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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010


o		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


Delaware		41-1464066
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)

Registrant’s telephone number, including area code: (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 o No þ

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 o No þ

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T ((§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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. o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act


Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (Do not check if smaller reporting company)		Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o No þ

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30,


2010		$15,620,308

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Apache Corporation’s proxy statement relating to its 2011 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		8
2. PROPERTIES		8
3. LEGAL PROCEEDINGS		11

PART II

5. MARKET FOR THE PARTNERSHIP’S SECURITIES AND RELATED SECURITY HOLDER MATTERS		12
6. SELECTED FINANCIAL DATA		12
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		13
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		20
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		23
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		41
9A. CONTROLS AND PROCEDURES		41
9B. OTHER INFORMATION		41

PART III

10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP		42
11. EXECUTIVE COMPENSATION		42
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		42
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		42
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		42

PART IV

15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K		43
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-99.1

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, a Delaware general partnership (the Investment Partnership), was formed on October 31, 1983, consisting of Apache Corporation, a Delaware corporation, (Apache or Managing Partner), as Managing Partner and public investors (the Investing Partners). The Investment Partnership invested its entire capital in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership (the Operating Partnership), of which Apache is the sole general partner and the Investment Partnership is the sole limited partner. The primary business of the Investment Partnership is to serve as the sole limited partner of the Operating Partnership. The primary business of the Operating Partnership is to conduct oil and gas exploration, development and production operations. The Operating Partnership conducts the operations of the Investment Partnership.

The Investment Partnership does not maintain its own website. However, copies of this Form 10-K and the Partnership’s periodic filings with the Securities and Exchange Commission (SEC) can be found on the Managing Partner’s website at www.apachecorp.com/Offshore_Investment_Partnership. The Investment Partnership will also 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’ principal executive officer and principal financial officer that are required by applicable laws and regulations. Any requests to the Partnership for copies of documents filed with the SEC should be made by mail to Apache Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas 77056, Attention: Glenn Hitchcock, or by telephone at 713-296-7097. The Partnership’s reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

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, 2010, 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 Operating Partnership. As used hereafter, the term “Partnership” refers to either the Investment Partnership or the Operating Partnership, as the case may be.

The Partnership’s business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. Except for the Matagorda Island Block 681 and 682 interests, as described below, the Partnership acquired its oil and gas interests through the purchase of 85 percent of the working interests held by Apache as a participant in a venture (the Venture) with Shell Oil Company (Shell) and certain other companies. The Partnership owns working interests ranging from 6.29 percent to 7.08 percent in the Venture’s properties.

The Venture acquired substantially all of its oil and gas properties through bidding for leases offered by the federal government. The Venture members relied on Shell’s knowledge and expertise in determining bidding strategies for the acquisitions. When Shell was successful in obtaining the properties, it generally billed participating members on a promoted basis (one-third for one-quarter) for the acquisition of exploratory leases and on a straight-up basis for the acquisition of leases defined as drainage tracts. All such billings were proportionately reduced to each member’s working interest.

In November 1992, Apache and the Partnership formed a joint venture to acquire Shell’s 92.6 percent working interest in Matagorda Island Blocks 681 and 682 pursuant to a jointly-held contractual preferential right to purchase. Apache and the Partnership previously owned working interests in the blocks equal to 1.109 percent and 6.287 percent, respectively, and net revenue interests of .924 percent and 5.239 percent, respectively. To facilitate the acquisition, Apache and the Partnership contributed all of their interests in Matagorda Island Blocks 681 and 682 to a newly formed joint venture, and Apache contributed $64.6 million ($55.6 million net of purchase price adjustments) to the joint venture to finance the acquisition. The Partnership had neither the cash nor additional financing to fund a proportionate share of the acquisition and participated through an increased net revenue interest in the joint venture.

Under the terms of the joint venture agreement, the Partnership’s effective net revenue interest in the Matagorda Island Block 681 and 682 properties increased to 13.284 percent as a result of the acquisition, while its working interest was unchanged. The acquisition added approximately 7.5 Bcf of natural gas and 16 Mbbls of oil to the Partnership’s reserve base without any incremental expenditures by the Partnership.

Since the Venture is not expected to acquire any additional exploratory acreage, future acquisitions, if any, will be confined to those leases defined as drainage tracts. The current Venture members would pay their proportionate share of acquiring any drainage tracts on a non-promoted basis.

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.

2010 Results and Business Development

The Partnership reported net income in 2010 of $1.6 million, or $1,065 per Investing Partner Unit. Earnings were up $0.2 million, or 17 percent, from 2009 on higher oil and gas prices and lower operating expenses. The Partnership’s average realized oil price increased 33 percent from a year ago to $76.78 per barrel, while the Partnership’s average realized natural gas price increased 20 percent to $4.68 per mcf. Natural gas production averaged 1,647 Mcf per day in 2010, up 13 percent from 2009 with a full year’s production from Matagorda Island 681/682. The Partnership’s average daily oil production declined 52 percent from 2009 as the Partnership’s largest oil-producing field, South Timbalier 295, was shut-in for nearly half of 2010.

The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the field may be shut-in until April 2011 as a new sales line is built to restore production. Production from the field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. The shut-in of the South Timbalier 295 production significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2010.

Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $2.5 million in 2011 for drilling at Ship Shoal 258/259, completion of the new sales line at South Timbalier 295 and recompletions at North Padre Island 969/976. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by contractors or changes by the operator to the development plan.

Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2010, 45 of those prospects have been surrendered or sold. As of December 31, 2010, the Partnership had 35 producing wells on the Partnership’s four remaining developed fields. Four of the Partnership’s producing wells are dual completions. The Partnership had, at December 31, 2010, estimated proved oil and gas reserves of 5.7 Bcfe.

Marketing

Apache, on behalf of the Partnership, seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. The objective is to maximize the value of the crude oil or natural gas sold by identifying the best markets and most economical transportation routes available to move the oil or natural gas. The oil contracts are generally thirty (30) day evergreen contracts and renew automatically until cancelled by either party. These contracts provide for sales that are priced daily at prevailing market prices. The Partnership’s oil and condensate production during 2010 was purchased largely by Shell Trading Company at market prices.

The Managing Partner markets the Partnership’s and its own U.S. natural gas production. The Partnership’s natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, and integrated major oil companies. Most of Apache’s and the Partnership’s natural gas is sold on a monthly basis at either monthly or daily market prices. The Partnership believes that the sales prices it receives for natural gas sales are market prices.

See Note (5) “Major Customer and Related Parties Information” to the Partnership’s financial statements under Item 8. Because the Partnership’s oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse affect on the Partnership’s business or results of operations.

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.

Future economic conditions in the U.S. and key international markets may materially adversely impact the Partnership’s operating results.

The U.S. and other world economies are slowly recovering from a recession that began in 2008 and extended into 2009. Growth has resumed but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than we have experienced in recent years. In addition, more volatility may occur before a sustainable growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for the Partnership’s crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.

Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results.

The Partnership’s revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2010 ranged from a high of $92.89 per barrel to a low of $68.10 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond the Partnership’s control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

	•		worldwide and domestic supplies of crude oil and natural gas;

	•		actions taken by foreign oil and gas producing nations;

	•		political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;

	•		the level of global crude oil and natural gas inventories;

	•		the price and level of imported foreign crude oil and natural gas;

	•		the price and availability of alternative fuels, including coal and biofuels;

	•		the availability of pipeline capacity and infrastructure;

	•		the availability of crude oil transportation and refining capacity;

	•		weather conditions;

	•		electricity generation;

	•		domestic and foreign governmental regulations and taxes; and

	•		the overall economic environment.

Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:

	•		limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;

	•		reducing the amount of crude oil and natural gas that we can produce economically;

	•		causing us to delay or postpone some of our capital projects;

	•		reducing our revenues, operating income and cash flows;

	•		a reduction in the carrying value of our crude oil and natural gas properties; or

Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

A portion of our natural gas and oil production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

The shut-in of production from our South Timbalier 295 field could have a material adverse effect on our business, financial condition or results of operations.

Production from the South Timbalier 295 field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. Production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the shut-in may be for a lengthy period of time waiting on regulatory approvals for the required work and for completion of the new sales line. If we are unable to receive regulatory approvals for the completion of the work in a timely manner or if the work is not completed for an extended period, this shut-in could have a material adverse effect on the Partnership’s financial position, results of operations and our cash flows.

Weather and climate change may have a significant adverse impact on our revenues and productivity.

Demand for oil and natural gas is, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. Our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather, and not all such effects can be predicted, eliminated or insured against.

Declining commodity prices may require the Partnership to reduce capital expenditures or distributions to partners, or both, as cash from operating activities decline.

The Partnership is not likely to make any distributions to Investing Partners during 2011 as a result of capital outlays for drilling at Ship Shoal 258/259 and the completion of a new oil sales line at South Timbalier 295. If commodity prices remain at or decline from levels realized in 2010, the Partnership may not be able to make any distributions to Investing Partners during 2012. Declines in cash from operating activities may reduce funds available for capital expenditures.

We are exposed to counterparty credit risk as a result of our receivables.

The Partnership is exposed to risk of financial loss from trade, joint venture and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. Some of our purchasers and non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.

The Partnership may not realize an adequate return on its drilling activities.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we participate in may not be productive and we may not recover all or any portion of our investment in those wells. 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

	•		increase in cost of, or shortages or delays in the delivery of equipment.

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. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Partnership is not likely to participate in exploratory drilling at this time.

Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which the Partnership adopted effective December 31, 2009, our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:

	•		historical production from the area compared with production from other areas;

	•		the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reserves reporting requirements;

	•		assumptions concerning future crude oil and natural gas prices;

	•		future operating costs;

	•		development costs; and

	•		workover and remediation costs.

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

The Partnership may incur significant costs related to environmental matters.

As an owner or lessee of interests in oil and gas properties, the Partnership 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. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations.

Our operations are subject to governmental risks that may impact our operations.

Our operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection laws and regulations. Such regulations may adversely impact our results on operations.

Proposed regulations related to emissions and the impact of any changes in climate could adversely impact our business.

While legislation is not currently pending in the United States, there has been discussion regarding legislation or regulation of greenhouse gas (GHG). Any such legislation, if enacted, could tax or assess some form of GHG related fees on the Partnership’s operations and could lead to increased operating expenses. Such legislation, if enacted, could also potentially cause the Partnership to make significant capital investments for infrastructure modifications.

Furthermore, various governmental entities have discussed regulatory initiatives that could, if adopted, require the Partnership to modify existing or planned infrastructure to meet GHG emissions performance standards and necessitate significant capital expenditures. At some level, the cost of performance standards may force the early retirement of smaller production facilities, which in the aggregate may have a material adverse effect on the Partnership’s business.

Several indirect consequences of regulation and business trends have potential to impact us. Taxes or fees on carbon emissions could lead to decreased demand for fossil fuels. Consumers may prefer alternative products and unknown technological innovations may make oil and gas less significant energy sources.

In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact the Partnership’s assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.

Proposed federal regulation regarding hydraulic fracturing could increase our operating and capital costs.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. The Partnership may use fracturing techniques to expand the available space for natural gas to migrate toward the well-bore. It is typically done at substantial depths in very tight formations.

Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.

Oil and gas operations involve a high degree of operational risk, particularly risk of personal injury, damage or loss of equipment and environmental accidents.

The Partnership’s operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:

	•		drilling well blowouts, explosions and cratering;

	•		pipeline ruptures and spills;

	•		fires;

	•		formations with abnormal pressures;

	•		equipment malfunctions; and

	•		hurricanes which could affect our operations in the Gulf of Mexico, as well as other natural disasters.

Failure or loss of equipment, as the result of equipment malfunctions or natural disasters, could result in property damages, personal injury, environmental pollution and other damages for which the Partnership could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a well blowout or pipeline rupture could result in environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flow and, in turn, our results of operations could be materially and adversely affected.

Any additional drilling laws and regulations, delays in the processing and approval of permits and other related developments in the Gulf of Mexico resulting from the Deepwater Horizon incident could adversely affect the Partnership’s business.

As has been widely reported, in April 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which lead to a significant oil spill that affected the Gulf of Mexico. In response to this incident, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) of the U.S. Department of the Interior (DOI) ceased issuing drilling permits pursuant to a series of moratoria, and all deepwater drilling activities in progress were suspended. Although the moratoria have been lifted, the DOI has not issued any permits related to the drilling of new exploratory wells in the deepwater Gulf of Mexico as of January 31, 2011. In 2010 the DOI issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to regulate drilling activities and increase liability.

In January 2011, the President’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government require additional regulation and an increase in liability caps. Additional legislation or regulation is being discussed which could require companies operating in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility, a certificate required by the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual insurance fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.

The BOEMRE is expected to continue to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. We are monitoring legislation and regulatory developments; however, it is difficult to predict the ultimate impact of any new guidelines, regulations or legislation. A prolonged suspension of drilling activity in the U.S. and new regulations and increased liability for companies operating in this sector could adversely affect the Partnership’s operations.

We have limited control over the activities on properties we do not operate.

Other companies operate the properties in which we have an interest. The Partnership has limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of projected costs and future cash flow.

The Partnership faces significant industry competition.

The Partnership is a very minor participant 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.

Insurance policies do 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. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The Partnership had no comments from the staff of the SEC that were unresolved as of the date of filing of this report.

ITEM 2. PROPERTIES

Acreage

Acreage is held by the Partnership pursuant to the terms of various leases on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The Partnership does not anticipate any difficulty in retaining any of its leases. A summary of the Partnership’s gross and net acreage as of December 31, 2010, 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	TX		10,840		681

			46,061		3,096

At December 31, 2010, 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, 2010, is set forth below:


		Gas				Oil
Lease Block	State	Gross		Net		Gross		Net
Ship Shoal 258, 259	LA		6		.38		—		—
South Timbalier 276, 295, 296	LA		1		.07		18		1.27
North Padre Island 969, 976	TX		6		.43		—		—
Matagorda Island 681, 682	TX		4		.25		—		—

			17		1.13		18		1.27

Net Wells Drilled

The following table shows the results of the oil and gas wells drilled and tested for each of the last three fiscal years:


	Net Exploratory						Net Development
Year	Productive		Dry		Total		Productive		Dry		Total
2010		—		—		—		.07		—		.07
2009		—		—		—		—		—		—
2008		—		—		—		—		.07		.07

Production and Pricing Data

The following table provides, 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 Lease		Average Sales Price
	Oil		NGLs		Gas		Operating		Oil		NGLs		Gas
Year Ended December 31,	(Mbbls)		(Mbbls)		(MMcf)		Cost per Mcfe		(Per bbl)		(Per bbl)		(Per Mcf)
2010
South Timbalier 295		16		1		28	$	3.01	$	76.62	$	51.21	$	5.29
Other fields		1		2		573		1.66		78.65		49.49		4.65

Total		17		3		601	$	1.90	$	76.78	$	50.21	$	4.68

2009
South Timbalier 295		34		4		61	$	1.57	$	57.25	$	31.90	$	4.04
Other fields		2		2		470		2.19		64.36		32.35		3.87

Total		36		6		531	$	1.96	$	57.60	$	32.07	$	3.89

2008
South Timbalier 295		29		3		54	$	1.69	$	110.58	$	59.85	$	9.24
Other fields		2		3		414		1.83		111.25		60.94		8.89

Total		31		6		468	$	1.78	$	110.61	$	60.32	$	8.93

The South Timbalier 295 field contains more than 15 percent of the Partnership’s proved reserved, expressed on an oil-equivalent-barrels basis. No other field contained 15 percent or more of the Partnership’s proved reserves as of December 31, 2010.

Estimated Proved Reserves and Future Net Cash Flows

Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set for the by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries—Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved

reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGL’s that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Reserve estimates are considered proved if they are economical producible and are supported by either actual production or conclusive formation tests. Estimated 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 active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.

As of December 31, 2010, the Partnership had total estimated proved reserves of 486,768 barrels of crude oil and condensate, 74,480 barrels of NGLs and 2.4 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 5.7 Bcf of gas. The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.

The following table shows proved oil, NGL and gas reserves as of December 31, 2010, based on commodity average prices in effect on the first day of each month in 2010, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.


	Oil		NGL		Gas
	(Mbbls)		(Mbbls)		(MMcf)
Proved developed		487		74		2,249
Proved undeveloped						105

Total proved		487		74		2,354

The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2010, 2009 and 2008, 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 2010 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows as of December 31, 2010 and 2009 were calculated using a discount rate of 10 percent per annum, end of period costs, and average commodity prices in effect on the first day of each month, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. Future net cash flows as of December 31, 2008, were estimated using commodity prices in effect at the end of those years, in accordance with the SEC guidelines in effect prior to the issuance of the Modernization Rules.

As of December 31, 2010, the Partnership had one undrilled location classified as proved undeveloped. The location is in North Padre Island 969/976 and is scheduled to be drilled within the next five years. The Partnership carried proved undeveloped reserves of 0.1 Bcf at both December 31, 2010 and 2009.

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 utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. A copy of Ryder Scott’s report on the Shell Offshore Venture, of which the partnership owns approximately 85 percent, is filed as an exhibit to this Form 10-K.

The primarily technical person responsible for overseeing the preparation of the Partnership’s reserve estimates is Mrs. Jennifer A. Fitzgerald, a Vice President with Ryder Scott. Mrs. Fitzgerald has more than nine years of industry experience and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

At least annually, each property is reviewed in detail by Apache’s centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. Apache’s engineers furnish this information and estimates of dismantlement and abandonment cost to Ryder Scott for their consideration in preparing the Partnership’s reserve reports. The internal property reviews and collection of data provided to Ryder Scott is overseen by Apache’s Executive Vice President of Corporate Reservoir Engineering.

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.

PART II

ITEM 5. MARKET FOR THE PARTNERSHIP’S SECURITIES AND RELATED SECURITY HOLDER MATTERS

As of December 31, 2010, there were 1,021.5 of the Partnership’s Units outstanding held by 869 Investing Partners of record. The Partnership has no other class of security outstanding or authorized. The Units are not traded on any security market. No distributions were made to Investing Partners during 2010 or 2009.

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.

On June 6, 2008, certain affiliates of MacKenzie Patterson Fuller, LP (Purchasers) announced a tender offer to purchase up to 207 Units for $13,850 per Unit, less the amount of any distributions declared or made with respect to the Units between June 6, 2008 and July 18, 2008 (the offer expiration date). After resolution of an issue regarding an improperly submitted Unit, the offer resulted in the tender, and the acceptance for payment by the Purchasers, of a total of 6.1728 Units. Upon completion of the offer, the Purchasers hold an aggregate of 6.1728 Units, or approximately 0.6 percent of the total Investing Partner outstanding Units.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2010, should be read in conjunction with the Partnership’s financial statements and related notes included under Item 8 below of this Form 10-K.


	As of or For the Year Ended December 31,
	2010		2009		2008		2007		2006
	(In thousands, except per Unit amounts)
Total assets	$	10,992	$	8,236	$	6,680	$	8,308	$	8,629

Partners’ capital	$	7,483	$	6,086	$	5,191	$	6,960	$	7,625

Oil and gas sales	$	4,270	$	4,311	$	7,928	$	7,679	$	10,255

Net income	$	1,555	$	1,332	$	5,335	$	4,834	$	7,149

Net income allocated to:
Managing Partner	$	467	$	447	$	1,229	$	1,146	$	1,702
Investing Partners		1,088		885		4,106		3,688		5,447

	$	1,555	$	1,332	$	5,335	$	4,834	$	7,149

Net income per Investing Partner Unit	$	1,065	$	867	$	3,976	$	3,531	$	5,178

Cash distributions per Investing Partner Unit	$	—	$	—	$	5,500	$	4,000	$	7,500

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 participant 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’s focus on production activities and development of existing leases.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, and the Risk Factors information set forth in Part I, Item 1A of this Form 10-K.

The Partnership derives its revenue from the production and sale of crude oil, natural gas and natural gas liquids (NGLs). With only modest levels of production from current wells, the Partnership sells its production at market prices and has not used derivative financial instruments or otherwise engaged in hedging activities. During 2010, the Partnership benefited from higher market prices as its average realized oil and gas prices increased 33 percent and 20 percent, respectively from a year ago. Prices in recent year, however, have remained volatile and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate widely over the years.

While oil prices increased during 2010, the Partnership was unable to fully recognize potential benefits as the Partnership’s largest oil-producing field was shut-in for nearly half of the year. The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the field may be shut-in until the second quarter of 2011 as a new sales line is built to restore production. Production from the field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. The shut-in of the South Timbalier 295 production significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2010.

The Partnership participates in development drilling and recompletion activities as recommended by outside operators and the Partnership’s Managing Partner. During 2010, the Partnership’s oil and gas property expenditures totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. The Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 during 2010 and began the installation of new equipment at South Timbalier 295 as part of the new oil sales line tie-in.

Generally, the Partnership has used its available cash to fund distributions to its Partners. With the shut-in of the South Timbalier 295 field for nearly half of 2010 and the Partnership’s participation in drilling and recompletion projects during the year, the Partnership did not make any distributions to the Investing Partners during 2010. No distributions to Investing Partners were made in 2009 with the shut-in of the Matagorda Island 681/682 production, low oil and gas prices and an increase in the Partnership cash reserves for higher asset retirement obligation (ARO) liabilities.

We do not anticipate that the Partnership will make any distributions to Investing Partners during 2011 as the Partnership plans to participate in drilling wells at Ship Shoal 258/259 during 2011 and maintain cash reserves for future ARO expenditures. The timing of when distributions will be reinstated is dependent upon oil and gas prices realized by the Partnership for the sale of its production, the timing of when the South Timbalier 295 field is returned to production and the level of drilling and recompletion activity in 2011 and 2012.

Results of Operations

This section includes a discussion of the Partnership’s results of operations, and items contributing to changes in revenues and expenses during 2010, 2009, and 2008.

Net Income and Revenue

The Partnership reported net income of $1.6 million for 2010, up 17 percent from 2009 on higher oil and gas prices. Net income per Investing Partner Unit increased in 2010 to $1,065, up from $867 in 2009. The Partnership reported earnings of $1.3 million in 2009 and $5.3 million in 2008.

Total revenues in 2010 of $4.3 million were essentially even with 2009 as higher oil and gas prices offset the impact of lower oil production. Interest income earned by the Partnership on short-term cash investments in 2010 of $77 decreased from 2009 as a result of lower interest rates in 2010. Interest income totaled $229 in 2009 and $46,193 in 2008.

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 its control. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on the prices received for the Partnership’s 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 drilling will take place on leases in which the Partnership currently holds interests.

The Partnership’s oil, gas and natural gas liquids (NGL) production volume and price information is summarized in the following table:


	For the Year Ended December 31,
			Increase					Increase
	2010		(Decrease)			2009		(Decrease)			2008
Gas volumes — Mcf per day		1,647		+13	%		1,455		+14	%		1,277
Average gas price — per Mcf	$	4.68		+20	%	$	3.89		-56	%	$	8.93
Oil volumes — barrels per day		47		-52	%		98		+17	%		84
Average oil price — per barrel	$	76.78		+33	%	$	57.60		-48	%	$	110.61
NGL volumes — barrels per day		8		-50	%		16		n/a	%		16
Average NGL price — per barrel	$	50.21		+57	%	$	32.07		-47	%	$	60.32

Natural Gas Sales

2010 vs. 2009 Natural gas sales for 2010 increased 36 percent from a year ago, rising to $2.8 million in the current period. A 20 percent increase in the Partnership’s average gas price increased sales by $0.4 million while a 13 percent increase in natural gas volumes during 2010 boosted sales by $0.3 million. The Partnership’s average realized gas prices increased to $4.68 per Mcf in 2010 from $3.89 per Mcf in 2009. The Partnership’s gas production in 2009 was hindered by the shut-in of Matagorda Island 681/682 for repairs to a third-party pipeline. The full year’s production at Matagorda 681/682 in 2010 boosted sales volumes by 406 Mcf per day over 2009, more than offsetting impact of the shut-in of production at South Timbalier 295 in 2010 and natural depletion at Ship Shoal 258/259 and North Padre Island 969/976.

2009 vs. 2008 The Partnership’s natural gas sales in 2009 totaled $2.1 million or 51 percent less than reported in 2008. During 2009, the partnership’s average realized natural gas price declined $5.04 per Mcf, or 56 percent, from 2008 and reduced sales by nearly $2.4 million. Production increases from 2008 offset $0.2 million of the impact of lower prices. Average daily production in 2009 increased 14 percent from 2008, rising to 1,455 Mcf per day in 2009. The increase in natural gas volumes reflected successful recompletions at Matagorda Island 681/682 during the second half of 2008 and at North Padre Island 969/976 during 2009, successful workover projects performed in 2009, and reduced downtime for inclement weather. Further increase in production was thwarted by the downtime at Matagorda Island 681/682 during 2009 for third-party pipeline repairs.

Crude Oil Sales

2010 vs. 2009 Crude oil sales for 2010 decreased 36 percent from a year ago, decreasing from $2.0 million in 2009 to $1.3 million in 2010. The Partnership’s crude oil volumes decreased from 98 barrels per day during 2009 to 47 barrels per day during 2010 as a result of the third-party pipeline shut-in of South Timbalier 295. The lower volumes reduced sales by $1.4 million. A $19.18 per barrel increase in oil prices from a year ago raised sales by $0.7 million, which partially offset the 51 barrel per day decline in production. The Partnership’s average realized price for the oil during 2010 increased 33 percent from 2009, rising to $76.78 per barrel in 2010.

2009 vs. 2008 Crude oil sales in 2009 dropped 39 percent from the $3.4 million of oil sales reported in 2008. A $53.01 per barrel, or 48 percent, decline in average realized oil price from 2008 drove the decline in sales. A $1.6 million decline in sales from lower prices was partially offset by $0.3 million of production increases. The Partnership’s 2009 crude oil sales volumes increased 17 percent from 2008, rising to 35,742 barrels of oil per day in 2009. The increase in production reflected less downtime at South Timbalier 295 for inclement weather and third-party pipeline repairs.

NGL Sales

The Partnership sold 8 barrels per day of NGL in 2010, down from 16 barrels per day in 2009. The decrease reflected lower production from South Timbalier 295 during 2010. NGL volumes also totaled 16 barrels per day in 2008. NGL prices declined 47 percent from 2008 to 2009 with the decline in oil prices and then increased 57 percent in 2010 with the resurgence in oil prices.

Operating Expenses

2010 vs. 2009 The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 19 percent during 2010, down from 22 percent in 2009. The decrease in rate as a percentage of oil and gas sales was driven by higher oil and gas prices in 2010. Lease operating expense (LOE) decreased 15 percent over the previous year on lower workover and repair and maintenance costs. During 2010, the Partnership participated in repairs at Matagorda Island 681/682, North Padre Island 969/976, Ship Shoal 258/259 and South Timbalier 295. Gathering and transportation costs increased from 2009 levels reflecting the increase in sales volumes in 2010 at Matagorda Island 681/682 and new marketing arrangements for North Padre Island 969 where the Partnership pays for its transportation cost instead of receiving a gas sales price which is net of transportation. Administrative expense for the year decreased slightly from 2009 to $403,000.

2009 vs. 2008 The Partnership’s DD&A rate, expressed as a percentage of oil and gas sales, was approximately 22 percent during 2009, up from 11 percent in 2008. The increase in rate as a percentage of oil and gas sales was driven by lower oil and gas prices in 2009. DD&A on an absolute basis increased as a result of increased production and higher plugging and dismantlement cost. LOE increased 25 percent over the previous year on higher workover and repair and maintenance costs. During 2009, the Partnership participated in workovers at North Padre Island 969/976, Ship Shoal 258/259 and South Timbalier 295. LOE for the period also included repairs to a compressor on the South Timbalier 295 platform and maintenance cost at Matagorda Island 681/682. LOE for 2009 excludes $64,605 of expected insurance reimbursement for Hurricane Ike damage. The repair cost subject to insurance reimbursement is primarily for a gathering line at Ship Shoal 258/259 and for handrail, grating and decking repairs on various platforms. Gathering and transportation costs increased from 2008 levels reflecting the increase in sales volumes in 2009. Administrative expense for the year decreased slightly from 2008 to $418,000.

The Partnership sells oil and natural gas under two types of transactions, both of which include a transportation charge. One is a netback arrangement, under which the Partnership sells oil or natural gas as 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 costs.

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.5 million for 2010. The Partnership’s 2010 net cash provided by operating activities increased $0.5 million from 2009 on increased earnings and reduced receivables. Net cash provided by operating activities in 2009 of $2.0 million decreased 69 percent from 2008 as a result of oil and gas prices dropping 48 percent and 56 percent, respectively, from 2008. A $.3 million increase in lease operating expense in 2009 also contributed to net cash provided by operating activities declining from 2008.

At December 31, 2010, the Partnership had approximately $3.0 million in cash and cash equivalents, up from slightly more than $2.0 million at December 31, 2009. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the value of its future asset retirement obligations (ARO) and to participate in future drilling and recompletion opportunities. The Partnership increased its cash balances during 2010 as a reserve for the higher projected ARO and to fund capital expenditures projected for the first half of 2011.

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.

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.

Approximately 75 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, 2010. The Partnership’s liquidity may be negatively impacted if the actual quantities 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. The Partnership does not intend to incur debt from banks or other outside sources or solicit capital from exiting Unit holders or in the open market.

On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment cost. The Partnership did not sell any properties in 2010, 2009 or 2008.

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, 2010. The Partnership did not have any contractual obligations as of December 31, 2010, 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 the ARO as discussed under the discussion of critical accounting policies noted below.

During 2010, the Partnership’s oil and gas property expenditures totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. During the year, the Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 and began the installation of new equipment at South Timbalier 295 as part of the new sales line tie-in. While all of the recompletions during 2010 were successful, the South Timbalier 295 wells remained shut-in with the rest of the field while the Partnership worked on installing a new oil sales line. During 2009, the Partnership’s oil and gas property expenditures totaled $0.6 million. The Partnership participated in two recompletions in the North Padre Island 969/976 field and one recompletion at Matagorda Island 681/682 during the year. During 2008, the Partnership’s oil and gas property expenditures totaled $1.0 million. The Partnership participated in drilling one well in the North Padre Island 969/976 Field during 2008. The well was unsuccessful in its initial evaluation, and Apache and the Partnership elected not to participate in a sidetrack well proposed by the operator. The Partnership also participated in recompletions at Matagorda 681/682 and South Timbalier 295 during 2008.

No distributions were paid to Investing Partners during 2010 or 2009 as a result of the shut-in of production for extended periods of time during the period and cash requirements for drilling, recompletion and repair activities. Distributions of $5,500 per Unit were made to Partners during 2008 resulting in total distributions to Limited Partners of $5.7 million in 2008. 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.

We do not anticipate that the Partnership will make any distribution to Investing Partners in 2011 as a result of planned capital outlays for drilling and recompletion activities during 2011 and the continued shut-in of South Timbalier 295 while a new oil sales line is being constructed. Once oil production has resumed at South Timbalier 295, the Partnership will need to replenish its cash reserve for future plugging and abandonment expenditures. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the value of its future asset retirement obligations.

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 2010 and 2009, the Partnership did not offer to purchase any Units from Investing Partners as a result of the limited amount of cash available for discretionary purposes. In 2008, Investing Partners were paid $228,995, respectively, for a total of 16.7 Units.

There will be two rights of presentment in 2011, 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. The Partnership is not likely to have funds available to repurchase Units during 2011.

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.

Insurance

The Managing Partner maintains insurance coverage that includes coverage for physical damage to the Partnership’s oil and gas properties, third party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. The insurance coverage includes deductibles which must be met prior to recovery. Additionally, the Managing Partner’s insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

The Managing Partner’s various insurance policies also provide coverage for, among other things, liability related to negative environmental impacts of a sudden pollution, charterer’s legal liability and general liability, employer’s liability and auto liability. The Managing Partner’s service agreements, including drilling contracts, generally indemnify Apache and the Partnership for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

In light of the recent catastrophic accident in the Gulf of Mexico, the Managing Partner and the Partnership may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

Critical Accounting Policies and Estimates

The Partnership prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and accompanying notes. Management identifies certain accounting policies as critical based on, among other things, their impact on the Partnership’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their development. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Following is a discussion of Partnership’s most critical accounting policies:

Reserve Estimates

Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set forth by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries—Oil and Gas". The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.

Despite the inherent imprecision in these engineering estimates, the Partnership’s reserves have a significant impact on its financial statements. For example, the quantity of reserves could significantly impact the Partnership’s DD&A expense. The Partnership’s oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. These reserves are the basis for our supplemental oil and gas disclosures.

Reserves as of December 31, 2010 and 2009 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of production, except where prices are defined by contractual arrangements. Reserves as of December 31, 2008 were estimated using prices in effect at the end of those years, in accordance with SEC guidance in effect prior to the issuance of the Modernization Rules.

The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.

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 (ARO)

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.

Asset retirement obligations associated with retiring tangible long-lived assets, are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable. This liability is offset by a corresponding increase in the carrying amount of the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Partnership’s oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.

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. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, weather and climate, and governmental risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

The Partnership’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to the Partnership’s natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. During 2010, monthly oil price realizations ranged from a low of $60.51 per barrel to a high of $84.09 per barrel. Gas price realizations ranged from a monthly low of $3.57 per Mcf to a monthly high of $6.67 per Mcf during the same period. Based on the Partnership’s average daily production for 2010, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $17,000 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 $60,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2010. Due to the volatility of commodity prices, the Partnership is not in a position to predict future oil and gas prices.

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2010, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

	•		the market prices of oil, natural gas, NGLs and other products or services;

	•		the supply and demand for oil, natural gas, NGLs and other products or services;

	•		production and reserve levels;

	•		drilling risks;

	•		economic and competitive conditions;

	•		the availability of capital resources;

	•		capital expenditure and other contractual obligations;

	•		weather conditions;

	•		inflation rates;

	•		the availability of goods and services;

	•		legislative or regulatory changes;

	•		terrorism;

	•		the capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and

	•		other factors disclosed under Items 1 and 2 — “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A — “Risk Factors,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this Form 10-K.

All subsequent written and oral forward-looking statements attributable to the Partnership, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

ADDITIONAL INFORMATION ABOUT THE PARTNERSHIP

Remediation Plans and Procedures

The Partnership’s Managing Partner adopted a Region Spill Response Plan for its Gulf of Mexico operations to ensure a rapid and effective response to spill events that may occur on Apache-operated properties. The Partnership does not operate any properties for itself or others. Periodically, drills are conducted by Apache to measure and maintain the effectiveness of its plan. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache in the event of a spill is CGA. Apache has received approval for its plan from the Bureau of Ocean Energy Management, Regulatory and Enforcement (formerly, the Minerals Management Service). Apache personnel review the plan annually and update where necessary.

As part of our Region Spill Response Plan, the Managing Partner is a member of, and has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine Preservation Association. MSRC maintains CGA’s equipment (including skimmers, fast response vessels, fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies which provide support services during spill response. In the event of a spill, MSRC will activate these contracts as necessary to provide additional resources or support services requested by its customers. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), which provides aircrafts and dispersant capabilities for CGA member companies.

In the event that CGA and MSRC resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited is the world’s largest oil spill preparedness and response organization, dedicated to providing resources to respond to oil spills efficiently and effectively on a global basis. In addition, resources of other organizations are available to Apache as a non-member, such as those of National Response

Corporation (NRC) and MSRC, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels and dispersant aircraft. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland work boats, vacuum transfer units and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time-to-time and current information is generally available on each of the companies’ websites.

In light of the current events in the Gulf of Mexico, Apache is participating in a number of industry-wide task forces, which are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties, the Partnership is subject to numerous federal, state and local 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, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

The Partnership has made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. The Managing Partner has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to the Partnership’s operations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, the Partnership does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures or earnings.

Changes to existing, or additions of, laws, regulations, enforcement policies or requirements could require the Partnership to make additional capital expenditures. While the events in the U.S. Gulf of Mexico in 2010 have resulted in the enactment of, and may result in the enactment of additional, laws or requirements regulating the discharge of materials into the environment, we do not believe that any such regulations or laws enacted or adopted as of this date will have a material adverse impact on the Partnership’s cost of operations or earnings.


ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

APACHE OFFSHORE INVESTMENT PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS


	Page
	Number
Report of Management on Internal Control over Financial Reporting		24

Report of Independent Registered Public Accounting Firm		25

Statement of Consolidated Income for each of the three years in the period ended December 31, 2009		26

Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2010		27

Consolidated Balance Sheet as of December 31, 2010 and 2009		28

Statement of Consolidated Changes in Partners’ Capital for each of the three years in the period ended December 31, 2010		29

Notes to Consolidated Financial Statements		30

Supplemental Oil and Gas Disclosures		38

Supplemental Quarterly Financial Data		40

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.

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Partnership is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.

Management of the Partnership is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (Exchange Act). The Partnership’s and Managing Partner’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by the Managing Partner’s board of directors, applicable to all the Managing Partner’s directors, officers and employees.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2010.


	G. Steven Farris Chairman and Chief Executive Officer (principal executive officer) of Apache Corporation, Managing Partner


	Thomas P. Chambers Executive Vice President and Chief Financial Officer (principal financial officer) of Apache Corporation, Managing Partner


	Rebecca A. Hoyt Vice President, Chief Accounting Officer and Controller (principal accounting officer) of Apache Corporation, Managing Partner

Houston, Texas
February 28, 2011

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) as of December 31, 2010 and 2009, 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, 2010. 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.

As discussed in Note 2 to the consolidated financial statements, in 2009, the Partnership adopted SEC Release 33-8995 and the amendments to ASC Topic 932, “Extractive Industries — Oil and Gas,” resulting from ASU 2010-03 (collectively, the Modernization Rules).

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Offshore Investment Partnership at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.


	ERNST & YOUNG LLP

Houston, Texas
February 28, 2011

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED INCOME


	For the Year Ended December 31,
	2010		2009		2008
REVENUES:
Oil and gas sales	$	4,270,245	$	4,310,969	$	7,927,690
Interest income		77		229		46,193


		4,270,322		4,311,198		7,973,883


OPERATING EXPENSES:
Depreciation, depletion and amortization		822,053		960,632		901,633
Asset retirement obligation accretion		118,557		67,297		63,489
Lease operating expenses		1,229,104		1,445,122		1,153,688
Gathering and transportation costs		142,737		88,064		69,022
Administrative		403,000		418,000		451,154


		2,715,451		2,979,115		2,638,986


NET INCOME	$	1,554,871	$	1,332,083	$	5,334,897


NET INCOME ALLOCATED TO:
Managing Partner	$	466,589	$	446,888	$	1,228,783
Investing Partners		1,088,282		885,195		4,106,114


	$	1,554,871	$	1,332,083	$	5,334,897


NET INCOME PER INVESTING PARTNER UNIT	$	1,065	$	867	$	3,976


WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING		1,021.5		1,021.5		1,032.7

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CASH FLOWS


	For the Year Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,554,871		$	1,332,083		$	5,334,897
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		822,053			960,632			901,633
Asset retirement obligation accretion		118,557			67,297			63,489
Dismantlement and abandonment cost		(180,941	)		(37,720	)		—
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables		81,532			(13,594	)		31,441
Increase (decrease) in accrued operating expense		3,389			7,799			(139,712	)
Change in receivable/payable from Apache Corporation		145,885			(329,519	)		195,645


Net cash provided by operating activities		2,545,346			1,986,978			6,387,393


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(2,590,734	)		(610,279	)		(956,051	)
Increase (decrease) in accrued development cost and drilling payables		1,126,540			(22,629	)		22,629


Net cash used in investing activities		(1,464,194	)		(632,908	)		(933,422	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Repurchase of Partnership Units		—			—			(228,995	)
Distributions to Investing Partners		—			—			(5,679,725	)
Distributions to Managing Partner		(157,664	)		(437,273	)		(1,195,521	)


Net cash used in financing activities		(157,664	)		(437,273	)		(7,104,241	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		923,488			916,797			(1,650,270	)

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		2,048,412			1,131,615			2,781,885


CASH AND CASH EQUIVALENTS, END OF YEAR	$	2,971,900		$	2,048,412		$	1,131,615

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

CONSOLIDATED BALANCE SHEET


	December 31,
	2010			2009
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	2,971,900		$	2,048,412
Accrued revenues receivable		238,431			319,734
Accrued insurance receivable		24,449			24,678
Receivable from Apache Corporation		—			82,902

		3,234,780			2,475,726


OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties		191,277,205			188,458,320
Less — Accumulated depreciation, depletion and amortization		(183,520,231	)		(182,698,178	)

		7,756,974			5,760,142

	$	10,991,754		$	8,235,868


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accrued operating expense	$	109,794		$	106,405
Accrued development cost		520,950			—
Payable to Apache Corporation		668,573			—

		1,299,317			106,405


ASSET RETIREMENT OBLIGATION		2,209,662			2,043,895


COMMITMENTS AND CONTINGENCIES (Note 7)

PARTNERS’ CAPITAL:
Managing Partner		383,005			74,080
Investing Partners (1,021.5 Units outstanding)		7,099,770			6,011,488

		7,482,775			6,085,568

	$	10,991,754		$	8,235,868

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL


	Managing Partner			Investing Partners			Total
BALANCE, DECEMBER 31, 2007	$	31,203		$	6,928,899		$	6,960,102

Distributions		(1,195,521	)		(5,679,725	)		(6,875,246	)

Repurchase of Partnership Units		—			(228,995	)		(228,995	)

Net income		1,228,783			4,106,114			5,334,897


BALANCE, DECEMBER 31, 2008	$	64,465		$	5,126,293		$	5,190,758

Distributions		(437,273	)		—			(437,273	)

Net income		446,888			885,195			1,332,083


BALANCE, DECEMBER 31, 2009	$	74,080		$	6,011,488		$	6,085,568

Distributions		(157,664	)		—			(157,664	)

Net income		466,589			1,088,282			1,554,871


BALANCE, DECEMBER 31, 2010	$	383,005		$	7,099,770		$	7,482,775

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION

Nature of Operations

Apache Offshore Investment Partnership, a Delaware general partnership (the Investment Partnership), was formed on October 31, 1983, consisting of Apache Corporation (Apache or Managing Partner) as Managing Partner and public investors (the Investing Partners). The Investment Partnership invested its entire capital in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership (the Operating Partnership). The primary business of the Investment Partnership is to serve as the sole limited partner of the Operating Partnership. The primary business of the Operating Partnership is to conduct oil and gas exploration, development and production operations. The Operating Partnership conducts the operations of the Investment Partnership. The accompanying financial statements include the accounts of both the Investment Partnership and Operating Partnership. Apache is the general partner of both the Investment and Operating partnerships, and held approximately five percent of the 1,021.5 Investing Partner Units (Units) outstanding at December 31, 2010. The term “Partnership”, as used hereafter, refers to the Investment Partnership or the Operating 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 (over the same period, 45 of those prospects have been surrendered/sold). The Partnership’s working interests in the four remaining venture prospects range from 6.29 percent to 7.08 percent. As of December 31, 2010, the Partnership held a remaining interest in nine tracts acquired through federal lease sales.

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.

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 Partnership.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Right of Presentment

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. The Partnership did not offer to purchase any Units from Investing Partners in either 2010 or 2009 as a result of the limited amount of cash available for discretionary purposes. In 2008, Investing Partners were paid $228,995, respectively, for a total of 16.7 Units.

The Partnership is not in a position to predict how many Units will be presented for repurchase during 2010; 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 Valuation		Valuation Price Per
Valuation Date	Price		Unit
December 31, 2007		15,806,599		13,225
June 30, 2008		17,239,136		13,245
December 31, 2008		9,701,665		9,497
June 30, 2009		8,864,008		8,677
December 31, 2009		15,742,174		15,411
June 30, 2010		16,477,118		16,130


Investing Partner Units Outstanding:	2010		2009		2008
Balance, beginning of year		1,021.5		1,021.5		1,038.2
Repurchase of Partnership Units		—		—		(16.7	)


Balance, end of year		1,021.5		1,021.5		1,021.5

Capital Contributions

A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2010. 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 1,021.5 Units at December 31, 2010.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by the Partnership reflect industry practices and conform to accounting principles generally accepted in the United States (GAAP). Significant policies are discussed below.

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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. 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 the unaudited “Supplemental Oil and Gas Disclosures” below), asset retirement obligations and contingency obligations.

Cash Equivalents

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2010 and 2009, the Partnership had $3.0 and $2.0 million of cash equivalents.

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 of accounting, 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. The Partnership includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance as described in Note 8. 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.

Under the full-cost method of accounting, 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. This ceiling test is performed each quarter. 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

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

The estimate of future net cash flows as of December 31, 2010 and 2009, were calculated using a discount rate of 10 percent per annum, end-of-period costs, and an unweighted arithmetic average commodity prices in effect on the first day of each month, held flat for the life of production, except where prices are defined by contractual arrangements. Prior to adoption of the Modernization Rules, estimated future net cash flows were calculated using commodity prices in effect at the end of each quarter.

Asset Retirement Obligation

The initial estimated asset retirement obligation (ARO) related to properties is recognized as a liability, with an associated increase in property and equipment for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

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 collectability 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, 2010 and 2009, the Partnership did not have any liabilities for 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, 2010 and 2009.

Insurance Coverage

The Partnership recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

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.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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.

Maintenance and Repairs

Maintenance and repairs are charged to expense as incurred.

Recently Issued Accounting Standards Not Yet Adopted

All new accounting pronouncements previously issued have been adopted as of or prior to December 31, 2010.

(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,
		2010		2009		2008
		(In thousands)
a.	Apache is reimbursed for general, administrative and
	overhead expenses incurred in connection with the
	management and operation of the Partnership's business	$	322	$	334	$	361


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	$	53	$	30	$	26

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.

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.


	2010		2009		2008
	(In thousands)
Oil and Gas Properties

Balance, beginning of year	$	188,458	$	186,955	$	185,999
Costs incurred during the year:
Development —
Investing Partners		2,735		1,407		939
Managing Partner		84		96		17


Balance, end of year	$	191,277	$	188,458	$	186,955

Development cost for 2009 includes $.9 million of asset retirement cost.


	Managing		Investing
	Partner		Partners		Total
	(In thousands)
Accumulated Depreciation, Depletion and Amortization

Balance, December 31, 2007	$	20,897	$	159,939	$	180,836
Provision		16		886		902


Balance, December 31, 2008	$	20,913	$	160,825	$	181,738
Provision		18		942		960


Balance, December 31, 2009	$	20,931	$	161,767	$	182,698
Provision		21		801		822


Balance, December 31, 2010	$	20,952	$	162,568	$	183,520

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2010, 2009 and 2008 was 19 percent, 22 percent and 11 percent, respectively.

(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

Revenues received from major third party customers that equaled ten percent or more of oil and gas sales are discussed below. No other third party customers individually accounted for ten percent or more of oil and gas sales.

In 2010, sales to Shell Trading Company, Florida Power Corporation and Sequent Energy Management LP accounted for 30 percent, 16 percent and 10 percent, respectively, of the Partnership’s oil and gas sales for the year. Sales to Shell Trading Company accounted for 48 percent of the Partnership’s oil and gas sales in 2009. Sales to Shell Trading Company and Plains Marketing LP accounted for 27 percent and 16 percent, respectively, of the Partnership’s oil and gas sales in 2008.

Effective November 1992, with Apache’s and the Partnership’s acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees totaling $40,562 in 2010, $24,210 in 2009 and $19,124 in 2008 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 consummated at fair value.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2010 and 2009 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, 2010.

(7) COMMITMENTS AND CONTINGENCIES

Litigation — The Partnership 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

The following table is a reconciliation of the Partnership’s ARO liability for the years ended December 31, 2010 and 2009:


	2010			2009
Asset retirement obligation at beginning of period	$	2,043,895		$	1,121,808
Accretion expense		118,557			67,297
Liabilities settled		(180,941	)		(37,720	)
Revisions in estimated liabilities		228,151			892,510


Asset retirement obligation at December 31	$	2,209,662		$	2,043,895

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Partnership’s oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. 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.

Liabilities settled primarily relate to individual wells plugged and abandoned during the periods presented. Revisions to estimated liabilities in 2009 reflected the Managing Partner’s updated estimates of the extent of the work required and cost involved in the dismantlement and site reclamation of offshore properties, and shorter reserve lives projected for certain of the Partnership’s properties.

In September 2010 the Bureau of Ocean Management, Regulation and Enforcement (BOEMRE, formerly known as the Minerals Management Service), a division of the U.S. Department of the Interior, issued Notice to Lessees (NTL) No. 2010-G05, which includes guidelines for decommissioning idle infrastructure on active leases in the Gulf of Mexico within a specified period of time. During 2010, the Partnership adjusted the timing of its abandonment program accordingly.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) 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:


	2010			2009			2008
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	(25,363	)	$	1,464,728		$	5,184,702

Plus: Items of current expense for tax reporting purposes only —
Intangible drilling cost		2,142,424			579,318			851,644
Dismantlement and abandonment cost		180,941			37,720			—
Tax depreciation		197,479			278,246			263,673

		2,520,844			895,284			1,115,317


Less: full cost DD&A expense		(822,053	)		(960,632	)		(901,633	)
Less: asset retirement obligation accretion		(118,557	)		(67,297	)		(63,489	)


Net income	$	1,554,871		$	1,332,083		$	5,334,897

The Partnership’s tax bases in net oil and gas properties at December 31, 2010 and 2009 was $5,696,154 and $3,950,153, 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, 2010 and 2009.

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,
	2010		2009
Liabilities for federal income tax purposes	$	1,299,317	$	106,405
Asset retirement liability		2,209,662		2,043,895


Liabilities under accounting principles generally accepted in the United States	$	3,508,979	$	2,150,300

Asset retirement liabilities for future dismantlement and abandonment costs are not recognized for federal income tax reporting purposes until settled.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)

Oil and Gas Reserve Information

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)


	2010						2009						2008
	Oil			Gas			Oil			Gas			Oil			Gas
Proved Reserves

Beginning of year		555			2,427			492			2,422			571			3,004
Extensions, discoveries and other additions		15			111			—			—			—			—
Revisions of previous estimates		11			417			105			536			(42	)		(114	)
Production		( 20	)		( 601	)		( 42	)		( 531	)		( 37	)		( 468	)


End of year		561			2,354			555			2,427			492			2,422


Proved Developed

Beginning of year		555			2,322			492			2,317			571			2,899


End of year		561			2,249			555			2,322			492			2,317

Oil includes crude oil, condensate and natural gas liquids.

All the Partnership’s reserves are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas.

Approximately 75 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.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(UNAUDITED)

Future Net Cash Flows

Future cash inflows as of December 31, 2010 and 2009 were calculated using an average of oil and gas prices in effect on the first day of each month, except where prices are defined by contractual arrangements. Future cash inflows as of December 31, 2008 were estimated using oil and gas prices in effect at the end of those years, except where prices are defined by contractual arrangements, in accordance with SEC guidance in effect prior to the issuance of the Modernization Rules. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. 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,
	2010			2009			2008
				(In thousands)
Future cash inflows	$	52,801		$	40,838		$	36,059
Future production costs		(10,290	)		(7,499	)		(7,580	)
Future development costs		(5,689	)		(6,026	)		(4,136	)

Net cash flows		36,822			27,313			24,343
10 percent annual discount rate		(17,783	)		(12,760	)		(8,312	)

Discounted future net cash flows	$	19,039		$	14,553		$	16,031

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2010			2009			2008
				(In thousands)
Sales, net of production costs	$	(2,898	)	$	(2,778	)	$	(6,705	)
Net change in prices and production costs		3,857			797			(13,629	)
Revisions of quantities		1,923			4,439			(1,083	)
Discoveries and improved recoveries, net of cost		1,292			—			—
Accretion of discount		1,455			1,603			3,190
Changes in future development costs		336			(843	)		285
Changes in production rates and other		(1,479	)		(4,696	)		2,074

	$	4,486		$	(1,478	)	$	(15,868	)

APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)


	First		Second		Third		Fourth			Total
	(In thousands, except per Unit amounts)
2010
Revenues	$	1,724	$	1,337	$	596	$	613		$	4,270
Expenses		787		653		558		717			2,715

Net income (loss)	$	937	$	684	$	38	$	(104	)	$	1,555

Net income (loss) allocated to:
Managing Partner	$	253	$	181	$	30	$	3		$	467
Investing Partners		684		503		8		(107	)		1,088

	$	937	$	684	$	38	$	(104	)	$	1,555

Net income (loss) per Investing Partner Unit (1)	$	669	$	493	$	8	$	(105	)	$	1,065

2009
Revenues	$	1,131	$	759	$	1,074	$	1,347		$	4,311
Expenses		832		696		716		735			2,979

Net income	$	299	$	63	$	358	$	612		$	1,332

Net income allocated to:
Managing Partner	$	116	$	48	$	111	$	172		$	447
Investing Partners		183		15		247		440			885

	$	299	$	63	$	358	$	612		$	1,332

Net income per Investing Partner Unit (1)	$	180	$	15	$	242	$	430		$	867


(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.

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 Chairman of the Board and Chief Executive Officer (principal executive officer) , and Thomas P. Chambers, the Managing Partner’s Executive Vice President and Chief Financial Officer (principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2010, 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 and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2010, 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

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the Report of Management on Internal Control over Financial Reporting, included on page 20 of this report. This annual report does not include an attestation report of the Partnership’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There was no change in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2010, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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 2011 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), and revised it in November 2010. The revised Code of Conduct 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 “Governance” page of Apache’s website at www.apachecorp.com. Changes in and any 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 “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards,” “Outstanding Equity Awards at Fiscal Year-End,” “Option Exercises and Stock Vested,” “Non-Qualified Deferred Compensation,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements,” and “Director Compensation” in the Apache Proxy Statement 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 5.2 percent of the outstanding Units of the Partnership, as of December 31, 2010. Directors and officers of Apache own four Units, less than one percent of the Partnership’s Units, as of December 31, 2010. 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 which owns 53 Units or 5.2 percent of the outstanding Units. Apache did not acquire additional Units during the three years covered by these financial statements. Apache’s ownership percentage exceeds five percent due to the decrease in the number of outstanding units resulting from the right of presentment (see Note 1).

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 the Apache Proxy.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(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 Principal Executive Officer.

	*		31.2 Certification of Principal Financial Officer.

	*		32.1 Certification of Principal Executive Officer and Principal Financial Officer.

	*		99.1 Report of Ryder Scott Company, L.P., Petroleum Consultants.

	99.2		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).

	99.3		Proxy statement to be dated on or about March 31, 2011, relating to the 2011 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.

See a (3) above.

See a (2) above.

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, Managing Partner




Date: February 28, 2011	By:	/s/ G. Steven Farris
		G. Steven Farris
		Chairman of the Board and Chief Executive Officer

POWER OF ATTORNEY

The officers and directors of Apache Corporation, Managing Partner of Apache Offshore Investment Partnership, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Thomas P. Chambers, P. Anthony Lannie, and Rebecca A. Hoyt, 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 G. Steven Farris	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 28, 2011

/s/ Thomas P. Chambers Thomas P. Chambers	Executive Vice President and Chief Financial Officer (principal financial officer)	February 28, 2011

/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 28, 2011


Name	Title	Date

/s/ Frederick M. Bohen Frederick M. Bohen	Director	February 28, 2011

/s/ Randolph M. Ferlic Randolph M. Ferlic	Director	February 28, 2011

/s/ Eugene C. Fiedorek Eugene C. Fiedorek	Director	February 28, 2011

/s/ A. D. Frazier, Jr. A. D. Frazier, Jr.	Director	February 28, 2011

/s/ Patricia Albjerg Graham Patricia Albjerg Graham	Director	February 28, 2011

/s/ Scott D. Josey Scott D. Josey	Director	February 28, 2011

/s/ Chansoo Joung Chansoo Joung	Director	February 28, 2011

/s/ John A. Kocur John A. Kocur	Director	February 28, 2011

/s/ George D. Lawrence George D. Lawrence	Director	February 28, 2011

/s/ F. H. Merelli F. H. Merelli	Director	February 28, 2011

/s/ Rodman D. Patton Rodman D. Patton	Director	February 28, 2011

/s/ Charles J. Pitman Charles J. Pitman	Director	February 28, 2011

exv23w1

EXHIBIT 23.1

Consent of Ryder Scott Company, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Offshore Investment Partnership to our Firm’s name and our Firm’s review of the proved oil and gas reserve quantities of Apache Offshore Investment Partnership as of December 31, 2010, and to the inclusion of our report, dated February 11, 2011, as an exhibit to this Form 10-K filed with the Securities and Exchange Commission.


	/s/ Ryder Scott Company, L.P. Ryder Scott Company, L.P. TBPE Firm Registration No. F-1580

Houston, Texas
February 28, 2011

exv31w1

EXHIBIT 31.1

CERTIFICATIONS

I, G. Steven Farris, certify that:

1.		I have reviewed this annual report on Form 10-K of Apache Offshore Investment Partnership;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information ; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ G. Steven Farris
	G. Steven Farris
	Chairman of the Board and Chief Executive Officer (principal executive officer) of Apache Corporation, Managing Partner

Date: February 28, 2011

exv31w2

EXHIBIT 31.2

CERTIFICATIONS

I, Thomas P. Chambers, certify that:

1.		I have reviewed this annual report on Form 10-K of Apache Offshore Investment Partnership;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ Thomas P. Chambers
	Thomas P. Chambers
	Executive Vice President and Chief Financial Officer (principal financial officer) of Apache Corporation, Managing Partner

Date: February 28, 2011

exv32w1

Exhibit 32.1

APACHE OFFSHORE INVESTMENT PARTNERSHIP

Certification of Chief Executive Officer
and Principal Financial Officer

I, G. Steven Farris, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Offshore Investment Partnership for the period ended December 31, 2010, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.



	/s/ G. Steven Farris
	By:	G. Steven Farris
	Title:	Chairman of the Board and Chief Executive Officer (principal executive officer) of Apache Corporation, Managing Partner
Date: February 28, 2011

I, Thomas P. Chambers, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Offshore Investment Partnership for the period ended December 31, 2010, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.



	/s/ Thomas P. Chambers
	By:	Thomas P. Chambers
	Title:	Executive Vice President and Chief Financial Officer (principal financial officer) of Apache Corporation, Managing Partner
Date: February 28, 2011

exv99w1

Exhibit 99.1

APACHE CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

In The

Shell Offshore Venture

SEC Parameters

As of

December 31, 2010


	\s\ Jennifer Fitzgerald Jennifer Fitzgerald, P.E. TBPE License No. 100572 Vice President

RYDER SCOTT COMPANY, L.P.
TBPE Firm License No. F-1580

[SEAL]

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


TBPE REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5235	TELEPHONE (713) 651-9191

February 11, 2011

Apache Corporation
2000 Post Oak Boulevard, Suite 100
Houston, Texas 77056

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests in the Shell Offshore Venture for Apache Corporation (Apache) as of December 31, 2010. The subject properties are located in the federal waters offshore Louisiana and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves study, completed on January 27, 2011 and presented herein, was prepared for public disclosure by Apache in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of the Shell Offshore Venture for Apache as of December 31, 2010.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized on the following page.

600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790
621 17TH STREET, SUITE 1550DENVER, COLORADO 80293-1501TEL (303) 623-9147 FAX (303) 623-4258

Apache Corporation
February 11, 2011
Page 2

SEC PARAMETERS
Apache Corporation
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests in the
Shell Offshore Venture
As of December 31, 2010


	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
*Net Remaining Reserves*
Oil/Condensate — Barrels		133,997		438,633		14		572,644
Plant Products — Barrels		16,766		70,857		0		87,623
Gas — MMCF		797		1,823		123		2,743

*Income Data*
Future Gross Revenue	$	15,063,868	$	46,381,264	$	539,388	$	61,984,520
Deductions		7,409,885		10,883,138		506,942		18,799,965

Future Net Income (FNI)	$	7,653,983	$	35,498,126	$	32,446	$	43,184,555

Discounted FNI @ 10%	$	7,432,215	$	14,835,074	$	6,453	$	22,273,742

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of 60º Fahrenheit and 14.73 psia.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Apache. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, transportation costs (incorporated as other costs), and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 80 percent and gas reserves account for the remaining 20 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 3


	Discounted Future Net Income
	As of December 31, 2010
Discount Rate	Total
Percent	Proved
5	$	29,738,889
15	$	17,780,572
20	$	14,866,742
25	$	12,851,493

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Apache’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 4

Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Apache’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Apache owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 5

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis and/or material balance which utilized extrapolations of historical production and pressure data available through November, 2010 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Apache or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method or analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Apache or which we have obtained from public data sources that were available through November, 2010. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Apache has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Apache with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation costs, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Apache. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 6

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Apache furnished us with the above mentioned average prices in effect on December 31, 2010. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table on the following page summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 7

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Apache. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Average

Price

Benchmark

Realized

Geographic Area

Product

Reference

Prices

North America

United States

Oil/Condensate

WTI Cushing

$79.64/Bbl

$78.58/Bbl

NGLs

WTI Cushing

$79.64/Bbl

$48.95/Bbl

Gas

Henry Hub

$4.38/MMBTU

$4.63/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Apache and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Transportation costs are included as deductions and incorporated as other costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Apache. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Apache and are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Apache were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2010. The implementation of Apache’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Apache’s management. As the result of our inquiries during the course of preparing this report, Apache has informed us that the development activities

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
Page 8

included herein have been subjected to and received the internal approvals required by Apache’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Apache. Additionally, Apache has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Apache were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Apache. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Apache.

We have provided Apache with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Apache

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation
February 11, 2011
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and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.


	Very truly yours, RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580
	\s\ Jennifer Fitzgerald Jennifer Fitzgerald, P.E. TBPE License No. 100572 Vice President			[SEAL]

JAF/sm

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jennifer A. Fitzgerald was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Mrs. Fitzgerald, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2006, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mrs. Fitzgerald served in a number of engineering positions with ExxonMobil. For more information regarding Mrs. Fitzgerald’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mrs. Fitzgerald earned a Bachelor of Science degree in Chemical Engineering from University of Illinois Urbana-Champaign in 2001 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Evaluation Engineers and Society of Petroleum Engineers. She currently serves as the Secretary/Treasurer of the Houston Chapter of the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mrs. Fitzgerald fulfills. As part of her 2010 continuing education hours, Mrs. Fitzgerald attended 8 hours of formalized training including the 2010 RSC Reserves Conference and various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald attended an additional 3 hours of formalized in-house training as well as 7 hours of formalized external training during 2010 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. She also presented a presentation at the 2010 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald also previously attended the one and two day short courses presented by Dr. John Lee specific to the new SEC regulations.

Based on her educational background, professional training and more than 9 years of practical experience in the estimation and evaluation of petroleum reserves, Mrs. Fitzgerald has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
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(CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

	(1)		completion intervals which are open at the time of the estimate, but which have not started producing;

	(2)		wells which were shut-in for market conditions or pipeline connections; or

	(3)		wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS