from the prior year, increasing from $27,081 in 2003 to $39,087 in 2004.
The Partnership's oil and gas production volume and price information is
summarized in the following table:
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------
2005 2004 2003
---- ---- ----
Gas volumes - Mcf per day 3,172 3,820 3,924
Average gas price - per Mcf $ 8.78 $ 6.23 $ 5.56
Oil volumes - barrels per day 203 301 342
Average oil price - per barrel $ 53.91 $ 40.62 $ 30.73
NGL volumes - barrels per day 51 71 16
Average NGL price - per barrel $ 33.98 $ 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 2005 totaled $10.2 million, up 17 percent from 2004
on higher prices. The Partnership's average realized natural gas price for 2005
improved 41 percent from 2004. The $2.55 per Mcf increase in gas price from a
year ago boosted sales by approximately $3.6 million. Daily gas production for
2005 decreased 17 percent from 2004, decreasing sales by $2.1 million. The
decline in production from 2004 reflected natural depletion, downtime for
hurricanes, and the sale of Partnership's interest in the South Pass 83 Field in
early 2005. The Partnership completed the Ship Shoal 259 JA-9 well in August and
the Ship Shoal JB-7 in late November which partially mitigated the production
decline from 2004.
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.
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
In 2005, the Partnerships crude oil sales totaled $4.0 million. A $13.29
per barrel, or 33 percent increase in the Partnership's average realized oil
price in 2004 increased oil revenues by $.8 million from 2004. Oil production
9
decreased 33 percent from 2004 as a result of production declines at South
Timbalier 295 resulting from natural depletion.
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.
OPERATING EXPENSES
The Partnership's depreciation, depletion and amortization (DD&A) rate,
expressed as a percentage of oil and gas sales, decreased to 14 percent in 2005.
The decrease in DD&A rate as a percentage of sales reflected higher oil and gas
prices in 2005. The lower DD&A in 2005 also reflected favorable reserve
revisions at Ship Shoal 258/259 and proceeds from the sale of South Pass 83. The
Partnership's DD&A rate, expressed as a percentage of oil and gas sales,
decreased to 20 percent in 2004 from 24 percent in 2003 as a result of higher
oil and gas prices in 2004. DD&A expense declined slightly in 2004 on an
absolute basis as a result of the decline in the Partnership's production from
2004, and as a result of reserve additions from drilling at Ship Shoal 258/259.
Lease operating costs in 2005 increased approximately $241,000 from a year
ago primarily as result of a workover on the North Padre Island 976 A-3 well,
repairs on the North Padre 969/976 platform, repairs at South Pass 83 in January
and painting platforms at Ship Shoal 258/259, Matagorda 681/682 and South
Timbalier 295 in 2005. Air and marine transportation costs also increased LOE in
2005 with higher fuel costs. Administrative expense increased slightly from last
year, increasing to $417,000 in 2005. The increase largely reflected higher
auditing, tax and reservoir engineering fees in 2005.
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.
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 $12.3 million for 2005. Benefiting from
strong commodity prices throughout 2005, the Partnership's 2005 net cash
provided by operating activities increased $.6 million, or 5 percent, from a
year ago. Net cash provided by operating activities in 2004 increased 16 percent
from 2003 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 68 percent of the Partnership's 2005 production
and 54 percent of total proved reserves, on an energy equivalent basis, the
Partnership is affected more by fluctuations in natural gas prices than in oil
prices.
The Partnership's oil and gas reserves and production will also
significantly impact future results of operations and cash from operating
activities. The Partnership's production is subject to fluctuations in response
to remaining quantities
10
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 69 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, 2005. 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.
On an ongoing basis, the Partnership reviews the possible sale of lower
value properties prior to incurring associated dismantlement and abandonment
cost. During 2005, the Partnership sold its interest in the South Pass 83 field
to a third party for $134,060. The purchaser also assumed all dismantlement and
abandonment obligations for the property. The South Pass 83 field had
insignificant levels of production at the time of the sale and the divestiture
is not expected to materially impact future operating income.
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, 2005. The Partnership did
not have any contractual obligations as of December 31, 2005, 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 2005, the Partnership's oil and gas property expenditures totaled
$1.8 million, primarily related to the Partnership's participation in drilling
three wells at Ship Shoal 258/259. During the year, the Partnership drilled the
Ship Shoal 259 JA-9, Ship Shoal 258 JB-7 and Ship Shoal 259 JA-10 wells. The
JA-9 and JB-7 wells were completed as producers in 2005, while the JA-10 well
was a dry hole. The Partnership also participated in one recompletion project at
South Timbalier 295 during 2005. During 2004, the Partnership's oil and gas
property expenditures totaled $1.9 million. These additions related to the
Partnership's participation in drilling four wells at Ship Shoal 258/259, a
recompletion at South Timbalier 295 and a recompletion at Ship Shoal 259. 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.
Based on preliminary information provided by the operators of the
properties in which the Partnership owns interests, the Partnership anticipates
capital expenditures will total less than $1 million in 2006. Such estimates may
change based on realized oil and gas prices, drilling results, rates charged by
drilling contractors or changes by the operator to the development plan.
During 2005, distributions of $9.5 million, or $9,000 per Unit, were paid
to Investing Partners. 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 2005. 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,
11
and prudent cash reserves for future dismantlement and abandonment costs that
will be incurred after the Partnership's reserves are depleted.
In February 1994, an amendment to the Partnership Agreement created a
right of presentment under which all Investing Partners have a limited and
voluntary right to offer their Units to the Partnership twice each year to be
purchased for cash. In 2005, the first right of presentment offer of $12,418 per
Unit, plus interest to the date of payment, was made to Investing Partners based
on a December 31, 2004 valuation date. The second right of presentment offer of
$9,337 per Unit was made to the Investing Partners based a valuation date of
June 30, 2005. As a result the Partnership acquired 2.3 units for a total of
$22,776. In 2004 and 2003, Investing Partners were paid $55,881 and $295,734,
respectively, for a total of 29.2 Units.
There will be two rights of presentment in 2006, 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 AND ESTIMATES
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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 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 2005, monthly oil price realizations
ranged from a low of $45.04 per barrel to a high of $62.80 per barrel. Gas price
13
realizations ranged from a monthly low of $5.85 per Mcf to a monthly high of
$14.23 per Mcf during the same period. While remaining strong compared to
historical levels, gas prices trended upward during most of 2005. Based on the
Partnership's average daily production for 2005, a $1.00 per barrel change in
the weighted average realized oil price would have increased or decreased
revenues for the year by approximately $74,000 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 $115,788. The Partnership did not use
derivative financial instruments or otherwise engage in hedging activities
during the three-year period ended December 31, 2005. 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.
GOVERNMENTAL RISK
The Partnership's operations have been, and at times in the future may be,
affected by political developments and by federal, state and local laws and
regulations impacting production levels, taxes, environmental requirements and
other assessments including a potential Windfall Profits Tax.
WEATHER AND CLIMATE RISK
Demand for oil and natural gas are, to a significant degree, dependent on
weather and climate, which impacts the price the Partnership receives for the
commodities it produces. In addition, production, development activities and
equipment can be adversely affected by severe weather, such as hurricanes in the
Gulf of Mexico.
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, 2005..... 17
Statement of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2005.................................................................................. 18
Consolidated Balance Sheet as of December 31, 2005 and 2004............................................ 19
Statement of Consolidated Changes in Partners' Capital for each of the three years in the period
ended December 31, 2005............................................................................ 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, 2005 and 2004, 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, 2005. 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. We were not engaged to
perform an audit of the Partnership's internal control over Financial reporting.
Our audits included 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 and subsidiary at December 31, 2005 and 2004,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 2005 in conformity with U.S.
generally accepted accounting principles.
ERNST & YOUNG LLP
Houston, Texas
March 10, 2006
16
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------
2005 2004 2003
----------- ----------- -----------
REVENUES:
Oil and gas sales $14,778,653 $13,873,998 $11,950,908
Interest income 99,970 39,087 27,081
Other revenue - - 14,567
----------- ----------- -----------
14,878,623 13,913,085 11,992,556
----------- ----------- -----------
OPERATING EXPENSES:
Depreciation, depletion and amortization 2,039,571 2,816,528 2,875,896
Asset retirement obligation accretion 45,672 48,744 37,605
Lease operating costs 1,159,366 918,337 818,636
Gathering and transportation expense 169,114 135,263 121,067
Administrative 417,000 403,000 405,000
----------- ----------- -----------
3,830,723 4,321,872 4,258,204
----------- ----------- -----------
Operating income before cumulative effect of
change in accounting principle $11,047,900 $ 9,591,213 $ 7,734,352
Cumulative effect of change in accounting principle - - 302,407
----------- ----------- -----------
NET INCOME $11,047,900 $ 9,591,213 $ 8,036,759
=========== =========== ===========
NET INCOME ALLOCATED TO:
Managing Partner $ 2,554,528 $ 2,407,360 $ 2,036,681
Investing Partners 8,493,372 7,183,853 6,000,078
----------- ----------- -----------
$11,047,900 $ 9,591,213 $ 8,036,759
=========== =========== ===========
NET INCOME PER INVESTING PARTNER UNIT $ 8,048 $ 6,786 $ 5,598
=========== =========== ===========
WEIGHTED AVERAGE INVESTING PARTNER
UNITS OUTSTANDING 1,055.4 1,058.6 1,071.9
=========== =========== ===========
The accompanying notes to financial statements are
an integral part of this statement.
17
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------
2005 2004 2003
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 11,047,900 $ 9,591,213 $ 8,036,759
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,039,571 2,816,528 2,875,896
Asset retirement obligation accretion 45,672 48,744 37,605
Cumulative effect of change in accounting principle - - (302,407)
Dismantlement and abandonment cost (167,767) (323,966) (254,134)
Changes in operating assets and liabilities:
(Increase) decrease in accrued revenues receivable (470,419) (324,111) (26,046)
Increase (decrease) in accrued operating expenses (3,204) 11,693 3,598
Increase (decrease) in receivable from
Apache Corporation (191,796) (79,257) (210,169)
------------ ------------ ------------
Net cash provided by operating activities 12,299,957 11,740,844 10,161,102
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (1,678,072) (1,570,794) (1,916,566)
Increase (decrease) in accrued development costs 551,324 (334,740) 282,927
Proceeds from sales of oil and gas properties 134,060 - -
------------ ------------ ------------
Net cash used in investing activities (992,688) (1,905,534) (1,633,639)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units (22,775) (55,881) (295,734)
Distributions to Investing Partners (9,499,617) (6,350,335) (4,789,313)
Distributions to Managing Partner (2,506,864) (2,366,949) (2,086,812)
------------ ------------ ------------
Net cash used in financing activities (12,029,256) (8,773,165) (7,171,859)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (721,987) 1,062,145 1,355,604
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 3,333,640 2,271,495 915,891
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 2,611,653 $ 3,333,640 $ 2,271,495
============ ============ ============
The accompanying notes to financial statements are
an integral part of this statement.
18
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-------------------------------
2005 2004
------------- -------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,611,653 $ 3,333,640
Accrued revenues receivable 1,435,740 965,321
Receivable from Apache Corporation 357,270 165,474
------------- -------------
4,404,663 4,464,435
------------- -------------
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties 185,573,656 184,065,602
Less - Accumulated depreciation, depletion and amortization (178,354,788) (176,315,217)
------------- -------------
7,218,868 7,750,385
------------- -------------
$ 11,623,531 $ 12,214,820
============= =============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued development costs $ 551,324 $ -
Accrued operating expenses 60,565 63,769
------------- -------------
611,889 63,769
------------- -------------
COMMITMENTS AND CONTINGENCIES (Note 7)
ASSET RETIREMENT OBLIGATION 700,154 858,207
------------- -------------
PARTNERS' CAPITAL:
Managing Partner 255,285 207,621
Investing Partners (1,053.4 and 1,055.7 Units
outstanding, respectively) 10,056,203 11,085,223
------------- -------------
10,311,488 11,292,844
------------- -------------
$ 11,623,531 $ 12,214,820
============= =============
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, 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
Distributions (2,506,864) (9,499,617) (12,006,481)
Repurchase of Partnership Units - (22,775) (22,775)
Net income 2,554,528 8,493,372 11,047,900
------------ ------------ ------------
BALANCE, DECEMBER 31, 2005 $ 255,285 $ 10,056,203 $ 10,311,488
============ ============ ============
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 1,053.4 Investing Partner Units (Units) outstanding at December 31,
2005. 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, 44 of those prospects have been surrendered/sold). The Partnership's
working interests in the five remaining venture prospects range from 6.29
percent to 7.08 percent. As of December 31, 2005, the Partnership held a
remaining interest in 10 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 68
percent of the Partnership's 2005 production and 54 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 2005, the first right of
presentment offer of $12,418 per Unit, plus interest to the date of
payment, was made to Investing Partners based on a December 31, 2004
valuation date. The second right of presentment offer of $9,337 per Unit
was made to the Investing Partners based a valuation date of June 30,
2005. As a result the Partnership acquired 2.3 units for a total of
$22,775. In 2004 and 2003, Investing Partners were paid $55,881 and
$295,734, respectively, for a total of 29.2 Units.
The Partnership is not in a position to predict how many Units will
be presented for repurchase during 2006, 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, 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
December 31, 2004 17,331,746 12,418
June 30, 2005 15,131,715 9,337
INVESTING PARTNER UNITS OUTSTANDING: 2005 2004 2003
------- ------- -------
Balance, beginning of year 1,055.7 1,060.7 1,084.9
Repurchase of Partnership Units (2.3) (5.0) (24.2)
------- ------- -------
Balance, end of year 1,053.4 1,055.7 1,060.7
======= ======= =======
22
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CAPITAL CONTRIBUTIONS-
A total of $85,000 per Unit, or approximately 57 percent, of
investor subscription had been called through December 31, 2005. 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 1,053.4 Units at December 31, 2005.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
STATEMENT PRESENTATION-
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. 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.
Given the volatility of oil and gas prices, it is reasonably
possible that the Partnership's estimate of discounted future net cash
flows from proved oil and gas reserves could change in the near term. If
oil and gas prices decline significantly, even if only for a short period
of time, it is possible that write-downs of oil and gas properties could
occur in the future.
23
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
REVENUE RECOGNITION-
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, 2005 and 2004, 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, 2005, 2004 and 2003.
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 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.
24
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
----------------------------------------
2005 2004 2003
---- ---- ----
(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 $334 $322 $324
==== ==== ====
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 $ 71 $ 86
==== ==== ====
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.
25
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(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.
2005 2004 2003
--------- --------- ---------
(In thousands)
Oil and Gas Properties
Balance, beginning of year $ 184,066 $ 182,174 $ 179,657
Costs incurred during the year:
Development-
Investing Partners 1,766 1,841 2,154
Managing Partner 44 51 37
Asset retirement cost from adoption of
SFAS No. 143-
Investing Partners - - 323
Managing Partner - - 3
Property sales-
Investing Partners (274) - -
Managing Partners (28) - -
--------- --------- ---------
Balance, end of year $ 185,574 $ 184,066 $ 182,174
========= ========= =========
MANAGING INVESTING
PARTNER PARTNERS TOTAL
--------- --------- ---------
(In thousands)
Accumulated Depreciation, Depletion and Amortization
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
Provision 52 1,988 2,040
--------- --------- ---------
Balance, December 31, 2005 $ 20,892 $ 157,463 $ 178,355
========= ========= =========
The Partnership's aggregate DD&A expense as a percentage of oil and
gas sales for 2005, 2004 and 2003 was 14 percent, 20 percent and 24
percent, respectively.
(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION
Revenues received from major third party customers that exceeded 10
percent of oil and gas sales are discussed below. No other third party
customers individually accounted for more than ten percent of oil and gas
sales.
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.
26
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Sales to Cinergy accounted for 37 percent of the Partnership's oil
and gas sales in 2003. 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.
Sales to Plains Marketing LP accounted for 26 percent and 32 percent
of the Partnership's oil and gas sales in 2005 and 2004, respectively,
while sales to Morgan Stanley Capital Group accounted for 10 percent of
2005 oil and gas sales. Sales to Chevron Texaco accounted for 32 percent
of the Partnership's oil and gas sales in 2003.
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 of $15,185 in 2005. The
Partnership paid the Apache subsidiary transportation fees totaling
$31,008 in 2004 and $43,606 in 2003 for the Partnership's share of gas.
The fees were at the same rates and terms as previously paid to Shell.
All transactions with related parties were consumated at fair value.
The Partnership's revenues are derived principally from
uncollateralized sales to customers in the oil and gas industry;
therefore, customers may be similarly affected by changes in economic and
other conditions within the industry. The Partnership has not experienced
material credit losses on such sales.
(6) FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents, accrued revenues
receivables and accrued costs included in the accompanying balance sheet
approximated their fair values at December 31, 2005 and 2004 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, 2005.
(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,
27
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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:
2005 2004
--------- ---------
Asset retirement obligation at beginning of period $ 858,207 $ 812,520
Liabilities incurred 167,767 -
Liabilities settled (336,100) (6,101)
Accretion expense 45,672 48,744
Revisions in estimated liabilities (35,392) 3,044
--------- ---------
Asset retirement obligation at December 31 $ 700,154 $ 858,207
========= =========
Liabilities settled in 2005 included $168,333 related to the
Partnership's sale of its interest in the South Pass 83 Field.
(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.
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:
2005 2004 2003
------------ ------------ ------------
Net partnership ordinary income for federal income
tax reporting purposes $ 11,103,205 $ 9,993,343 $ 7,846,759
Plus: Items of current (income) expense for tax reporting
purposes only -
Intangible drilling cost 1,318,588 1,457,967 1,358,245
Dismantlement and abandonment cost 167,767 6,101 575,553
Gain on sale of properties (134,060) - -
Tax depreciation 677,643 999,074 867,296
------------ ------------ ------------
2,029,938 2,463,142 2,801,094
------------ ------------ ------------
Less: full cost DD&A expense (2,039,571) (2,816,528) (2,875,896)
Less: asset retirement obligation accretion (45,672) (48,744) (37,605)
Plus: cumulative effect of change in accounting principle - - 302,407
------------ ------------ ------------
Net income $ 11,047,900 $ 9,591,213 $ 8,036,759
============ ============ ============
The Partnership's tax bases in net oil and gas properties at
December 31, 2005 and 2004 was $4,168,176 and $4,351,881, 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,
2005 and 2004.
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,
------------------------
2005 2004
---------- ----------
Liabilities for federal income tax purposes $ 611,889 $ 63,769
Asset retirement liability 700,154 858,207
---------- ----------
Liabilities under accounting principles generally
accepted in the United States $1,312,043 $ 921,976
========== ==========
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)
2005 2004 2003
--------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
---- ------ ---- ------ ---- ------
Proved Reserves
Beginning of year 648 5,244 618 5,992 849 6,339
Extensions, discoveries and other additions 4 147 32 1,027 12 161
Revisions of previous estimates 83 305 134 (377) (112) 924
Production (92) (1,158) (136) (1,398) (131) (1,432)
---- ------ ---- ------ ---- ------
End of year 643 4,538 648 5,244 618 5,992
==== ====== ==== ====== ==== ======
Proved Developed
Beginning of year 648 5,140 618 5,883 849 6,230
==== ====== ==== ====== ==== ======
End of year 643 4,433 648 5,140 618 5,883
==== ====== ==== ====== ==== ======
Oil includes crude oil, condensate and natural gas liquids.
Approximately 69 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,
----------------------------------
2005 2004 2003
-------- -------- --------
(In thousands)
Future cash inflows $ 79,709 $ 58,854 $ 55,014
Future production costs (7,962) (5,943) (5,645)
Future development costs (3,485) (3,571) (3,789)
-------- -------- --------
Net cash flows 68,262 49,340 45,580
10 percent annual discount rate (26,666) (17,590) (14,995)
-------- -------- --------
Discounted future net cash flows $ 41,596 $ 31,750 $ 30,585
======== ======== ========
The following table sets forth the principal sources of change in
the discounted future net cash flows:
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------
2005 2004 2003
-------- -------- --------
(In thousands)
Sales, net of production costs $(13,451) $(12,820) $(11,011)
Net change in prices and production costs 15,482 4,435 3,731
Extensions, discoveries and other additions 1,616 6,331 1,247
Development costs incurred 65 233 490
Revisions of quantities 4,391 1,644 813
Accretion of discount 3,175 3,059 3,083
Changes in future development costs (126) - -
Changes in production rates and other (1,306) (1,717) 1,407
-------- -------- --------
$ 9,846 $ 1,165 $ (240)
======== ======== ========
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)
2005
Revenues $ 3,398 $ 3,366 $ 3,154 $ 4,961 $14,879
Expenses 1,037 899 944 951 3,831
------- ------- ------- ------- -------
Net income $ 2,361 $ 2,467 $ 2,210 $ 4,010 $11,048
------- ------- ------- ------- -------
Net income allocated to:
Managing Partner $ 568 $ 571 $ 515 $ 901 $ 2,555
Investing Partners 1,793 1,896 1,695 3,109 8,493
------- ------- ------- ------- -------
$ 2,361 $ 2,467 $ 2,210 $ 4,010 $11,048
======= ======= ======= ======= =======
Net income per Investing
Partner Unit (1) $ 1,698 $ 1,797 $ 1,606 $ 2,947 $ 8,048
======= ======= ======= ======= =======
2004
Revenues $ 3,257 $ 3,180 $ 3,454 $ 4,022 $13,913
Expenses 1,037 1,052 1,098 1,135 4,322
------- ------- ------- ------- -------
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
======= ======= ======= ======= =======
(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, 2005 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. In September 2005, the SEC further extended the compliance date for U.S.
non-accelerated filers until fiscal years ending on or after July 15, 2007. 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 years ended December 31, 2004
or 2005.
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 2006 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 (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 http://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 Grants Table", "Option/SAR Exercises and Year-End Value
Table", "Employment Contracts and Termination of Employment and
Change-in-Control Arrangements", and "Director Compensation" in the 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,
2005. Directors and officers of Apache own four Units, less than one percent of
the Partnership's Units, as of December 31, 2005. 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 2006 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 27, 2006,
relating to the 2006 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, 2005.
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 10, 2006 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 10, 2006
- -------------------------------------------- Officer and Chief Operating Officer
G. Steven Farris (Principal Executive Officer)
/s/ Roger B. Plank Executive Vice President and Chief March 10, 2006
- -------------------------------------------- Financial Officer (Principal
Roger B. Plank Financial Officer)
/s/ Thomas L. Mitchell Vice President and Controller March 10, 2006
- -------------------------------------------- (Principal Accounting Officer)
Thomas L. Mitchell
NAME TITLE DATE
---- ----- ----
/s/ Raymond Plank Chairman of the Board March 10, 2006
- --------------------------------------------
Raymond Plank
/s/ Frederick M. Bohen Director March 10, 2006
- --------------------------------------------
Frederick M. Bohen
/s/ Randolph M. Ferlic Director March 10, 2006
- --------------------------------------------
Randolph M. Ferlic
/s/ Eugene C. Fiedorek Director March 10, 2006
- --------------------------------------------
Eugene C. Fiedorek
/s/ A. D. Frazier, Jr. Director March 10, 2006
- --------------------------------------------
A. D. Frazier, Jr.
/s/ Patricia Albjerg Graham Director March 10, 2006
- --------------------------------------------
Patricia Albjerg Graham
/s/ John A. Kocur Director March 10, 2006
- --------------------------------------------
John A. Kocur
/s/ George D. Lawrence Director March 10, 2006
- --------------------------------------------
George D. Lawrence
/s/ F. H. Merelli Director March 10, 2006
- --------------------------------------------
F. H. Merelli
/s/ Rodman D. Patton Director March 10, 2006
- --------------------------------------------
Rodman D. Patton
/s/ Charles J. Pitman Director March 10, 2006
- --------------------------------------------
Charles J. Pitman
/s/ Jay A. Precourt Director March 10, 2006
- --------------------------------------------
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 27, 2006, relating to the 2006
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