APACHE OFFSHORE INVESTMENT PARTNERSHIP - 10-Q Quarterly Report

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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 June 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)

The accompanying notes to financial statements
are an integral part of this statement.

1

APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CASH FLOWS
(UNAUDITED)

The accompanying notes to financial statements
are an integral part of this statement.

2

APACHE OFFSHORE INVESTMENT PARTNERSHIP
BALANCE SHEET
(UNAUDITED)

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.

Reclassifications -

Certain prior period amounts have been reclassified to conform with current
year presentations.

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 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. The Investing
Partners will have second right of presentment during the fourth quarter of 2003
based on a valuation date of June 30, 2003.

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 $18,529.

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 second quarter and first six 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 $2 million during the second quarter of 2003, more
than double the net income reported in the second quarter a year ago on the
strength of higher prices and production. Net income per Investing Partner Unit
increased to $1,348 in the second quarter of 2003 from $570 in the second
quarter of 2002.

Net income for the first half of 2003, including the cumulative effect of a
change in accounting principle, totaled $4.3 million or $3,016 per Investing
Partner Unit. Net income for the same period in 2002 totaled $1.5 million or
$970 per Investing Partner Unit. Current net income before the change in
accounting principle was 162 percent over the same period of 2002 on higher oil
and gas prices and production.

Total revenues for the second quarter increased 69 percent from a year ago,
increasing from $1.8 million in 2002 to $3.0 million in 2003. For the six months
ending June 30, 2003, revenues were $6.2 million or 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):

SECOND QUARTER 2003 COMPARED TO SECOND QUARTER 2002

Natural gas production revenues for the second quarter of 2003 totaled $2.1
million, up 94 percent from the second quarter of 2002. Natural gas prices for
the second quarter of 2003 increased 58 percent compared to the year-earlier
period. The $2.06 per Mcf increase in gas prices from a year ago boosted sales
by approximately $.6 million. Natural gas volumes on a daily basis increased 23
percent from a year ago as a result of recompletion activities at South
Timbalier 295 during 2003 and drilling in the field in 2002. Also, production at
North Padre Island 969 was shut-in during all of the second quarter 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.

The Partnership's crude oil production revenues for the second quarter of
2003 totaled $.9 million, a 29 percent increase from the second quarter of 2002.
A $3.76 per barrel, or 15 percent, increase in the Partnership's average
realized oil price increased oil revenues by $.1 million. Oil production was 12
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
another $.1 million.

YEAR-TO-DATE 2003 COMPARED TO YEAR-TO-DATE 2002

Gas sales for the first half of 2003 of $4.4 million increased $2.5
million, or 137 percent, when compared to the same period in 2002. The
Partnership's average realized gas prices increased $3.21 per Mcf, when compared
with the first six months of 2002, positively impacting sales by $2.0 million.
Daily gas production for the first half of 2003 also increased 14 percent when
compared to the same period in 2002, increasing revenues by $.5 million.
Production increases in 2003 are a result of successful recompletions on South
Timbalier 295 during the first half of 2003 and a full six months of production
from North Padre 969 during 2003.

5

For the six months ended June 30, 2003, oil sales increased 43 percent from
a year ago to $1.8 million. The Partnership's oil sales revenues were favorably
impacted by a 35 percent increase in the average realized oil price and a six
percent increase in oil production, which increased sales by $.4 million and $.1
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.

OPERATING EXPENSES

The Partnership's depreciation, depletion and amortization (DD&A) rate,
expressed as a percentage of oil and gas sales, was approximately 23 percent
during the second quarter of 2003 compared to 34 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 DD&A expense increased primarily as a
result of higher volumes sold in 2003. The Partnership recognized $9,332 of
accretion expense on the asset retirement obligation during the second quarter
of 2003 and $18,529 for the first six months of 2003.

Lease operating expense (LOE) in the second quarter of 2003 increased 28
percent from the second 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 pipeline
company.

During the first half of 2003, LOE totaled $.4 million, up 38 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 second quarter and first six months of 2003 increased from the comparable
periods 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 $5.3 million for the first six months of
2003. Net cash provided by operating activities in 2003 was more than twice the
$2.2 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 67 percent of the Partnership's production for
the first half of 2003 and 55 percent of total proved reserves at 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

6

of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical
performance and workover, recompletion and drilling activities. Declines in oil
and gas production can be expected in future years as a result of normal
depletion and the Partnership not participating in acquisition or exploration
activities. Based on production estimates from independent engineers and current
market conditions, the Partnership expects it will be able to meet its liquidity
needs for routine operations in the foreseeable future. The Partnership will
reduce capital expenditures and distributions to partners as cash from operating
activities decline.

In the event that future short-term operating cash requirements are greater
than the Partnership's financial resources, the Partnership may seek short-term,
interest-bearing advances from the Managing Partner as needed. The Managing
Partner, however, is not obligated to make loans to the Partnership.

On an ongoing basis, the Partnership reviews the possible sale of lower
value properties prior to incurring associated dismantlement and abandonment
cost.

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 June 30, 2003.

During the first six months of 2003, the Partnership's oil and gas property
additions totaled $1.2 million as the Partnership participated in recompletions
at South Timbalier Block 295. Expenditures were primarily for recompletion costs
on the South Timbalier A-9, A-17 and A-24 wells during the first quarter and the
A-5, A-14, A-15 and A-31 wells during the second quarter of this year. The
Partnership did not participate in drilling any new wells during the first six
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 half of
2002. The amount of future distributions will be dependent on actual and
expected production levels, realized and expected oil and gas prices, expected
drilling and recompletion expenditures, and prudent cash reserves for future
dismantlement and abandonment costs that will be incurred after the
Partnership's reserves are depleted. Based on available cash balances and
projections of the above items for the second half of 2003, the Partnership
anticipates it will make a distribution to Investing Partners in the fourth
quarter of 2003.

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. The Investing Partners will have second right of
presentment during the fourth quarter of 2003 based on a valuation date of June
30, 2003.

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
portion of the reserves to be produced over four years. The impact of these
transactions on the Partnership is not known at this time.

7

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 six 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: August 13, 2003 /s/ Roger B. Plank
-----------------------------------------
Roger B. Plank
Executive Vice President and Chief
Financial Officer

Dated: August 13, 2003 /s/ Thomas L. Mitchell
-----------------------------------------
Thomas L. Mitchell
Vice President and Controller
(Chief Accounting Officer)

EXHIBIT INDEX

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