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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from ________________ to ________________
Commission File Number 0-13546
------------------
APACHE OFFSHORE INVESTMENT PARTNERSHIP
(Exact Name of Registrant as Specified in Its Charter)
Delaware 41-1464066
- ------------------------------- ---------------------
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)
Suite 100, One Post Oak Central
2000 Post Oak Boulevard, Houston, TX 77056-4400
- ---------------------------------------- ----------
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (713) 296-6000
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 [ ]
PART I - FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF INCOME
(UNAUDITED)
FOR THE QUARTER FOR THE NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
------------------------------ -----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
REVENUES:
Oil and gas sales $ 2,938,759 $ 1,668,501 $ 9,145,409 $ 4,786,809
Interest income 8,626 5,574 18,409 15,932
Other revenue 14,567 - 14,567 -
------------- ------------- ------------- -------------
2,961,952 1,674,075 9,178,385 4,802,741
------------- ------------- ------------- -------------
EXPENSES:
Depreciation, depletion and amortization 753,110 589,566 2,198,496 1,578,239
Asset retirement obligation accretion 9,468 - 27,997 -
Lease operating expense 182,551 171,870 632,169 497,208
Gathering and transportation expense 10,115 15,727 99,300 71,264
Administrative 96,000 115,000 306,000 345,000
------------- ------------- ------------- -------------
1,051,244 892,163 3,263,962 2,491,711
------------- ------------- ------------- -------------
OPERATING INCOME BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,910,708 781,912 5,914,423 2,311,030
============= ============= ============= =============
Cumulative effect of change in accounting
principle - - 302,407 -
============= ============= ============= =============
NET INCOME $ 1,910,708 $ 781,912 $ 6,216,830 $ 2,311,030
============= ============= ============= =============
NET INCOME ALLOCATED TO:
Managing Partner $ 508,426 $ 244,735 $ 1,549,814 $ 698,320
Investing Partners 1,402,282 537,177 4,667,016 1,612,710
------------- ------------- ------------- -------------
$ 1,910,708 $ 781,912 $ 6,216,830 $ 2,311,030
============= ============= ============= =============
NET INCOME PER INVESTING PARTNER UNIT $ 1,321 $ 490 $ 4,340 $ 1,461
============= ============= ============= =============
WEIGHTED AVERAGE INVESTING PARTNER
UNITS OUTSTANDING 1,061.7 1,095.2 1,075.4 1,104.0
============= ============= ============= =============
The accompanying notes to financial statements
are an integral part of this statement.
1
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CASH FLOWS
(UNAUDITED)
FOR THE NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------------------
2003 2002
--------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 6,216,830 $ 2,311,030
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,198,496 1,578,239
Asset retirement obligation accretion 27,997 -
Cumulative effect of change in accounting principle (302,407) -
Changes in operating assets and liabilities:
(Increase) decrease in accrued revenues receivable 17,154 (56,114)
Increase (decrease) in accrued operating expenses 24,716 (54,281)
(Increase) decrease in payable to/receivable from
Apache Corporation (142,800) (298,993)
--------------- ---------------
Net cash provided by operating activities 8,039,986 3,479,881
--------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (1,697,747) (2,678,465)
Non-cash portion of oil and gas property additions 49,944 (259,732)
--------------- ---------------
Net cash used in investing activities (1,647,803) (2,938,197)
--------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units (285,936) (134,477)
Distributions to Investing Partners (542,445) -
Distributions to Managing Partner (1,591,827) (689,347)
--------------- ---------------
Net cash used in financing activities (2,420,208) (823,824)
--------------- ---------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,971,975 (282,140)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 915,891 1,883,386
--------------- ---------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 4,887,866 $ 1,601,246
=============== ===============
The accompanying notes to financial statements
are an integral part of this statement.
2
APACHE OFFSHORE INVESTMENT PARTNERSHIP
BALANCE SHEET
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2003 2002
--------------- ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 4,887,866 $ 915,891
Accrued revenues receivable 598,010 615,164
Receivable from Apache Corporation 18,848 -
--------------- ----------------
5,504,724 1,531,055
--------------- ----------------
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties 181,680,382 179,656,827
Less - Accumulated depreciation, depletion and amortization (172,821,289) (171,353,743)
--------------- ----------------
8,859,093 8,303,084
--------------- ----------------
$ 14,363,817 $ 9,834,139
=============== ===============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Distributions payable $ 4,246,868 $ -
Accrued development costs 101,757 51,813
Accrued operating expenses 73,194 48,478
Payable to Apache Corporation - 123,952
--------------- ----------------
4,421,819 224,243
--------------- ----------------
ASSET RETIREMENT OBLIGATION 782,348 -
--------------- ----------------
PARTNERS' CAPITAL:
Managing Partner 175,328 217,341
Investing Partners (1,061.7 and 1,084.9 units outstanding, respectively) 8,984,322 9,392,555
--------------- ----------------
9,159,650 9,609,896
--------------- ----------------
$ 14,363,817 $ 9,834,139
=============== ===============
The accompanying notes to financial statements
are an integral part of this statement.
3
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
The financial statements included herein have been prepared by the Apache
Offshore Investment Partnership (the Partnership), without audit, pursuant to
the rules and regulations of the Securities and Exchange Commission, and reflect
all adjustments which are, in the opinion of management, necessary for a fair
statement of the results for the interim periods, on a basis consistent with the
annual audited financial statements. All such adjustments are of a normal,
recurring nature. Certain information, accounting policies, and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted pursuant to such
rules and regulations, although the Partnership believes that the disclosures
are adequate to make the information presented not misleading. These financial
statements should be read in conjunction with the financial statements and the
summary of significant accounting policies and notes thereto included in the
Partnership's latest annual report on Form 10-K.
1. RECEIVABLE FROM/PAYABLE TO APACHE CORPORATION
The receivable from/payable to Apache Corporation, the Partnership's
managing partner (Apache or the Managing Partner), 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 of operations are determined.
2. RIGHT OF PRESENTMENT
As provided in the Partnership Agreement, as amended (the Amended
Partnership Agreement), a first right of presentment offer for 2003 of $12,047
per Unit, plus interest to the date of payment, was made to Investing Partners
in April 2003, based on a valuation date of December 31, 2002. As a result, the
Partnership purchased 23.14 Units in June for a total of $285,936. A second
right of presentment offer for 2003 of $9,512 per Unit, plus interest to the
date of payment, was made to the Investing Partners on October 24, 2003, based
on a valuation date of June 30, 2003. The Investing Partners have until the
close of business on November 24, 2003 to present their Units for repurchase by
the Partnership. The Partnership will determine by December 15, 2003, whether or
not to accept each Unit offered during this election period.
The Partnership is not in a position to predict how many Units will be
presented for repurchase during the fourth quarter of 2003 and cannot, at this
time, determine if the Partnership will have sufficient funds available to
repurchase any Units. The Partnership has no obligation to purchase any Units
presented to the extent it determines that it has insufficient funds for such
purchases. The Amended Partnership Agreement contains limitations on the number
of Units that the Partnership can repurchase, including a limit of 10 percent of
the outstanding Units on an annual basis.
3. NEW ACCOUNTING PRONOUCEMENTS
Effective January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations," which resulted in an increase to net oil and gas properties of
$1.1 million and additional liabilities related to asset retirement obligations
of $.8 million. These entries reflect the asset retirement obligation of the
Partnership had the provisions of SFAS No. 143 been applied since inception.
This resulted in a cumulative-effect increase in net income of $.3 million.
Since January 1, 2003, the asset retirement obligation liability has increased
by accretion totaling $27,997.
Prior to adoption of this statement, such obligations were accrued ratably
over the productive lives of the assets through its depreciation, depletion and
amortization for oil and gas properties; therefore, had SFAS No. 143 not been
adopted, net income during the third quarter and first nine months of 2003 would
not have been materially different. In addition, the net income impact of
applying SFAS No. 143 to the comparable periods in 2002 would not have resulted
in a material difference. If SFAS No. 143 had been adopted effective January 1,
2002, the liability as of that date would have been approximately $.7 million.
4
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
NET INCOME AND REVENUE
The Partnership earned $1.9 million during the third quarter of 2003, more
than double the net income reported in the third quarter a year ago on the
strength of higher prices and production. Net income per Investing Partner Unit
increased to $1,321 in the third quarter of 2003 from $490 in the third quarter
of 2002.
Net income for the first nine months of 2003, including the cumulative
effect of a change in accounting principle, totaled $6.2 million or $4,340 per
Investing Partner Unit. Net income for the same period in 2002 totaled $2.3
million, or $1,461 per Investing Partner Unit. Current net income before the
change in accounting principle was 156 percent over the same period of 2002 on
higher oil and gas prices and production.
Total revenues for the third quarter increased 76 percent from a year ago,
from $1.7 million in 2002 to $3.0 million in 2003. For the nine months ending
September 30, 2003, revenues were $9.2 million or almost twice the revenues for
the same period in 2002 on higher oil and gas prices and production.
The Partnership's oil and gas production volume and price information is
summarized in the following table (gas volumes presented in thousand cubic feet
(Mcf) per day):
FOR THE QUARTER ENDED SEPTEMBER 30, FOR THE NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------- ----------------------------------------
INCREASE INCREASE
2003 2002 (DECREASE) 2003 2002 (DECREASE)
---------- ---------- ---------- ---------- ---------- ------------
Gas volume - Mcf per day 4,125 3,094 33% 3,989 3,313 20%
Average gas price - per Mcf $ 5.13 $ 3.26 57% $ 5.83 $ 3.08 89%
Oil volume - barrels per day 366 297 23% 336 301 12%
Average oil price - per barrel $ 29.43 $ 27.14 8% $ 30.43 $ 24.30 25%
THIRD QUARTER 2003 COMPARED TO THIRD QUARTER 2002
Natural gas production revenues for the third quarter of 2003 totaled $1.9
million, up 110 percent from the third quarter of 2002. Natural gas prices for
the third quarter of 2003 increased 57 percent compared to the year-earlier
period. The $1.87 per Mcf increase in gas prices from a year ago boosted sales
by approximately $.5 million. Natural gas volumes on a daily basis increased 33
percent from a year ago as a result of recompletion activities at South
Timbalier 295 during 2003 and drilling in the field in 2002. The South Timbalier
295 B-4, B-5 and B-6 wells were brought on production during the second half of
2002. Also, production at North Padre Island 969 was shut-in for nearly all of
the first nine months of 2002 for a dispute with a pipeline company on increased
fees charged for the transportation of natural gas. The dispute was resolved in
the producers' favor in August 2002 with only a slight increase in
transportation rates from the field, and production from the North Padre Island
Field resumed in late September 2002.
The Partnership's crude oil production revenues for the third quarter of
2003 totaled $1.0 million, a 34 percent increase from the third quarter of 2002.
Oil production was 23 percent higher than a year ago as recompletions and
workovers at South Timbalier 295 during 2003 and drilling in the field during
2002 boosted oil revenues $.2 million. A $2.29 per barrel, or eight percent,
increase in the Partnership's average realized oil price increased oil revenues
by approximately $.1 million.
YEAR-TO-DATE 2003 COMPARED TO YEAR-TO-DATE 2002
Gas sales for the first nine months of 2003 of $6.4 million increased $3.5
million, or 128 percent, when compared to the same period in 2002. The
Partnership's average realized gas prices increased $2.75 per Mcf, when compared
with the first nine months of 2002, positively impacting sales by $2.5 million.
Daily gas production for the first nine months of 2003 also increased 20 percent
when compared to the same period in 2002, increasing revenues by $1.0 million.
Production increases in 2003 are a result of successful recompletions on South
Timbalier 295 during the first nine months of 2003 and a full nine months of
production from North Padre 969 during 2003.
5
For the nine months ended September 30, 2003, oil sales increased 40
percent from a year ago to $2.8 million. The Partnership's oil sales revenues
were favorably impacted by a 25 percent increase in the average realized oil
price and a 12 percent increase in oil production, which increased sales by $.5
million and $.3 million, respectively. The increase in oil production is a
result of the successful recompletions and workover at South Timbalier 295
during 2003.
Declines in oil and gas production can be expected in future periods due to
natural depletion. Given the small number of producing wells owned by the
Partnership, and their natural depletion, the Partnership's future production
will be subject to more volatility than those companies with greater reserves
and longer-lived properties.
The Partnership reported other revenues of $14,567 during the current
quarter for the final settlement of business interruption claims related to
Hurricane Lili in 2002.
OPERATING EXPENSES
The Partnership's depreciation, depletion and amortization (DD&A) rate,
expressed as a percentage of oil and gas sales, was approximately 26 percent
during the third quarter of 2003 compared to 35 percent during the same period
in 2002. This decline in rate reflected the impact of higher oil and gas prices
in the current year. The Partnership's total DD&A expense increased primarily as
a result of higher volumes sold in 2003. The Partnership recognized $9,468 of
accretion expense on the asset retirement obligation during the third quarter of
2003 and $27,997 for the first nine months of 2003.
Lease operating expense (LOE) in the third quarter of 2003 increased six
percent from the third quarter of 2002 as a result of higher overall repair and
maintenance costs in 2003 and higher costs at North Padre Island 969 compared to
2002. Operations and costs in the field were sustained at a reduced level in
2002 while shut-in during the dispute between the producers and a pipeline
company (as referenced above under the "Third Quarter 2003 Compared to Third
Quarter 2002" discussion of natural gas production revenues).
During the nine months of 2003, LOE totaled $.6 million, up 27 percent over
the same period the year before. The increase is attributable to workover costs
incurred on the South Timbalier 295 A-21 well during the first quarter of 2003,
higher overall repair and maintenance costs in 2003 and higher costs at North
Padre Island 969 compared to 2002.
Gathering and transportation costs include amounts paid by the Partnership
to third parties to transport oil and gas to a purchaser-specified delivery
point. Such costs vary based on the volume and distance shipped, and the fee
charged by the transporter, which may be price sensitive. The transportation
cost may also vary from period to period based on marketing and delivery options
utilized by the Partnership to realize the highest net price (gross price less
transportation) for either oil or gas. Gathering and transportation costs during
the first nine months of 2003 increased from the comparable period in 2002
primarily as a result of increased volumes from South Timbalier 295 and North
Padre Island 969, and delivery options utilized for Matagorda Island 681/682.
CASH FLOW, LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES AND LIQUIDITY
The Partnership's primary capital resource is net cash provided by
operating activities, which totaled $8.0 million for the first nine months of
2003. Net cash provided by operating activities in 2003 was more than twice the
$3.5 million reported a year ago, reflecting increases in oil and gas prices and
production from 2002. Future cash flows will be influenced by fluctuations in
product prices, production levels and operating costs.
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 66 percent of the Partnership's production for
the nine months of 2003 and 55 percent of total proved reserves at
6
December 31, 2002, on an energy equivalent basis, the Partnership is affected
more by fluctuations in natural gas prices than in oil prices.
The Partnership's oil and gas reserves and production will also
significantly impact future results of operations and cash from operating
activities. The Partnership's production is subject to fluctuations in response
to remaining quantities of oil and gas reserves, weather, pipeline capacity,
consumer demand, mechanical performance and workover, recompletion and drilling
activities. Declines in oil and gas production can be expected in future years
as a result of normal depletion and the Partnership not participating in
acquisition or exploration activities. Based on production estimates from
independent engineers and current market conditions, the Partnership expects it
will be able to meet its liquidity needs for routine operations in the
foreseeable future. The Partnership will reduce capital expenditures and
distributions to partners as cash from operating activities declines.
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
costs.
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 September 30, 2003.
During the first nine months of 2003, the Partnership's oil and gas
property additions totaled $1.7 million as the Partnership participated in nine
recompletions at South Timbalier Block 295. The Partnership did not participate
in drilling any new wells during the first nine months of 2003. Based on
information supplied by the operators of the properties, the Partnership
anticipates capital expenditures of approximately $.3 million for the remainder
of 2003, primarily for recompletions at South Timbalier Block 295. Such
estimates may change based on realized prices, drilling results or changes by
the operator to the development plan.
On March 5, 2003, the Partnership paid distributions to Investing Partners
totaling $.5 million, or $500 per Investing Partner unit. The Partnership did
not make a cash distribution to Investing Partners during the first nine months
of 2002. The Partnership declared a distribution of $4,000 per Investing Partner
unit on September 18, 2003, that was paid to Unitholders on October 9, 2003. The
amount of future distributions will be dependent on actual and expected
production levels, realized and expected oil and gas prices, expected drilling
and recompletion expenditures, and prudent cash reserves for future
dismantlement and abandonment costs that will be incurred after the
Partnership's reserves are depleted.
As provided in the Amended Partnership Agreement, a first right of
presentment offer for 2003 of $12,047 per Unit, plus interest to the date of
payment, was made to Investing Partners in April 2003, based on a valuation date
of December 31, 2002. As a result, the Partnership purchased 23.14 Units in June
2003 for a total of $285,936. A second right of presentment offer for 2003 of
$9,512 per Unit, plus interest to the date of payment, was made to the Investing
Partners on October 24, 2003, based on a valuation date of June 30, 2003. The
Investing Partners have until the close of business on November 24, 2003 to
present their Units for repurchase by the Partnership. The Partnership will
determine by December 15, 2003, whether or not to accept each Unit offered
during this election period.
The Partnership is not in a position to predict how many Units will be
presented for repurchase during the fourth quarter of 2003 and cannot, at this
time, determine if the Partnership will have sufficient funds available to
repurchase any Units. The Partnership has no obligation to purchase any Units
presented to the extent it determines that it has insufficient funds for such
purchases. The Amended Partnership Agreement contains limitations on the number
of Units that the Partnership can repurchase, including a limit of 10 percent of
the outstanding Units on an annual basis.
Effective July 1, 2003, the Managing Partner acquired from Shell
Exploration and Production Company (Shell) interests in certain producing
properties in the Gulf of Mexico and two onshore gas plants for $200 million in
cash. The purchase price is subject to normal post closing adjustments. Prior to
the transaction between Apache and Shell, Morgan Stanley Capital Group, Inc.
paid Shell $300 million in cash to acquire an overriding royalty interest in a
7
portion of the reserves to be produced over four years. The impact of these
transactions on the Partnership is not known at this time.
In conjunction with the Shell transaction, Apache acquired Shell's interest
in the Ship Shoal 259 field. As an interest-owner in that field, the Partnership
held a preferential right to purchase the acquired interest for $22.7 million.
The Partnership waived that right.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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. The Partnership has not used derivative
financial instruments or otherwise engaged in hedging activities during 2002 or
the first nine months of 2003.
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 expects that the sales prices it
will receive for future natural gas sales will be comparable to prices that
would have been received from Cinergy.
The information set forth under "Commodity Risk" in Item 7A of the
Partnership's Form 10-K for the year ended December 31, 2002, is incorporated by
reference. Information about market risks for the current quarter is not
materially different.
ITEM 4 - CONTROLS AND PROCEDURES
G. Steven Farris, the Managing Partner's President, Chief Executive Officer
and Chief Operating Officer, and Roger B. Plank, the Managing Partner's
Executive Vice President and Chief Financial Officer, evaluated the
effectiveness of the Partnership's disclosure controls and procedures within the
last 90 days preceding the date of this report. Based on that review and as of
the date of that evaluation, the Partnership's disclosure controls were found to
be adequate, providing effective means to insure that the Partnership timely and
accurately disclose the information it is required to disclose under applicable
laws and regulations. Also, we made no significant changes in the Partnership's
internal controls or any other factors that could affect the Partnership's
internal controls since our most recent internal controls evaluation.
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 on certain events, risks and
uncertainties that may be outside the Partnership's control, and which could
cause actual results to differ materially from those anticipated. Some of these
include, but are not limited to, the market prices of oil and gas, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, political and economic uncertainties of foreign
governments, future business decisions, and other uncertainties, all of which
are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
timing of development expenditures. The total amount or timing of actual future
production may vary significantly from reserves and production estimates. The
drilling of exploratory wells can involve significant risks, including those
related to timing, success rates 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.
8
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. CHANGES IN SECURITIES
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
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
b. Reports filed on Form 8-K - None.
9
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
Dated: November 13, 2003 /s/ Roger B. Plank
---------------------------------------
Roger B. Plank
Executive Vice President and
Chief Financial Officer
Dated: November 13, 2003 /s/ Thomas L. Mitchell
---------------------------------------
Thomas L. Mitchell
Vice President and Controller
(Chief Accounting Officer)
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
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