10-K 1 d283617d10k.htm FORM 10-K FORM 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

OR

 

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

For the transition period from              to             

Commission File Number 0-13546

 

 

APACHE OFFSHORE INVESTMENT PARTNERSHIP

 

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

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices)

Registrant’s telephone number, including area code: (713) 296-6000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Partnership Units

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.    Yes  ¨    No  x

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

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

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

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

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

 

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

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

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2011

   $ 13,073,624   

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Apache Corporation’s proxy statement relating to its 2012 annual meeting of stockholders have been incorporated by reference into Part III hereof.

 

 

 


Table of Contents

TABLE OF CONTENTS

DESCRIPTION

 

Item

       Page  
 

PART I

  
1.  

BUSINESS

     1   
1A.  

RISK FACTORS

     3   
1B.  

UNRESOLVED STAFF COMMENTS

     8   
2.  

PROPERTIES

     8   
3.  

LEGAL PROCEEDINGS

     10   
4.  

MINE SAFETY DISCLOSURES

     10   
 

PART II

  
5.  

MARKET FOR THE PARTNERSHIP’S SECURITIES AND RELATED SECURITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     11   
6.  

SELECTED FINANCIAL DATA

     11   
7.  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     12   
7A.  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     19   
8.  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     22   
9.  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     40   
9A.  

CONTROLS AND PROCEDURES

     40   
9B.  

OTHER INFORMATION

     40   
 

PART III

  
10.  

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     41   
11.  

EXECUTIVE COMPENSATION

     41   
12.  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

     41   
13.  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

     41   
14.  

PRINCIPAL ACCOUNTANT FEES AND SERVICES

     41   
 

PART IV

  
15.  

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

     42   

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


Table of Contents

PART I

 

ITEM 1. BUSINESS

General

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

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

The Investing Partners purchased Units of Partnership Interests (Units) in the Investment Partnership at $150,000 per Unit, with five percent down and the balance in payments as called by the Investment Partnership. As of December 31, 2011, 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 expenditure by the Partnership.

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

Offshore exploration differs from onshore exploration in that production from a prospect generally will not commence until a sufficient number of productive wells have been drilled to justify the significant costs associated with construction of a production platform. Exploratory wells usually are drilled from mobile platforms until there are sufficient indications of commercial production to justify construction of a permanent production platform.

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.

2011 Results and Business Development

The Partnership reported net income in 2011 of $1.8 million, or $1,225 per Investing Partner Unit. Earnings were up $0.2 million, or 16 percent, from 2010 on higher oil prices and oil and gas production. Lower gas prices in 2011 and higher operating expenses limited further gains in net income. The Partnership’s average realized oil price increased 43 percent from a year ago to $109.55 per barrel. Natural gas production averaged 1,712 Mcf per day in 2011, up four percent from 2010 with production added from drilling at Ship Shoal 258/259 during 2011. Oil production averaged 55 barrels of oil per day in 2011, up 17 percent from 2010. South Timbalier 295, the Partnership’s largest oil-producing field, was brought back on production in mid-2011 after being shut-in nearly a year while a new oil sales pipeline was built.

During 2011, the Partnership’s oil and gas property additions totaled $3.2 million with $2.9 million of development cost and $0.3 million of additional asset retirement cost. The Partnership participated in drilling three wells at Ship Shoal 258/259 during 2011 with two wells being completed as producers and one being unsuccessful at finding commercial quantities of oil and gas. During the year, the Partnership also participated in two recompletions at North Padre Island 969/976 and completed the installation of new oil sales pipeline at South Timbalier 295.

Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $1.0 million in 2012 for recompletion activity. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by contractors or changes by the operator to the development plan.

Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2011, 45 of those prospects have been surrendered or sold. As of December 31, 2011, the Partnership had 36 producing wells on the Partnership’s four remaining developed fields. One of the Partnership’s producing wells has dual completions. The Partnership had, at December 31, 2011, estimated proved oil and gas reserves of 5.2 Bcfe.

Marketing

Apache, on behalf of the Partnership, seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. The objective is to maximize the value of the crude oil or natural gas sold by identifying the best markets and most economical transportation routes available to move the oil or natural gas. The oil contracts are generally thirty (30) day evergreen contracts that renew automatically until cancelled by either party. These contracts provide for sales that are priced daily at prevailing market prices. The Partnership’s oil and condensate production during 2011 was purchased largely by Shell Trading Company at market prices.

 

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

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

 

ITEM 1A. RISK FACTORS

The Partnership’s business activities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Partnership’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders of the Partnership Units could lose part or all of their investments.

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

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

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

The Partnership’s revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2011 ranged from a high of $113.93 per barrel to a low of $75.67 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2011 ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond the Partnership’s control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

 

   

worldwide and domestic supplies of crude oil and natural gas;

 

   

actions taken by foreign oil and gas producing nations;

 

   

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

 

   

the level of global crude oil and natural gas inventories;

 

   

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

 

   

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

 

   

the availability of pipeline capacity and infrastructure;

 

   

the availability of crude oil transportation and refining capacity;

 

   

weather conditions;

 

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electricity generation;

 

   

domestic and foreign governmental regulations and taxes; and

 

   

the overall economic environment.

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

 

   

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

 

   

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

 

   

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

 

   

reducing our revenues, operating income and cash flows; or

 

   

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

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

A portion of our natural gas and oil production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. For example, from July 2010 until mid-2011, the Partnership’s production at South Timbalier 295 was shut-in as a result of a leak in a third-party pipeline, which significantly reduced the Partnership’s revenues, earnings cash flow from operating activities and liquidity in 2011 and 2010. If a substantial amount of our production is interrupted at the same time or for an extended period of time, it could temporarily adversely affect our cash flow.

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

Demand for oil and natural gas is, 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.

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

The Partnership is not likely to make any distributions to Investing Partners during 2012 as a result of the Partnership’s plan to build cash reserves to fund future asset retirement obligations (ARO). The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover its undiscounted future ARO. If natural gas prices remain at or fall below current low levels, the Partnership may not be able to make any distributions to Investing Partners during 2012. Declines in cash from operating activities may reduce funds available for capital expenditures.

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

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

 

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

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

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

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we participate in may not be productive and we may not recover all or any portion of our investment in those wells. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

fires, explosions, blow-outs and surface cratering;

 

   

marine risks such as capsizing, collisions and hurricanes;

 

   

other adverse weather conditions; and

 

   

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

Future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Partnership is not likely to participate in exploratory drilling at this time.

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

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

 

   

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

 

   

the assumed effects of regulations by governmental agencies;

 

   

future operating costs and capital expenditures; and

 

   

workover and remediation costs.

 

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

The Partnership may incur significant costs related to environmental matters.

As an owner or lessee of interests in oil and gas properties, the Partnership is subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

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

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

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

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

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

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

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

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

 

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

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

 

   

drilling well blowouts, explosions and cratering;

 

   

pipeline ruptures and spills;

 

   

fires;

 

   

formations with abnormal pressures;

 

   

equipment malfunctions; and

 

   

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

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

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

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

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

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

The Partnership faces significant industry competition.

The Partnership is a very minor participant in the oil and gas industry in the Gulf of Mexico area and faces strong competition from much larger producers for the marketing of its oil and gas. The Partnership’s ability to compete for purchasers and favorable marketing terms will depend on the general demand for oil and gas from Gulf of Mexico producers. More particularly, it will depend largely on the efforts of Apache to find the best markets for the sale of the Partnership’s oil and gas production.

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

Exploration for and production of oil and natural gas can be hazardous, involving 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.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2011, the Partnership did not have any unresolved comments from the staff of the SEC.

 

ITEM 2. PROPERTIES

Acreage

Acreage is held by the Partnership pursuant to the terms of various leases on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The Partnership does not anticipate any difficulty in retaining any of its leases. A summary of the Partnership’s gross and net acreage as of December 31, 2011, 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, 2011, 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, 2011, is set forth below:

 

$0000,00000 $0000,00000 $0000,00000 $0000,00000 $0000,00000
            Gas      Oil  

Lease Block

   State      Gross      Net      Gross      Net  

Ship Shoal 258, 259

     LA         7         .44         —           —     

South Timbalier 276, 295, 296

     LA         1         .07         19         1.34   

North Padre Island 969, 976

     TX         5         .36         —           —     

Matagorda Island 681, 682

     TX         4         .25         —           —     
     

 

 

    

 

 

    

 

 

    

 

 

 
        17         1.12         19         1.34   
     

 

 

    

 

 

    

 

 

    

 

 

 

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:

 

$000,00000 $000,00000 $000,00000 $000,00000 $000,00000 $000,00000
     Net Exploratory      Net Development  

Year

   Productive      Dry      Total      Productive      Dry      Total  

2011

     —           —           —           .15         .07         .22   

2010

     —           —           —           .07         —           .07   

2009

     —           —           —           —           —           —     

 

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Production, Pricing and Lease Operating Cost Data

The following table provides, for each of the last three fiscal years, oil, natural gas liquids (NGLs), and gas production for the Partnership, average lease operating costs per Mcfe (including gathering and transportation expense) and average sales prices.

 

     Production      Average Lease      Average Sales Price  

Year Ended December 31,

   Oil
(Mbbls)
     NGLs
(Mbbls)
     Gas
(MMcf)
     Operating
Cost per Mcfe
     Oil
(Per bbl)
     NGLs
(Per bbl)
     Gas
(Per Mcf)
 

2011

                    

South Timbalier 295

     19         3         35       $ 6.18       $ 109.99       $ 64.70       $ 3.77   

Other fields

     1         4         590         1.25         102.76         56.35         4.13   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     20         7         625       $ 2.30       $ 109.55       $ 60.13       $ 4.11   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2010

                    

South Timbalier 295

     16         1         28       $ 3.01       $ 76.62       $ 51.21       $ 5.29   

Other fields

     1         2         573         1.66         78.65         49.49         4.65   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     17         3         601       $ 1.90       $ 76.78       $ 50.21       $ 4.68   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2009

                    

South Timbalier 295

     34         4         61       $ 1.57       $ 57.25       $ 31.90       $ 4.04   

Other fields

     2         2         470         2.19         64.36         32.35         3.87   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     36         6         531       $ 1.96       $ 57.60       $ 32.07       $ 3.89   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The South Timbalier 295 field contains more than 15 percent of the Partnership’s proved reserved, expressed on an oil-equivalent-barrels basis. No other field contained 15 percent or more of the Partnership’s proved reserves as of December 31, 2011.

Estimated Proved Reserves and Future Net Cash Flows

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

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

As of December 31, 2011, the Partnership had total estimated proved reserves of 441,776 barrels of crude oil and condensate, 71,512 barrels of NGLs and 2.1 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 5.2 Bcf of gas. The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.

 

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Table of Contents

The following table shows proved oil, NGL and gas reserves as of December 31, 2011, based on commodity average prices in effect on the first day of each month in 2011, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

 

     Oil
(Mbbls)
     NGL
(Mbbls)
     Gas
(MMcf)
 

Proved developed

     442         72         1,989   

Proved undeveloped

     —           —           105   
  

 

 

    

 

 

    

 

 

 

Total proved

     442         72         2,094   
  

 

 

    

 

 

    

 

 

 

The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2011, 2010 and 2009, 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 2011 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows as of December 31, 2011, 2010 and 2009 were calculated using a discount rate of 10 percent per annum, end of period costs, and average commodity prices in effect on the first day of each month in the respective year, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

As of December 31, 2011, the Partnership had one undrilled location classified as proved undeveloped. The location is in North Padre Island 969/976 and is scheduled to be drilled within the next five years. The Partnership carried proved undeveloped reserves of 0.1 Bcf at both December 31, 2011 and 2010.

The volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

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

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

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

 

ITEM 3. LEGAL PROCEEDINGS

There are no material legal proceedings pending to which the Partnership is a party or to which the Partnership’s interests are subject.

 

ITEM 4. MINE SAFETY DISCLOSURES

None.

 

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Table of Contents

PART II

 

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

As of December 31, 2011, there were 1,021.5 of the Partnership’s Units outstanding held by 874 Investing Partners of record. The Partnership has no other class of security outstanding or authorized. The Units are not traded on any security market. No distributions were made to Investing Partners during 2011 or 2010.

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

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, 2011, 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,  
     2011      2010      2009      2008      2007  
     (In thousands, except per Unit amounts)   

Total assets

   $ 11,612       $ 10,992       $ 8,236       $ 6,680       $ 8,308   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Partners’ capital

   $ 8,859       $ 7,483       $ 6,086       $ 5,191       $ 6,960   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Oil and gas sales

   $ 5,195       $ 4,270       $ 4,311       $ 7,928       $ 7,679   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income

   $ 1,803       $ 1,555       $ 1,332       $ 5,335       $ 4,834   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income allocated to:

              

Managing Partner

   $ 552       $ 467       $ 447       $ 1,229       $ 1,146   

Investing Partners

     1,251         1,088         885         4,106         3,688   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 1,803       $ 1,555       $ 1,332       $ 5,335       $ 4,834   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income per Investing Partner Unit

   $ 1,225       $ 1,065       $ 867       $ 3,976       $ 3,531   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Cash distributions per Investing Partner Unit

   $ —         $ —         $ —         $ 5,500       $ 4,000   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

The Partnership’s business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The Partnership is a very minor participant in the oil and gas industry and faces strong competition in all aspects of its business. With a relatively small amount of capital invested in the Partnership and management’s decision to avoid incurring debt, the Partnership has not engaged in acquisition or exploration activities in recent years. The Partnership has not carried any debt since January 1997. The limited amount of capital and the Partnership’s modest reserve base, have contributed to the Partnership’s focus on production activities and development of existing leases.

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

The Partnership derives its revenue from the production and sale of crude oil, natural gas and natural gas liquids (NGLs). With only modest levels of production from current wells, the Partnership sells its production at market prices and has not used derivative financial instruments or otherwise engaged in hedging activities. During 2011, the Partnership benefited from higher market prices for crude oil as its average realized oil increased 43 percent from a year ago. The Partnership’s average realized price for natural gas, however, declined 12 percent during 2011 as market prices declined in the second half of 2011 and beyond. Prices in recent years have remained volatile and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate widely over the years.

While oil prices increased during 2011, the Partnership was unable to fully recognize potential benefits as the Partnership’s largest oil-producing field was shut-in for nearly half of the year. The Partnership’s production from South Timbalier 295 was shut-in on July 11, 2010, as a result of a leak in a third-party pipeline and remained shut-in until mid-2011. The shut-in of the South Timbalier 295 production significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2011 and 2010.

The Partnership participates in development drilling and recompletion activities as recommended by outside operators and the Partnership’s Managing Partner. During 2011, the Partnership’s oil and gas property additions totaled $3.2 million. The Partnership participated in drilling three new wells during 2011, two of which were completed as producers and one was not successful in finding commercial quantities of oil and gas. The Partnership also participated in two recompletions at North Padre Island 969/976 during 2011 and completed the installation of the new oil sales pipeline at South Timbalier 295.

Generally, the Partnership has used its available cash to fund distributions to its Partners. With the shut-in of the South Timbalier 295 field for nearly a year and the Partnership’s participation in drilling and recompletion projects over the last two years, the Partnership did not make any distributions to the Investing Partners during 2011 or 2010. No distributions to Investing Partners were made in 2009 with the shut-in of the Matagorda Island 681/682 production, low oil and gas prices and an increase in the Partnership cash reserves for higher asset retirement obligation (ARO) liabilities.

We do not anticipate that the Partnership will make any distributions to Investing Partners during 2012 as the Partnership plans to rebuild cash reserves for future ARO expenditures. The timing of when distributions will be reinstated is dependent upon oil and gas prices realized by the Partnership for the sale of its production and the level of drilling and recompletion activity in 2012 and 2013.

Results of Operations

This section includes a discussion of the Partnership’s results of operations, and items contributing to changes in revenues and expenses during 2011, 2010, and 2009.

 

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Table of Contents

Net Income and Revenue

The Partnership reported net income of $1.8 million for 2011, up 16 percent from 2010 on higher oil prices and oil and gas production. Net income per Investing Partner Unit increased in 2011 to $1,225, up from $1,065 in 2010. The Partnership reported earnings of $1.6 million in 2010 and $1.3 million in 2009.

Total revenues in 2011 of $5.2 million increased 22 percent from 2010 on higher oil prices and production. Further gains were offset by the impact of lower natural gas prices. Interest income earned by the Partnership on short-term cash investments in 2011 of $36 decreased from 2010 as a result of lower interest rates in 2011. Interest income totaled $77 in 2010 and $229 in 2009.

The Partnership’s revenues are sensitive to changes in prices received for its products. A substantial portion of the Partnership’s production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of its control. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on the prices received for the Partnership’s production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.

Declines in oil and gas production can be expected in future years as a result of normal depletion. Given the small number of producing wells owned by the Partnership, and that production from offshore wells tends to decline at a faster rate than production from onshore wells, the Partnership’s future production will be subject to more volatility than those companies with greater reserves and longer-lived properties. It is not anticipated that the Partnership will acquire any additional exploratory leases or that significant drilling will take place on leases in which the Partnership currently holds interests.

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

 

     For the Year Ended December 31,  
     2011      Increase
(Decrease)
    2010      Increase
(Decrease)
    2009  

Gas volumes – Mcf per day

     1,712         +4     1,647         +13     1,455   

Average gas price – per Mcf

   $ 4.11         -12   $ 4.68         +20   $ 3.89   

Oil volumes – barrels per day

     55         +17     47         -52     98   

Average oil price – per barrel

   $ 109.55         +43   $ 76.78         +33   $ 57.60   

NGL volumes – barrels per day

     19         +138     8         -50     16   

Average NGL price – per barrel

   $ 60.14         +20   $ 50.21         +57   $ 32.07   

Natural Gas Sales

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

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

 

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Table of Contents

Crude Oil Sales

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

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

NGL Sales

The Partnership sold 19 barrels per day of NGL in 2011, up from 8 barrels per day in 2010. The increase reflected higher production from South Timbalier 295 during 2011. NGL volumes also totaled 16 barrels per day in 2009. NGL prices increased 57 percent from 2009 to 2010 with the increase in oil prices and then increased 20 percent in 2011 with further improvement in oil prices.

Operating Expenses

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

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

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.

 

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Table of Contents

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.7 million for 2011. The Partnership’s 2011 net cash provided by operating activities increased $0.2 million from 2010 on increased earnings. The Partnership’s 2010 net cash provided by operating activities of $2.5 million increased $0.5 million from 2009 on increased earnings and receivables. Net cash provided by operating activities in 2009 totaled $2.0 million.

At December 31, 2011, the Partnership had approximately $1.4 million in cash and cash equivalents, down from slightly under $3 million at December 31, 2010. The Partnership’s goal of maintaining cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations (ARO) had to be temporally suspended in 2011 as a result of the Partnership’s production from South Timbalier 295 being shut-in for nearly a year and the Partnership’s capital expenditures at Ship Shoal 258/259 and South Timbalier 295. The partnership intends to replenish cash reserves in 2012 with cash from operating activities.

The Partnership’s future financial condition, results of operations and cash from operating activities will largely depend upon prices received for its oil and natural gas production. A substantial portion of the Partnership’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Partnership’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.

The Partnership’s oil and gas reserves and production will also significantly impact future results of operations and cash from operating activities. The Partnership’s production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can be expected in future years as a result of normal depletion and the Partnership not participating in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership expects it will be able to meet its liquidity needs for routine operations in the foreseeable future.

Approximately 75 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves and that the estimated reserves from these projects are based on prices at December 31, 2011. 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 2011, 2010 or 2009.

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, 2011. The Partnership did not have any contractual obligations as of December 31, 2011, other than the

 

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Table of Contents

liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for the fair value of the ARO as discussed under the discussion of critical accounting policies noted below.

During 2011, the Partnership’s oil and gas property additions totaled $3.2 million with $2.9 million of development cost and $0.3 million of additional asset retirement cost. The Partnership participated in drilling three wells at Ship Shoal 258/259 during 2011 with two wells being completed as producers and one being unsuccessful at finding commercial quantities of oil and gas. During the year, the Partnership also participated in two recompletions at North Padre Island 969/976 and completed the installation of new oil sales pipeline at South Timbalier 295. During 2010, the Partnership’s oil and gas property development cost totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. During 2010, the Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 and began the installation of new equipment at South Timbalier 295 as part of the new sales line tie-in. During 2009, the Partnership’s oil and gas property expenditures totaled $0.6 million. The Partnership participated in two recompletions in the North Padre Island 969/976 field and one recompletion at Matagorda Island 681/682 during the year.

Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $1 million in 2012 for recompletion activity. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by contractors or changes by the operator to the development plan.

No distributions were paid to Investing Partners during 2011, 2010 or 2009 as a result of the shut-in of production for extended periods of time during the period and cash requirements for drilling, recompletion and repair activities. The amount of future distributions will be dependent on actual and expected production levels, realized and expected oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted.

We do not anticipate that the Partnership will make any distribution to Investing Partners in 2012 as the Partnership plans to rebuild cash reserves for future ARO expenditures. The timing of when distributions will be reinstated is dependent upon oil and gas prices realized by the Partnership for the sale of its production and the level of drilling and recompletion activity in 2012 and 2013.

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 2011, 2010 and 2009 the Partnership did not offer to purchase any Units from Investing Partners as a result of the limited amount of cash available for discretionary purposes.

There will be two rights of presentment in 2012, 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 2012.

Off-Balance Sheet Arrangements

The Partnership does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership.

Insurance

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

 

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

In light of the catastrophic accident in the Gulf of Mexico in 2010, the Managing Partner and the Partnership may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

Critical Accounting Policies and Estimates

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

Reserve Estimates

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGL’s that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

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

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

Reserves as of December 31, 2011, 2010, and 2009, were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month in the respective year, held flat for the life of production, except where prices are defined by contractual arrangements.

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

The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner.

Asset Retirement Obligation (ARO)

The Partnership has obligations to remove tangible equipment and restore the land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership’s limited operations and estimate of remaining reserves. The Partnership’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because

 

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most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

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

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

 

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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 the Partnership’s natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. During 2011, monthly oil price realizations ranged from a low of $91.72 per barrel to a high of $121.44 per barrel. Gas price realizations ranged from a monthly low of $3.22 per Mcf to a monthly high of $4.53 per Mcf during the same period. Based on the Partnership’s average daily production for 2011, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $20,000 and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $62,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2011. Due to the volatility of commodity prices, the Partnership is not in a position to predict future oil and gas prices.

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

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2011, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

 

   

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

 

   

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

 

   

pipeline and gathering system capacity;

 

   

production and reserve levels;

 

   

drilling risks;

 

   

economic and competitive conditions;

 

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the availability of capital resources;

 

   

capital expenditure and other contractual obligations;

 

   

weather conditions;

 

   

inflation rates;

 

   

the availability of goods and services;

 

   

legislative or regulatory changes;

 

   

terrorism;

 

   

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

 

   

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

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

ADDITIONAL INFORMATION ABOUT THE PARTNERSHIP

Remediation Plans and Procedures

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

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

 

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In the event that CGA and MSRC resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited is the world’s largest oil spill preparedness and response organization, dedicated to providing resources to respond to oil spills efficiently and effectively on a global basis. In addition, resources of other organizations are available to Apache as a non-member, such as those of National Response Corporation (NRC) and MSRC, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels and dispersant aircraft. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland workboats, vacuum transfer units, and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time-to-time and current information is generally available on each of the companies’ websites.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties, the Partnership is subject to numerous federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

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

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

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

APACHE OFFSHORE INVESTMENT PARTNERSHIP

INDEX TO FINANCIAL STATEMENTS

 

     Page
Number
 

Report of Management on Internal Control over Financial Reporting

     23   

Report of Independent Registered Public Accounting Firm

     24   

Statement of Consolidated Income for each of the three years in the period ended December 31, 2011

     25   

Statement of Consolidated Cash Flows for each of the three years in the period ended December  31, 2011

     26   

Consolidated Balance Sheet as of December 31, 2011 and 2010

     27   

Statement of Consolidated Changes in Partners’ Capital for each of the three years in the period ended December 31, 2011

     28   

Notes to Consolidated Financial Statements

     29   

Supplemental Oil and Gas Disclosures

     37   

Supplemental Quarterly Financial Data

     39   

Schedules –

All financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the financial statements or related notes thereto.

 

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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, 2011. 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, 2011.

 

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

 

/s/ Thomas P. Chambers

Executive Vice President and

Chief Financial Officer

(principal financial officer)
of Apache Corporation, Managing Partner

 

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

Houston, Texas

February 28, 2012

 

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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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, in 2009, the Partnership adopted SEC Release 33-8995 and the amendments to ASC Topic 932, “Extractive Industries – Oil and Gas,” resulting from ASU 2011-03 (collectively, the Modernization Rules).

 

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2012

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED INCOME

 

     For the Year Ended December 31,  
     2011      2010      2009  

REVENUES:

        

Oil and gas sales

   $ 5,195,487       $ 4,270,245       $ 4,310,969   

Interest income

     36         77         229   
  

 

 

    

 

 

    

 

 

 
     5,195,523         4,270,322         4,311,198   
  

 

 

    

 

 

    

 

 

 

OPERATING EXPENSES:

        

Depreciation, depletion and amortization

     1,053,964         822,053         960,632   

Asset retirement obligation accretion

     132,120         118,557         67,297   

Lease operating expenses

     1,661,778         1,229,104         1,445,122   

Gathering and transportation costs

     147,518         142,737         88,064   

Administrative

     397,000         403,000         418,000   
  

 

 

    

 

 

    

 

 

 
     3,392,380         2,715,451         2,979,115   
  

 

 

    

 

 

    

 

 

 

NET INCOME

   $ 1,803,143       $ 1,554,871       $ 1,332,083   
  

 

 

    

 

 

    

 

 

 

NET INCOME ALLOCATED TO:

        

Managing Partner

   $ 551,769       $ 466,589       $ 446,888   

Investing Partners

     1,251,374         1,088,282         885,195   
  

 

 

    

 

 

    

 

 

 
   $ 1,803,143       $ 1,554,871       $ 1,332,083   
  

 

 

    

 

 

    

 

 

 

NET INCOME PER INVESTING PARTNER UNIT

   $ 1,225       $ 1,065       $ 867   
  

 

 

    

 

 

    

 

 

 

WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING

     1,021.5         1,021.5         1,021.5   
  

 

 

    

 

 

    

 

 

 

 

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,  
     2011     2010     2009  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income

   $ 1,803,143      $ 1,554,871      $ 1,332,083   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation, depletion and amortization

     1,053,964        822,053        960,632   

Asset retirement obligation accretion

     132,120        118,557        67,297   

Changes in operating assets and liabilities:

      

(Increase) decrease in accrued receivables

     (26,315     81,532        (13,594

Increase (decrease) in accrued operating expense

     296,686        3,389        7,799   

Change in receivable/payable from Apache Corporation

     99,448        145,885        (329,519

Increase (decrease) in deferred credits and other

     (635,930     (180,941     (37,720
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     2,723,116        2,545,346        1,986,978   
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Additions to oil and gas properties

     (3,863,213     (1,464,194     (632,908
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (3,863,213     (1,464,194     (632,908
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Distributions to Investing Partners

     —          —          —     

Distributions to Managing Partner

     (427,409     (157,664     (437,273
  

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

     (427,409     (157,664     (437,273
  

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH

EQUIVALENTS

     (1,567,506     923,488        916,797   

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR

     2,971,900        2,048,412        1,131,615   
  

 

 

   

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, END OF YEAR

   $ 1,404,394      $ 2,971,900      $ 2,048,412   
  

 

 

   

 

 

   

 

 

 

 

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,  
     2011     2010  

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 1,404,394      $ 2,971,900   

Accrued revenues receivable

     289,195        238,431   

Accrued insurance receivable

     —          24,449   
  

 

 

   

 

 

 
     1,693,589        3,234,780   
  

 

 

   

 

 

 

OIL AND GAS PROPERTIES, on the basis of full cost accounting:

    

Proved properties

     194,492,252        191,277,205   

Less – Accumulated depreciation, depletion and amortization

     (184,574,195     (183,520,231
  

 

 

   

 

 

 
     9,918,057        7,756,974   
  

 

 

   

 

 

 
   $ 11,611,646      $ 10,991,754   
  

 

 

   

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

    

CURRENT LIABILITIES:

    

Accrued operating expense

   $ 406,480      $ 109,794   

Accrued development cost

     148,577        520,950   

Payable to Apache Corporation

     162,431        668,573   
  

 

 

   

 

 

 
     717,488        1,299,317   
  

 

 

   

 

 

 

ASSET RETIREMENT OBLIGATION

     2,035,649        2,209,662   
  

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 7)

    

PARTNERS’ CAPITAL:

    

Managing Partner

     507,365        383,005   

Investing Partners (1,021.5 Units outstanding)

     8,351,144        7,099,770   
  

 

 

   

 

 

 
     8,858,509        7,482,775   
  

 

 

   

 

 

 
   $ 11,611,646      $ 10,991,754   
  

 

 

   

 

 

 

 

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
Partner
    Investing
Partners
     Total  

BALANCE, DECEMBER 31, 2008

   $ 64,465      $ 5,126,293       $ 5,190,758   

Distributions

     (437,273     —           (437,273

Net income

     446,888        885,195         1,332,083   
  

 

 

   

 

 

    

 

 

 

BALANCE, DECEMBER 31, 2009

   $ 74,080      $ 6,011,488       $ 6,085,568   

Distributions

     (157,664     —           (157,664

Net income

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

 

 

   

 

 

    

 

 

 

BALANCE, DECEMBER 31, 2010

   $ 383,005      $ 7,099,770       $ 7,482,775   

Distributions

     (427,409     —           (427,409

Net income

     551,769        1,251,374         1,803,143   
  

 

 

   

 

 

    

 

 

 

BALANCE, DECEMBER 31, 2011

   $ 507,365      $ 8,351,144       $ 8,858,509   
  

 

 

   

 

 

    

 

 

 

 

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, 2011. The term “Partnership”, as used hereafter, refers to the Investment Partnership or the Operating Partnership, as the case may be.

The Partnership purchased, at cost, an 85 percent interest in offshore leasehold interests acquired by Apache as a co-venturer in a series of oil and gas exploration, development and production activities on 87 federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The remaining 15 percent interest was purchased by an affiliated partnership or retained by Apache. The Partnership acquired an increased net revenue interest in Matagorda Island Blocks 681 and 682 in November 1992, when the Partnership and Apache formed a joint venture to acquire a 92.6 percent working interest in the blocks.

Since inception, the Partnership has participated in 14 federal offshore lease sales in which 49 prospects were acquired (over the same period, 45 of those prospects have been surrendered/sold). The Partnership’s working interests in the four remaining venture prospects range from 6.29 percent to 7.08 percent. As of December 31, 2011, the Partnership held a remaining interest in nine tracts acquired through federal lease sales.

The Partnership’s future financial condition and results of operations will depend largely upon prices received for its oil and natural gas production and the costs of acquiring, finding, developing and producing reserves. A substantial portion of the Partnership’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Partnership’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.

Under the terms of the Partnership Agreements, the Investing Partners receive 80 percent and Apache receives 20 percent of revenue. Lease operating, gathering and transportation, and administrative expenses are allocated to the Investing Partners and Apache in the same proportion as revenues. The Investing Partners receive 100 percent of the interest income earned on short-term cash investments. The Investing Partners generally pay for 90 percent and Apache generally pays for 10 percent of exploration and development costs and expenses incurred by the Partnership. However, intangible drilling costs, interest costs and fees or expenses related to the loans incurred by the Partnership are allocated 99 percent to the Investing Partners and one percent to Apache until such time as the amount so allocated to the Investing Partners equals 90 percent of the total amount of such costs, including such costs incurred by Apache prior to the formation of the Partnership.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Right of Presentment

In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. The Partnership did not offer to purchase any Units from Investing Partners in 2011, 2010 or 2009 as a result of the limited amount of cash available for discretionary purposes.

The Partnership is not in a position to predict how many Units will be presented for repurchase during 2012; however, no more than 10 percent of the outstanding Units may be purchased under the right of presentment in any year. The Partnership has no obligation to purchase any Units presented to the extent that it determines that it has insufficient funds for such purchases.

The table below sets forth the total repurchase price and the repurchase price per Unit for all outstanding Units at each presentment period, based on the right of presentment valuation formula defined in the amendment to the Partnership Agreement. The right of presentment offers made twice annually are based on a discounted Unit value formula. The discounted Unit value will be not less than the Investing Partner’s share of: (a) the sum of (i) 70 percent of the discounted estimated future net revenues from proved reserves, discounted at a rate of 1.5 percent over prime or First National Bank of Chicago’s base rate in effect at the time the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv) accounts receivable less a reasonable reserve for doubtful accounts, (v) oil and gas properties other than proved reserves at cost less any amounts attributable to drilling and completion costs incurred by the Partnership and included therein, and (vi) the book value of all other assets of the Partnership, less the debts, obligations and other liabilities of all kinds (including accrued expenses) then allocable to such interest in the Partnership, all determined as of the valuation date, divided by (b) the number of Units, and fractions thereof, outstanding as of the valuation date. The discounted Unit value does not purport to be, and may be substantially different from, the fair market value of a Unit.

 

Right of Presentment

Valuation Date

   Total  Valuation
Price
     Valuation Price  Per
Unit
 

December 31, 2008

   $ 9,701,665       $ 9,497   

June 30, 2009

     8,864,008         8,677   

December 31, 2009

     15,742,174         15,411   

June 30, 2010

     16,477,118         16,130   

December 31, 2010

     15,237,383         14,917   

June 30, 2011

     13,790,742         13,500   

 

Investing Partner Units Outstanding:    2011      2010      2009  

Balance, beginning of year

     1,021.5         1,021.5         1,021.5   

Repurchase of Partnership Units

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Balance, end of year

     1,021.5         1,021.5         1,021.5   
  

 

 

    

 

 

    

 

 

 

Capital Contributions

A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2011. 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, 2011.

 

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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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. (see the unaudited “Supplemental Oil and Gas Disclosures” below) and assessing asset retirement obligations (see Note 8 — Asset Retirement Obligation).

Cash Equivalents

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2011 and 2010, the Partnership had $1.4 million and $3.0 million, respectively, of cash and cash equivalents.

Oil and Gas Properties

The Partnership follows the full-cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method of accounting, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. 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 expense and reflected as additional DD&A in the accompanying statement of consolidated income. In 2009, the Partnership adopted U.S. Securities and Exchange Commission (SEC) Release 33-8995 and the amendments

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

to Accounting Standards Codification (ASC) Topic 932 “Extractive Industries — Oil and Gas” (the Modernization Rules). Under the Modernization Rules, estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements. Prior to December 31, 2009, estimated future net cash flows were calculated using commodity prices in effect at the end of each quarter. 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.

Asset Retirement Obligation

The initial estimated asset retirement obligation related to properties is recorded as a liability, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. Accretion expense on the liability is recognized over the estimated productive life of the related assets. If the fair value of the recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

Revenue Recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. The Partnership uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. As of December 31, 2011 and 2010, 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, 2011 and 2010.

Insurance Coverage

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

Net Income Per Investing Unit

The net income per Investing Partner Unit is calculated by dividing the aggregate Investing Partners’ net income for the period by the number of weighted average Investing Partner Units outstanding for that period.

Income Taxes

The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.

Receivable from / Payable to Apache Corporation

The receivable from/payable to Apache Corporation, the Partnership’s Managing Partner (Apache or the Managing Partner), represents the net result of the Investing Partners’ revenue and expenditure transactions in the current month. Generally, cash in this amount will be paid by Apache to the Partnership or transferred to Apache in the month after the Partnership’s transactions are processed and the net results of operations are determined.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Maintenance and Repairs

Maintenance and repairs are charged to expense as incurred.

Recently Issued Accounting Standards Not Yet Adopted

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04, which amends ASC Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Partnership does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

(3) COMPENSATION TO AFFILIATES

Apache is entitled to the following types of compensation and reimbursement for costs and expenses.

 

     Total Reimbursed by the Investing Partners
for the Year Ended December 31,
 
     2011      2010      2009  
     (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

   $ 318       $ 322       $ 334   
  

 

 

    

 

 

    

 

 

 

b.      Apache is reimbursed for development overhead costs incurred in the Partnership’s operations. These costs are based on development activities and are capitalized to oil and gas properties

   $ 61       $ 53       $ 30   
  

 

 

    

 

 

    

 

 

 

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.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

(4) OIL AND GAS PROPERTIES

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

 

     2011      2010      2009  
     (In thousands)  

Oil and Gas Properties

        

Balance, beginning of year

   $ 191,277       $ 188,458       $ 186,955   

Costs incurred during the year:

        

Development –

        

Investing Partners

     3,084         2,735         1,407   

Managing Partner

     131         84         96   
  

 

 

    

 

 

    

 

 

 

Balance, end of year

   $ 194,492       $ 191,277       $ 188,458   
  

 

 

    

 

 

    

 

 

 

Development cost for 2011, 2010 and 2009 includes $0.3 million, $0.2 million and $0.9 million, respectively, of asset retirement cost.

 

     Managing
Partner
     Investing
Partners
     Total  
     (In thousands)  

Accumulated Depreciation, Depletion and Amortization

        

Balance, December 31, 2008

   $ 20,913       $ 160,825       $ 181,738   

Provision

     18         942         960   
  

 

 

    

 

 

    

 

 

 

Balance, December 31, 2009

   $ 20,931       $ 161,767       $ 182,698   

Provision

     21         801         822   
  

 

 

    

 

 

    

 

 

 

Balance, December 31, 2010

   $ 20,952       $ 162,568       $ 183,520   

Provision

     33         1,021         1,054   
  

 

 

    

 

 

    

 

 

 

Balance, December 31, 2011

   $ 20,985       $ 163,589       $ 184,574   
  

 

 

    

 

 

    

 

 

 

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2011, 2010 and 2009 was 20 percent, 19 percent and 22 percent, respectively.

(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

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

In 2011, sales to Shell Trading Company accounted for 42 percent of the Partnership’s oil and gas sales for the year. In 2010, sales to Shell Trading Company, Florida Power Corporation and Sequent Energy Management LP accounted for 30 percent, 16 percent and 10 percent, respectively, of the Partnership’s oil and gas sales for the year. Sales to Shell Trading Company accounted for 48 percent of the Partnership’s oil and gas sales in 2009.

Effective November 1992, with Apache’s and the Partnership’s acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees totaling $26,553 in 2011, $40,562 in 2010 and $24,210 in 2009 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.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The Partnership’s revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. The Partnership has not experienced material credit losses on such sales.

(6) FAIR VALUE MEASUREMENTS

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

Cash, Cash Equivalents, Accounts Receivables and Accounts Payable —

As of December 31, 2011 and 2010, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2011.

(7) COMMITMENTS AND CONTINGENCIES

Litigation – The Partnership is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache’s management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations.

Environmental – The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. Apache maintains insurance coverage on the Partnership’s properties, which it believes is customary in the industry, although the Partnership is not fully insured against all environmental risks.

(8) ASSET RETIREMENT OBLIGATION

The following table describes changes to the Partnership’s ARO liability for the years ended December 31, 2011 and 2010:

 

     2011     2010  

Asset retirement obligation at beginning of year

   $ 2,209,662      $ 2,043,895   

Accretion expense

     132,120        118,557   

Liabilities settled

     (635,930     (180,941

Revisions in estimated liabilities

     329,797        228,151   
  

 

 

   

 

 

 

Asset retirement obligation at end of year

   $ 2,035,649      $ 2,209,662   
  

 

 

   

 

 

 

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

Liabilities settled primarily relate to individual wells plugged and abandoned during the periods presented. Revisions to estimated liabilities in 2011 reflected the Managing Partner’s updated estimates of the extent of the work required and cost involved in the dismantlement and site reclamation of offshore properties, and shorter reserve lives projected for certain of the Partnership’s properties.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

(9) TAX-BASIS FINANCIAL INFORMATION

A reconciliation of ordinary income for federal income tax reporting purposes to net income under accounting principles generally accepted in the United States is as follows:

 

     2011     2010     2009  

Net partnership ordinary income (loss) for federal

income tax reporting purposes

   $ (49,125   $ (25,363   $ 1,464,728   

Plus: Items of current expense for tax reporting purposes only –

      

Intangible drilling cost

     2,058,342        2,142,424        579,318   

Dismantlement and abandonment cost

     635,930        180,941        37,720   

Tax depreciation

     344,080        197,479        278,246   
  

 

 

   

 

 

   

 

 

 
     3,038,352        2,520,844        895,284   
  

 

 

   

 

 

   

 

 

 

Less: full cost DD&A expense

     (1,053,964     (822,053     (960,632

Less: asset retirement obligation accretion

     (132,120     (118,557     (67,297
  

 

 

   

 

 

   

 

 

 

Net income

   $ 1,803,143      $ 1,554,871      $ 1,332,083   
  

 

 

   

 

 

   

 

 

 

The Partnership’s tax bases in net oil and gas properties at December 31, 2011 and 2010 was $7,374,409 and $5,696,154, respectively, lower than the carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2011 and 2010.

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,  
     2011      2010  

Liabilities for federal income tax purposes

   $ 717,488       $ 1,299,317   

Asset retirement liability

     2,035,649         2,209,662   
  

 

 

    

 

 

 

Liabilities under accounting principles generally accepted in the United States

   $ 2,753,137       $ 3,508,979   
  

 

 

    

 

 

 

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

 

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Schedule

APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

Oil and Gas Reserve Information

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (NGLs) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact.

(Oil in Mbbls and gas in MMcf)

 

$0000,000 $0000,000 $0000,000 $0000,000 $0000,000 $0000,000
     2011     2010     2009  
     Oil     Gas     Oil     Gas     Oil     Gas  

Proved Reserves

            

Beginning of year

     561        2,354        555        2,427        492        2,422   

Extensions, discoveries and other additions

     4        354        15        111        —          —     

Revisions of previous estimates

     (25     11        11        417        105        536   

Production

     (27     (625     (20     (601     (42     (531
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of year

     513        2,094        561        2,354        555        2,427   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed

            

Beginning of year

     561        2,249        555        2,322        492        2,317   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

End of year

     513        1,989        561        2,249        555        2,322   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Oil includes crude oil, condensate and natural gas liquids.

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

Approximately 75 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves. The capital and economic impact of production timing are reflected in the Partnership’s standardized measure under Future Net Cash Flows.

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

(UNAUDITED)

 

Future Net Cash Flows

Future cash inflows were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

Discounted Future Net Cash Flows Relating to Proved Reserves

 

     December 31,  
     2011     2010     2009  
     (In thousands)  

Future cash inflows

   $ 63,150      $ 52,801      $ 40,838   

Future production costs

     (9,578     (10,290     (7,499

Future development costs

     (5,344     (5,689     (6,026
  

 

 

   

 

 

   

 

 

 

Net cash flows

     48,228        36,822        27,313   

10 percent annual discount rate

     (22,296     (17,783     (12,760
  

 

 

   

 

 

   

 

 

 

Discounted future net cash flows

   $ 25,932      $ 19,039      $ 14,553   
  

 

 

   

 

 

   

 

 

 

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

 

     For the Year Ended December 31,  
     2011     2010     2009  
     (In thousands)  

Sales, net of production costs

   $ (3,386   $ (2,898   $ (2,778

Net change in prices and production costs

     7,264        3,857        797   

Revisions of quantities

     (780     1,923        4,439   

Discoveries and improved recoveries, net of cost

     1,680        1,292        —     

Accretion of discount

     1,904        1,455        1,603   

Changes in future development costs

     341        336        (843

Changes in production rates and other

     (130     (1,479     (4,696
  

 

 

   

 

 

   

 

 

 
   $ 6,893      $ 4,486      $ (1,478
  

 

 

   

 

 

   

 

 

 

 

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

(UNAUDITED)

 

$00,00000 $00,00000 $00,00000 $00,00000 $00,00000
     First      Second      Third      Fourth     Total  
     (In thousands, except per Unit amounts)  

2011

             

Revenues

   $ 738       $ 1,078       $ 1,754       $ 1,625      $ 5,195   

Expenses

     562         632         836         1,362        3,392   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income

   $ 176       $ 446       $ 918       $ 263      $ 1,803   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income allocated to:

             

Managing Partner

   $ 65       $ 129       $ 248       $ 110      $ 552   

Investing Partners

     111         317         670         153        1,251   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
   $ 176       $ 446       $ 918       $ 263      $ 1,803   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income per Investing Partner Unit (1)

   $ 109       $ 310       $ 656       $ 150      $ 1,225   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

2010

             

Revenues

   $ 1,724       $ 1,337       $ 596       $ 613      $ 4,270   

Expenses

     787         653         558         717        2,715   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss)

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

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss) allocated to:

             

Managing Partner

   $ 253       $ 181       $ 30       $ 3      $ 467   

Investing Partners

     684         503         8         (107     1,088   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

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

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss) per Investing Partner Unit (1)

   $ 669       $ 493       $ 8       $ (105   $ 1,065   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(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, in his capacity as principal executive officer, and Thomas P. Chambers, the Managing Partner’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2011, 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, 2011, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Report on Internal Control Over Financial Reporting

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the Report of Management on Internal Control over Financial Reporting, included on page 23 of this report. This annual report does not include an attestation report of the Partnership’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There was no change in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2011, 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, EXECUTIVE OFFICERS OF THE PARTNERSHIP AND CORPORATE GOVERNANCE

All management functions are performed by Apache, the Managing Partner of the Partnership. The Partnership itself has no officers or directors. Information concerning the officers and directors of Apache set forth under the captions “Nominees for Election as Directors”, “Continuing Directors”, “Executive Officers of the Company”, and “Securities Ownership and Principal Holders” in the proxy statement relating to the 2012 annual meeting of stockholders of Apache (the Apache Proxy) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, Apache was required to adopt a code of business conduct and ethics for its directors, officers, and employees. In February 2004, Apache’s Board of Directors adopted a Code of Business Conduct (Code of Conduct), and revised it in November 2011. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access Apache’s Code of Conduct on the “Governance” page of Apache’s website at www.apachecorp.com. Changes in and any waivers to the Code of Conduct for Apache’s directors, chief executive officer and certain senior financial officers will be posted on Apache’s website within five business days and maintained for at least twelve months.

 

ITEM 11. EXECUTIVE COMPENSATION

See Note (3), “Compensation to Affiliates” of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. The information concerning the compensation paid by Apache to its officers and directors set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards,” “Outstanding Equity Awards at Fiscal Year-End,” “Option Exercises and Stock Vested,” “Non-Qualified Deferred Compensation,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements,” and “Director Compensation” in the Apache Proxy Statement is incorporated herein by reference.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

Apache, as an Investing Partner and the General Partner, owns 53 Units, or 5.2 percent of the outstanding Units of the Partnership, as of December 31, 2011. Directors and officers of Apache own four Units, less than one percent of the Partnership’s Units, as of December 31, 2011. Apache owns a one-percent General Partner interest (15 equivalent Units). To the knowledge of the Partnership, no Investing Partner owns, of record or beneficially, more than five percent of the Partnership’s outstanding Units, except for Apache which owns 53 Units or 5.2 percent of the outstanding Units. Apache did not acquire additional Units during the three years covered by these financial statements. Apache’s ownership percentage exceeds five percent due to the decrease in the number of outstanding units resulting from the right of presentment (see Note 1).

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

See Note (3), “Compensation to Apache” of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. See Note (5), “Major Customers and Related Parties Information” of the Partnership’s financial statements for amounts paid to subsidiaries of Apache, and for other related party information.

 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Accountant fees and services paid to Ernst & Young LLP, the Partnership’s independent auditors, are included in amounts paid by the Partnership’s Managing Partner. Information on the Managing Partner’s principal accountant fees and services is set forth under the caption “Independent Public Accountants” in the Apache Proxy.

 

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PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

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

 

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

 

  (3) Exhibits

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

  *31.1 Certification of Principal Executive Officer.

 

  *31.2 Certification of Principal Financial Officer.

 

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

 

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

 

    99.2 Consent statement of the Partnership, dated January 7, 1994 (incorporated by reference to Exhibit 99.1 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).

 

    99.3 Proxy statement to be dated on or about March 31, 2012, relating to the 2012 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).

 

  **101.INS     XBRL Instance Document.

 

  **101.SCH   XBRL Taxonomy Schema Document.

 

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  **101.CAL   XBRL Calculation Linkbase Document.

 

  **101.DEF   XBRL Definition Linkbase Document

 

  **101.LAB   XBRL Label Linkbase Document.

 

  **101.PRE    XBRL Presentation Linkbase Document.

 

  * Filed herewith.
  ** Furnished herewith.

 

b. See a (3) above.

 

c. See a (2) above.

 

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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 28, 2012       By:   /s/ G. Steven Farris        
        G. Steven Farris
        Chairman of the Board and Chief Executive Officer

POWER OF ATTORNEY

The officers and directors of Apache Corporation, Managing Partner of Apache Offshore Investment Partnership, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Thomas P. Chambers, P. Anthony Lannie, and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Name

  

Title

 

Date

/s/ G. Steven Farris

G. Steven Farris

  

Chairman of the Board and Chief Executive Officer

(principal executive officer)

  February 28, 2012

/s/ Thomas P. Chambers

Thomas P. Chambers

  

Executive Vice President and Chief Financial Officer

(principal financial officer)

  February 28, 2012

/s/ Rebecca A. Hoyt

Rebecca A. Hoyt

  

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

  February 28, 2012


Table of Contents

 

Name

  

Title

 

Date

/s/ Randolph M. Ferlic

Randolph M. Ferlic

  

Director

  February 28, 2012

/s/ Eugene C. Fiedorek

Eugene C. Fiedorek

  

Director

  February 28, 2012

/s/ A. D. Frazier, Jr.

A. D. Frazier, Jr.

  

Director

  February 28, 2012

/s/ Patricia Albjerg Graham

Patricia Albjerg Graham

  

Director

  February 28, 2012

/s/ Scott D. Josey

Scott D. Josey

  

Director

  February 28, 2012

/s/ Chansoo Joung

Chansoo Joung

  

Director

  February 28, 2012

/s/ John A. Kocur

John A. Kocur

  

Director

  February 28, 2012

/s/ George D. Lawrence

George D. Lawrence

  

Director

  February 28, 2012

/s/ William C. Montgomery

William C. Montgomery

  

Director

  February 28, 2012

/s/ Rodman D. Patton

Rodman D. Patton

  

Director

  February 28, 2012

/s/ Charles J. Pitman

Charles J. Pitman

  

Director

  February 28, 2012