ITEM 1. BUSINESS
General
Apache Offshore Investment Partnership, a Delaware general partnership (the Investment Partnership), was formed on October 31, 1983, consisting of Apache Corporation, a Delaware corporation, (Apache or Managing Partner), as Managing Partner and public investors (the Investing Partners). The Investment Partnership invested its entire capital in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership (the Operating Partnership), of which Apache is the sole general partner and the Investment Partnership is the sole limited partner. The primary business of the Investment Partnership is to serve as the sole limited partner of the Operating Partnership. The primary business of the Operating Partnership is to conduct oil and gas exploration, development and production operations. The Operating Partnership conducts the operations of the Investment Partnership.
The Investment Partnership does not maintain its own website. However, copies of this Form 10-K and the Partnership’s periodic filings with the Securities and Exchange Commission (SEC) can be found on the Managing Partner’s website at www.apachecorp.com/Offshore_Investment_Partnership. The Investment Partnership will also provide paper copies of these filings, free of charge, to anyone so requesting. Included in the Investment Partnership’s annual reports on Form 10-K and quarterly reports on Form 10-Q are the certifications of the Managing Partners’ principal executive officer and principal financial officer that are required by applicable laws and regulations. Any requests to the Partnership for copies of documents filed with the SEC should be made by mail to Apache Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas 77056, Attention: Glenn Hitchcock, or by telephone at 713-296-7097. The Partnership’s reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.
The Investing Partners purchased Units of Partnership Interests (Units) in the Investment Partnership at $150,000 per Unit, with five percent down and the balance in payments as called by the Investment Partnership. As of December 31, 2010, a total of $85,000 had been called for each Unit. In 1989, the Investment Partnership determined that the full $150,000 per Unit was not needed, fixed the total calls at $85,000 per Unit, and released the Investing Partners from liability for future calls. The Investment Partnership invested, and will continue to invest, its entire capital in the Operating Partnership. As used hereafter, the term “Partnership” refers to either the Investment Partnership or the Operating Partnership, as the case may be.
The Partnership’s business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. Except for the Matagorda Island Block 681 and 682 interests, as described below, the Partnership acquired its oil and gas interests through the purchase of 85 percent of the working interests held by Apache as a participant in a venture (the Venture) with Shell Oil Company (Shell) and certain other companies. The Partnership owns working interests ranging from 6.29 percent to 7.08 percent in the Venture’s properties.
The Venture acquired substantially all of its oil and gas properties through bidding for leases offered by the federal government. The Venture members relied on Shell’s knowledge and expertise in determining bidding strategies for the acquisitions. When Shell was successful in obtaining the properties, it generally billed participating members on a promoted basis (one-third for one-quarter) for the acquisition of exploratory leases and on a straight-up basis for the acquisition of leases defined as drainage tracts. All such billings were proportionately reduced to each member’s working interest.
In November 1992, Apache and the Partnership formed a joint venture to acquire Shell’s 92.6 percent working interest in Matagorda Island Blocks 681 and 682 pursuant to a jointly-held contractual preferential right to purchase. Apache and the Partnership previously owned working interests in the blocks equal to 1.109 percent and 6.287 percent, respectively, and net revenue interests of .924 percent and 5.239 percent, respectively. To facilitate the acquisition, Apache and the Partnership contributed all of their interests in Matagorda Island Blocks 681 and 682 to a newly formed joint venture, and Apache contributed $64.6 million ($55.6 million net of purchase price adjustments) to the joint venture to finance the acquisition. The Partnership had neither the cash nor additional financing to fund a proportionate share of the acquisition and participated through an increased net revenue interest in the joint venture.
Under the terms of the joint venture agreement, the Partnership’s effective net revenue interest in the Matagorda Island Block 681 and 682 properties increased to 13.284 percent as a result of the acquisition, while its working interest was unchanged. The acquisition added approximately 7.5 Bcf of natural gas and 16 Mbbls of oil to the Partnership’s reserve base without any incremental expenditures by the Partnership.
Since the Venture is not expected to acquire any additional exploratory acreage, future acquisitions, if any, will be confined to those leases defined as drainage tracts. The current Venture members would pay their proportionate share of acquiring any drainage tracts on a non-promoted basis.
Offshore exploration differs from onshore exploration in that production from a prospect generally will not commence until a sufficient number of productive wells have been drilled to justify the significant costs associated with construction of a production platform. Exploratory wells usually are drilled from mobile platforms until there are sufficient indications of commercial production to justify construction of a permanent production platform.
On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs.
Apache, as Managing Partner, manages the Partnership’s operations. Apache uses a portion of its staff and facilities for this purpose and is reimbursed for actual costs paid on behalf of the Partnership, as well as for general, administrative and overhead costs properly allocable to the Partnership.
2010 Results and Business Development
The Partnership reported net income in 2010 of $1.6 million, or $1,065 per Investing Partner Unit. Earnings were up $0.2 million, or 17 percent, from 2009 on higher oil and gas prices and lower operating expenses. The Partnership’s average realized oil price increased 33 percent from a year ago to $76.78 per barrel, while the Partnership’s average realized natural gas price increased 20 percent to $4.68 per mcf. Natural gas production averaged 1,647 Mcf per day in 2010, up 13 percent from 2009 with a full year’s production from Matagorda Island 681/682. The Partnership’s average daily oil production declined 52 percent from 2009 as the Partnership’s largest oil-producing field, South Timbalier 295, was shut-in for nearly half of 2010.
The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the field may be shut-in until April 2011 as a new sales line is built to restore production. Production from the field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. The shut-in of the South Timbalier 295 production significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2010.
During 2010, the Partnership’s oil and gas property expenditures totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. During the year, the Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 and began the installation of new equipment at South Timbalier 295 as part of the new sales line tie-in. While all of the recompletions were successful, the South Timbalier 295 wells remained shut-in with the rest of the field while the Partnership worked on installing a new oil sales line.
Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $2.5 million in 2011 for drilling at Ship Shoal 258/259, completion of the new sales line at South Timbalier 295 and recompletions at North Padre Island 969/976. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by contractors or changes by the operator to the development plan.
Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2010, 45 of those prospects have been surrendered or sold. As of December 31, 2010, the Partnership had 35 producing wells on the Partnership’s four remaining developed fields. Four of the Partnership’s producing wells are dual completions. The Partnership had, at December 31, 2010, estimated proved oil and gas reserves of 5.7 Bcfe.
Marketing
Apache, on behalf of the Partnership, seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. The objective is to maximize the value of the crude oil or natural gas sold by identifying the best markets and most economical transportation routes available to move the oil or natural gas. The oil contracts are generally thirty (30) day evergreen contracts and renew automatically until cancelled by either party. These contracts provide for sales that are priced daily at prevailing market prices. The Partnership’s oil and condensate production during 2010 was purchased largely by Shell Trading Company at market prices.
The Managing Partner markets the Partnership’s and its own U.S. natural gas production. The Partnership’s natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, and integrated major oil companies. Most of Apache’s and the Partnership’s natural gas is sold on a monthly basis at either monthly or daily market prices. The Partnership believes that the sales prices it receives for natural gas sales are market prices.
See Note (5) “Major Customer and Related Parties Information” to the Partnership’s financial statements under Item 8. Because the Partnership’s oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse affect on the Partnership’s business or results of operations.
ITEM 1A.
ITEM 1A. RISK FACTORS
The Partnership’s business activities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Partnership’s business, financial condition, liquidity and/or results of operations could be materially harmed, and holders of the Partnership Units could lose part or all of their investments.
Future economic conditions in the U.S. and key international markets may materially adversely impact the Partnership’s operating results.
The U.S. and other world economies are slowly recovering from a recession that began in 2008 and extended into 2009. Growth has resumed but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than we have experienced in recent years. In addition, more volatility may occur before a sustainable growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for the Partnership’s crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.
Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results.
The Partnership’s revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2010 ranged from a high of $92.89 per barrel to a low of $68.10 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond the Partnership’s control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:
•
worldwide and domestic supplies of crude oil and natural gas;
•
actions taken by foreign oil and gas producing nations;
•
political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;
•
the level of global crude oil and natural gas inventories;
•
the price and level of imported foreign crude oil and natural gas;
•
the price and availability of alternative fuels, including coal and biofuels;
•
the availability of pipeline capacity and infrastructure;
•
the availability of crude oil transportation and refining capacity;
•
weather conditions;
•
electricity generation;
•
domestic and foreign governmental regulations and taxes; and
•
the overall economic environment.
Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:
•
limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;
•
reducing the amount of crude oil and natural gas that we can produce economically;
•
causing us to delay or postpone some of our capital projects;
•
reducing our revenues, operating income and cash flows;
•
a reduction in the carrying value of our crude oil and natural gas properties; or
Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
A portion of our natural gas and oil production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
The shut-in of production from our South Timbalier 295 field could have a material adverse effect on our business, financial condition or results of operations.
Production from the South Timbalier 295 field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. Production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the shut-in may be for a lengthy period of time waiting on regulatory approvals for the required work and for completion of the new sales line. If we are unable to receive regulatory approvals for the completion of the work in a timely manner or if the work is not completed for an extended period, this shut-in could have a material adverse effect on the Partnership’s financial position, results of operations and our cash flows.
Weather and climate change may have a significant adverse impact on our revenues and productivity.
Demand for oil and natural gas is, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. Our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather, and not all such effects can be predicted, eliminated or insured against.
Declining commodity prices may require the Partnership to reduce capital expenditures or distributions to partners, or both, as cash from operating activities decline.
The Partnership is not likely to make any distributions to Investing Partners during 2011 as a result of capital outlays for drilling at Ship Shoal 258/259 and the completion of a new oil sales line at South Timbalier 295. If commodity prices remain at or decline from levels realized in 2010, the Partnership may not be able to make any distributions to Investing Partners during 2012. Declines in cash from operating activities may reduce funds available for capital expenditures.
We are exposed to counterparty credit risk as a result of our receivables.
The Partnership is exposed to risk of financial loss from trade, joint venture and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. Some of our purchasers and non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.
The Partnership may not realize an adequate return on its drilling activities.
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we participate in may not be productive and we may not recover all or any portion of our investment in those wells. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
•
unexpected drilling conditions;
•
pressure or irregularities in formations;
•
equipment failures or accidents;
•
fires, explosions, blow-outs and surface cratering;
•
marine risks such as capsizing, collisions and hurricanes;
•
other adverse weather conditions; and
•
increase in cost of, or shortages or delays in the delivery of equipment.
Future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Partnership is not likely to participate in exploratory drilling at this time.
Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which the Partnership adopted effective December 31, 2009, our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
•
historical production from the area compared with production from other areas;
•
the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reserves reporting requirements;
•
assumptions concerning future crude oil and natural gas prices;
•
future operating costs;
•
development costs; and
•
workover and remediation costs.
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
The Partnership may incur significant costs related to environmental matters.
As an owner or lessee of interests in oil and gas properties, the Partnership is subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations.
Our operations are subject to governmental risks that may impact our operations.
Our operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection laws and regulations. Such regulations may adversely impact our results on operations.
Proposed regulations related to emissions and the impact of any changes in climate could adversely impact our business.
While legislation is not currently pending in the United States, there has been discussion regarding legislation or regulation of greenhouse gas (GHG). Any such legislation, if enacted, could tax or assess some form of GHG related fees on the Partnership’s operations and could lead to increased operating expenses. Such legislation, if enacted, could also potentially cause the Partnership to make significant capital investments for infrastructure modifications.
Furthermore, various governmental entities have discussed regulatory initiatives that could, if adopted, require the Partnership to modify existing or planned infrastructure to meet GHG emissions performance standards and necessitate significant capital expenditures. At some level, the cost of performance standards may force the early retirement of smaller production facilities, which in the aggregate may have a material adverse effect on the Partnership’s business.
Several indirect consequences of regulation and business trends have potential to impact us. Taxes or fees on carbon emissions could lead to decreased demand for fossil fuels. Consumers may prefer alternative products and unknown technological innovations may make oil and gas less significant energy sources.
In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact the Partnership’s assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.
Proposed federal regulation regarding hydraulic fracturing could increase our operating and capital costs.
Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. The Partnership may use fracturing techniques to expand the available space for natural gas to migrate toward the well-bore. It is typically done at substantial depths in very tight formations.
Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.
Oil and gas operations involve a high degree of operational risk, particularly risk of personal injury, damage or loss of equipment and environmental accidents.
The Partnership’s operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:
•
drilling well blowouts, explosions and cratering;
•
pipeline ruptures and spills;
•
fires;
•
formations with abnormal pressures;
•
equipment malfunctions; and
•
hurricanes which could affect our operations in the Gulf of Mexico, as well as other natural disasters.
Failure or loss of equipment, as the result of equipment malfunctions or natural disasters, could result in property damages, personal injury, environmental pollution and other damages for which the Partnership could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a well blowout or pipeline rupture could result in environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flow and, in turn, our results of operations could be materially and adversely affected.
Any additional drilling laws and regulations, delays in the processing and approval of permits and other related developments in the Gulf of Mexico resulting from the Deepwater Horizon incident could adversely affect the Partnership’s business.
As has been widely reported, in April 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which lead to a significant oil spill that affected the Gulf of Mexico. In response to this incident, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) of the U.S. Department of the Interior (DOI) ceased issuing drilling permits pursuant to a series of moratoria, and all deepwater drilling activities in progress were suspended. Although the moratoria have been lifted, the DOI has not issued any permits related to the drilling of new exploratory wells in the deepwater Gulf of Mexico as of January 31, 2011. In 2010 the DOI issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to regulate drilling activities and increase liability.
In January 2011, the President’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government require additional regulation and an increase in liability caps. Additional legislation or regulation is being discussed which could require companies operating in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility, a certificate required by the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual insurance fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.
The BOEMRE is expected to continue to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. We are monitoring legislation and regulatory developments; however, it is difficult to predict the ultimate impact of any new guidelines, regulations or legislation. A prolonged suspension of drilling activity in the U.S. and new regulations and increased liability for companies operating in this sector could adversely affect the Partnership’s operations.
We have limited control over the activities on properties we do not operate.
Other companies operate the properties in which we have an interest. The Partnership has limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of projected costs and future cash flow.
The Partnership faces significant industry competition.
The Partnership is a very minor participant in the oil and gas industry in the Gulf of Mexico area and faces strong competition from much larger producers for the marketing of its oil and gas. The Partnership’s ability to compete for purchasers and favorable marketing terms will depend on the general demand for oil and gas from Gulf of Mexico producers. More particularly, it will depend largely on the efforts of Apache to find the best markets for the sale of the Partnership’s oil and gas production.
Insurance policies do not cover all risks.
Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Partnership had no comments from the staff of the SEC that were unresolved as of the date of filing of this report.
ITEM 2.
ITEM 2. PROPERTIES
Acreage
Acreage is held by the Partnership pursuant to the terms of various leases on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The Partnership does not anticipate any difficulty in retaining any of its leases. A summary of the Partnership’s gross and net acreage as of December 31, 2010, is set forth below:
At December 31, 2010, the Partnership did not have an interest in any undeveloped acreage.
Productive Oil and Gas Wells
The number of productive oil and gas wells in which the Partnership had an interest as of December 31, 2010, is set forth below:
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:
Production and Pricing Data
The following table provides, for each of the last three fiscal years, oil, natural gas liquids (NGLs) and gas production for the Partnership, average production costs (including gathering and transportation expense) and average sales prices.
The South Timbalier 295 field contains more than 15 percent of the Partnership’s proved reserved, expressed on an oil-equivalent-barrels basis. No other field contained 15 percent or more of the Partnership’s proved reserves as of December 31, 2010.
Estimated Proved Reserves and Future Net Cash Flows
Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set for the by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries-Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved
reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGL’s that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Reserve estimates are considered proved if they are economical producible and are supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.
As of December 31, 2010, the Partnership had total estimated proved reserves of 486,768 barrels of crude oil and condensate, 74,480 barrels of NGLs and 2.4 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 5.7 Bcf of gas. The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.
The following table shows proved oil, NGL and gas reserves as of December 31, 2010, based on commodity average prices in effect on the first day of each month in 2010, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.
The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2010, 2009 and 2008, changes in estimated proved reserves during the last three years, and estimates of future net cash flows and discounted future net cash flows from proved reserves are contained in the Supplemental Oil and Gas Disclosures (Unaudited) in the 2010 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows as of December 31, 2010 and 2009 were calculated using a discount rate of 10 percent per annum, end of period costs, and average commodity prices in effect on the first day of each month, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. Future net cash flows as of December 31, 2008, were estimated using commodity prices in effect at the end of those years, in accordance with the SEC guidelines in effect prior to the issuance of the Modernization Rules.
As of December 31, 2010, the Partnership had one undrilled location classified as proved undeveloped. The location is in North Padre Island 969/976 and is scheduled to be drilled within the next five years. The Partnership carried proved undeveloped reserves of 0.1 Bcf at both December 31, 2010 and 2009.
The volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. A copy of Ryder Scott’s report on the Shell Offshore Venture, of which the partnership owns approximately 85 percent, is filed as an exhibit to this Form 10-K.
The primarily technical person responsible for overseeing the preparation of the Partnership’s reserve estimates is Mrs. Jennifer A. Fitzgerald, a Vice President with Ryder Scott. Mrs. Fitzgerald has more than nine years of industry experience and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
At least annually, each property is reviewed in detail by Apache’s centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. Apache’s engineers furnish this information and estimates of dismantlement and abandonment cost to Ryder Scott for their consideration in preparing the Partnership’s reserve reports. The internal property reviews and collection of data provided to Ryder Scott is overseen by Apache’s Executive Vice President of Corporate Reservoir Engineering.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are no material legal proceedings pending to which the Partnership is a party or to which the Partnership’s interests are subject.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE PARTNERSHIP’S SECURITIES AND RELATED SECURITY HOLDER MATTERS
As of December 31, 2010, there were 1,021.5 of the Partnership’s Units outstanding held by 869 Investing Partners of record. The Partnership has no other class of security outstanding or authorized. The Units are not traded on any security market. No distributions were made to Investing Partners during 2010 or 2009.
As discussed in Item 7, an amendment to the Partnership Agreement in February 1994, created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash.
On June 6, 2008, certain affiliates of MacKenzie Patterson Fuller, LP (Purchasers) announced a tender offer to purchase up to 207 Units for $13,850 per Unit, less the amount of any distributions declared or made with respect to the Units between June 6, 2008 and July 18, 2008 (the offer expiration date). After resolution of an issue regarding an improperly submitted Unit, the offer resulted in the tender, and the acceptance for payment by the Purchasers, of a total of 6.1728 Units. Upon completion of the offer, the Purchasers hold an aggregate of 6.1728 Units, or approximately 0.6 percent of the total Investing Partner outstanding Units.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data for the five years ended December 31, 2010, should be read in conjunction with the Partnership’s financial statements and related notes included under Item 8 below of this Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
The Partnership’s business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The Partnership is a very minor participant in the oil and gas industry and faces strong competition in all aspects of its business. With a relatively small amount of capital invested in the Partnership and management’s decision to avoid incurring debt, the Partnership has not engaged in acquisition or exploration activities in recent years. The Partnership has not carried any debt since January 1997. The limited amount of capital and the Partnership’s modest reserve base, have contributed to the Partnership’s focus on production activities and development of existing leases.
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, and the Risk Factors information set forth in Part I, Item 1A of this Form 10-K.
The Partnership derives its revenue from the production and sale of crude oil, natural gas and natural gas liquids (NGLs). With only modest levels of production from current wells, the Partnership sells its production at market prices and has not used derivative financial instruments or otherwise engaged in hedging activities. During 2010, the Partnership benefited from higher market prices as its average realized oil and gas prices increased 33 percent and 20 percent, respectively from a year ago. Prices in recent year, however, have remained volatile and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate widely over the years.
While oil prices increased during 2010, the Partnership was unable to fully recognize potential benefits as the Partnership’s largest oil-producing field was shut-in for nearly half of the year. The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the field may be shut-in until the second quarter of 2011 as a new sales line is built to restore production. Production from the field accounted for approximately 54 percent and 44 percent of the Partnership’s total oil and gas sales dollars for 2009 and first half of 2010, respectively. The shut-in of the South Timbalier 295 production significantly reduced the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2010.
The Partnership participates in development drilling and recompletion activities as recommended by outside operators and the Partnership’s Managing Partner. During 2010, the Partnership’s oil and gas property expenditures totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. The Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 during 2010 and began the installation of new equipment at South Timbalier 295 as part of the new oil sales line tie-in.
Generally, the Partnership has used its available cash to fund distributions to its Partners. With the shut-in of the South Timbalier 295 field for nearly half of 2010 and the Partnership’s participation in drilling and recompletion projects during the year, the Partnership did not make any distributions to the Investing Partners during 2010. No distributions to Investing Partners were made in 2009 with the shut-in of the Matagorda Island 681/682 production, low oil and gas prices and an increase in the Partnership cash reserves for higher asset retirement obligation (ARO) liabilities.
We do not anticipate that the Partnership will make any distributions to Investing Partners during 2011 as the Partnership plans to participate in drilling wells at Ship Shoal 258/259 during 2011 and maintain cash reserves for future ARO expenditures. The timing of when distributions will be reinstated is dependent upon oil and gas prices realized by the Partnership for the sale of its production, the timing of when the South Timbalier 295 field is returned to production and the level of drilling and recompletion activity in 2011 and 2012.
Results of Operations
This section includes a discussion of the Partnership’s results of operations, and items contributing to changes in revenues and expenses during 2010, 2009, and 2008.
Net Income and Revenue
The Partnership reported net income of $1.6 million for 2010, up 17 percent from 2009 on higher oil and gas prices. Net income per Investing Partner Unit increased in 2010 to $1,065, up from $867 in 2009. The Partnership reported earnings of $1.3 million in 2009 and $5.3 million in 2008.
Total revenues in 2010 of $4.3 million were essentially even with 2009 as higher oil and gas prices offset the impact of lower oil production. Interest income earned by the Partnership on short-term cash investments in 2010 of $77 decreased from 2009 as a result of lower interest rates in 2010. Interest income totaled $229 in 2009 and $46,193 in 2008.
The Partnership’s revenues are sensitive to changes in prices received for its products. A substantial portion of the Partnership’s production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of its control. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on the prices received for the Partnership’s production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.
Declines in oil and gas production can be expected in future years as a result of normal depletion. Given the small number of producing wells owned by the Partnership, and the fact that offshore wells tend to decline at a faster rate than onshore wells, the Partnership’s future production will be subject to more volatility than those companies with greater reserves and longer-lived properties. It is not anticipated that the Partnership will acquire any additional exploratory leases or that significant drilling will take place on leases in which the Partnership currently holds interests.
The Partnership’s oil, gas and natural gas liquids (NGL) production volume and price information is summarized in the following table:
Natural Gas Sales
2010 vs. 2009 Natural gas sales for 2010 increased 36 percent from a year ago, rising to $2.8 million in the current period. A 20 percent increase in the Partnership’s average gas price increased sales by $0.4 million while a 13 percent increase in natural gas volumes during 2010 boosted sales by $0.3 million. The Partnership’s average realized gas prices increased to $4.68 per Mcf in 2010 from $3.89 per Mcf in 2009. The Partnership’s gas production in 2009 was hindered by the shut-in of Matagorda Island 681/682 for repairs to a third-party pipeline. The full year’s production at Matagorda 681/682 in 2010 boosted sales volumes by 406 Mcf per day over 2009, more than offsetting impact of the shut-in of production at South Timbalier 295 in 2010 and natural depletion at Ship Shoal 258/259 and North Padre Island 969/976.
2009 vs. 2008 The Partnership’s natural gas sales in 2009 totaled $2.1 million or 51 percent less than reported in 2008. During 2009, the partnership’s average realized natural gas price declined $5.04 per Mcf, or 56 percent, from 2008 and reduced sales by nearly $2.4 million. Production increases from 2008 offset $0.2 million of the impact of lower prices. Average daily production in 2009 increased 14 percent from 2008, rising to 1,455 Mcf per day in 2009. The increase in natural gas volumes reflected successful recompletions at Matagorda Island 681/682 during the second half of 2008 and at North Padre Island 969/976 during 2009, successful workover projects performed in 2009, and reduced downtime for inclement weather. Further increase in production was thwarted by the downtime at Matagorda Island 681/682 during 2009 for third-party pipeline repairs.
Crude Oil Sales
2010 vs. 2009 Crude oil sales for 2010 decreased 36 percent from a year ago, decreasing from $2.0 million in 2009 to $1.3 million in 2010. The Partnership’s crude oil volumes decreased from 98 barrels per day during 2009 to 47 barrels per day during 2010 as a result of the third-party pipeline shut-in of South Timbalier 295. The lower volumes reduced sales by $1.4 million. A $19.18 per barrel increase in oil prices from a year ago raised sales by $0.7 million, which partially offset the 51 barrel per day decline in production. The Partnership’s average realized price for the oil during 2010 increased 33 percent from 2009, rising to $76.78 per barrel in 2010.
2009 vs. 2008 Crude oil sales in 2009 dropped 39 percent from the $3.4 million of oil sales reported in 2008. A $53.01 per barrel, or 48 percent, decline in average realized oil price from 2008 drove the decline in sales. A $1.6 million decline in sales from lower prices was partially offset by $0.3 million of production increases. The Partnership’s 2009 crude oil sales volumes increased 17 percent from 2008, rising to 35,742 barrels of oil per day in 2009. The increase in production reflected less downtime at South Timbalier 295 for inclement weather and third-party pipeline repairs.
NGL Sales
The Partnership sold 8 barrels per day of NGL in 2010, down from 16 barrels per day in 2009. The decrease reflected lower production from South Timbalier 295 during 2010. NGL volumes also totaled 16 barrels per day in 2008. NGL prices declined 47 percent from 2008 to 2009 with the decline in oil prices and then increased 57 percent in 2010 with the resurgence in oil prices.
Operating Expenses
2010 vs. 2009 The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 19 percent during 2010, down from 22 percent in 2009. The decrease in rate as a percentage of oil and gas sales was driven by higher oil and gas prices in 2010. Lease operating expense (LOE) decreased 15 percent over the previous year on lower workover and repair and maintenance costs. During 2010, the Partnership participated in repairs at Matagorda Island 681/682, North Padre Island 969/976, Ship Shoal 258/259 and South Timbalier 295. Gathering and transportation costs increased from 2009 levels reflecting the increase in sales volumes in 2010 at Matagorda Island 681/682 and new marketing arrangements for North Padre Island 969 where the Partnership pays for its transportation cost instead of receiving a gas sales price which is net of transportation. Administrative expense for the year decreased slightly from 2009 to $403,000.
2009 vs. 2008 The Partnership’s DD&A rate, expressed as a percentage of oil and gas sales, was approximately 22 percent during 2009, up from 11 percent in 2008. The increase in rate as a percentage of oil and gas sales was driven by lower oil and gas prices in 2009. DD&A on an absolute basis increased as a result of increased production and higher plugging and dismantlement cost. LOE increased 25 percent over the previous year on higher workover and repair and maintenance costs. During 2009, the Partnership participated in workovers at North Padre Island 969/976, Ship Shoal 258/259 and South Timbalier 295. LOE for the period also included repairs to a compressor on the South Timbalier 295 platform and maintenance cost at Matagorda Island 681/682. LOE for 2009 excludes $64,605 of expected insurance reimbursement for Hurricane Ike damage. The repair cost subject to insurance reimbursement is primarily for a gathering line at Ship Shoal 258/259 and for handrail, grating and decking repairs on various platforms. Gathering and transportation costs increased from 2008 levels reflecting the increase in sales volumes in 2009. Administrative expense for the year decreased slightly from 2008 to $418,000.
The Partnership sells oil and natural gas under two types of transactions, both of which include a transportation charge. One is a netback arrangement, under which the Partnership sells oil or natural gas as the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Partnership records sales at the price received from the purchaser which is net of transportation costs. Under the other arrangement, the Partnership sells oil or natural gas at a specific delivery point, pays transportation to a carrier and receives from the purchaser a price with no transportation deduction. In this case, the Partnership records the transportation cost as gathering and transportation costs. The Partnership’s treatment of transportation costs is pursuant to Emerging Issues Task Force Issue 00-10, “Accounting or Shipping and Handling Fees and Costs” and as a result a portion of our transporting costs are reflected in sales prices and a portion is reflected as transportation and gathering costs.
Capital Resources and Liquidity
The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.5 million for 2010. The Partnership’s 2010 net cash provided by operating activities increased $0.5 million from 2009 on increased earnings and reduced receivables. Net cash provided by operating activities in 2009 of $2.0 million decreased 69 percent from 2008 as a result of oil and gas prices dropping 48 percent and 56 percent, respectively, from 2008. A $.3 million increase in lease operating expense in 2009 also contributed to net cash provided by operating activities declining from 2008.
At December 31, 2010, the Partnership had approximately $3.0 million in cash and cash equivalents, up from slightly more than $2.0 million at December 31, 2009. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the value of its future asset retirement obligations (ARO) and to participate in future drilling and recompletion opportunities. The Partnership increased its cash balances during 2010 as a reserve for the higher projected ARO and to fund capital expenditures projected for the first half of 2011.
The Partnership’s future financial condition, results of operations and cash from operating activities will largely depend upon prices received for its oil and natural gas production. A substantial portion of the Partnership’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Partnership’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.
The Partnership’s oil and gas reserves and production will also significantly impact future results of operations and cash from operating activities. The Partnership’s production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can be expected in future years as a result of normal depletion and the Partnership not participating in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership expects it will be able to meet its liquidity needs for routine operations in the foreseeable future.
Approximately 75 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves and that the estimated reserves from these projects are based on prices at December 31, 2010. The Partnership’s liquidity may be negatively impacted if the actual quantities of reserves that are ultimately produced are materially different from current estimates. Also, if prices decline significantly from current levels, the Partnership may not be able to fund the necessary capital investment, or development of the remaining reserves may not be economical for the Partnership.
The Partnership may reduce capital expenditures or distributions to partners, or both, as cash from operating activities decline. In the event that future short-term operating cash requirements are greater than the Partnership’s financial resources, the Partnership may seek short-term, interest-bearing advances from the Managing Partner as needed. The Managing Partner, however, is not obligated to make loans to the Partnership. The Partnership does not intend to incur debt from banks or other outside sources or solicit capital from exiting Unit holders or in the open market.
On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment cost. The Partnership did not sell any properties in 2010, 2009 or 2008.
Capital Commitments
The Partnership’s primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. The Partnership had no outstanding debt or lease commitments at
December 31, 2010. The Partnership did not have any contractual obligations as of December 31, 2010, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for the fair value of the ARO as discussed under the discussion of critical accounting policies noted below.
During 2010, the Partnership’s oil and gas property expenditures totaled $2.6 million. The Partnership participated in drilling one well during 2010; the Ship Shoal 259 JA-3 ST2 which was completed as a producer in December 2010. During the year, the Partnership also participated in three recompletions in the South Timbalier 295 field, two recompletions at North Padre Island 969/976 and began the installation of new equipment at South Timbalier 295 as part of the new sales line tie-in. While all of the recompletions during 2010 were successful, the South Timbalier 295 wells remained shut-in with the rest of the field while the Partnership worked on installing a new oil sales line. During 2009, the Partnership’s oil and gas property expenditures totaled $0.6 million. The Partnership participated in two recompletions in the North Padre Island 969/976 field and one recompletion at Matagorda Island 681/682 during the year. During 2008, the Partnership’s oil and gas property expenditures totaled $1.0 million. The Partnership participated in drilling one well in the North Padre Island 969/976 Field during 2008. The well was unsuccessful in its initial evaluation, and Apache and the Partnership elected not to participate in a sidetrack well proposed by the operator. The Partnership also participated in recompletions at Matagorda 681/682 and South Timbalier 295 during 2008.
Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $2.5 million in 2011 for drilling at Ship Shoal 258/259, completion of the new sales line at South Timbalier 295 and recompletions at North Padre Island 969/976. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by contractors or changes by the operator to the development plan.
No distributions were paid to Investing Partners during 2010 or 2009 as a result of the shut-in of production for extended periods of time during the period and cash requirements for drilling, recompletion and repair activities. Distributions of $5,500 per Unit were made to Partners during 2008 resulting in total distributions to Limited Partners of $5.7 million in 2008. The amount of future distributions will be dependent on actual and expected production levels, realized and expected oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted.
We do not anticipate that the Partnership will make any distribution to Investing Partners in 2011 as a result of planned capital outlays for drilling and recompletion activities during 2011 and the continued shut-in of South Timbalier 295 while a new oil sales line is being constructed. Once oil production has resumed at South Timbalier 295, the Partnership will need to replenish its cash reserve for future plugging and abandonment expenditures. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the value of its future asset retirement obligations.
In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. In 2010 and 2009, the Partnership did not offer to purchase any Units from Investing Partners as a result of the limited amount of cash available for discretionary purposes. In 2008, Investing Partners were paid $228,995, respectively, for a total of 16.7 Units.
There will be two rights of presentment in 2011, but the Partnership is not in a position to predict how many Units will be presented for repurchase and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase Units. The Amended Partnership Agreement contains limitations on the number of Units that the Partnership can repurchase, including an annual limit on repurchases of 10 percent of outstanding Units. The Partnership has no obligation to repurchase any Units presented to the extent that it determines that it has insufficient funds for such repurchases. The Partnership is not likely to have funds available to repurchase Units during 2011.
Off-Balance Sheet Arrangements
The Partnership does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership.
Insurance
The Managing Partner maintains insurance coverage that includes coverage for physical damage to the Partnership’s oil and gas properties, third party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. The insurance coverage includes deductibles which must be met prior to recovery. Additionally, the Managing Partner’s insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
The Managing Partner’s various insurance policies also provide coverage for, among other things, liability related to negative environmental impacts of a sudden pollution, charterer’s legal liability and general liability, employer’s liability and auto liability. The Managing Partner’s service agreements, including drilling contracts, generally indemnify Apache and the Partnership for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.
In light of the recent catastrophic accident in the Gulf of Mexico, the Managing Partner and the Partnership may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.
Critical Accounting Policies and Estimates
The Partnership prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and accompanying notes. Management identifies certain accounting policies as critical based on, among other things, their impact on the Partnership’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their development. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Following is a discussion of Partnership’s most critical accounting policies:
Reserve Estimates
Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set forth by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries-Oil and Gas". The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
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, 2010 and 2009 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of production, except where prices are defined by contractual arrangements. Reserves as of December 31, 2008 were estimated using prices in effect at the end of those years, in accordance with SEC guidance in effect prior to the issuance of the Modernization Rules.
The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.
The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner.
Asset Retirement Obligation (ARO)
The Partnership has obligations to remove tangible equipment and restore the land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership’s limited operations and estimate of remaining reserves. The Partnership’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Asset retirement obligations associated with retiring tangible long-lived assets, are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable. This liability is offset by a corresponding increase in the carrying amount of the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Partnership’s oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, weather and climate, and governmental risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
The Partnership’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to the Partnership’s natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. During 2010, monthly oil price realizations ranged from a low of $60.51 per barrel to a high of $84.09 per barrel. Gas price realizations ranged from a monthly low of $3.57 per Mcf to a monthly high of $6.67 per Mcf during the same period. Based on the Partnership’s average daily production for 2010, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $17,000 and a $.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $60,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2010. Due to the volatility of commodity prices, the Partnership is not in a position to predict future oil and gas prices.
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.
Forward-Looking Statements and Risk
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2010, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
•
the market prices of oil, natural gas, NGLs and other products or services;
•
the supply and demand for oil, natural gas, NGLs and other products or services;
•
production and reserve levels;
•
drilling risks;
•
economic and competitive conditions;
•
the availability of capital resources;
•
capital expenditure and other contractual obligations;
•
weather conditions;
•
inflation rates;
•
the availability of goods and services;
•
legislative or regulatory changes;
•
terrorism;
•
the capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and
•
other factors disclosed under Items 1 and 2 - “Business and Properties - Estimated Proved Reserves and Future Net Cash Flows,” Item 1A - “Risk Factors,” Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A - “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this Form 10-K.
All subsequent written and oral forward-looking statements attributable to the Partnership, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.
ADDITIONAL INFORMATION ABOUT THE PARTNERSHIP
Remediation Plans and Procedures
The Partnership’s Managing Partner adopted a Region Spill Response Plan for its Gulf of Mexico operations to ensure a rapid and effective response to spill events that may occur on Apache-operated properties. The Partnership does not operate any properties for itself or others. Periodically, drills are conducted by Apache to measure and maintain the effectiveness of its plan. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache in the event of a spill is CGA. Apache has received approval for its plan from the Bureau of Ocean Energy Management, Regulatory and Enforcement (formerly, the Minerals Management Service). Apache personnel review the plan annually and update where necessary.
As part of our Region Spill Response Plan, the Managing Partner is a member of, and has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine Preservation Association. MSRC maintains CGA’s equipment (including skimmers, fast response vessels, fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies which provide support services during spill response. In the event of a spill, MSRC will activate these contracts as necessary to provide additional resources or support services requested by its customers. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), which provides aircrafts and dispersant capabilities for CGA member companies.
In the event that CGA and MSRC resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited is the world’s largest oil spill preparedness and response organization, dedicated to providing resources to respond to oil spills efficiently and effectively on a global basis. In addition, resources of other organizations are available to Apache as a non-member, such as those of National Response
Corporation (NRC) and MSRC, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels and dispersant aircraft. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland work boats, vacuum transfer units and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time-to-time and current information is generally available on each of the companies’ websites.
In light of the current events in the Gulf of Mexico, Apache is participating in a number of industry-wide task forces, which are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.
Environmental Compliance
As an owner or lessee and operator of oil and gas properties, the Partnership is subject to numerous federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.
The Partnership has made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. The Managing Partner has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to the Partnership’s operations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, the Partnership does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures or earnings.
Changes to existing, or additions of, laws, regulations, enforcement policies or requirements could require the Partnership to make additional capital expenditures. While the events in the U.S. Gulf of Mexico in 2010 have resulted in the enactment of, and may result in the enactment of additional, laws or requirements regulating the discharge of materials into the environment, we do not believe that any such regulations or laws enacted or adopted as of this date will have a material adverse impact on the Partnership’s cost of operations or earnings.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
APACHE OFFSHORE INVESTMENT PARTNERSHIP
Schedules -
All financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the financial statements or related notes thereto.
REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Partnership is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
Management of the Partnership is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (Exchange Act). The Partnership’s and Managing Partner’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by the Managing Partner’s board of directors, applicable to all the Managing Partner’s directors, officers and employees.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2010.
G. Steven Farris
Chairman and Chief Executive Officer
(principal executive officer)
of Apache Corporation, Managing Partner
Thomas P. Chambers
Executive Vice President and Chief Financial Officer
(principal financial officer)
of Apache Corporation, Managing Partner
Rebecca A. Hoyt
Vice President, Chief Accounting Officer and Controller
(principal accounting officer)
of Apache Corporation, Managing Partner
Houston, Texas
February 28, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Apache Offshore Investment Partnership:
We have audited the accompanying consolidated balance sheets of Apache Offshore Investment Partnership (a Delaware general partnership) as of December 31, 2010 and 2009, and the related consolidated statements of income, cash flows and changes in partners’ capital for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, in 2009, the Partnership adopted SEC Release 33-8995 and the amendments to ASC Topic 932, “Extractive Industries - Oil and Gas,” resulting from ASU 2010-03 (collectively, the Modernization Rules).
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Offshore Investment Partnership at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
Houston, Texas
February 28, 2011
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
The accompanying notes to financial statements are
an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying notes to financial statements are
an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
The accompanying notes to financial statements are
an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL
The accompanying notes to financial statements are
an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION
Nature of Operations
Apache Offshore Investment Partnership, a Delaware general partnership (the Investment Partnership), was formed on October 31, 1983, consisting of Apache Corporation (Apache or Managing Partner) as Managing Partner and public investors (the Investing Partners). The Investment Partnership invested its entire capital in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership (the Operating Partnership). The primary business of the Investment Partnership is to serve as the sole limited partner of the Operating Partnership. The primary business of the Operating Partnership is to conduct oil and gas exploration, development and production operations. The Operating Partnership conducts the operations of the Investment Partnership. The accompanying financial statements include the accounts of both the Investment Partnership and Operating Partnership. Apache is the general partner of both the Investment and Operating partnerships, and held approximately five percent of the 1,021.5 Investing Partner Units (Units) outstanding at December 31, 2010. The term “Partnership”, as used hereafter, refers to the Investment Partnership or the Operating Partnership, as the case may be.
The Partnership purchased, at cost, an 85 percent interest in offshore leasehold interests acquired by Apache as a co-venturer in a series of oil and gas exploration, development and production activities on 87 federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The remaining 15 percent interest was purchased by an affiliated partnership or retained by Apache. The Partnership acquired an increased net revenue interest in Matagorda Island Blocks 681 and 682 in November 1992, when the Partnership and Apache formed a joint venture to acquire a 92.6 percent working interest in the blocks.
Since inception, the Partnership has participated in 14 federal offshore lease sales in which 49 prospects were acquired (over the same period, 45 of those prospects have been surrendered/sold). The Partnership’s working interests in the four remaining venture prospects range from 6.29 percent to 7.08 percent. As of December 31, 2010, the Partnership held a remaining interest in nine tracts acquired through federal lease sales.
The Partnership’s future financial condition and results of operations will depend largely upon prices received for its oil and natural gas production and the costs of acquiring, finding, developing and producing reserves. A substantial portion of the Partnership’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Partnership’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.
Under the terms of the Partnership Agreements, the Investing Partners receive 80 percent and Apache receives 20 percent of revenue. Lease operating, gathering and transportation, and administrative expenses are allocated to the Investing Partners and Apache in the same proportion as revenues. The Investing Partners receive 100 percent of the interest income earned on short-term cash investments. The Investing Partners generally pay for 90 percent and Apache generally pays for 10 percent of exploration and development costs and expenses incurred by the Partnership. However, intangible drilling costs, interest costs and fees or expenses related to the loans incurred by the Partnership are allocated 99 percent to the Investing Partners and one percent to Apache until such time as the amount so allocated to the Investing Partners equals 90 percent of the total amount of such costs, including such costs incurred by Apache prior to the formation of the Partnership.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Right of Presentment
In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. The Partnership did not offer to purchase any Units from Investing Partners in either 2010 or 2009 as a result of the limited amount of cash available for discretionary purposes. In 2008, Investing Partners were paid $228,995, respectively, for a total of 16.7 Units.
The Partnership is not in a position to predict how many Units will be presented for repurchase during 2010; however, no more than 10 percent of the outstanding Units may be purchased under the right of presentment in any year. The Partnership has no obligation to purchase any Units presented to the extent that it determines that it has insufficient funds for such purchases.
The table below sets forth the total repurchase price and the repurchase price per Unit for all outstanding Units at each presentment period, based on the right of presentment valuation formula defined in the amendment to the Partnership Agreement. The right of presentment offers made twice annually are based on a discounted Unit value formula. The discounted Unit value will be not less than the Investing Partner’s share of: (a) the sum of (i) 70 percent of the discounted estimated future net revenues from proved reserves, discounted at a rate of 1.5 percent over prime or First National Bank of Chicago’s base rate in effect at the time the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv) accounts receivable less a reasonable reserve for doubtful accounts, (v) oil and gas properties other than proved reserves at cost less any amounts attributable to drilling and completion costs incurred by the Partnership and included therein, and (vi) the book value of all other assets of the Partnership, less the debts, obligations and other liabilities of all kinds (including accrued expenses) then allocable to such interest in the Partnership, all determined as of the valuation date, divided by (b) the number of Units, and fractions thereof, outstanding as of the valuation date. The discounted Unit value does not purport to be, and may be substantially different from, the fair market value of a Unit.
Capital Contributions
A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2010. The Partnership determined the full purchase price of $150,000 per Unit was not needed, and upon completion of the last subscription call in November 1989, released the Investing Partners from their remaining liability. As a result of investors defaulting on cash calls and repurchases under the presentment offer discussed above, the original 1,500 Units have been reduced to 1,021.5 Units at December 31, 2010.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by the Partnership reflect industry practices and conform to accounting principles generally accepted in the United States (GAAP). Significant policies are discussed below.
Statement Presentation
The accompanying consolidated financial statements include the accounts of Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. (See the unaudited “Supplemental Oil and Gas Disclosures” below), asset retirement obligations and contingency obligations.
Cash Equivalents
The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2010 and 2009, the Partnership had $3.0 and $2.0 million of cash equivalents.
Oil and Gas Properties
The Partnership uses the full cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method of accounting, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. Costs associated with production and administrative functions are expensed in the period incurred. The Partnership includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance as described in Note 8. Unless a significant portion of the Partnership’s reserve volumes are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains or losses are not recognized.
Capitalized costs of oil and gas properties are amortized on the future gross revenue method whereby depreciation, depletion and amortization (DD&A) expense is computed quarterly by dividing current period oil and gas sales by estimated future gross revenue from proved oil and gas reserves (including current period oil and gas sales) and applying the resulting rate to the net cost of evaluated oil and gas properties, including estimated future development costs.
Under the full-cost method of accounting, the Partnership limits the capitalized costs of proved oil and gas properties, net of accumulated DD&A, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, if any. This ceiling test is performed each quarter. If capitalized costs exceed this limit, the excess is charged to DD&A expense. The Partnership has not recorded any write-downs of capitalized costs for the three years
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
presented. Please see “Future Net Cash Flows” in the Supplemental Oil and Gas Disclosures included in this Form 10-K for a discussion on calculation of estimated future net cash flows.
Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set for the by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries-Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
The estimate of future net cash flows as of December 31, 2010 and 2009, were calculated using a discount rate of 10 percent per annum, end-of-period costs, and an unweighted arithmetic average commodity prices in effect on the first day of each month, held flat for the life of production, except where prices are defined by contractual arrangements. Prior to adoption of the Modernization Rules, estimated future net cash flows were calculated using commodity prices in effect at the end of each quarter.
Asset Retirement Obligation
The initial estimated asset retirement obligation (ARO) related to properties is recognized as a liability, with an associated increase in property and equipment for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.
Revenue Recognition
Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. The Partnership uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. As of December 31, 2010 and 2009, the Partnership did not have any liabilities for imbalances in excess of remaining reserves. No receivables are recorded for those wells where the Partnership has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas revenues and future cash flows in the unaudited supplemental oil and gas disclosures. Adjustments for gas imbalances totaled less than one percent of the Partnership’s proved gas reserves at December 31, 2010 and 2009.
Insurance Coverage
The Partnership recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.
Net Income Per Investing Unit
The net income per Investing Partner Unit is calculated by dividing the aggregate Investing Partners’ net income for the period by the number of weighted average Investing Partner Units outstanding for that period.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income Taxes
The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.
Receivable from / Payable to Apache Corporation
The receivable from/payable to Apache Corporation, the Partnership’s Managing Partner (Apache or the Managing Partner), represents the net result of the Investing Partners’ revenue and expenditure transactions in the current month. Generally, cash in this amount will be paid by Apache to the Partnership or transferred to Apache in the month after the Partnership’s transactions are processed and the net results of operations are determined.
Maintenance and Repairs
Maintenance and repairs are charged to expense as incurred.
Recently Issued Accounting Standards Not Yet Adopted
All new accounting pronouncements previously issued have been adopted as of or prior to December 31, 2010.
(3) COMPENSATION TO APACHE
Apache is entitled to the following types of compensation and reimbursement for costs and expenses.
Apache operates certain Partnership properties. Billings to the Partnership are made on the same basis as to unaffiliated third parties or at prevailing industry rates.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4) OIL AND GAS PROPERTIES
The following tables contain direct cost information and changes in the Partnership’s oil and gas properties for each of the years ended December 31. All costs of oil and gas properties are currently being amortized.
Development cost for 2009 includes $.9 million of asset retirement cost.
The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2010, 2009 and 2008 was 19 percent, 22 percent and 11 percent, respectively.
(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION
Revenues received from major third party customers that equaled ten percent or more of oil and gas sales are discussed below. No other third party customers individually accounted for ten percent or more of oil and gas sales.
In 2010, sales to Shell Trading Company, Florida Power Corporation and Sequent Energy Management LP accounted for 30 percent, 16 percent and 10 percent, respectively, of the Partnership’s oil and gas sales for the year. Sales to Shell Trading Company accounted for 48 percent of the Partnership’s oil and gas sales in 2009. Sales to Shell Trading Company and Plains Marketing LP accounted for 27 percent and 16 percent, respectively, of the Partnership’s oil and gas sales in 2008.
Effective November 1992, with Apache’s and the Partnership’s acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees totaling $40,562 in 2010, $24,210 in 2009 and $19,124 in 2008 for the Partnership’s share of gas. The fees were at the same rates and terms as previously paid to Shell.
All transactions with related parties were consummated at fair value.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Partnership’s revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. The Partnership has not experienced material credit losses on such sales.
(6) FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents, accrued revenues receivables and accrued costs included in the accompanying balance sheet approximated their fair values at December 31, 2010 and 2009 due to their short maturities. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2010.
(7) COMMITMENTS AND CONTINGENCIES
Litigation - The Partnership is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache’s management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations.
Environmental - The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. Apache maintains insurance coverage on the Partnership’s properties, which it believes, is customary in the industry, although it is not fully insured against all environmental risks.
(8) ASSET RETIREMENT OBLIGATION
The following table is a reconciliation of the Partnership’s ARO liability for the years ended December 31, 2010 and 2009:
The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Partnership’s oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
Liabilities settled primarily relate to individual wells plugged and abandoned during the periods presented. Revisions to estimated liabilities in 2009 reflected the Managing Partner’s updated estimates of the extent of the work required and cost involved in the dismantlement and site reclamation of offshore properties, and shorter reserve lives projected for certain of the Partnership’s properties.
In September 2010 the Bureau of Ocean Management, Regulation and Enforcement (BOEMRE, formerly known as the Minerals Management Service), a division of the U.S. Department of the Interior, issued Notice to Lessees (NTL) No. 2010-G05, which includes guidelines for decommissioning idle infrastructure on active leases in the Gulf of Mexico within a specified period of time. During 2010, the Partnership adjusted the timing of its abandonment program accordingly.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(9) TAX-BASIS FINANCIAL INFORMATION
A reconciliation of ordinary income for federal income tax reporting purposes to net income under accounting principles generally accepted in the United States is as follows:
The Partnership’s tax bases in net oil and gas properties at December 31, 2010 and 2009 was $5,696,154 and $3,950,153, respectively, lower than carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2010 and 2009.
A reconciliation of liabilities for federal income tax reporting purposes to liabilities under accounting principles generally accepted in the United States is as follows:
Asset retirement liabilities for future dismantlement and abandonment costs are not recognized for federal income tax reporting purposes until settled.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
Oil and Gas Reserve Information
Effective December 31, 2009, the Partnership adopted revised oil and gas disclosure requirements set for the by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries-Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
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)
Oil includes crude oil, condensate and natural gas liquids.
All the Partnership’s reserves are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas.
Approximately 75 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves. The capital and economic impact of production timing are reflected in the Partnership’s standardized measure under Future Net Cash Flows.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL OIL AND GAS DISCLOSURES - (Continued)
(UNAUDITED)
Future Net Cash Flows
Future cash inflows as of December 31, 2010 and 2009 were calculated using an average of oil and gas prices in effect on the first day of each month, except where prices are defined by contractual arrangements. Future cash inflows as of December 31, 2008 were estimated using oil and gas prices in effect at the end of those years, except where prices are defined by contractual arrangements, in accordance with SEC guidance in effect prior to the issuance of the Modernization Rules. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
Discounted Future Net Cash Flows Relating to Proved Reserves
The following table sets forth the principal sources of change in the discounted future net cash flows:
APACHE OFFSHORE INVESTMENT PARTNERSHIP
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
(1)
The sum of the individual net income per Investing Partner Unit may not agree with the year-to-date net income per Investing Partner Unit as each quarterly computation is based on the weighted average number of Investing Partner Units during that period.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Control and Procedures
G. Steven Farris, the Managing Partner’s Chairman of the Board and Chief Executive Officer (principal executive officer) , and Thomas P. Chambers, the Managing Partner’s Executive Vice President and Chief Financial Officer (principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2010, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2010, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
Report on Internal Control Over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the Report of Management on Internal Control over Financial Reporting, included on page 20 of this report. This annual report does not include an attestation report of the Partnership’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this annual report.
Changes in Internal Control Over Financial Reporting
There was no change in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2010, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP
All management functions are performed by Apache, the Managing Partner of the Partnership. The Partnership itself has no officers or directors. Information concerning the officers and directors of Apache set forth under the captions “Nominees for Election as Directors”, “Continuing Directors”, “Executive Officers of the Company”, and “Securities Ownership and Principal Holders” in the proxy statement relating to the 2011 annual meeting of stockholders of Apache (the Apache Proxy) is incorporated herein by reference.
Code of Business Conduct
Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, Apache was required to adopt a code of business conduct and ethics for its directors, officers and employees. In February 2004, Apache’s Board of Directors adopted a Code of Business Conduct (Code of Conduct), and revised it in November 2010. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access Apache’s Code of Conduct on the “Governance” page of Apache’s website at www.apachecorp.com. Changes in and any waivers to the Code of Conduct for Apache’s directors, chief executive officer and certain senior financial officers will be posted on Apache’s website within five business days and maintained for at least twelve months.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
See Note (3), “Compensation to Apache” of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. The information concerning the compensation paid by Apache to its officers and directors set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards,” “Outstanding Equity Awards at Fiscal Year-End,” “Option Exercises and Stock Vested,” “Non-Qualified Deferred Compensation,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements,” and “Director Compensation” in the Apache Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Apache, as an Investing Partner and the General Partner, owns 53 Units, or 5.2 percent of the outstanding Units of the Partnership, as of December 31, 2010. Directors and officers of Apache own four Units, less than one percent of the Partnership’s Units, as of December 31, 2010. Apache owns a one-percent General Partner interest (15 equivalent Units). To the knowledge of the Partnership, no Investing Partner owns, of record or beneficially, more than five percent of the Partnership’s outstanding Units, except for Apache which owns 53 Units or 5.2 percent of the outstanding Units. Apache did not acquire additional Units during the three years covered by these financial statements. Apache’s ownership percentage exceeds five percent due to the decrease in the number of outstanding units resulting from the right of presentment (see Note 1).
ITEM 13.
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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Accountant fees and services paid to Ernst & Young LLP, the Partnership’s independent auditors, are included in amounts paid by the Partnership’s Managing Partner. Information on the Managing Partner’s principal accountant fees and services is set forth under the caption “Independent Public Accountants” in the Apache Proxy.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
a.
(1) Financial Statements - See accompanying index to financial statements in Item 8 above.
(2)
Financial Statement Schedules - See accompanying index to financial statements in Item 8 above.
(3)
Exhibits
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.
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,
/s/ Thomas P. Chambers
Thomas P. Chambers
Executive Vice President and
Chief Financial Officer
(principal financial officer)
February 28,
/s/ Rebecca A. Hoyt
Rebecca A. Hoyt
Vice President, Chief
Accounting Officer and Controller
(principal accounting officer)
February 28,