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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2008
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from              to             
Commission File Number 0-13546
APACHE OFFSHORE INVESTMENT PARTNERSHIP
     
A Delaware   IRS Employer
General Partnership   No. 41-1464066
One Post Oak Central
2000 Post Oak Boulevard, Suite 100
Houston, Texas 77056-4400
Telephone Number (713) 296-6000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
PARTNERSHIP UNITS
   Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes o   No þ
   Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
   Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ   No o
   Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
   Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer o   Smaller reporting company þ
        (Do not check if a smaller reporting company)    
   Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o  No þ
         
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of December 31, 2008
   $ 16,342,701  
DOCUMENTS INCORPORATED BY REFERENCE:
   Portions of Apache Corporation’s proxy statement relating to its 2009 annual meeting of stockholders have been incorporated by reference into Part III hereof.
 
 

 

 

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 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
     All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily-prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion cubic feet (Bcf). Oil is quantified in terms of barrels (bbls), thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (bopd) and thousands of cubic feet of gas per day (Mcfd), respectively. With respect to information relating to the Partnership’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Partnership’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.

 

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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: David Higgins, or by telephone at 713-296-6690. 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, 2008, 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.

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     Under the terms of the joint venture agreement, the Partnership’s effective net revenue interest in the Matagorda Island Block 681 and 682 properties increased to 13.284 percent as a result of the acquisition, while its working interest was unchanged. The acquisition added approximately 7.5 Bcf of natural gas and 16 Mbbls of oil to the Partnership’s reserve base without any incremental expenditures by the Partnership.
     Since the Venture is not expected to acquire any additional exploratory acreage, future acquisitions, if any, will be confined to those leases defined as drainage tracts. The current Venture members would pay their proportionate share of acquiring any drainage tracts on a non-promoted basis.
     Offshore exploration differs from onshore exploration in that production from a prospect generally will not commence until a sufficient number of productive wells have been drilled to justify the significant costs associated with construction of a production platform. Exploratory wells usually are drilled from mobile platforms until there are sufficient indications of commercial production to justify construction of a permanent production platform.
     On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs.
     Apache, as Managing Partner, manages the Partnership’s operations. Apache uses a portion of its staff and facilities for this purpose and is reimbursed for actual costs paid on behalf of the Partnership, as well as for general, administrative and overhead costs properly allocable to the Partnership.
2008 Results and Business Development
     The Partnership reported net income in 2008 of $5.3 million, or $3,976 per Investing Partner Unit. Earnings were up $.5 million from 2007 on higher oil and gas prices. Natural gas production averaged 1,277 Mcf per day in 2008, while oil sales averaged 84 barrels per day.
     The Partnership participated in drilling one well in the North Padre island 969 Field during 2008. The well was unsuccessful in its initial evaluation and Apache and the Partnership elected not to participate in a sidetrack well proposed by the operator. The Partnership also participated in two recompletions in each of its Matagorda 681/682 and South Timbalier 295 fields during 2008. The two recompletions at Matagorda Island 681/682 were successful while the recompletions at South Timbalier 295 were unsuccessful.
     Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2008, 45 of those prospects have been surrendered or sold.
     As of December 31, 2008, the Partnership had 39 producing wells on the Partnership’s four remaining developed fields. Three of the Partnership’s producing wells are dual completions. The Partnership had, at December 31, 2008, estimated proved oil and gas reserves of 5.4 Bcfe, of which 45 percent was natural gas.
Marketing
     Apache, on behalf of the Partnership, seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. The objective is to maximize the value of the crude oil or natural gas sold by identifying the best markets and most economical transportation routes available to move the oil or natural gas. The oil contracts are generally thirty (30) day evergreen contracts and renew automatically until cancelled by either party. The Partnership’s oil and condensate production during 2008 was purchased largely by Shell Trading Company at market prices.
     The Managing Partner markets the Partnership’s and its own U.S. natural gas production. Most of Apache’s and the Partnership’s natural gas is sold on a monthly basis at either monthly or daily market prices. The Partnership believes that the sales prices it receives for natural gas sales are market prices.
     See Note (5) “Major Customer and Related Parties Information” to the Partnership’s financial statements under Item 8. Because the Partnership’s oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse affect on the Partnership’s business or results of operations. The Partnership is not in a position to predict future oil and gas prices.

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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.
The Partnership’s profitability and the carrying value of its properties is highly dependent on the prices of crude oil, natural gas and natural gas liquids, which have historically been very volatile.
     The Partnership’s estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and natural gas liquids, which are affected by numerous factors beyond its control. These prices have historically been very volatile and are likely to remain volatile in the future. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves.
     Under the full-cost method of accounting as allowed by the SEC, the Partnership is required to review the carrying value of its proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, plus the lower of the cost or fair value of unproved properties included in the costs being amortized. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal year and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. The Partnership did not require a write-down of its oil and gas properties at December 31, 2008. Write-downs required by these rules do not impact cash flow from operating activities. If oil and gas prices deteriorate from the Partnership’s year-end realized prices, it is possible that a write-down will occur in 2009.
Our ability to sell natural gas and/or receive market prices for our gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
     A portion of our natural gas and oil production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
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 a distribution in the first quarter of 2009 as capital outlays for drilling in North Padre Island 969 and the weather-related curtailment of production in the second half of 2008 has combined to reduce cash available for distributions. If commodity prices remain at or decline from levels realized at the end of 2008, the Partnership will significantly decrease distributions in other quarters in 2009 or make no distributions at all during 2009. Declines in cash from operating activities may reduce funds available for capital expenditures.
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;

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  •   equipment failures or accidents;
 
  •   fires, explosions, blow-outs and surface cratering;
 
  •   marine risks such as capsizing, collisions and hurricanes;
 
  •   other adverse weather conditions; and
 
  •   increase in cost of, or shortages or delays in the delivery of equipment.
     Future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Partnership is not likely to participate in exploratory drilling at this time.
Our operations are subject to governmental risks that may impact our operations.
     Our operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection laws and regulations. Such regulations may adversely impact our results on operations.
Uncertainty in calculating reserves; rates of production; development expenditures; cash flows.
     There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves of any category and in projecting future rates of production and timing of development expenditures, which underlie the reserve estimates, including many factors beyond the Partnership’s control. Reserve data represent only estimates. In addition, the estimates of future net cash flows from the Partnership’s proved reserves and their present value are based upon various assumptions about future production levels, prices and costs that may prove to be incorrect over time. Any significant variance from the assumptions could result in the actual quantity of the Partnership’s reserves and future net cash flows from them being materially different from the estimates. In addition, the Partnership’s estimated reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and gas prices, operating and development costs and other factors.
Weather and climate 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.
The Partnership may incur significant costs related to environmental matters.
     As an owner or lessee of interests in oil and gas properties, the Partnership is subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations.
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.

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The Partnership faces significant industry competition.
     The Partnership is a very minor participant in the oil and gas industry in the Gulf of Mexico area and faces strong competition from much larger producers for the marketing of its oil and gas. The Partnership’s ability to compete for purchasers and favorable marketing terms will depend on the general demand for oil and gas from Gulf of Mexico producers. More particularly, it will depend largely on the efforts of Apache to find the best markets for the sale of the Partnership’s oil and gas production.
Insurance policies do not cover all risks.
     Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.
ITEM 1B. UNRESOLVED STAFF COMMENTS
     The Partnership had no comments from the staff of the SEC that were unresolved as of the date of filing of this report.
ITEM 2. PROPERTIES
Acreage
     Acreage is held by the Partnership pursuant to the terms of various leases. 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, 2008, 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, 2008, 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, 2008, 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       23       1.63  
North Padre Island 969, 976
   TX     4       .28       —       —  
Matagorda Island 681, 682
   TX     4       .25       —       —  
 
                                        
 
             16       1.04       23       1.63  
 
                                        

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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
2008
     —       —       —       —       .07       .07  
2007
     —       —       —       —       —       —  
2006
     —       —       —       —       —       —  
Production and Pricing Data
     The following table describes, for each of the last three fiscal years, oil, natural gas liquids (NGLs) and gas production for the Partnership, average production costs (including gathering and transportation expense) and average sales prices.
                                                         
    Production   Average   Average Sales Prices
Year Ended   Oil   Gas   NGLs   Production   Oil   Gas   NGLs
December 31,   (Mbbls)   (MMcf)   (Mbbls)   Cost per Mcfe   (per Bbl)   (per Mcf)   (per Bbl)
2008
     31       468       6     $ 1.78     $ 110.61     $ 8.93     $ 60.32  
2007
     45       555       10       1.69       74.07       7.10       45.05  
2006
     55       795       16       1.08       65.39       7.58       38.59  
     See the Supplemental Oil and Gas Disclosures under Item 8 for estimated proved oil and gas reserves quantities.
Estimated Proved Reserves and Future Net Cash Flows
     As of December 31, 2008, the Partnership had total estimated proved reserves of 492,378 barrels of crude oil, condensate and NGLs and 2.4 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 5.4 Bcf of gas. Estimated proved developed reserves comprise 98 percent of the Partnership’s total estimated proved reserves on a Bcfe basis.
     Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if economical producibility is supported by either actual production or conclusive formation tests. 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 installed program in the reservoir provides support for the engineering analysis on which the project or program is based.
     Approximately 63 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 volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
     The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner.

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     The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2008, 2007 and 2006, 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 2008 Consolidated Financial Statements under Item 8 of this Form 10-K. These estimated future net cash flows are based on prices on the last day of the year and are calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10.
ITEM 3. LEGAL PROCEEDINGS
     There are no material legal proceedings pending to which the Partnership is a party or to which the Partnership’s interests are subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     There were no matters submitted to a vote of security holders during 2008.

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PART II
ITEM 5.   MARKET FOR THE PARTNERSHIP’S SECURITIES AND RELATED SECURITY HOLDER MATTERS
     As of December 31, 2008, there were 1,021.5 of the Partnership’s Units outstanding held by 856 investors of record. The Partnership has no other class of security outstanding or authorized. The Units are not traded on any security market. Cash distributions to Investing Partners totaled approximately $5.7 million, or $5,500 per Unit, during 2008 and approximately $4.2 million, or $4,000 per Unit, during 2007.
     As discussed in Item 7, an amendment to the Partnership Agreement in February 1994 created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash.
     On June 6, 2008, certain affiliates of MacKenzie Patterson Fuller, LP (Purchasers) announced a tender offer to purchase up to 207 Units for $13,850 per Unit, less the amount of any distributions declared or made with respect to the Units between June 6, 2008 and July 18, 2008 (the offer expiration date). After resolution of an issue regarding an improperly submitted Unit, the offer resulted in the tender, and the acceptance for payment by the Purchasers, of a total of 6.1728 Units. Upon completion of the offer, the Purchasers hold an aggregate of 6.1728 Units, or approximately 0.6 percent of the total Investing Partner outstanding Units.
ITEM 6. SELECTED FINANCIAL DATA
     The following selected financial data for the five years ended December 31, 2008, 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,  
    2008     2007     2006     2005     2004  
    (In thousands, except per Unit amounts)  
Total assets
   $ 6,680     $ 8,308     $ 8,629     $ 11,624     $ 12,215  
 
                              
Partners’ capital
   $ 5,191     $ 6,960     $ 7,625     $ 10,311     $ 11,293  
 
                              
Oil and gas sales
   $ 7,928     $ 7,679     $ 10,255     $ 14,779     $ 13,874  
 
                              
Net income
   $ 5,335     $ 4,834     $ 7,149     $ 11,048     $ 9,591  
 
                              
 
                                        
Net income allocated to:
                                        
Managing Partner
   $ 1,229     $ 1,146     $ 1,702     $ 2,555     $ 2,407  
Investing Partners
     4,106       3,688       5,447       8,493       7,184  
 
                              
 
   $ 5,335     $ 4,834     $ 7,149     $ 11,048     $ 9,591  
 
                              
 
                                        
Net income per Investing Partner Unit
   $ 3,976     $ 3,531     $ 5,178     $ 8,048     $ 6,786  
 
                              
 
                                        
Cash distributions per Investing Partner Unit
   $ 5,500     $ 4,000     $ 7,500     $ 9,000     $ 6,000  
 
                              

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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 Partnership derives its revenue from the production and sale of crude oil, natural gas and natural gas liquids. The Partnership sells its production at market prices and has not used derivative financial instruments or otherwise engaged in hedging activities. Oil prices rose to historically high levels in 2008 as a result of geopolitical tensions, rising demand from developing nations, hedge fund trading, and supply and demand concerns, but declined dramatically in the fourth quarter of 2008 as the economies of the United States and other countries slowed significantly. Gas prices also rose to historically high levels in 2008 before declining significantly during the fourth quarter of 2008. Oil and gas prices continued to decline during the first part of 2009. Commodity prices remain volatile and have at times fluctuated significantly from month to month. This volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate widely over the years. The Partnership’s oil and gas production has declined in each of the last two years and is expected to continue to decline with Partnership’s limited capital expenditures.
     Since all of the Partnership’s properties are located in the Gulf of Mexico, its operations and cash flow can be significantly impacted by hurricanes and other inclement weather. These events may also have detrimental impact on third-party pipelines and processing facilities, which the Partnership relies upon to transport and process the crude oil and natural gas it produces. During the third quarter of 2008, two hurricanes struck in the Gulf of Mexico which significantly impacted the Partnership’s operations. These two storms, Hurricanes Gustav and Ike, came ashore in Louisiana and Texas, respectively, and caused production curtailments as the storms damaged third-party pipelines and disrupted the operations of crews which could assess and repair damage to the Partnership’s or other’s facilities. While the Partnership’s platforms avoided major damage, the Partnership’s production was curtailed from the time personnel were evacuated for safety purposes, through assessment and repair to the Partnership’s platforms and repairs to third-party pipelines and facilities. In all, South Timbalier 295 was shut-in for 112 days and Ship Shoal 258/259 was shut-in for 61 days as a result of the two hurricanes and time to repair damage to platforms and third-party pipelines. The hurricanes reduced the Partnership’s average daily oil and gas production for 2008 by approximately 33 barrels per day and 155 Mcf per day, respectively.
     The Partnership participates in development drilling and recompletion activities as recommended by outside operators and the Partnership’s Managing Partner. The Partnership participated in drilling one well in the North Padre Island 969 field during 2008. The well was unsuccessful in its initial evaluation and Apache and the Partnership elected not to participate in a sidetrack well proposed by the operator. The Partnership also participated in two recompletions in each of its Matagorda 681/682 and South Timbalier 295 fields during 2008. The two recompletions at Matagorda Island 681/682 were successful while the recompletions at South Timbalier 295 were unsuccessful
     Generally, the Partnership has used its available cash to fund distributions to its Partners. Reflecting the significant impact of higher prices during the first three quarters of 2008 on net income and cash from operating activities, distributions to Investing Partners increased to $5,500 per Unit in 2008, up 38 percent from 2007. Distributions to Investing Partners decreased to $4,000 per Unit in 2007 from $7,500 in 2006.
     The Partnership is not likely to make a distribution in the first quarter of 2009 as capital outlays for drilling in North Padre Island 969 and the weather-related curtailment of production in the second half of 2008 has combined to reduce cash available for distributions. If commodity prices remain at or decline from levels realized at the end of 2008, the Partnership will significantly decrease distributions in other quarters in 2009 or make no distributions at all during 2009.

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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 2008, 2007, and 2006.
Net Income and Revenue
     The Partnership reported net income of $5.3 million for 2008, up 10 percent from 2007 on higher oil and gas prices. Net income per Investing Partner Unit increased in 2008 to $3,976, up from $3,531 in 2007. The Partnership reported earnings of $4.8 million in 2007 and $7.1 million in 2006.
     Total revenues in 2008 of $8.0 million increased $0.2 million from 2007 as a result of higher oil and gas prices. Interest income earned by the Partnership on short-term cash investments in 2008 of $46,193 decreased 56 percent from 2007 as a result of lower cash balances and interest rates in 2008. Interest income totaled $104,274 in 2007 and $158,140 in 2006.
     The Partnership’s revenues are sensitive to changes in prices received for its products. A substantial portion of the Partnership’s production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on the prices we receive for our production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.
     Declines in oil and gas production can be expected in future years as a result of normal depletion. Given the small number of producing wells owned by the Partnership, and the fact that offshore wells tend to decline at a faster rate than onshore wells, the Partnership’s future production will be subject to more volatility than those companies with greater reserves and longer-lived properties. It is not anticipated that the Partnership will acquire any additional exploratory leases or that significant drilling will take place on leases in which the Partnership currently holds interests.
     The Partnership’s oil and gas production volume and price information is summarized in the following table:
                         
    For the Year Ended December 31,
    2008   2007   2006
Gas volumes — Mcf per day
     1,277       1,520       2,178  
Average gas price — per Mcf
   $ 8.93     $ 7.10     $ 7.58  
Oil volumes — barrels per day
     84       122       152  
Average oil price — per barrel
   $ 110.61     $ 74.07     $ 65.39  
NGL volumes — barrels per day
     16       26       43  
Average NGL price — per barrel
   $ 60.32     $ 45.05     $ 38.59  
Year 2008 Compared to Year 2007
Natural Gas and Crude Oil Sales
     The Partnership’s natural gas sales in 2008 of $4.2 million increased six percent from the same period in 2007. During 2008, the Partnership’s average realized gas price increased 26 percent or $1.83 per Mcf over the same period in 2007, rising to $8.93 per Mcf. With extended downtime resulting from Hurricanes Gustav and Ike and natural depletion, the Partnership’s natural gas production declined 16 percent from 2007 to a daily average of 1,277 Mcf per day in 2008. Ship Shoal 258/259 was shut in from late August through late October and South Timbalier was shut in from late August until late December as a result of downtime for the hurricanes and repairs to third-party pipelines. Hurricanes Gustav and Ike reduced natural gas sales approximately 155 Mcf per day, while natural depletion contributed approximately 88 Mcf per day to the decline in natural gas volumes from 2007.
     Crude oil sales in 2008 totaled $3.4 million, up two percent from the same period in 2007 on higher oil prices. The Partnership’s average realized oil price for the year increased 49 percent to a record $110.61 per barrel. The Partnership’s realized oil price reached a high of $135.51 per barrel in June 2008 before declining to approximately $40.00 per barrel at the end of December 2008. Crude oil sales volumes in 2008 declined 31 percent from 2007 primarily as a result of South Timbalier 295 being shut in for nearly one-third of the year for downtime for

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Hurricanes Gustav and Ike and damage to a third-party pipeline caused by Hurricane Ike. Oil production from South Timbalier commenced flowing in late December as repairs were completed to the third-party sales line.
Operating Expenses
     The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 11 percent during 2008, down slightly from the 13 percent in 2007. The decline in rate as a percentage of sales reflected favorable reserve revisions booked in the fourth quarter of 2007, lower net amortizable cost and higher oil and gas prices boosting 2008 oil and gas sales. Lease operating expenses (LOE) decreased 17 percent from the previous year on lower repair and maintenance costs at North Padre Island 969. Accretion on asset retirement obligations increased from $44,522 in 2007 to $63,489 in 2008 with the increase in provision for estimated future plugging cost during late 2007. Gathering and transportation costs decreased 28 percent from 2007 levels reflecting the decrease in sales volumes for the period. Administrative expense for the year increased slightly for the year to $451,154 as a result of legal costs associated with a third-party tender offer described under Part II, Item 5 of this Annual Report on Form 10-K.
     The Partnership sells oil and natural gas under two types of transactions, both of which include a transportation charge. One is a netback arrangement, under which the Partnership sells oil or natural gas as the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Partnership records sales at the price received from the purchaser which is net of transportation costs. Under the other arrangement, the Partnership sells oil or natural gas at a specific delivery point, pays transportation to a carrier and receives from the purchaser a price with no transportation deduction. In this case, the Partnership records the transportation cost as gathering and transportation costs. The Partnership’s treatment of transportation costs is pursuant to Emerging Issues Task Force Issue 00-10, “Accounting or Shipping and Handling Fees and Costs” and as a result a portion of our transporting costs are reflected in sales prices and a portion is reflected as transportation and gathering costs.
Year 2007 Compared to Year 2006
Natural Gas and Crude Oil Sales
     In 2007, the Partnership’s natural gas sales totaled $4.0 million, down 35 percent from 2006 on lower volumes and prices. Average daily production in 2007 declined 30 percent from 2006 as a result of natural depletion, dropping to 1,520 Mcf per day in 2007. While the Partnership’s natural gas volumes were negatively impacted by 76 days of downtime for third-party pipeline repairs at Matagorda Island 681/682 during 2007, the field was curtailed 102 days in 2006 for pipeline repairs and maintenance. Reflecting higher natural gas storage levels in the United States, the Partnership’s average realized gas price declined six percent to $7.10 per Mcf in 2007.
     Crude oil sales in 2007 totaled $3.3 million, down nine percent from the same period a year ago. The 2007 crude oil sales volumes declined 19 percent from 2006 primarily as a result of natural depletion at South Timbalier 295. The production decline was partially offset by 13 percent increase in the average realized price from 2006. The Partnership’s realized oil price reached a high of $95.05 per barrel in November 2007 and averaged a historically high $74.07 for the full year of 2007.
Operating Expenses
     The Partnership’s DD&A rate, expressed as a percentage of oil and gas sales, was approximately 13 percent during 2007, down from 14 percent in 2006. The slight decline in rate reflected favorable reserve revisions in 2007 which were largely driven by higher oil prices. LOE increased 18 percent over the previous year on higher repair and maintenance costs and overall cost increases. Gathering and transportation costs decreased from 2006 levels reflecting the decrease in sales volumes in 2007. Administrative expense for the year decreased slightly from 2006 to $416,000.
Capital Resources and Liquidity
     The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $6.4 million for 2008. The Partnership’s 2008 net cash provided by operating activities increased $0.3 million, or five percent, from a year ago as a result of higher oil and gas prices. Net cash provided by operating activities in 2007 of $6.1 million declined 40 percent from 2006 on lower oil and gas volumes.

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     The Partnership’s future financial condition, results of operations and cash from operating activities will largely depend upon prices received for its oil and natural gas production. A substantial portion of the Partnership’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Partnership’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.
     The Partnership’s oil and gas reserves and production will also significantly impact future results of operations and cash from operating activities. The Partnership’s production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can be expected in future years as a result of normal depletion and the Partnership not participating in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership expects it will be able to meet its liquidity needs for routine operations in the foreseeable future.
     Approximately 63 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves and that the estimated reserves from these projects are based on prices at December 31, 2008. The Partnership’s liquidity may be negatively impacted if the actual quantities of reserves that are ultimately produced are materially different from current estimates. Also, if prices decline significantly from current levels, the Partnership may not be able to fund the necessary capital investment, or development of the remaining reserves may not be economical for the Partnership.
     The Partnership may reduce capital expenditures or distributions to partners, or both, as cash from operating activities decline. In the event that future short-term operating cash requirements are greater than the Partnership’s financial resources, the Partnership may seek short-term, interest-bearing advances from the Managing Partner as needed. The Managing Partner, however, is not obligated to make loans to the Partnership. The Partnership does not intend to incur debt from banks or other outside sources or solicit capital from exiting Unit holders or in the open market.
     On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment cost. The Partnership did not sell any properties in 2008, 2007 or 2006.
Capital Commitments
     The Partnership’s primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. The Partnership had no outstanding debt or lease commitments at December 31, 2008. The Partnership did not have any contractual obligations as of December 31, 2008, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for the fair value of this asset retirement obligation (ARO) as discussed under the discussion of critical accounting policies noted below.
     During 2008, the Partnership’s oil and gas property expenditures totaled $1.0 million. The Partnership participated in drilling one well in the North Padre island 969 Field during 2008. The well was unsuccessful in its initial evaluation and Apache and the Partnership elected not to participate in a sidetrack well proposed by the operator. The Partnership also participated in two recompletions in each of its Matagorda 681/682 and South Timbalier 295 fields during 2008. The two recompletions at Matagorda Island 681/682 were successful while the recompletions at South Timbalier 295 were unsuccessful. During 2007, the Partnership’s oil and gas property expenditures totaled less than $0.2 million as the Partnership did not participate in any drilling or recompletion projects in 2007. During 2006, the Partnership’s oil and gas property expenditures totaled less than $0.01 million as the Partnership did not participate in any drilling or recompletion projects in 2006.

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     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 $0.9 million in 2009. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by drilling contractors or changes by the operator to the development plan.
     During 2008, distributions of $5.7 million, or $5,500 per Unit, were paid to Investing Partners. Distributions of $4,000 per Unit and $7,500 per Unit were made to Partners during 2007 and 2006, respectively, resulting in total distribution to Limited Partners of $4.2 million in 2007 and $7.9 million in 2006. The amount of future distributions will be dependent on actual and expected production levels, realized and expected oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted.
     The Partnership is not likely to make a distribution in the first quarter of 2009 as capital outlays for drilling in North Padre Island 969 and the weather-related curtailment of production in the second half of 2008 has combined to reduce cash available for distributions. The Partnership intends to maintain cash and cash equivalents in the Partnership at least sufficient to cover the discounted value of its future asset retirement obligations.
     In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. In 2008, the first right of presentment offer of $13,225 per Unit, plus interest to the date of payment, was made to Investing Partners based on a December 31, 2007 valuation date. The second right of presentment offer of $13,245 per Unit was made to the Investing Partners based a valuation date of June 30, 2008. As a result, the Partnership acquired 16.7 units for a total of $228,995. In 2007 and 2006, Investing Partners were paid $124,512 and $57,312, respectively, for a total of 15.2 Units.
     There will be two rights of presentment in 2009, but the Partnership is not in a position to predict how many Units will be presented for repurchase and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase Units. The Amended Partnership Agreement contains limitations on the number of Units that the Partnership can repurchase, including an annual limit on repurchases of 10 percent of outstanding Units. The Partnership has no obligation to repurchase any Units presented to the extent that it determines that it has insufficient funds for such repurchases. The Partnership is not likely to have funds available to repurchase Units during the first half of 2009.
Off-Balance Sheet Arrangements
     The Partnership does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership.
Critical Accounting Policies and Estimates
     The 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. The following details the more significant accounting policies, estimates and judgments of the Partnership. Additional accounting policies and estimates made by management are discussed in Note 2 of Item 8 of this Form 10-K.
Full Cost Method of Accounting for Oil and Gas Operations
     The accounting for the Partnership’s business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full cost method. There are several significant differences between these methods. Under the successful efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to oil and gas properties. In the measurement of impairment of oil and gas properties, the successful efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, where the first measurement for impairment is

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to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect at the end of the reporting period. If the full cost pool is in excess of the ceiling limitation, the excess amount is charged through income.
     The Partnership has elected to use the full cost method to account for its investment in oil and gas properties. Under this method, the Partnership capitalizes all acquisition, exploration and development costs for the purpose of finding oil and gas reserves. Although some of these costs will ultimately result in no additional reserves, it expects the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized cost and the proved oil and gas reserves of the Company. As a result, the Partnership believes that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. The Partnership’s financial position and results of operations would have been significantly different had it used the successful efforts method of accounting for oil and gas investments. Generally, the application of the full-cost method of accounting for oil and gas property results in higher capitalized costs and higher depletion, depreciation and amortization rates compared to similar companies applying the successful efforts method of accounting.
Reserve Estimates
     The Partnership’s estimate of proved reserves are based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, engineers must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership’s reserves.
     Despite the inherent imprecision in these engineering estimates, the Partnership’s reserves have a significant impact on its financial statements. For example, the quantity of reserves could significantly impact the Partnership’s DD&A expense. The Partnership’s oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. These reserves are the basis for our supplemental oil and gas disclosures.
     The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner.
Asset Retirement Obligation (ARO)
     The Partnership has obligations to remove tangible equipment and restore the land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership’s limited operations and estimate of remaining reserves. The Partnership’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
     Asset retirement obligations associated with retiring tangible long-lived assets, are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable. This liability is offset by a corresponding increase in the carrying amount of the underlying asset. The 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, weather and climate, and governmental risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
     The Partnership’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. During 2008, monthly oil price realizations ranged from a low of $34.61 per barrel to a high of $135.61 per barrel. Gas price realizations ranged from a monthly low of $6.08 per Mcf to a monthly high of $12.77 per Mcf during the same period. Based on the Partnership’s average daily production for 2008, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $31,000 and a $.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $47,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2008. Due to the volatility of commodity prices, the Partnership is not in a position to predict future oil and gas prices.
     If oil and gas prices decline significantly in the future, even if only for a short period of time, it is possible that non-cash write-downs of the Partnership’s oil and gas properties could occur under the full cost accounting rules of the SEC. Under these rules, the Partnership reviews the carrying value of its proved oil and gas properties each quarter to ensure the capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization do not exceed the “ceiling”. This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent. If capitalized costs exceed this limit, the excess is charged to additional DD&A expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.
     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.
     The Partnership’s operations have been, and at times in the future may be, affected by political developments and by federal, state, local and provincial laws and regulations impacting production levels, taxes, environmental requirements and other assessments including a potential Windfall Profits Tax. See Item 1A — “Risk Factors” in this Form 10-K, for further discussion.
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, 2008 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.

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Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
  •   the market prices of oil, natural gas, NGLs and other products or services;
 
  •   the supply and demand for oil, natural gas, NGLs and other products or services;
 
  •   production and reserve levels;
 
  •   drilling risks;
 
  •   economic and competitive conditions;
 
  •   the availability of capital resources;
 
  •   capital expenditure and other contractual obligations;
 
  •   weather conditions;
 
  •   inflation rates;
 
  •   the availability of goods and services;
 
  •   legislative or regulatory changes;
 
  •   terrorism;
 
  •   the capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and
 
  •   other factors disclosed under Items 1 and 2 — “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A — “Risk Factors,” Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this Form 10-K.
All subsequent written and oral forward-looking statements attributable to the Partnership, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
APACHE OFFSHORE INVESTMENT PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS
     
    Page
    Number
  18
  19
  20
  21
  22
  23
  24
  31
  33
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.

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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, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2008.
G. Steven Farris
Chairman and Chief Executive Officer
(principal executive officer)
of Apache Corporation, Managing Partner
Roger B. Plank
President (principal financial officer)
of Apache Corporation, Managing Partner
Rebecca A. Hoyt
Vice President and Controller
(principal accounting officer)
of Apache Corporation, Managing Partner
Houston, Texas
February 27, 2009

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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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
ERNST & YOUNG LLP
Houston, Texas
February 27, 2009

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
                         
    For the Year Ended December 31,  
    2008     2007     2006  
REVENUES:
                        
Oil and gas sales
   $ 7,927,690     $ 7,679,104     $ 10,254,559  
Interest income
     46,193       104,274       158,140  
 
                  
 
                        
 
     7,973,883       7,783,378       10,412,699  
 
                  
 
                        
OPERATING EXPENSES:
                        
Depreciation, depletion and amortization
     901,633       998,826       1,482,299  
Asset retirement obligation accretion
     63,489       44,522       42,002  
Lease operating expenses
     1,153,688       1,393,734       1,183,159  
Gathering and transportation costs
     69,022       96,082       137,448  
Administrative
     451,154       416,000       419,000  
 
                  
 
                        
 
     2,638,986       2,949,164       3,263,908  
 
                  
 
                        
NET INCOME
   $ 5,334,897     $ 4,834,214     $ 7,148,791  
 
                  
 
                        
NET INCOME ALLOCATED TO:
                        
Managing Partner
   $ 1,228,783     $ 1,145,720     $ 1,702,177  
Investing Partners
     4,106,114       3,688,494       5,446,614  
 
                  
 
                        
 
   $ 5,334,897     $ 4,834,214     $ 7,148,791  
 
                  
 
                        
NET INCOME PER INVESTING PARTNER UNIT
   $ 3,976     $ 3,531     $ 5,178  
 
                  
 
                        
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING
     1,032.7       1,044.5       1,051.9  
 
                  
The accompanying notes to financial statements are
an integral part of this statement.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
                         
    For the Year Ended December 31,  
    2008     2007     2006  
CASH FLOWS FROM OPERATING ACTIVITIES:
                        
Net income
   $ 5,334,897     $ 4,834,214     $ 7,148,791  
Adjustments to reconcile net income to net cash provided by operating activities:
                        
Depreciation, depletion and amortization
     901,633       998,826       1,482,299  
Asset retirement obligation accretion
     63,489       44,522       42,002  
Changes in operating assets and liabilities:
                        
Decrease in accrued revenues receivable
     31,441       170,918       902,563  
Increase (decrease) in accrued operating expense
     (139,712 )     150,712       27,041  
Increase (decrease) in receivable/payable from Apache Corporation
     195,645       (123,581 )     531,823  
 
                  
 
                        
Net cash provided by operating activities
     6,387,393       6,075,611       10,134,519  
 
                  
 
                        
CASH FLOWS FROM INVESTING ACTIVITIES:
                        
Additions to oil and gas properties
     (956,051 )     (153,814 )     (369 )
Increase (decrease) in accrued development cost
     22,629       —       (551,324 )
 
                  
 
                        
Net cash used in investing activities
     (933,422 )     (153,814 )     (551,693 )
 
                  
 
                        
CASH FLOWS FROM FINANCING ACTIVITIES:
                        
Repurchase of Partnership Units
     (228,995 )     (124,512 )     (57,312 )
Distributions to Investing Partners
     (5,679,725 )     (4,184,610 )     (7,895,978 )
Distributions to Managing Partner
     (1,195,521 )     (1,189,789 )     (1,882,190 )
 
                  
 
                        
Net cash used in financing activities
     (7,104,241 )     (5,498,911 )     (9,835,480 )
 
                  
 
                        
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
     (1,650,270 )     422,886       (252,654 )
 
                        
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR
     2,781,885       2,358,999       2,611,653  
 
                  
 
                        
CASH AND CASH EQUIVALENTS, END OF YEAR
   $ 1,131,615     $ 2,781,885     $ 2,358,999  
 
                  
The accompanying notes to financial statements are
an integral part of this statement.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
                 
    December 31,  
    2008     2007  
ASSETS
                
 
                
CURRENT ASSETS:
                
Cash and cash equivalents
   $ 1,131,615     $ 2,781,885  
Accrued revenues receivable
     330,818       362,259  
 
            
 
     1,462,433       3,144,144  
 
            
 
                
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
                
Proved properties
     186,955,531       185,999,480  
Less — Accumulated depreciation, depletion and amortization
     (181,737,546 )     (180,835,913 )
 
            
 
     5,217,985       5,163,567  
 
            
 
   $ 6,680,418     $ 8,307,711  
 
            
 
                
LIABILITIES AND PARTNERS’ CAPITAL
                
 
                
CURRENT LIABILITIES:
                
Accrued operating expense
   $ 98,606     $ 238,318  
Accrued exploration and development
     22,629       —  
Payable to Apache Corporation
     246,617       50,972  
 
            
 
     367,852       289,290  
 
            
 
                
ASSET RETIREMENT OBLIGATION
     1,121,808       1,058,319  
 
            
 
                
COMMITMENTS AND CONTINGENCIES (Note 7)
                
 
                
PARTNERS’ CAPITAL:
                
Managing Partner
     64,465       31,203  
Investing Partners (1,021.5 and 1,038.2 Units outstanding, respectively)
     5,126,293       6,928,899  
 
            
 
     5,190,758       6,960,102  
 
            
 
   $ 6,680,418     $ 8,307,711  
 
            
The accompanying notes to financial statements are
an integral part of this statement.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL
                         
    Managing     Investing        
    Partner     Partners     Total  
BALANCE, DECEMBER 31, 2005
   $ 255,285     $ 10,056,203     $ 10,311,488  
 
                        
Distributions
     (1,882,190 )     (7,895,978 )     (9,778,168 )
 
                        
Repurchase of Partnership Units
     —       (57,312 )     (57,312 )
 
                        
Net income
     1,702,177       5,446,614       7,148,791  
 
                  
 
                        
BALANCE, DECEMBER 31, 2006
   $ 75,272     $ 7,549,527     $ 7,624,799  
 
                        
Distributions
     (1,189,789 )     (4,184,610 )     (5,374,399 )
 
                        
Repurchase of Partnership Units
     —       (124,512 )     (124,512 )
 
                        
Net income
     1,145,720       3,688,494       4,834,214  
 
                  
 
                        
BALANCE, DECEMBER 31, 2007
   $ 31,203     $ 6,928,899     $ 6,960,102  
 
                        
 
                        
Distributions
     (1,195,521 )     (5,679,725 )     (6,875,246 )
 
                        
Repurchase of Partnership Units
     —       (228,995 )     (228,995 )
 
                        
Net income
     1,228,783       4,106,114       5,334,897  
 
                  
 
                        
BALANCE, DECEMBER 31, 2008
   $ 64,465     $ 5,126,293     $ 5,190,758  
 
                  
The accompanying notes to financial statements are
an integral part of this statement.

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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, 2008. 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 (through the same date, 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, 2008, 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. With natural gas accounting for 68 percent of the Partnership’s 2008 production on an energy equivalent basis, the Partnership is affected more by fluctuations in natural gas prices than in oil prices.
     Under the terms of the Partnership Agreements, the Investing Partners receive 80 percent and Apache receives 20 percent of revenue. Lease operating, gathering and transportation and administrative expenses are allocated to the Investing Partners and Apache in the same proportion as revenues. The Investing Partners receive 100 percent of the interest income earned on short-term cash investments. The Investing Partners generally pay for 90 percent and Apache generally pays for 10 percent of exploration and development costs and expenses incurred by the Partnership. However, intangible drilling costs, interest costs and fees or expenses related to the loans incurred by the Partnership are allocated 99 percent to the Investing Partners and one percent to Apache until such time as the amount so allocated to the Investing Partners equals 90 percent of the total amount of such costs, including such costs incurred by Apache prior to the formation of the Partnerships.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Right of Presentment —
     An amendment to the Partnership Agreements adopted in February 1994, created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. In 2008, the first right of presentment offer of $13,225 per Unit, plus interest to the date of payment, was made to Investing Partners based on a December 31, 2007 valuation date. The second right of presentment offer of $13,245 per Unit was made to the Investing Partners based a valuation date of June 30, 2008. As a result the Partnership acquired 16.7 units for a total of $228,995. In 2007 and 2006, Investing Partners were paid $124,512 and $57,312, respectively, for a total of 15.2 Units.
     The Partnership is not in a position to predict how many Units will be presented for repurchase during 2009, however, no more than 10 percent of the outstanding Units may be purchased under the right of presentment in any year. The Partnership has no obligation to purchase any Units presented to the extent that it determines that it has insufficient funds for such purchases.
     The table below sets forth the total repurchase price and the repurchase price per Unit for all outstanding Units at each presentment period, based on the right of presentment valuation formula defined in the amendment to the Partnership Agreement. The right of presentment offers made twice annually are based on a discounted Unit value formula. The discounted Unit value will be not less than the Investing Partner’s share of: (a) the sum of (i) 70 percent of the discounted estimated future net revenues from proved reserves, discounted at a rate of 1.5 percent over prime or First National Bank of Chicago’s base rate in effect at the time the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv) accounts receivable less a reasonable reserve for doubtful accounts, (v) oil and gas properties other than proved reserves at cost less any amounts attributable to drilling and completion costs incurred by the Partnership and included therein, and (vi) the book value of all other assets of the Partnership, less the debts, obligations and other liabilities of all kinds (including accrued expenses) then allocable to such interest in the Partnership, all determined as of the valuation date, divided by (b) the number of Units, and fractions thereof, outstanding as of the valuation date. The discounted Unit value does not purport to be, and may be substantially different from, the fair market value of a Unit.
                 
Right of Presentment   Total Repurchase   Repurchase Price
      Valuation Date   Price   Per Unit
December 31, 2005
   $ 17,123,974     $ 12,756  
June 30, 2006
     14,748,744       10,016  
December 31, 2006
     15,207,303       12,507  
June 30, 2007
     13,866,608       11,282  
December 31, 2007
     15,806,599       13,225  
June 30, 2008
     17,239,136       13,245  
                         
Investing Partner Units Outstanding:   2008   2007   2006
Balance, beginning of year
     1,038.2       1,048.3       1,053.4  
Repurchase of Partnership Units
     (16.7 )     (10.1 )     (5.1 )
 
                        
 
                        
Balance, end of year
     1,021.5       1,038.2       1,048.3  
 
                        
Capital Contributions —
     A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2008. 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, 2008.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by the Partnership reflect industry practices and conform to accounting principles generally accepted in the United States (GAAP). Significant policies are discussed below.
Statement Presentation —
     The accompanying consolidated financial statements include the accounts of Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions.
Cash Equivalents —
     The Partnership considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Oil and Gas Properties —
     The Partnership uses the full cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. Costs associated with production and administrative functions are expensed in the period incurred. The Partnership includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance as described in Note 8. Unless a significant portion of the Partnership’s reserve volumes are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains or losses are not recognized.
     Capitalized costs of oil and gas properties are amortized on the future gross revenue method whereby depreciation, depletion and amortization (DD&A) expense is computed quarterly by dividing current period oil and gas sales by estimated future gross revenue from proved oil and gas reserves (including current period oil and gas sales) and applying the resulting rate to the net cost of evaluated oil and gas properties, including estimated future development costs.
     Under the full-cost method of accounting, the Partnership limits the capitalized costs of proved oil and gas properties, net of accumulated DD&A, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, if any. This ceiling test is performed each quarter. If capitalized costs exceed this limit, the excess is charged to DD&A expense. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. Please see “Future Net Cash Flows” in the Supplemental Oil and Gas Disclosures included in this Form 10-K for a discussion on calculation of estimated future net cash flows.
     Given the volatility of oil and gas prices, it is reasonably possible that the Partnership’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenue Recognition —
     Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. The Partnership uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. As of December 31, 2008 and 2007, 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, 2008, 2007 and 2006.
Net Income Per Investing Unit —
     The net income per Investing Partner Unit is calculated by dividing the aggregate Investing Partners’ net income for the period by the number of weighted average Investing Partner Units outstanding for that period.
Income Taxes —
     The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.
Use of Estimates —
     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. (See the unaudited “Supplemental Oil and Gas Disclosures” below), asset retirement obligations and contingency obligations.
Payable to Apache Corporation —
     The payable to Apache represents the net result of the Investing Partners’ revenue and expenditure transactions in the current month. Generally, cash in this amount will be paid by Apache to the Partnership 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.
Shipping and Handling Costs —
     To comply with the consensus reached on Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs”, third party gathering and transportation costs have been reported as an operating cost instead of a reduction of revenues.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(3) COMPENSATION TO APACHE
     Apache is entitled to the following types of compensation and reimbursement for costs and expenses.
                                 
            Total Reimbursed by the Investing Partners  
            for the Year Ended December 31,  
            2008     2007     2006  
            (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
   $ 361     $ 333     $ 335  
       
 
                  
  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
   $ 26     $ 7     $ —  
       
 
                  
     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.
                         
    2008     2007     2006  
    (In thousands)  
Oil and Gas Properties
                        
 
                        
Balance, beginning of year
   $ 185,999     $ 185,574     $ 185,574  
Costs incurred during the year:
                        
Development —
                        
Investing Partners
     939       319       —  
Managing Partner
     17       106       —  
 
                  
 
                        
Balance, end of year
   $ 186,955     $ 185,999     $ 185,574  
 
                  
                         
    Managing     Investing        
    Partner     Partners     Total  
    (In thousands)  
Accumulated Depreciation, Depletion and Amortization
                        
 
                        
Balance, December 31, 2005
   $ 20,892     $ 157,463     $ 178,355  
Provision
     1       1,481       1,482  
 
                  
 
                        
Balance, December 31, 2006
   $ 20,893     $ 158,944     $ 179,837  
Provision
     4       995       999  
 
                  
 
                        
Balance, December 31, 2007
   $ 20,897     $ 159,939     $ 180,836  
Provision
     16       886       902  
 
                  
 
                        
Balance, December 31, 2008
   $ 20,913     $ 160,825     $ 181,738  
 
                  
     The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2008, 2007 and 2006 was 11 percent, 13 percent and 14 percent, respectively.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION
     Revenues received from major third party customers that exceeded ten percent of oil and gas sales are discussed below. No other third party customers individually accounted for more than ten percent of oil and gas sales.
     In 2008, sales to Shell Trading Company and Plains Marketing LP accounted for 27 percent and 16 percent, respectively, of the Partnership’s oil and gas sales. Sales to Shell Trading Company accounted for 35 percent of the Partners oil and gas sales in 2007. Sales to Plains Marketing LP and Morgan Stanley Capital Group accounted for 32 percent and 20 percent, respectively, of the Partnership’s oil and gas sales in 2006.
     Effective November 1992, with Apache’s and the Partnership’s acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees of $19,124 in 2008. The partnership paid the Apache subsidiary transportation fees totaling $4,248 in 2007 and $7,676 in 2006 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) FINANCIAL INSTRUMENTS
     The carrying amount of cash and cash equivalents, accrued revenues receivables and accrued costs included in the accompanying balance sheet approximated their fair values at December 31, 2008 and 2007 due to their short maturities. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2008.
(7) COMMITMENTS AND CONTINGENCIES
     Litigation — The Partnership is involved in litigation and is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache’s management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations.
     Environmental — The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. Apache maintains insurance coverage on the Partnership’s properties, which it believes, is customary in the industry, although it is not fully insured against all environmental risks.
(8) ASSET RETIREMENT OBLIGATION
     Asset retirement obligations (ARO) associated with the retirement of a tangible long-lived asset are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable. The liability is offset by an increase in the carrying amount of the associated asset. The cost of the tangible asset is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company’s credit-adjusted risk-free interest rate.
     Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
     The following table is a reconciliation of the asset retirement obligation liability:
                 
    2008     2007  
Asset retirement obligation at beginning of period
   $ 1,058,319     $ 742,156  
Accretion expense
     63,489       44,522  
Revisions in estimated liabilities
     —       271,641  
 
            
 
                
Asset retirement obligation at December 31
   $ 1,121,808     $ 1,058,319  
 
            
(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:
                         
    2008     2007     2006  
Net partnership ordinary income for federal income tax reporting purposes
   $ 5,184,702     $ 5,475,029     $ 8,176,253  
 
                        
Plus: Items of current expense for tax reporting purposes only —
                        
 
                        
Intangible drilling cost
     851,644       35,699       43,739  
Tax depreciation
     263,673       366,834       453,100  
 
                  
 
     1,115,317       402,533       496,839  
 
                  
 
                        
Less: full cost DD&A expense
     (901,633 )     (998,826 )     (1,482,299 )
Less: asset retirement obligation accretion
     (63,489 )     (44,522 )     (42,002 )
 
                  
 
                        
Net income
   $ 5,334,897     $ 4,834,214     $ 7,148,791  
 
                  
     The Partnership’s tax bases in net oil and gas properties at December 31, 2008 and 2007 was $3,160,711 and $2,879,179, respectively, lower than carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2008 and 2007.
     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,  
    2008     2007  
Liabilities for federal income tax purposes
   $ 367,852     $ 289,920  
Asset retirement liability
     1,121,808       1,058,319  
 
            
 
                
Liabilities under accounting principles generally accepted in the United States
   $ 1,489,660     $ 1,348,239  
 
            
     Asset retirement liabilities for future dismantlement and abandonment costs are not recognized for federal income tax reporting purposes until settled.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
Oil and Gas Reserve Information —
     Proved oil and gas reserve quantities are based on estimates prepared by Ryder Scott Company, L.P., Petroleum Consultants, independent petroleum engineers, in accordance with guidelines established by the SEC. These reserves are subject to revision due to the inherent imprecision in estimating reserves, and are revised as additional information becomes available. All the Partnership’s reserves are located offshore Texas and Louisiana.
     There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact.
(Oil in Mbbls and gas in MMcf)
                                                 
    2008   2007   2006
    Oil   Gas   Oil   Gas   Oil   Gas
Proved Reserves
                                                
 
                                                
Beginning of year
     571       3,004       605       3,433       643       4,538  
Extensions, discoveries and other additions
     —       —       —       —       —       —  
Revisions of previous estimates
     (42 )     (114 )     20       126       33       (310 )
Production
     (37 )     ( 468 )     (54 )     (555 )     (71 )     (795 )
 
                                                
 
                                                
End of year
     492       2,422       571       3,004       605       3,433  
 
                                                
 
                                                
Proved Developed
                                                
 
                                                
Beginning of year
     571       2,899       605       3,328       643       4,433  
 
                                                
 
                                                
End of year
     492       2,317       571       2,899       605       3,328  
 
                                                
     Oil includes crude oil, condensate and natural gas liquids.
     Approximately 63 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.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(UNAUDITED)
Future Net Cash Flows —
     The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. Future cash inflows are based on year-end prices. Operating costs and future development costs are based on current costs with no escalation. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
Discounted Future Net Cash Flows Relating to Proved Reserves
                         
    December 31,  
    2008     2007     2006  
    (In thousands)  
Future cash inflows
   $ 36,059     $ 70,569     $ 54,599  
Future production costs
     (7,580 )     (8,710 )     (6,193 )
Future development costs
     (4,136 )     (4,421 )     (3,485 )
 
                  
Net cash flows
     24,343       57,438       44,921  
10 percent annual discount rate
     (8,312 )     (25,539 )     (17,156 )
 
                  
Discounted future net cash flows
   $ 16,031     $ 31,899     $ 27,765  
 
                  
     The following table sets forth the principal sources of change in the discounted future net cash flows:
                         
    For the Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
Sales, net of production costs
   $ (6,705 )   $ (6,189 )   $ (8,935 )
Net change in prices and production costs
     (13,629 )     10,719       (8,315 )
Revisions of quantities
     (1,083 )     1,469       (459 )
Accretion of discount
     3,190       2,777       4,160  
Changes in future development costs
     285       (453 )     —  
Changes in production rates and other
     2,074       (4,189 )     (282 )
 
                  
 
   $ (15,868 )   $ 4,134     $ (13,831 )
 
                  
     Impact of Pricing — The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices. Forward price volatility is largely attributable to supply and demand perceptions for natural gas and oil.
     Under full-cost accounting rules, the Partnership reviews the carrying value of its proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent (the “ceiling”). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded. Given the volatility of oil and gas prices, it is reasonably possible that the Partnership’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
                                         
    First     Second     Third     Fourth     Total  
    (In thousands, except per Unit amounts)  
2008
                                        
Revenues
   $ 2,210     $ 2,610     $ 2,042     $ 1,112     $ 7,974  
Expenses
     602       634       739       664       2,639  
 
                              
Net income
   $ 1,608     $ 1,976     $ 1,303     $ 448     $ 5,335  
 
                              
Net income allocated to:
                                        
Managing Partner
   $ 361     $ 438     $ 297     $ 133     $ 1,229  
Investing Partners
     1,247       1,538       1,006       315       4,106  
 
                              
 
   $ 1,608     $ 1,976     $ 1,303     $ 448     $ 5,335  
 
                              
Net income per Investing
                                        
Partner Unit (1)
   $ 1,201     $ 1,485     $ 97       7 $306     $ 3,976  
 
                              
2007
                                        
Revenues
   $ 1,918     $ 1,828     $ 1,903     $ 2,134     $ 7,783  
Expenses
     640       858       646       805       2,949  
 
                              
Net income
   $ 1,278     $ 970     $ 1,257     $ 1,329     $ 4,834  
 
                              
Net income allocated to:
                                        
Managing Partner
   $ 306     $ 239     $ 297     $ 304     $ 1,146  
Investing Partners
     972       731       960       1,025       3,688  
 
                              
 
   $ 1,278     $ 970     $ 1,257     $ 1,329     $ 4,834  
 
                              
Net income per Investing
                                        
Partner Unit (1)
   $ 928     $ 698     $ 920     $ 986     $ 3,531  
 
                              
 
(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.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Control and Procedures
     G. Steven Farris, the Managing Partner’s Chairman of the Board and Chief Executive Officer (principal executive officer) , and Roger B. Plank, the Managing Partner’s President (principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2008, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2008 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 Report of Management on Internal Control over Financial Reporting, included on page 18 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 temporary 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, 2008, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
     None.

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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP
     All management functions are performed by Apache, the Managing Partner of the Partnership. The Partnership itself has no officers or directors. Information concerning the officers and directors of Apache set forth under the captions “Nominees for Election as Directors”, “Continuing Directors”, “Executive Officers of the Company”, and “Securities Ownership and Principal Holders” in the proxy statement relating to the 2009 annual meeting of stockholders of Apache (the Apache Proxy) is incorporated herein by reference.
Code of Business Conduct
     Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, Apache was required to adopt a code of business conduct and ethics for its directors, officers and employees. In February 2004, Apache’s Board of Directors adopted a Code of Business Conduct (Code of Conduct), which also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access Apache’s Code of Conduct on the Investor Relations page of the Apache’s website at apachecorp.com. Changes in and any waivers to the Code of Conduct for Apache’s directors, chief executive officer and certain senior financial officers will be posted on Apache’s website within five business days and maintained for at least twelve months.
ITEM 11. EXECUTIVE COMPENSATION
     See Note (3), “Compensation to Apache” of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. The information concerning the compensation paid by Apache to its officers and directors set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards,” “Outstanding Equity Awards at Fiscal Year-End,” “Option Exercises and Stock Vested,” “Non-Qualified Deferred Compensation,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements,” and “Director Compensation” in the Apache Proxy is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
     Apache, as an Investing Partner and the General Partner, owns 53 Units, or 5.2 percent of the outstanding Units of the Partnership, as of December 31, 2008. Directors and officers of Apache own four Units, less than one percent of the Partnership’s Units, as of December 31, 2008. 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
     See Note (3), “Compensation to Apache” of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. See Note (5), “Major Customers and Related Parties Information” of the Partnership’s financial statements for amounts paid to subsidiaries of Apache, and for other related party information.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
     Accountant fees and services paid to Ernst & Young LLP, the Partnership’s independent auditors, are included in amounts paid by the Partnership’s Managing Partner. Information on the Managing Partner’s principal accountant fees and services is set forth under the caption “Independent Public Accountants” in the Apache Proxy.

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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
             
a.
    (1 )   Financial Statements — See accompanying index to financial statements in Item 8 above.
 
            
 
    (2 )   Financial Statement Schedules — See accompanying index to financial statements in Item 8 above.
 
            
 
    (3 )   Exhibits
             
 
    3.1     Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit (3)(i) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
 
            
 
    3.2     Amendment No. 1, dated February 11, 1994, to the Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit 3.3 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).
 
            
 
    3.3     Limited Partnership Agreement of Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit (3)(ii) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
 
            
 
    10.1     Form of Assignment and Assumption Agreement between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.2 to Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, Commission File No. 0-13546).
 
            
 
    10.2     Joint Venture Agreement, dated as of November 23, 1992, between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.6 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).
 
            
 
    10.3     Matagorda Island 681 Field Purchase and Sale Agreement with Option to Exchange, dated November 24, 1992, between Apache Corporation, Shell Offshore, Inc. and SOI Royalties, Inc. (incorporated by reference to Exhibit 10.7 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).
 
            
 
    *23.1     Consent of Ryder Scott Company, L.P., Petroleum Consultants.
 
            
 
    *31.1     Certification of Principal Executive Officer.
 
            
 
    *31.2     Certification of Principal Financial Officer.
 
            
 
    *32.1     Certification of Principal Executive Officer and Principal Financial Officer.
 
            
 
    99.1     Consent statement of the Partnership, dated January 7, 1994 (incorporated by reference to Exhibit 99.1 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).
 
            
 
    99.2     Proxy statement to be dated on or about March 30, 2009, relating to the 2009 annual meeting of stockholders of Apache Corporation (incorporated by reference to the document filed by Apache pursuant to Rule 14A, Commission File No. 1-4300).
 
*   Filed herewith.
     
b.
  See a (3) above.
 
    
c.
  See a (2) above.

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SIGNATURES
     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
             
    APACHE OFFSHORE INVESTMENT PARTNERSHIP  
 
            
 
   By:   Apache Corporation, Managing Partner    
 
            
Date: February 27, 2009
   By:   /s/ G. Steven Farris
 
G. Steven Farris 		   
 
       Chairman of the Board and Chief Executive Officer    
POWER OF ATTORNEY
     The officers and directors of Apache Corporation, Managing Partner of Apache Offshore Investment Partnership, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, 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
 
   Chairman of the Board and Chief    February 27, 2009
G. Steven Farris
   Executive Officer    
 
   (principal executive officer)    
 
        
/s/ Roger B. Plank
 
Roger B. Plank
   President (principal financial officer)    February 27, 2009
 
        
/s/ Rebecca A. Hoyt
 
   Vice President and Controller    February 27, 2009
Rebecca A. Hoyt
   (principal accounting officer)    

 

Table of Contents

         
Name   Title   Date
         
/s/ Frederick M. Bohen
 
Frederick M. Bohen
   Director    February 27, 2009
         
/s/ Randolph M. Ferlic
 
Randolph M. Ferlic
   Director    February 27, 2009
         
/s/ Eugene C. Fiedorek
 
Eugene C. Fiedorek
   Director    February 27, 2009
         
/s/ A. D. Frazier, Jr.
 
A. D. Frazier, Jr.
   Director    February 27, 2009
         
/s/ Patricia Albjerg Graham
 
   Director    February 27, 2009
Patricia Albjerg Graham
        
         
/s/ John A. Kocur
 
John A. Kocur
   Director    February 27, 2009
         
/s/ George D. Lawrence
 
George D. Lawrence
   Director    February 27, 2009
         
/s/ F. H. Merelli
 
F. H. Merelli
   Director    February 27, 2009
         
/s/ Rodman D. Patton
 
Rodman D. Patton
   Director    February 27, 2009
         
/s/ Charles J. Pitman
 
Charles J. Pitman
   Director    February 27, 2009

 

exv23w1
EXHIBIT 23.1
[Letterhead of Ryder Scott Company, L.P.]
Consent of Ryder Scott Company, L.P.
As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Offshore Investment Partnership to our Firm’s name and our Firm’s review of the proved oil and gas reserve quantities of Apache Offshore Investment Partnership as of January 1, 2009.
         
     
  /s/ Ryder Scott Company, L.P.    
  Ryder Scott Company, L.P.   
     
 
Houston, Texas
February 27, 2009

 

exv31w1
EXHIBIT 31.1
CERTIFICATIONS
I, G. Steven Farris, certify that:
1.   I have reviewed this annual report on Form 10-K of Apache Offshore Investment Partnership;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information ; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
     
/s/ G. Steven Farris
 
G. Steven Farris
    
Chairman of the Board and
    
Chief Executive Officer (principal executive officer)
    
of Apache Corporation, Managing Partner
    
Date: February 27, 2009

 

exv31w2
EXHIBIT 31.2
CERTIFICATIONS
I, Roger B. Plank, certify that:
1.   I have reviewed this annual report on Form 10-K of Apache Offshore Investment Partnership;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
     
/s/ Roger B. Plank
 
Roger B. Plank
   
President (principal financial officer)
    
of Apache Corporation, Managing Partner
    
Date: February 27, 2009

 

exv32w1
Exhibit 32.1
APACHE OFFSHORE INVESTMENT PARTNERSHIP
Certification of Chief Executive Officer
and Principal Financial Officer
     I, G. Steven Farris, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Offshore Investment Partnership for the period ended December 31, 2008, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.
         
By:
  /s/ G. Steven Farris
 
G. Steven Farris 		   
Title:
  Chairman of the Board    
    and Chief Executive Officer (principal executive officer)    
    of Apache Corporation, Managing Partner    
         
Date:
  February 27, 2009    
     I, Roger B. Plank, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Offshore Investment Partnership for the period ended December 31, 2008, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.
         
By:
  /s/ Roger B. Plank
 
Roger B. Plank 		   
Title:
  President (principal financial officer)    
    of Apache Corporation, Managing Partner    
         
Date:
  February 27, 2009