Apache Offshore Investment Partnership (AOIP) 10-K 2012 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

OR

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

For the transition period from            to            

Commission File Number: 0-13546

APACHE OFFSHORE INVESTMENT PARTNERSHIP

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  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark 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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨]

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

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	x

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2012. $15,427,909

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Apache Corporation’s proxy statement relating to its 2013 annual meeting of stockholders have been referenced 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		10
4. MINE SAFETY DISCLOSURES		10
PART II
5. MARKET FOR REGISTRANT’S SECURITIES, RELATED SECURITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		11
6. SELECTED FINANCIAL DATA		11
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		12
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		18
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		22
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		40
9A. CONTROLS AND PROCEDURES		40
9B. OTHER INFORMATION		40
PART III
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		41
11. EXECUTIVE COMPENSATION		41
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS		41
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		41
14. PRINCIPAL ACCOUNTING FEES AND SERVICES		41
PART IV
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		42

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, 2012, 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.

1

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 expenditure 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.

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.

2012 Results and Business Development

The Partnership reported net income in 2012 of $1.5 million, or $1,005 per Investing Partner Unit. Earnings were down $0.3 million from 2011 on lower gas prices and gas production. Lower operating expenses in 2012 partially offset the decline in gas sales. The Partnership’s average realized gas price decreased 31 percent from a year ago to $2.84 per Mcf. Natural gas production averaged 1,194 Mcf per day in 2012, down 30 percent from 2011. Oil production averaged 75 barrels of oil per day in 2012, up 36 percent from 2011. South Timbalier 295, the Partnership’s largest oil-producing field, was brought back on production in mid-2011 after being shut-in nearly a year while a new oil sales pipeline was built. During 2012, the Partnership’s cash outlays for oil and gas property additions were negligible as the Partnership did not participate in any new drilling or recompletion projects.

Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total less than $1.0 million in 2013 for recompletion activity. 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, 2012, 45 of those prospects have been surrendered or sold. As of December 31, 2012, the Partnership had 34 producing wells on the Partnership’s four remaining developed fields. One of the Partnership’s producing wells has dual completions. The Partnership had, at December 31, 2012, estimated proved oil and gas reserves of 4.3 Bcfe.

For a more in-depth discussion of the Partnership’s 2012 results and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K

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 that 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 2012 was purchased largely by Shell Trading Company at market prices.

2

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 effect 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 global financial crisis and recession that began in 2008. Growth has resumed but is modest and at an unsteady rate. The continuation of current global market conditions, uncertainty or further deterioration, including the economic instability in Europe, is likely to have significant long-term effects, including a future global economic growth rate that is slower than in the years leading up to the crisis, and more volatility may occur before any 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 2012 ranged from a high of $109.77 per barrel to a low of $77.69 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2012 ranged from a high of $3.90 per MMBtu to a low of $1.91 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.

3

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; or

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

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. For example, from July 2010 until mid-2011, the Partnership’s production at South Timbalier 295 was shut-in as a result of a leak in a third-party pipeline, which significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities, and liquidity in 2011 and 2010. If a substantial amount of our production is interrupted at the same time or for an extended period of time, it could adversely affect our cash flow.

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

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. 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.

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:

• well blowouts, explosions, and cratering;

• pipeline ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions;

• hurricanes which could affect our operations on- and offshore the Gulf Coast, and other natural disasters; and

• surface spillage and water contamination from petroleum constituents or hydraulic fracturing chemical additives

4

Failure or loss of equipment, as the result of equipment malfunctions, cyber-attacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we 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, or water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout, or pipeline rupture or surface spillage and water contamination from petroleum constituents or hydraulic fracturing chemical additives could result in extensive 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 flows, and, in turn, our results of operations could be materially and adversely affected.

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 the first half of 2013 as a result of the Partnership’s plan to build cash reserves to fund future asset retirement obligations (ARO) and planned capital expenditures in 2013. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover its undiscounted future ARO. If natural gas prices remain at or fall below current levels, the Partnership may not be able to make a distribution to Investing Partners during all of 2013. 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.

Reserves and production will decline materially without discoveries or acquisitions of reserves.

The production rate from oil and gas properties generally declines as reserves are depleted and production from offshore wells tends to decline at a faster rate than onshore wells, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through development or exploration drilling, identify and develop additional behind-pipe zones, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase. The Partnership has not and does not plan to engage in future acquisition or exploration activities, therefore, we expect declines in future oil and gas production, which are likely to adversely impact our cash flow and results from operations.

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;

5

• 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. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserve quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also 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;

• future operating costs and capital expenditures; 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 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 effect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

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 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. New political developments, laws and regulations may adversely impact our results on operations.

6

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.

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.

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.

In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010, and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), issued new guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These new regulations have imposed additional requirements with respect to development and production activities in the Gulf of Mexico and have delayed the approval of applications to drill in both deepwater and shallow-water areas.

Further, at this time, we cannot predict with any certainty what further impact, if any, the Deepwater Horizon incident may have on the regulation of offshore oil and gas exploration and development activity, or on the cost or availability of insurance coverage to cover the risks of such operations. The enactment of new or stricter regulations in the United States and increased liability for companies operating in this sector could adversely affect the Partnership’s operations in the U.S. Gulf of Mexico.

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.

7

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

The Partnership’s business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. The Managing Partner and the Partnership depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

Insurance policies do not cover all of the risks we face, which could result in significant financial exposure.

Exploration for and production of oil and natural gas can be hazardous, involving natural disasters and unforeseen events 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

As of December 31, 2012, the Partnership did not have any unresolved comments from the staff of the SEC.

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, 2012, 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, 2012, 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, 2012, is set forth below:

			Gas				Oil
Lease Block	State		Gross		Net		Gross		Net
Ship Shoal 258, 259		LA		7		.44		—		—
South Timbalier 276, 295, 296		LA		1		.07		17		1.20
North Padre Island 969, 976		TX		5		.36		—		—
Matagorda Island 681, 682		TX		4		.25		—		—
				17		1.12		17		1.20

8

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
2012		—		—		—		—		—		—
2011		—		—		—		.15		.07		.22
2010		—		—		—		.07		—		.07

Production, Pricing and Lease Operating Cost 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 lease operating costs per Mcfe (including gathering and transportation expense) and average sales prices.

	Production						Average Lease		Average Sales Price
Year Ended December 31,	Oil (Mbbls)		NGLs (Mbbls)		Gas (MMcf)		Operating Cost per Mcfe		Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)
2012
South Timbalier 295		26		3		41	$	2.94	$	108.90	$	36.17	$	3.36
Other fields		1		2		396		2.04		107.08		31.40		2.79
Total		27		5		437	$	2.35	$	108.83	$	34.19	$	2.84
2011
South Timbalier 295		19		3		35	$	6.18	$	109.99	$	64.70	$	3.77
Other fields		1		4		590		1.25		102.76		56.35		4.13
Total		20		7		625	$	2.30	$	109.55	$	60.14	$	4.11
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

At December 31, 2012, the South Timbalier 295 field contained approximately 86 percent of the Partnership’s proved reserved, expressed on an oil-equivalent-barrels basis.

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Reserve estimates are considered proved if they are economically 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 have been field tested and have 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.

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As of December 31, 2012, the Partnership had total estimated proved reserves of 421,716 barrels of crude oil and condensate, 75,045 barrels of NGLs and 1.3 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 4.3 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, 2012, based on commodity average prices in effect on the first day of each month in 2012, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

	Oil (Mbbls)		NGL (Mbbls)		Gas (MMcf)
Proved developed		422		75		1,331
Proved undeveloped		—		—		—
Total proved		422		75		1,331

The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2012, 2011, and 2010, 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 2012 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows as of December 31, 2012, 2011, and 2010 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 in the respective year, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

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 eleven 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.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S SECURITIES, RELATED SECURITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2012, there were 1,021.5 of the Partnership’s Units outstanding held by 881 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 2012, 2011, or 2010.

As discussed in Item 7, an amendment to the Partnership Agreement in February 1994, created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2012, 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,
	2012		2011		2010		2009		2008
	(In thousands, except per Unit amounts)
Total assets	$	12,218	$	11,612	$	10,992	$	8,236	$	6,680
Partners’ capital	$	9,820	$	8,859	$	7,483	$	6,086	$	5,191
Oil and gas sales	$	4,377	$	5,195	$	4,270	$	4,311	$	7,928
Net income	$	1,489	$	1,803	$	1,555	$	1,332	$	5,335
Net income allocated to:
Managing Partner	$	462	$	552	$	467	$	447	$	1,229
Investing Partners		1,027		1,251		1,088		885		4,106
	$	1,489	$	1,803	$	1,555	$	1,332	$	5,335
Net income per Investing Partner Unit	$	1,005	$	1,225	$	1,065	$	867	$	3,976
Cash distributions per Investing Partner Unit	$	—	$	—	$	—	$	—	$	5,500

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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 2012, the Partnership benefited from relatively stable market prices for crude oil as its realized oil price averaged $108.83 per barrel, down one percent from 2011. The Partnership’s average realized price for natural gas, however, declined 31 percent during 2012 as market prices stayed depressed throughout most of 2012. Prices in recent years 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.

The Partnership participates in development drilling and recompletion activities as recommended by outside operators and the Partnership’s Managing Partner. During 2012, the Partnership’s had negligible cash outlays for oil and gas property additions as the partnership did not participate in any new drilling or recompletion projects during 2012.

Generally, the Partnership has used its available cash to fund distributions to its Partners. During 2012, the Partnership replenished its cash reserves to be able to fund future asset retirement obligations. Its cash balances had been depleted by the shut-in of the South Timbalier 295 field for nearly a year and the Partnership’s participation in drilling and recompletion projects in 2011 and 2010. As a result of the low revenue and high capital costs, the Partnership did not make any distributions to the Investing Partners during the last three years.

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 and the level of drilling, recompletion and plugging activity in 2013.

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 2012, 2011, and 2010.

Net Income and Revenue

The Partnership reported net income of $1.5 million for 2012 compared to $1.8 million for 2011. Net income per Investing Partner Unit for 2012, of $1,005 was down from $1,225 per Unit in 2011. The decline in earnings and net income per Investing Partner Unit from 2011 reflected lower realized gas prices and lower gas production in 2012. The Partnership reported earnings of $1.6 million in 2010.

Total revenues in 2012 of $4.4 million decreased 16 percent from 2011 on lower gas prices and production. The Partnership’s total revenues in 2011 of $5.2 million increased 22 percent from 2010 on higher oil prices and production.

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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 that production from offshore wells tends to decline at a faster rate than production from 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 (gas volumes are presented in thousand cubic feet (Mcf) per day):

	For the Year Ended December 31,
				Increase					Increase
	2012			(Decrease)			2011		(Decrease)			2010
Gas volume – Mcf per day			1,194		(30	)%		1,712		4	%		1,647
Average gas price – per Mcf		$	2.84		(31	)%	$	4.11		(12	)%	$	4.68
Oil volume – barrels per day			75		36	%		55		17	%		47
Average oil price – per barrel		$	108.83		(1	)%	$	109.55		43	%	$	76.78
NGL volume – barrels per day			12		(37	)%		19		138	%		8
Average NGL price – per barrel		$	34.19		(43	)%	$	60.14		20	%	$	50.21

Natural Gas Sales

2012 vs. 2011Natural gas sales in 2012 decreased 52 percent from a year ago, dropping to $1.2 million in the current period. The Partnership’s average realized gas prices decreased from $4.11 per Mcf in 2011 to $2.84 per Mcf in 2012, reducing sales by $0.8 million. A 30 percent decrease in natural gas volumes during the 2012 from the same period a year ago curtailed sales by $0.5 million. The Partnership’s gas production in 2012 was impacted by the shut-in of North Padre Island 969/976 and Matagorda Island 681/682 for pipeline repairs during the second quarter of 2012, downtime for Hurricane Isaac during the third quarter of 2012, and natural depletion primarily at Matagorda Island 681/682 and North Padre Island 969/976 as these two fields approach the end of their economic lives.

2011 vs. 2010 The Partnership’s natural gas sales in 2011 totaled $2.6 million, down nine percent from 2010 on lower natural gas prices. During 2011, the partnership’s average realized natural gas price declined $.57 per Mcf, or 12 percent, from 2010 and decreased sales by $0.3 million. Production increases from 2010 offset $0.1 million of the impact of lower prices. Average daily production in 2011 increased four percent from 2010, rising to 1,712 Mcf per day in 2011. The increase in natural gas volumes reflected successful drilling at Ship Shoal 258/259 in 2011 and late 2010. Further increase in production was thwarted by natural depletion at Matagorda Island 681/682 and North Padre Island 969/976.

Crude Oil Sales

2012 vs. 2011 Crude oil sales in 2012 totaled $3.0 million, up 35 percent from 2011. The Partnership’s crude oil volumes increased to 75 barrels per day from 55 barrels per day during 2011 as a result of the shut-in of production at South Timbalier 295 in 2011. The Partnership’s production from South Timbalier 295 was shut-in from July 11, 2010, through June 14, 2011, as a result of a leak in a third-party pipeline, significantly reducing the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2011. The Partnership’s average realized oil price in 2012 decreased one percent from 2011, dropping to $108.83 per barrel in 2012.

2011 vs. 2010 Crude oil sales in 2011 of $2.2 million increased 68 percent from the $1.3 million of oil sales reported in 2010. A $32.77 per barrel, or 43 percent, increase in average realized oil price from 2010 boosted sales by $0.6 million. The Partnership’s 2011 crude oil sales volumes increased 17 percent from 2010, rising to 55 barrels of oil per day in 2011. The increase in production, which benefitted sales by $0.3 million, reflected less downtime at South Timbalier 295 for the construction of a new oil sales pipeline and for inclement weather.

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NGL Sales

The Partnership sold 12 barrels per day of natural gas liquids in 2012, down from 19 barrels per day in 2011. The decrease reflected lower processed volumes at Ship Shoal 258/259 and South Timbalier 295 in 2012. The lower average realized NGL price in 2012 reflected declining product prices with an abundant supply of liquid products in the United States. The Partnership sold 19 barrels per day of NGL in 2011, up from 8 barrels per day in 2010. The increase from 2010 reflected higher production from South Timbalier 295 during 2011.

Since the Partnership does not anticipate acquiring additional acreage or conducting exploratory drilling on leases in which it currently holds an interest, declines in oil and gas production can be expected in future periods as a result of natural depletion. Also, given the small number of producing wells owned by the Partnership and exposure to inclement weather in the Gulf of Mexico, the Partnership’s production may be subject to more volatility than those companies with a larger or more diversified property portfolio.

Operating Expenses

2012 vs. 2011 The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 21 percent in 2012 while DD&A, expressed as a percentage of oil and gas sales, for 2011 was 20 percent. The dollar amount of DD&A expense in 2012 decreased from the comparable periods a year ago as a result of lower oil and gas sales in 2012. For 2012, and 2011, the Partnership recognized asset retirement obligation accretion of $122,101 and $132,120, respectively. The decline in accretion expense from a year ago reflected the decrease in the Partnership’s asset retirement obligation liability for plugging operations performed in 2011. Lease operating expenses (LOE) for 2012 was down 20 percent from the same period a year ago, decreasing to $1.3 million in 2012, reflecting lower workovers, repairs, and transportation costs for personnel and materials during 2012. Gathering and transportation costs for the delivery of oil and gas decreased four percent from the same period in 2011 on lower gas volumes in 2012. Administrative expense for 2012 decreased one percent compared to the same period in 2011.

2011 vs. 2010 The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 20 percent during 2011, up from 19 percent in 2010. The increase in rate as a percentage of oil and gas sales was driven by capital expenditures in 2011 and lower gas prices from a year ago. DD&A on an absolute basis increased as a result of increased production and higher plugging and dismantlement cost. LOE increased 35 percent over the previous year on higher workover and repair and maintenance costs. During 2011, the Partnership participated in a significant workover project at South Timbalier 295. Gathering and transportation costs increased from 2010 levels reflecting the increase in sales volumes in 2011. Administrative expense for the year decreased slightly from 2010 to $397,000.

The Partnership generally sells oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which the Partnership sells oil or natural gas at the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Partnership records sales at the price received from the purchaser which is net of transportation costs. Under the other arrangement, the Partnership sells oil or natural gas at a specific delivery point, pays transportation to a carrier and receives from the purchaser a price with no transportation deduction. In this case, the Partnership records the separate transportation cost as gathering and transportation costs.

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.3 million for 2012. Net cash provided by operating activities during 2012 was down from $2.7 million in the comparable period in 2011 as a result of the lower gas prices and lower gas production which negatively impacted the Partnership’s earnings in 2012.

At December 31, 2012, the Partnership had approximately $3.1 million in cash and cash equivalents, up from approximately $1.4 million at December 31, 2011. The Partnership’s goal of maintaining cash at least sufficient to cover the undiscounted value of its future asset retirement obligation (ARO) liability had to be temporarily suspended in 2011 because of the near year-long shut-in of the Partnership’s production from South Timbalier 295 and the Partnership’s capital expenditures at Ship Shoal 258/259 and South Timbalier 295 in 2011.

14

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’s non-participation in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership forecasts it will be able to meet its liquidity needs for routine operations in the foreseeable future. The Partnership will reduce capital expenditures and distributions to partners as cash from operating activities declines.

Approximately 84 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 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.

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

On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs. The Partnership did not sell any properties in 2012, 2011, or 2010.

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. To the extent it has discretion, the Partnership allocates available capital to investment in the Partnership’s properties so as to maximize production and resultant cash flow. The Partnership had no outstanding debt or lease commitments at December 31, 2012. The Partnership did not have any contractual obligations as of December 31, 2012, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for the present value of this asset retirement obligation as discussed in the notes to the financial statements included in this annual report on Form 10-K.

During 2012, the Partnership had negligible cash outlays for oil and gas property additions as it did not participate in any new drilling or recompletion projects. During 2011, the Partnership’s oil and gas property additions totaled $3.2 million with $2.9 million of development cost and $0.3 million of additional asset retirement

15

cost. The Partnership participated in drilling three wells at Ship Shoal 258/259 during 2011 with two wells being completed as producers and one being unsuccessful at finding commercial quantities of oil and gas. During the year, the Partnership also participated in two recompletions at North Padre Island 969/976 and completed the installation of a new oil sales pipeline at South Timbalier 295. During 2010, the Partnership’s oil and gas property development cost 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 2010, 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.

Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $1 million in 2013 for recompletion activity. 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.

Because of low natural gas prices during most of 2012 and the need to replenish cash reserves for future asset retirement obligations, no distributions were made to Investing Partners during 2012. The Partnership also made no distribution to Investing Partners during 2011 as a result of the large amount of capital expenditures funded by the Partnership during 2011 and due to the loss of revenue in 2011 from the shut-in of South Timbalier 295.

The amount of future distributions will be dependent on actual and expected production levels, realized and anticipated 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. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations. We do not anticipate that the Partnership will make any distribution to Investing Partners during the first half of 2013 as the Partnership plans to rebuild cash reserves for future ARO expenditures and cover recompletion costs planned for the first half of the year. 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 and the level of drilling, recompletion, and plugging activity in 2013.

As provided in the Amended Partnership Agreement, a first right of presentment valuation was computed during the first quarter of 2012. The per-unit value was determined to be $15,516 based on the valuation date of December 31, 2011. A second right of presentment valuation was computed during October 2012 and the per-unit value was determined to be $15,932 based on a valuation date of June 30, 2012. The Partnership did not repurchase any Investing Partner Units (Units) during 2012 as a result of the Partnership’s limited amount of cash available for discretionary purposes. The per-unit right of presentment value computed during the first quarter of 2011 based on the valuation date of December 31, 2010, was $14,917 and the second per-unit right of presentment in 2011 was $13,500 based on a valuation date of June 30, 2011. The Partnership did not repurchase any Units during 2011. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to repurchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

There will be two rights of presentment in 2013, 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.

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.

16

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.

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. The following is a discussion of Partnership’s most critical accounting policies:

Reserve Estimates

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.

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.

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, 2012, 2011, and 2010, were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month in the respective year, held flat for the life of production, except where prices are defined by contractual arrangements.

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.

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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

The Partnership’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for oil and gas production continue to be volatile and unpredictable. The Partnership has not used derivative financial instruments or otherwise engaged in hedging activities during 2012 or 2011.

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 2012, monthly oil price realizations ranged from a low of $93.71 per barrel to a high of $121.55 per barrel. Gas price realizations ranged from a monthly low of $2.15 per Mcf to a monthly high of $3.63 per Mcf during the same period. Based on the Partnership’s average daily production for 2012, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $27,000 and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $43,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2012. 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.

18

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, 2012, 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;

• pipeline and gathering system capacity;

• 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, including environmental regulation;

• terrorism or cyber attacks;

• 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.

19

ADDITIONAL INFORMATION ABOUT THE PARTNERSHIP

Remediation Plans and Procedures

The Partnership’s Managing Partner developed Oil Spill Response Plans for its Gulf of Mexico operations to ensure rapid and effective responses 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. In the event of a spill, CGA is the primary oil spill response association available to Apache. Apache has received approval for its plan from the Bureau of Ocean Energy Management (BOEM). Apache personnel review the plan biennially and update where necessary.

As part of our Oil 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. Until December 31, 2012, CGA’s equipment was maintained by 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. CGA’s equipment maintained by MSRC included a high-volume open sea barge oil skimming system, 11 Koseq rigid sweeping arms, an oceangoing boom barge with 25,000 feet of offshore containment boom, a fire boom, six fast response vessels, 12 fast response skimming units, multiple shallow water skimming and recovery systems, wildlife cleaning and rehabilitation facilities, and dispersant inventory. In the event of a spill, MSRC stood ready to mobilize all of this equipment to CGA members. MSRC also handled the maintenance and mobilization of CGA non-marine equipment. Effective January 1, 2013, CGA’s marine and non-marine equipment is now maintained by the Clean Gulf Associates Service, LLC. In the event of a spill, this equipment, which is positioned at various staging points around the Gulf, is ready to be mobilized. In addition, CGA has contracted with Airborne Support Inc. to provide aircraft and dispersant capabilities for CGA member companies.

In the event that CGA resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited (OSRL), which entitles any Apache entity worldwide to access OSRL’s service. OSRL has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. OSRL has equipment stockpiles in Bahrain, Singapore, and Southampton that currently include approximately 153 skimmers, booms (of approximately 12,000 meters), two Hercules aircraft for equipment deployment and aerial dispersant spraying, two additional aircraft, dispersant spray systems and dispersant, floating storage tanks, all-terrain vehicles, and various other equipment. If necessary, OSRL’s resources may be, and have been, deployed to areas across the globe, such as the Gulf of Mexico. In addition, in February 2012, Apache became a member of MSRC and National Response Corporation (NRC), and their resources are available to Apache for its Gulf of Mexico operations. Furthermore, the spill response resources of other organizations are also available to Apache as a non-member, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment. MSRC’s equipment currently includes 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 290 skimming systems, approximately 50 self-propelled skimming vessels, 7 mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels, 22,500 feet of fire boom, and 6 dispersant aircraft. MSRC has contracts in place with over 100 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 workboats, 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 the MSRC and the NRC changes from time to time, and current information is generally available on each company’s website

Apache also participates in a number of industry-wide task forces that 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.

20

Environmental Compliance

As an owner or lessee and operator of oil and gas properties and facilities, 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.

21

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		23
Report of Independent Registered Public Accounting Firm		24
Statement of Consolidated Income for each of the three years in the period ended December 31, 2012		25
Statement of Consolidated Cash Flows for each of the three years in the period ended December  31, 2012		26
Consolidated Balance Sheet as of December 31, 2012 and 2011		27
Statement of Consolidated Changes in Partners’ Capital for each of the three years in the period ended December 31, 2012		28
Notes to Consolidated Financial Statements		29
Supplemental Oil and Gas Disclosures		37
Supplemental Quarterly Financial Data		39

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.

22

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, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control—Integrated Framework. Based on our assessment, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2012.

/s/ G. Steven Farris

Chairman and Chief Executive Officer

(principal executive officer) of Apache Corporation, Managing Partner

/s/ Thomas P. Chambers

Executive Vice President and Chief Financial Officer

(principal financial officer) of Apache Corporation, Managing Partner

/s/ Rebecca A. Hoyt

Vice President, Chief Accounting Officer and Controller

(principal accounting officer) of Apache Corporation, Managing Partner

Houston, Texas

February 28, 2013

23

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, 2012 and 2011, 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, 2012. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Offshore Investment Partnership at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ ERNST & YOUNG LLP                                    

Houston, Texas

February 28, 2013

24

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED INCOME

	For the Year Ended December 31,
	2012		2011		2010
REVENUES:
Oil and gas sales	$	4,376,662	$	5,195,487	$	4,270,245
Interest income		59		36		77
		4,376,721		5,195,523		4,270,322
EXPENSES:
Depreciation, depletion and amortization		897,763		1,053,964		822,053
Asset retirement obligation accretion		122,101		132,120		118,557
Lease operating expenses		1,334,687		1,661,778		1,229,104
Gathering and transportation costs		141,291		147,518		142,737
Administrative		392,000		397,000		403,000
		2,887,842		3,392,380		2,715,451
NET INCOME	$	1,488,879	$	1,803,143	$	1,554,871
NET INCOME ALLOCATED TO:
Managing Partner	$	462,382	$	551,769	$	466,589
Investing Partners		1,026,497		1,251,374		1,088,282
	$	1,488,879	$	1,803,143	$	1,554,871
NET INCOME PER INVESTING PARTNER UNIT	$	1,005	$	1,225	$	1,065
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING		1,021.5		1,021.5		1,021.5

The accompanying notes to consolidated financial statements

are an integral part of this statement.

25

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CASH FLOWS

	For the Year Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,488,879		$	1,803,143		$	1,554,871
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		897,763			1,053,964			822,053
Asset retirement obligation accretion		122,101			132,120			118,557
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables		170,348			(26,315	)		81,532
Increase (decrease) in receivable from/payable to
Apache Corporation		(87,410	)		99,448			145,885
Increase (decrease) in accrued operating expenses		(282,123	)		296,686			3,389
Increase (decrease) in deferred credits and other		2,937			(635,930	)		(180,941	)
Net cash provided by operating activities		2,312,495			2,723,116			2,545,346
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(71,158	)		(3,863,213	)		(1,464,194	)
Net cash used in investing activities		(71,158	)		(3,863,213	)		(1,464,194	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Managing Partner		(526,942	)		(427,409	)		(157,664	)
Net cash used in financing activities		(526,942	)		(427,409	)		(157,664	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,714,395			(1,567,506	)		923,488
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		1,404,394			2,971,900			2,048,412
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,118,789		$	1,404,394		$	2,971,900

The accompanying notes to consolidated financial statements

are an integral part of this statement.

26

APACHE OFFSHORE INVESTMENT PARTNERSHIP

CONSOLIDATED BALANCE SHEET

	December 31,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,118,789		$	1,404,394
Accrued revenues receivable		118,847			289,195
		3,237,636			1,693,589
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties		194,451,931			194,492,252
Less – Accumulated depreciation, depletion and amortization		(185,471,958	)		(184,574,195	)
		8,979,973			9,918,057
	$	12,217,609		$	11,611,646
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation	$	75,021		$	162,431
Accrued operating expenses		124,357			406,480
Accrued development costs		35,978			148,577
		235,356			717,488
ASSET RETIREMENT OBLIGATION		2,161,807			2,035,649
PARTNERS’ CAPITAL:
Managing Partner		442,805			507,365
Investing Partners (1,021.5 units outstanding)		9,377,641			8,351,144
		9,820,446			8,858,509
	$	12,217,609		$	11,611,646

The accompanying notes to consolidated financial statements

are an integral part of this statement.

27

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL

	Managing			Investing
	Partner			Partners		Total
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
Distributions		(427,409	)		—		(427,409	)
Net income		551,769			1,251,374		1,803,143
BALANCE, DECEMBER 31, 2011	$	507,365		$	8,351,144	$	8,858,509
Distributions		(526,942	)		—		(526,942	)
Net income		462,382			1,026,497		1,488,879
BALANCE, DECEMBER 31, 2012	$	442,805		$	9,377,641	$	9,820,446

The accompanying notes to consolidated financial statements

are an integral part of this statement.

28

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, 2012. 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, 2012, 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.

29

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2012, 2011, or 2010 as a result of the limited amount of cash available for discretionary purposes.

The Partnership is not in a position to predict how many Units will be presented for repurchase during 2013; 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 Valuation Date	Total Valuation Price		Valuation Price Per Unit
December 31, 2009	$	15,742,174	$	15,411
June 30, 2010		16,477,118		16,130
December 31, 2010		15,237,383		14,917
June 30, 2011		13,790,742		13,500
December 31, 2011		15,849,687		15,516
June 30, 2012		16,274,165		15,932

	2012		2011		2010
Investing Partner Units Outstanding:
Balance, beginning of year		1,021.5		1,021.5		1,021.5
Repurchase of Partnership Units		—		—		—
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, 2012. 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, 2012.

30

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 GAAP 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 Note10—Supplemental Oil and Gas Disclosures) and assessing asset retirement obligations (see Note 8 – Asset Retirement Obligation).

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, 2012 and 2011, the Partnership had $3.1 million and $1.4 million, respectively, of cash and cash equivalents.

Oil and Gas Properties

The Partnership follows 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. All costs related to 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 expense and reflected as additional DD&A in the accompanying statement of consolidated income. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of

31

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. See Note 10—Supplemental Oil and Gas Disclosures included in this Form 10-K for a discussion on calculation of estimated future net cash flows.

Asset Retirement Costs and Obligation

The initial estimated asset retirement obligation related to properties is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. If the fair value of the recorded asset retirement obligation changes, a revision 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. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

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, 2012 and 2011, 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, 2012 and 2011.

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.

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, 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.

32

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. COMPENSATION TO AFFILIATES

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,
	2012		2011		2010
	(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	$	314	$	318	$	322
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	$	—	$	61	$	53

Apache operates certain Partnership properties. Billings to the Partnership are made on the same basis as to unaffiliated third parties or at prevailing industry rates.

4. OIL AND GAS PROPERTIES

The following tables contain direct cost information and changes in the Partnership’s oil and gas properties for each of the years ended December 31. All costs of oil and gas properties are currently being amortized.

	2012			2011		2010
	(In thousands)
Oil and Gas Properties
Balance, beginning of year	$	194,492		$	191,277	$	188,458
Costs incurred during the year:
Development –
Investing Partners		(44	)		3,084		2,735
Managing Partner		4			131		84
Balance, end of year	$	194,452		$	194,492	$	191,277

Development cost for 2011 and 2010 includes $0.3 million and $0.2 million, respectively, of asset retirement cost, while 2012 asset retirement cost additions were negligible.

	Managing Partner		Investing Partners		Total
	(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 2009	$	20,931	$	161,767	$	182,698
Provision		21		801		822
Balance, December 31, 2010	$	20,952	$	162,568	$	183,520
Provision		33		1,021		1,054
Balance, December 31, 2011	$	20,985	$	163,589	$	184,574
Provision		27		871		898
Balance, December 31, 2012	$	21,012	$	164,460	$	185,472

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2012, 2011, and 2010 was 21 percent, 20 percent and 19 percent, respectively.

33

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2012, sales to Shell Trading Company accounted for 68 percent of the Partnership’s oil and gas sales for the year. In 2011, sales to Shell Trading Company accounted for 42 percent of the Partnership’s oil and gas sales for the year. 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.

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 $10,274 in 2012, $26,553 in 2011, and $40,562 in 2010 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.

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. FAIR VALUE MEASUREMENTS

Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable -

As of December 31, 2012, and December 31, 2011, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the years ended December 31, 2012, and 2011.

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 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 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 the Partnership is not fully insured against all environmental risks.

34

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2012 and 2011:

	2012			2011
Asset retirement obligation at beginning of year	$	2,035,649		$	2,209,662
Accretion expense		122,101			132,120
Liabilities settled		(33,041	)		(635,930	)
Revisions in estimated liabilities		37,098			329,797
Asset retirement obligation at end of year	$	2,161,807		$	2,035,649

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 2011 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.

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:

	2012			2011			2010
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	2,268,525		$	(49,125	)	$	(25,363	)
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost		(82,453	)		2,058,342			2,142,424
Dismantlement and abandonment cost		33,041			635,930			180,941
Tax depreciation		289,630			344,080			197,479
		240,218			3,038,352			2,520,844
Less: full cost DD&A expense		(897,763	)		(1,053,964	)		(822,053	)
Less: asset retirement obligation accretion		(122,101	)		(132,120	)		(118,557	)
Net income	$	1,488,879		$	1,803,143		$	1,554,871

35

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership’s tax bases in net oil and gas properties at December 31, 2012, and 2011 was $6,720,921 and $7,374,409, respectively, lower than the 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, 2012, and 2011.

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,
	2012		2011
Liabilities for federal income tax purposes	$	235,356	$	717,488
Asset retirement liability		2,161,807		2,035,649
Liabilities under accounting principles generally accepted in the United States	$	2,397,163	$	2,753,137

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

36

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Reserve Information

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (NGLs) 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.

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)

	2012						2011						2010
	Oil			Gas			Oil			Gas			Oil			Gas
Proved Reserves
Beginning of year		513			2,094			561			2,354			555			2,427
Extensions, discoveries and other additions		—			—			4			354			15			111
Revisions of previous estimates		16			(326	)		(25	)		11			11			417
Production		(32	)		(437	)		(27	)		(625	)		(20	)		(601	)
End of year		497			1,331			513			2,094			561			2,354
Proved Developed
Beginning of year		513			1,989			561			2,249			555			2,322
End of year		497			1,331			513			1,989			561			2,249

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 84 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.

Future Net Cash Flows

Future cash inflows as of December 31, 2012, 2011, and 2010 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. 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.

37

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Discounted Future Net Cash Flows Relating to Proved Reserves

	December 31,
	2012			2011			2010
	(In thousands)
Future cash inflows	$	54,044		$	63,150		$	52,801
Future production costs		(11,058	)		(9,578	)		(10,290	)
Future development costs		(5,020	)		(5,344	)		(5,689	)
Net cash flows		37,966			48,228			36,822
10 percent annual discount rate		(18,467	)		(22,296	)		(17,783	)
Discounted future net cash flows	$	19,499		$	25,932		$	19,039

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

	For the Year Ended December 31,
	2012			2011			2010
	(In thousands)
Sales, net of production costs	$	(2,901	)	$	(3,386	)	$	(2,898	)
Net change in prices and production costs		(2,976	)		7,264			3,857
Revisions of quantities		(1,241	)		(780	)		1,923
Discoveries and improved recoveries, net of cost		—			1,680			1,292
Accretion of discount		2,593			1,904			1,455
Changes in future development costs		177			341			336
Changes in production rates and other		(2,085	)		(130	)		(1,479	)
	$	(6,433	)	$	6,893		$	4,486

38

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First		Second		Third		Fourth		Total
	(In thousands, except per Unit amounts)
2012
Revenues	$	1,395	$	914	$	1,038	$	1,030	$	4,377
Expenses		804		640		746		698		2,888
Net income	$	591	$	274	$	292	$	332	$	1,489
Net income allocated to:
Managing Partner	$	168	$	90	$	99	$	105	$	462
Investing Partners		423		184		193		227		1,027
	$	591	$	274	$	292	$	332	$	1,489
Net income per Investing Partner Unit (1)	$	413	$	180	$	188	$	188	$	1,005
2011
Revenues	$	738	$	1,078	$	1,754	$	1,625	$	5,195
Expenses		562		632		836		1,362		3,392
Net income	$	176	$	446	$	918	$	263	$	1,803
Net income allocated to:
Managing Partner	$	65	$	129	$	248	$	110	$	552
Investing Partners		111		317		670		153		1,251
	$	176	$	446	$	918	$	263	$	1,803
Net income per Investing Partner Unit (1)	$	109	$	310	$	656	$	150	$	1,225

(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.

39

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2012, 2011 and 2010, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

G. Steven Farris, the Managing Partner’s Chairman and Chief Executive Officer (in his capacity as principal executive officer), and Thomas P. Chambers, the Managing Partner’s Executive Vice President and Chief Financial Officer (in his capacity as principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2012, 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 under 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, 2012, 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 23 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, 2012, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

40

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 2013 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 2011. 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 Affiliates” 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 AND RELATED SECURITY HOLDER MATTERS

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, 2012. Directors and officers of Apache own four Units, less than one percent of the Partnership’s Units, as of December 31, 2012. 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, AND DIRECTOR INDEPENDENCE

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. The Partnership itself has no directors. Information concerning the directors of Apache set forth under the caption “Director Independence” in the Apache Proxy is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING 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.

41

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

a.      (1)    Financial Statements – See accompanying index to financial statements in Item 8 above.

(2) Financial Statement Schedules – See accompanying index to financial statements in Item 8 above.

(3) Exhibits

3.1 Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit (3)(i) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).

3.2 Amendment No. 1, dated February 11, 1994, to the Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit 3.3 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).

3.3 Limited Partnership Agreement of Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit (3)(ii) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).

10.1 Form of Assignment and Assumption Agreement between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.2 to Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, Commission File No. 0-13546).

10.2 Joint Venture Agreement, dated as of November 23, 1992, between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.6 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).

10.3 Matagorda Island 681 Field Purchase and Sale Agreement with Option to Exchange, dated November 24, 1992, between Apache Corporation, Shell Offshore, Inc. and SOI Royalties, Inc. (incorporated by reference to Exhibit 10.7 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).

*23.1 Consent of Ryder Scott Company, L.P., Petroleum Consultants.

*31.1 Certification of 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 April 3, 2013, relating to the 2013 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).

42

**101.INS	XBRL Instance Document.
**101.SCH	XBRL Taxonomy Schema Document.
**101.CAL	XBRL Calculation Linkbase Document.
**101.DEF	XBRL Definition Linkbase Document.
**101.LAB	XBRL Label Linkbase Document.
**101.PRE	XBRL Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

b. See a (3) above.

c. See a (2) above.

43

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
Dated: February 28, 2013		/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, 2013
/s/ Thomas P. Chambers Thomas P. Chambers	Executive Vice President and Chief Financial Officer (principal financial officer)	February 28, 2013
/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 28, 2013

44

Name	Title	Date
/s/ Randolph M. Ferlic Randolph M. Ferlic	Director	February 28, 2013
/s/ Eugene C. Fiedorek Eugene C. Fiedorek	Director	February 28, 2013
/s/ A. D. Frazier, Jr. A. D. Frazier, Jr.	Director	February 28, 2013
/s/ Patricia Albjerg Graham Patricia Albjerg Graham	Director	February 28, 2013
/s/ Scott D. Josey Scott D. Josey	Director	February 28, 2013
/s/ Chansoo Joung Chansoo Joung	Director	February 28, 2013
/s/ John A. Kocur John A. Kocur	Director	February 28, 2013
/s/ George D. Lawrence George D. Lawrence	Director	February 28, 2013
/s/ William C. Montgomery William C. Montgomery	Director	February 28, 2013
/s/ Rodman D. Patton Rodman D. Patton	Director	February 28, 2013
/s/ Charles J. Pitman Charles J. Pitman	Director	February 28, 2013

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