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 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 Investment 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: Investor Relations, or by telephone at 1-281-302-2286. 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, 2018, 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 development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. Except for an additional interest acquired in Matagorda Island Block 681 and 682 in 1992, 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 Venture acquired substantially all of its oil and gas properties through bidding for leases offered by the federal government, and relied on Shell’s knowledge and expertise in determining bidding strategies and development of the properties. The Partnership owned working interests ranging from 6.29 percent to 7.08 percent in the Venture’s properties.
Apache, as Managing Partner, manages the Partnership’s business activities. 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.
2018 Results and Business Development
The Partnership reported net income for 2018 of $271 thousand, or $170 per Investing Partner Unit. This represents an increase of approximately $528 thousand from the $257 thousand net loss reported in 2017. The increase in net income compared to the prior year was predominately related to higher crude oil production and realized prices during 2018. The Partnership’s average realized crude oil prices increased 36 percent from a year ago to $65.36 per barrel while gas prices decreased 6 percent from 2017 to $3.27 per Mcf. Oil production averaged 53 barrels of oil per day in 2018, up 15 percent from 2017. Natural gas production averaged 101 Mcf per day in 2018, down 11 percent from 2017. The Partnership’s reduction in gas production for 2018 primarily reflects the third-party pipeline shut-down at Ship Shoal 258/259, which began at the end of the first quarter of 2017. The operator determined that is was uneconomical to bring production back on-line, and therefore, decided to not renew the lease, which expired early in 2018.
During 2018, the Partnership’s cash outlays for capital expenditures totaled $158 thousand, primarily for pipeline rerouting and recompletion projects at South Timbalier 295. The Partnership did not participate in any new drilling projects during the year. Based on preliminary information available to the Partnership, it anticipates that 2019 capital expenditures will be similar to 2018 levels for recompletion projects scheduled at South Timbalier 295. Additionally, $390 thousand is estimated to be spent in 2019 for abandonment activities at Ship Shoal 258/259 and to remove the idle platforms at North Padre Island
969/976. Decommissioning and abandonment activity has begun at Ship Shoal 258/259 and is expected to be completed over the next two years. The abandonment activity at North Padre Island 969/976 was originally scheduled to be completed prior to 2018, but has been deferred to 2019 pending approval from regulators. Such estimates may change based on realized oil and gas prices, drilling and recompletion results, rates charged by contractors or changes by the operator to their development or abandonment plans.
Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2018, 48 of those prospects have been surrendered or sold. As of December 31, 2018, the Partnership had 18 productive wells on its remaining developed field, South Timbalier 295, offshore Louisiana. The Partnership had estimated proved oil and gas reserves of 504,201 barrels of oil equivalent at December 31, 2018.
For a more in-depth discussion of the Partnership’s 2018 results and its capital resources and liquidity, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.
Marketing
The Partnership has historically marketed its oil and gas production under the joint operating agreements with the operators of its properties. Beginning in 2016, Apache, as Managing Partner of the Partnership, began marketing the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of production. The third-party operator continues to market all other production of the Partnership. The change in Apache’s marketing of oil production from South Timbalier 295 was made to improve the timing of cash receipts and reduce the credit risk from third-party purchasers and remitters. Apache primarily markets to major oil companies, marketing and transportation companies, and refiners at current index prices, adjusted for quality, transportation, and market-reflective differentials.
Through the operator, the Partnership’s natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, and integrated major oil companies. Most of 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 oil and natural gas sales are market prices.
For a more in-depth discussion of the Partnership’s significant customers, see Note 5 - “Major Customer and Related Parties Information” to the Partnership’s financial statements under Item 8 of this Form 10-K. Because the Partnership’s oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse effect on the Partnership’s business or results of operations.
ITEM 1A.
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.
Crude oil and natural gas price volatility could adversely affect our operating results.
The Partnership’s revenues and operating results 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. 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:
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worldwide and domestic supplies of crude oil and natural gas;
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actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
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political conditions and events (including instability, changes in governments, or armed conflict) in crude oil or natural gas producing regions;
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the level of global crude oil and natural gas inventories;
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the price and level of imported foreign crude oil and natural gas;
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the price and availability of alternative fuels, including coal and biofuels;
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the availability of pipeline capacity and infrastructure;
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the availability of crude oil transportation and refining capacity;
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weather conditions;
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domestic and foreign governmental regulations and taxes; and
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the overall economic environment.
Our results of operations as well as the carrying value of our oil and gas properties, are substantially dependent upon the prices of oil and natural gas, which have declined significantly since June 2014. Despite slight increases in oil and natural gas prices in 2018, prices have remained significantly lower than levels seen in recent years, which has adversely affected our revenues, operating income, cash flow, and proved reserves. Continued low prices could have a material adverse impact on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low prices of crude oil and natural gas may further adversely impact our business as follows:
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limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;
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reducing the amount of crude oil and natural gas that we can produce economically;
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causing us to delay or postpone some of our capital projects;
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reducing our revenues, operating income, and cash flows; or
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reducing the carrying and market value of our crude oil and natural gas properties.
Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
A portion of our natural gas and oil production may be interrupted, limited, 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 or for an extended period of time, it could adversely affect our cash flow.
Future economic conditions in the U.S. and certain international markets may materially adversely impact the Partnership’s operating results.
Current global market conditions and uncertainty, including the economic instability in Europe and certain emerging markets, are likely to have significant long-term effects on our operating results. 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.
Weather and climate may have a significant adverse impact on our revenues and production.
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 or freezing temperatures, 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 conditions, and not all such effects can be predicted, eliminated, or insured against.
Our 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:
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well blowouts, explosions, and cratering;
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pipeline or other facility ruptures and spills;
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fires;
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formations with abnormal pressures;
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equipment malfunctions;
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hurricanes and/or storms, which could affect our operations on and offshore the Gulf Coast, and other natural and anthropogenic disasters and weather conditions; and
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surface spillage and water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.
Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, or fire at a location where our equipment and services are used, or water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture or surface spillage and water contamination from petroleum constituents or hydraulic fracturing chemical additives could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, our cash flows and, in turn, our results of operations could be materially and adversely affected.
A decline in commodity prices may impact the Partnership’s ability to pay distributions to partners, fund capital expenditures, or both, as cash from operating activities decline.
The Partnership did not make any distributions to Investing Partners during 2018 as a result of the Partnership’s expected cash funding for asset retirement obligations (ARO). The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover its undiscounted future ARO. If oil and natural gas prices remain at or fall below levels at the end of 2018, the Partnership may not be able to make a distribution to Investing Partners during 2019. Declines in cash from operating activities may reduce funds available for capital expenditures.
The distressed financial conditions of our purchasers and operating partners could have an adverse impact on us in the event they are unable to pay us for the products we provide.
Concerns about global economic conditions and the volatility of oil and natural gas prices have had a significant adverse impact on the oil and gas industry. The Partnership is exposed to risk of financial loss from trade, joint venture, and other receivables. The Partnership currently sells its crude oil, natural gas, and natural gas liquids through the properties’ operators under the joint venture operating agreement and to a variety of purchasers. Some of the joint venture partners that act as operators or their oil and gas purchasers may experience liquidity problems and may not be able to meet their financial obligations. As a result of current economic conditions and the severe decline in oil and natural gas prices, some of our customers and operating partners may experience severe financial problems that may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers or operating partners will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our purchasers, customers, or operating partners or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or joint venture partner could result in significant financial losses.
Reserves and production will decline materially without discoveries or acquisitions of reserves.
The production rate from oil and gas properties generally declines as reserves are depleted, and production from offshore wells tends to decline at a faster rate than onshore wells, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through development or exploration drilling, identify and develop additional behind-pipe zones, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase. The Partnership has not and does not plan to engage in future acquisition or exploration activities, and, therefore, we expect declines in future oil and gas production, which are likely to adversely impact our cash flow and results from operations.
The Partnership may not realize an adequate return on its drilling activities.
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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fires, explosions, blowouts, and surface cratering;
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marine risks, such as capsizing, collisions, and hurricanes;
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other adverse weather conditions; and
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increases in the cost of or shortages or delays in the delivery of equipment.
Future drilling activities may not be successful, and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Partnership is not likely to participate in exploratory drilling at this time.
Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:
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historical production from the area compared with production from other areas;
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the effects of regulations by governmental agencies;
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future operating costs and capital expenditures; and
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workover and remediation costs.
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves, and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue, and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
The Partnership may incur significant costs related to environmental matters.
As an owner or lessee of interests in oil and gas properties, the Partnership is subject to various federal, state, and local laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. The Partnership’s efforts to limit its exposure to such liability and the operator of the properties ability to comply with applicable laws and regulations may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.
Our operations are subject to governmental risks.
Our operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations.
In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010 and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement issued guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico.
With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While requirements under the NTL have not yet been fully implemented by BOEM, the NTL will likely require the Partnership to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Partnership’s current ownership interests in various Gulf of Mexico leases. The Partnership will likely satisfy such requirements through the provision of bonds or other forms of security, if such security becomes necessary under the NTL.
New political developments, the enactment of new or stricter laws or regulations in the Gulf of Mexico or other governmental actions impacting our operations, and increased liability for companies operating in this sector may adversely impact our results of operations.
Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact our business.
There has been discussion in the United States regarding legislation or regulation of greenhouse gas (GHG). Any such legislation or regulation, if enacted, could tax or assess some form of GHG-related fees on the Partnership’s operations and could lead to increased operating expenses. Such legislation, if enacted, could also potentially cause the Partnership to make significant capital investments for infrastructure modifications.
In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact the Partnership’s assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
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 or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible links to induced seismicity. The Partnership may use fracturing techniques to expand the available space for natural gas and oil to migrate toward the wellbore. 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 governmental actions 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.
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.
A terrorist or cyberattack targeting systems and infrastructure used by the Partnership or others in the oil and gas industry may adversely impact our operations.
The Partnership’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. The Partnership, its Managing Partner, and joint venture operators depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with third party partners, and conduct many of our activities. Unauthorized access to our digital technology could lead to operational disruption, data corruption, communication interruption, loss of intellectual property, loss of confidential and fiduciary data, and loss or corruption of reserves or other proprietary information. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist attacks, environmental activist group activities, or cyberattacks than other targets in the United States. Also, external digital technologies control nearly all of the oil and gas distribution and refining systems in the United States, which are necessary to transport and market our production. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. Any such terrorist attack, environmental activist group activity, or cyberattack that affects the Partnership or others with whom we do business could have a material adverse effect on our business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage our reputation.
As cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures. The Partnership cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Insurance policies do not cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of oil and natural gas can be hazardous, involving natural disasters and other events such as blowouts, cratering, fires, explosions, 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.
If one or more of our operating partners performs poorly or declares bankruptcy, our business, financial condition and results of operations, ability to make distributions to our unitholders, and ability to comply with our asset retirement obligations could be adversely affected.
In general, we expect to rely on our operating partners for the day-to-day management and operation of our assets. In the event of a bankruptcy, we will have no control or only limited influence over the day-to-day management and operation of such assets. One or more of our operating partners may perform poorly in operating one or more of our assets for a variety of reasons. If one of our operating partners does not perform well or is forced to declare bankruptcy, we may not be able to
ameliorate the adverse effects of poor performance by terminating the operating partner and finding a replacement operating partnership to operate these assets in a timely manner. In such an instance, our business, results of operations, financial condition, ability to make distributions to our unitholders, and ability to comply with our asset retirement obligations could be materially adversely affected.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of December 31, 2018, the Partnership did not have any unresolved comments from the staff of the SEC.
ITEM 2.
ITEM 2.
PROPERTIES
Acreage
Acreage is held by the Partnership pursuant to the terms of federal lease tracts in the Gulf of Mexico, offshore Louisiana. The Partnership does not anticipate any difficulty in retaining its remaining leases. A summary of the Partnership’s gross and net acreage as of December 31, 2018, is set forth below:
At December 31, 2018, the Partnership did not have an interest in any undeveloped acreage.
The Partnership’s developed acreage on its Ship Shoal 258/259 lease block expired during the first quarter of 2018. The third-party operator determined that it was uneconomical to bring production back on-line after continued pipeline interruptions and production downtime. Upon lease expiration, approximately 10,141 gross acres and 638 net acres were relinquished and abandonment activities have commenced.
Productive Oil and Gas Wells
The number of productive oil and gas wells in which the Partnership had an interest as of December 31, 2018, 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, Pricing and Lease Operating Cost Data
The following table provides, for each of the last three fiscal years, oil, natural gas liquids, and gas production for the Partnership, average lease operating costs per Mcfe (including gathering and transportation costs) and average sales prices.
Estimated Proved Reserves and Future Net Cash Flows
Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Reserve estimates are considered proved if they are economically producible and are supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.
As of December 31, 2018, the Partnership had total estimated proved reserves of 363,233 barrels of crude oil and condensate, 29,301 barrels of NGLs and 670 MMcf of natural gas. Combined, these total estimated proved reserves are equivalent to 504,201 barrels of oil. 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, NGLs, and gas reserves as of December 31, 2018, based on commodity average prices in effect on the first day of each month in 2018, 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, 2018, 2017, and 2016, 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 Note 10-Supplemental Oil and Gas Disclosures (Unaudited) in the 2018 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows 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 of the previous 12 months, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.
The volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
The Partnership’s estimate of proved oil and gas reserves is prepared by Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) 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 owned 100 percent at December 31, 2018, is filed as an exhibit to this Form 10-K.
The primary technical person responsible for overseeing the preparation of the Partnership’s reserve estimates is Mr. Ali A. Porbandarwala, a Senior Vice President with Ryder Scott. Mr. Porbandarwala has more than ten years of experience in the estimation and evaluation of petroleum reserves and is a registered Professional Engineer in the State of Texas. He 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.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of December 31, 2018, there were 1,021.5 of the Partnership’s Units outstanding held by 919 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 2018, 2017, or 2016.
As discussed in Item 7, an amendment to the Partnership Agreement in February 1994, created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following selected financial data for the five years ended December 31, 2018, 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 development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana. 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 on 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 II, Item 8 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. Prices in recent years have remained volatile and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate widely over the years. During 2018, the Partnership’s average realized oil price increased 36 percent from 2017, while natural gas prices decreased 6 percent. Given the small number of producing wells owned by the Partnership and exposure to inclement weather and pipeline interruptions in the Gulf of Mexico, the Partnership’s production outlook for 2019 and beyond may be subject to more volatility than those companies with a larger or more diversified property portfolio. Extended downtime of the Partnership’s producing properties could materially impact any anticipated revenues, earnings and cash flow.
The Partnership participates in development drilling and recompletion activities as recommended by the operators of the properties in which the Partnership owns an interest. During 2018, the Partnership had cash outlays for oil and gas property additions of $158,444 primarily for pipeline rerouting and recompletion projects at South Timbalier 295. The Partnership did not participate in any new drilling projects during the year. Additionally, the Partnership’s development lease at Ship Shoal 258/259 expired during the first quarter of 2018. The third-party operator determined that it was uneconomical to bring production back on-line after continued pipeline interruptions and production downtime during 2017. Abandonment activities commenced on this lease during 2018.
Because of fluctuations in production levels over the past two years, the expiration of the lease at Ship Shoal 258/259, and the need to reserve cash for future asset retirement obligations, the Partnership did not make any distributions to the Investing Partners during 2018. The Partnership will continue to review available cash balances, scheduled plugging and abandonment activity, oil and gas prices realized by the Partnership for the sale of its production, and the anticipated level of recompletion and repair activity to determine whether there are sufficient funds to make a distribution to Investing Partners in 2019.
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 2018, 2017, and 2016.
Net Income and Revenue
The Partnership reported net income of $0.3 million for 2018 compared to a net loss of $0.3 million for 2017. On a per Investing Partner Unit basis, the Partnership reported income of $170 per Unit in 2018, compared to a net loss of $246 per Unit in 2017. The Partnership reported a net loss of $3.1 million in 2016. The 2016 net loss included $2.9 million of non-cash write-downs in the carrying value of the Partnership’s oil and gas properties and reduced revenues as a result of lower oil and gas prices.
Total revenues in 2018 of $1.5 million increased 49 percent from 2017 on higher oil prices and production as the result of less pipeline maintenance and downtime at South Timbalier 295. The Partnership’s total revenues in 2017 of $1.0 million decreased 24 percent from 2016 on lower oil and gas production as a result of extended downtime at both South Timbalier 295 and Ship Shoal 258/259.
Declines in oil and gas production can generally be expected in future years as a result of normal depletion. Given the small number of producing wells owned by the Partnership, and that production from offshore wells tends to decline at a faster rate than production from onshore wells, the Partnership’s future production will be subject to more volatility than those companies with greater reserves and longer-lived properties. It is not anticipated that the Partnership will acquire any additional exploratory leases or that significant drilling will take place on leases in which the Partnership currently holds interests.
The Partnership’s oil, gas and NGL production volume and price information is summarized in the following table (gas volumes are presented in thousand cubic feet (Mcf) per day):
During the second quarter of 2017, South Timbalier 295 was shut down to reroute the existing pipeline. The work was completed towards the end of the third quarter of 2017, and the pipeline was back on-line during the fourth quarter of 2017 and throughout 2018. Also during the second quarter of 2017, the third-party pipeline at Ship Shoal 258/259 was shut-down for maintenance, which extended through the end of 2017. The third-party operator determined during the first quarter of 2018 that it was uneconomical to bring production back on-line after continued pipeline interruptions and production downtime. The lease has now expired and abandonment activities commenced during 2018.
Crude Oil Sales
2018 vs. 2017 The Partnership’s crude oil sales in 2018 totaled $1,253,490, up 55 percent from 2017 on higher production, the result of the South Timbalier 295 pipeline interruption in the prior year. The Partnership’s average realized oil price in 2018 increased 36 percent from 2017, increasing to $65.36 per barrel in 2018.
2017 vs. 2016 The Partnership’s crude oil sales in 2017 totaled $806,620, down 20 percent from 2016 on lower production, the result of the South Timbalier 295 and Ship Shoal 258/259 pipeline interruptions. The Partnership’s average realized oil price in 2017 increased 19 percent from 2016, increasing to $48.00 per barrel in 2017.
Natural Gas Sales
2018 vs. 2017 Natural gas sales in 2018 decreased 17 percent from a year ago, totaling $120,763 on lower production as the result of the cessation of production at Ship Shoal 258/259. In addition, average realized gas prices decreased from $3.49 per Mcf in 2017 to $3.27 per Mcf in 2018.
2017 vs. 2016 Natural gas sales in 2017 decreased 45 percent from prior year, totaling $145,562 on lower production as a result of prolonged repairs on the Ship Shoal 258/259 third-party pipeline. The decrease in production was partially offset by average realized gas prices increasing from $2.50 per Mcf in 2016 to $3.49 per Mcf in 2017.
NGL Sales
The Partnership sold 4 barrels per day of natural gas liquids in 2018, up from 3 barrels per day in 2017. The increase was the result of the South Timbalier 295 pipeline interruptions in the prior year, partially offset by natural depletion. Additionally, NGL prices increased 21 percent from 2017, to $28.63 per barrel. The Partnership sold 7 barrels per day of natural gas liquids in 2016 which was significantly curtailed in the following year by pipeline interruptions throughout 2017.
Operating Expenses`
2018 vs. 2017 The Partnership’s depreciation, depletion and amortization (DD&A), expressed as a percentage of oil and gas sales, decreased to approximately 21 percent in 2018 from approximately 27 percent in 2017. The dollar amount of recurring DD&A expense for 2018 increased 14 percent from the comparable period a year ago as a result of a higher DD&A rate from increased oil production and lower reserves. For 2018 and 2017, the Partnership recognized asset retirement obligation (ARO) accretion expense of $96,832 and $105,135, respectively, as abandonment activities commenced at Ship Shoal 258/259.
Lease operating expenses (LOE) for 2018 decreased 15 percent from the same period a year ago to $492,713 in 2018. The decrease reflects the impact of repair and maintenance work for unexpected shut-ins at South Timbalier 295 and Ship Shoal 258/259 during 2017 and the subsequent expiration of the Ship Shoal 258/259 lease in early 2018. Gathering and transportation costs for the delivery of oil and gas have normalized following the prior year pipeline interruptions at South Timbalier 295, totaling $17,493 in 2018. Administrative expenses for 2018 increased 2 percent compared to 2017.
2017 vs. 2016 The Partnership’s DD&A, expressed as a percentage of oil and gas sales, decreased to approximately 27 percent in 2017 from approximately 38 percent in 2016. The dollar amount of recurring DD&A expense for 2017 decreased from the comparable period a year ago as a result of the lower DD&A rate and lower sales volumes from the pipeline interruptions. For 2017 and 2016, the Partnership recognized asset retirement obligation accretion of $105,135 and $79,661, respectively. The deferral of platform decommissioning activity at North Padre Island 969/976 and revisions in ARO liability shifted the timing of the Partnership’s abandonment obligations and increased accretion expense during 2017.
Under the full cost method of accounting, the Partnership is required to review the carrying value of its proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves discounted at 10 percent per annum. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. The Partnership did not recognize a write-down for the carrying value of its oil and gas properties during 2018 or 2017. The Partnership wrote-down the carrying value of its oil and gas properties by approximately $2.9 million during 2016. The write-downs are reflected as additional DD&A expense. If commodity prices experience sustained declines over a 12 month period, the Partnership may be required to recognize non-cash write-downs of the carrying value of its oil and gas properties in future periods.
LOE for 2017 increased 3 percent from the same period in 2016, increasing to $581,718 in 2017. The slight increase reflects the impact of repair and maintenance work for unexpected shut-ins at South Timbalier 295 and Ship Shoal 258/259 and operating costs that correspond to increases in commodity prices. Gathering and transportation costs for the delivery of oil and gas totaled $2,495, the result of lower production from pipeline downtime at Ship Shoal 258/259 and a change in oil marketing arrangements for South Timbalier 295. Administrative expenses for 2017 decreased 9 percent compared to the same period in 2016.
Capital Resources and Liquidity
The Partnership’s primary capital resource is net cash provided by operating activities, which totaled a cash inflow of $196,389 and $138,687 for 2018 and 2017, respectively. The increase reflected the impact of higher oil production and prices in 2018 which was partially offset by increased abandonment spending during the year. Net cash provided by operating activities totaled a cash outflow of $177,543 for 2016 driven by abandonment activities.
At December 31, 2018, the Partnership had approximately $5.1 million in cash and cash equivalents, down slightly from the end of 2017. The Partnership’s goal is to maintain cash and cash equivalents at least sufficient to cover the undiscounted value of its future asset retirement obligation liability. The Partnership also plans to reserve funds for repairs, which may disrupt the Partnership’s production and for future recompletion operations.
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 and economic conditions, the foreign and domestic supply of oil and natural gas, the price of foreign imports, the level of consumer demand, weather 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 generally be expected in future years as a result of normal depletion and the Partnership’s non-participation in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership forecasts it will be able to meet its liquidity needs for routine operations in 2018 and 2019.
Approximately 90 percent of the Partnership’s total proved reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves. The Partnership’s liquidity may be negatively impacted if the actual quantities of reserves that are ultimately produced are materially different from current estimates. Also, if prices decline significantly from current levels, the Partnership may not be able to fund the necessary capital investment, or development of the remaining reserves may not be economical for the Partnership.
The Partnership may reduce capital expenditures or distributions to partners, or both, to be in-line with cash from operating activities. 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 existing 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 costs. The Partnership did not sell any properties in 2018, 2017, or 2016.
Capital Commitments
The Partnership’s primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. To the extent it has discretion, the Partnership allocates available capital to investment in the Partnership’s properties so as to maximize production and resultant cash flow. The Partnership had no outstanding debt or lease commitments at December 31, 2018. The Partnership did not have any contractual obligations as of December 31, 2018, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for this asset retirement obligation as discussed in the notes to the financial statements included in this annual report on Form 10-K.
During each of the last three years, the Partnership had modest cash outlays for oil and gas property additions as it did not participate in any new drilling projects. The Partnership paid cash settlements for ARO liabilities totaling $0.4 million in 2018, $12,259 in 2017 and $0.3 million in 2016.
Based on preliminary information available to the Partnership, it anticipates that 2019 capital expenditures will be similar to 2018 levels for recompletion projects at South Timbalier 295. Additionally, $0.4 million is estimated to be spent in 2019 to abandon wells at Ship Shoal 258/259 and to remove the idle platforms at North Padre Island 969/976. The abandonment activity at North Padre Island 969/976 was originally scheduled to commence prior to 2018, but has been deferred to 2019 pending approval from regulators. Such estimates may change based on realized oil and gas prices, drilling and recompletion results, rates charged by contractors or changes by the operator to their development or abandonment plans.
Because of low oil and gas prices, pipeline interruptions to production, and the need to reserve cash for future asset retirement obligations, no distributions were made to Investing Partners during 2018, 2017 or 2016.
The amount of future distributions will be dependent on actual and expected production levels, realized and anticipated oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations. The Partnership will continue to review available cash balances, cash requirements for plugging and abandonment activity, oil and gas prices realized by the Partnership for the sale of its production, especially in light of lower commodity prices in recent years, and the level of drilling and recompletion activity to determine whether there are sufficient funds to make a distribution to Investing Partners in 2019.
With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued Notice to Lessees (NTL) No. 2016-N01 pertaining to the obligations of companies to provide supplemental assurances for performance with respect to plugging, abandonment, decommissioning, and site clearance obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. Under this NTL, implementation of which is currently suspended and which may be revised by the BOEM, the Partnership may be required to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Partnership’s current ownership interests in various Gulf of Mexico leases. The Partnership will likely satisfy such requirements through the provision of bonds or other forms of security. Management does not believe the ultimate satisfaction of the NTL requirements will adversely affect the Partnership’s overall liquidity.
As provided in the Amended Partnership Agreement, a first right of presentment valuation was computed during the first quarter of 2018. The per-unit value was determined to be $10,342 based on the valuation date of December 31, 2017. A second right of presentment valuation was computed during October 2018 and the per-unit value was determined to be $9,752 based on a valuation date of June 30, 2018. The Partnership did not repurchase any Investing Partner Units (Units) during 2018 as a result of the Partnership’s limited amount of cash available for discretionary purposes. The per-unit right of presentment value computed during the first quarter of 2017 based on the valuation date of December 31, 2016, was $9,242 and the second per-unit right of presentment in 2017 was $8,794 based on a valuation date of June 30, 2017. The Partnership did not repurchase any Units during 2017. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to repurchase any Units presented to the extent it determines that it has insufficient funds for such purchases.
There will be two rights of presentment in 2019, but the Partnership is not in a position to predict how many Units will be presented for repurchase and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase Units. The Amended Partnership Agreement contains limitations on the number of Units that the Partnership can repurchase, including an annual limit on repurchases of 10 percent of outstanding Units.
Off-Balance Sheet Arrangements
The Partnership does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership.
Insurance
The Managing Partner maintains insurance coverage that includes coverage for physical damage to the Partnership’s oil and gas properties, third-party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. The insurance coverage includes deductibles, which must be met prior to recovery. Additionally, the Managing Partner’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
The Managing Partner’s various insurance policies also provide coverage for, among other things, liability related to negative environmental impacts of a sudden pollution, charterer’s legal liability and general liability, employer’s liability and auto liability. The Managing Partner’s service agreements, including drilling contracts, generally indemnify Apache and the Partnership for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.
Critical Accounting Policies and Estimates
The Partnership prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and accompanying notes. Management identifies certain accounting policies as critical based on, among other things, their impact on the Partnership’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity, and complexity in their development. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The following is a discussion of Partnership’s most critical accounting policies:
Reserve Estimates
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
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 also the basis for our supplemental oil and gas disclosures.
Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of production, except where prices are defined by contractual arrangements.
The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.
The Partnership’s estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner.
Asset Retirement Obligation (ARO)
The Partnership has obligations to remove tangible equipment and restore the land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership’s limited operations and estimate of remaining reserves. The Partnership’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and 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
The Partnership’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for oil and gas production continue to be volatile and unpredictable. The Partnership has not used derivative financial instruments or otherwise engaged in hedging activities during 2018 or 2017.
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 production 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. For example, the NYMEX daily settlement price for the prompt month oil contract in 2018 ranged from a high of $76.41 per barrel to a low of $42.53 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2018 ranged from a high of $4.84 per MMBtu to a low of $2.55 per MMBtu. Based on the Partnership’s average daily production for 2018, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $19,000 and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $3,700. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2018. 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 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.
ADDITIONAL INFORMATION ABOUT THE PARTNERSHIP
Environmental Compliance
As an owner or lessee and operator of oil and gas properties and facilities, the Partnership is subject to numerous federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.
The Partnership has made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. The Managing Partner has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to the Partnership’s operations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, the Partnership does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures or earnings.
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, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on our assessment, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2018.
/s/ John J. Christmann IV
Chief Executive Officer and President
(principal executive officer)
of Apache Corporation, Managing Partner
/s/ Stephen J. Riney
Executive Vice President and Chief Financial Officer (principal financial officer)
of Apache Corporation, Managing Partner
/s/ Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer,
and Controller (principal accounting officer)
of Apache Corporation, Managing Partner
Houston, Texas
February 28, 2019
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Apache Offshore Investment Partnership:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Apache Offshore Investment Partnership (the Partnership) as of December 31, 2018 and 2017, the related statements of consolidated operations, cash flows and changes in partners’ capital for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ ERNST & YOUNG LLP
We have served as the Partnership’s auditor since 2002.
Houston, Texas
February 28, 2019
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED OPERATIONS
The accompanying notes to consolidated financial statements
are an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying notes to consolidated financial statements
are an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
The accompanying notes to consolidated financial statements
are an integral part of this statement.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL
The accompanying notes to consolidated 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 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, 2018. 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 also 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. As of December 31, 2018, the Partnership has only one active venture prospect at South Timbalier 295, located offshore Louisiana, with a 7.08 percent working interest.
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 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.
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 2018, 2017, or 2016 as a result of the limited amount of cash available for discretionary purposes.
The Partnership is not in a position to predict how many Units will be presented for repurchase during 2019; 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.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2018. 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, 2018.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by the Partnership reflect industry practices and conform to accounting principles generally accepted in the United States (GAAP). Significant policies are discussed below.
Statement Presentation
The accompanying consolidated financial statements include the accounts of Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions.
Use of Estimates
The preparation of financial statements in conformity with GAAP and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom (see Note 10 - Supplemental Oil and Gas Disclosures) and the assessment of asset retirement obligations (see Note 8 - Asset Retirement Obligation).
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2018 and 2017, the Partnership had $5.1 million and $5.1 million, respectively, of cash and cash equivalents.
Oil and Gas Properties
The Partnership follows the full-cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method of accounting, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. All costs related to production and administrative functions are expensed in the period incurred. The Partnership includes the present value of its dismantlement, restoration, and abandonment costs within the capitalized oil and gas property balance as described in Note 8. Unless greater than 25 percent of the Partnership’s reserve volumes are sold, proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains or losses are not recognized.
Capitalized costs of oil and gas properties are amortized on the future gross revenue method whereby depreciation, depletion and amortization (DD&A) expense is computed quarterly by dividing current period oil and gas sales by estimated future gross revenue from proved oil and gas reserves (including current period oil and gas sales) and applying the resulting rate to the net cost of evaluated oil and gas properties, including estimated future development costs.
Under the full-cost method of accounting, the Partnership limits the capitalized costs of proved oil and gas properties, net of accumulated DD&A, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, if any. This ceiling test is performed each quarter. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional DD&A in the accompanying statement of consolidated operations. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. As a result of the ceiling limitation, the Partnership recorded non-cash write-downs of the carrying value of its proved oil and gas properties totaling $2,873,180 during 2016. The Partnership did not record any write-downs of capitalized costs during 2018 or 2017. See Note 10 - Supplemental Oil and Gas Disclosures for a discussion on the calculation of estimated future net cash flows.
Asset Retirement Costs and Obligation
The initial estimated asset retirement obligation related to property and equipment is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. If the fair value of the recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. Accretion expense on the liability is recognized over the estimated productive life of the related assets.
Revenue Recognition
On January 1, 2018, the Partnership adopted Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Partnership elected to evaluate all contracts at the date of initial application. There was no impact to the opening balance of retained earnings as a result of the adoption, and the new standard is not anticipated to impact the Partnership’s net earnings on an ongoing basis.
The Partnership applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and natural gas liquids (NGLs) are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Partnership considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Partnership’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Apache, as Managing Partner of the Partnership, markets the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of production. Apache primarily markets to major oil companies, marketing and transportation companies, and refiners at current index prices, adjusted for quality, transportation, and market reflective differentials. The Partnership markets all other production under the joint operating agreements with the operator of its properties. The operator seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. These contracts provide for sales that are priced at prevailing market prices.
The Partnership records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Partnership routinely assesses the collectability of all material trade and other receivables. The Partnership accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Receivables from contracts with customers, net of allowance for doubtful accounts, totaled $120,116 and $92,881 as of December 31, 2018 and 2017, respectively.
The Partnership has concluded that disaggregating revenue by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The table below presents the total oil, gas, and NGLs revenues of the Partnership for the years ended December 31, 2018, 2017 and 2016:
Practical Expedients and Exemptions
The Partnership does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
The Partnership will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340. Currently, the Partnership does not have contract assets related to incremental costs to obtain a contract.
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 (Loss) Per Investing Unit
The net income (loss) per Investing Partner Unit is calculated by dividing the aggregate Investing Partners’ net income for the period by the number of weighted average Investing Partner Units outstanding for that period.
Income Taxes
The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Receivable from/Payable to Apache Corporation
The receivable from/payable to Apache Corporation, the Partnership’s Managing Partner, represents the net result of the Investing Partners’ revenue and expenditure transactions in the current month. Generally, cash in this amount will be paid by Apache to the Partnership or transferred to Apache in the month after the Partnership’s transactions are processed and the net results of operations are determined.
Maintenance and Repairs
Maintenance and repairs are charged to expense as incurred.
New Pronouncements Issued But Not Yet Adopted
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Partnership does not intend to early adopt. In January 2018, the FASB issued ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Partnership intends to elect both transitional practical expedients. The adoption of ASU 2016-02 will not have a material impact on the Partnership’s consolidated financial statements.
3. COMPENSATION TO AFFILIATES
Apache is entitled to the following types of compensation and reimbursement for costs and expenses.
Apache operated certain Partnership properties through September 30, 2013, at which time Fieldwood Energy LLC purchased Apache’s interest in South Timbalier 295 and Ship Shoal 258/259 and became operator of these properties. Billings to the Partnership were made on the same basis as to unaffiliated third parties or at prevailing industry rates.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 referenced. All costs of oil and gas properties are currently being amortized.
Development costs for 2018 include upward revisions of $305 thousand for estimated abandonment costs primarily related to revised cost estimates on its Ship Shoal 258/259 properties. Development costs for 2017 and 2016 include negative revisions of $66 thousand and $179 thousand, respectively, for estimated abandonment costs and the deferral of final platform decommissioning at North Padre Island 969/976. Removal of the platforms and final abandonment activity was previously expected to occur during 2016. Approximately $17 thousand and $178 thousand of capital costs were incurred in 2018 and 2017, respectively, for participation in pipeline and recompletion projects at South Timbalier 295, and approximately $35 thousand of capital costs were incurred in 2016 for participation in a recompletion project at Ship Shoal 258/259.
The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2018, 2017, and 2016 was 21 percent, 27 percent and 38 percent, respectively. As more fully described in Footnote 2 above, as a result of the full-cost method of accounting ceiling limitation, the Partnership recorded non-cash write-downs of the carrying value of its proved oil and gas properties totaling $2,873,180 during 2016.
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.
Remittances from Fieldwood Energy LLC accounted for 12 percent, 18 percent and 43 percent of the Partnership’s oil and gas sales for the years 2018, 2017 and 2016, respectively. Approximately 88 percent, 82 percent and 57 percent of the Partnership’s oil and gas sales in 2018, 2017 and 2016, respectively, were to Chevron Products Company.
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.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. FAIR VALUE MEASUREMENTS
Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable -
As of December 31, 2018 and December 31, 2017, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.
7. COMMITMENTS AND CONTINGENCIES
Litigation - The Partnership is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache’s management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations.
Environmental - The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. Apache maintains insurance coverage on the Partnership’s properties, which it believes is customary in the industry, although the Partnership is not fully insured against all environmental risks.
With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued Notice to Lessees (NTL) No. 2016-N01 pertaining to the obligations of companies to provide supplemental assurances for performance with respect to plugging, abandonment, decommissioning, and site clearance obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. Under this NTL, implementation of which is currently suspended and which may be revised by the BOEM, the Partnership may be required to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Partnership’s current ownership interests in various Gulf of Mexico leases. The Partnership will likely satisfy such requirements through the provision of bonds or other forms of security.
8. ASSET RETIREMENT OBLIGATION
The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2018 and 2017:
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 estimates from property operators and current market 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. The current portion of the ARO liability represents the retirement obligation expected to be incurred in the next twelve months.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 2018, decommissioning and abandonment activities began as a result of the lease expiration at Ship Shoal 258/259 which are expected to be completed within the next two years. The lease was relinquished earlier than previously estimated given unplanned third-party pipeline issues and the decision that returning the lease to production was uneconomic. The operator has also experienced challenges related to the plugging of wells which resulted in revising the field’s estimated abandonment obligation based on projected costs.
For 2017, a negative revision to ARO liability was recorded to reflect a reduction in estimated cost and the deferral of final platform abandonment at North Padre Island 969/976 to 2019 pending approval from regulators.
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, 2018, and 2017 was $2,649,454 and $2,335,252, respectively, lower than the carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2018, and 2017.
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Oil and Gas Reserve Information
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (NGLs) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact.
(Oil and NGL in Mbbls and gas in MMcf)
Oil includes crude oil and condensate.
All the Partnership’s reserves as of December 31, 2018 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 90 percent of the Partnership’s current 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 now not 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 is reflected in the Partnership’s standardized measure under Future Net Cash Flows.
Future Net Cash Flows
Future cash inflows as of December 31, 2018, 2017, and 2016 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. 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
The financial statements for the fiscal years ended December 31, 2018, 2017 and 2016, included in this report, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Managing Partner’s Chief Executive Officer and President (in his capacity as principal executive officer), and Stephen J. Riney, the Managing Partner’s Executive Vice President and Chief Financial Officer (in his capacity as principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2018, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified under the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2018, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
Management’s Annual 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 21 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, 2018, 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, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
All management functions are performed by Apache, the Managing Partner of the Partnership. The Partnership itself has no officers or directors. Information concerning the officers and directors of Apache set forth under the captions “Nominees for Election as Directors”, “Continuing Directors”, “Executive Officers of the Company”, and “Securities Ownership and Principal Holders” in the proxy statement relating to the 2019 annual meeting of stockholders of Apache (the Apache Proxy Statement) 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 and Ethics (Code of Conduct), and revised it in September 2017. 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 Affiliates of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. The information concerning the compensation paid by Apache to its officers and directors set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Potential Payments Upon Termination or Change-in-Control,” and “Director Compensation Table” in the Apache Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS
Apache, as an Investing Partner and the General Partner, owns 53 Units, or 5.2 percent of the outstanding Units of the Partnership, as of December 31, 2018. 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, as stated above. 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, AND DIRECTOR INDEPENDENCE
See Note 3-Compensation to Apache of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. See Note 5-Major Customers and Related Parties Information of the Partnership’s financial statements for amounts paid to subsidiaries of Apache, and for other related party information. The Partnership itself has no directors. Information concerning the directors of Apache set forth under the caption “Director Independence” in the Apache Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Accountant fees and services paid to Ernst & Young LLP, the Partnership’s independent auditors, are included in amounts paid by the Partnership’s Managing Partner. Information on the Managing Partner’s principal accountant fees and services is set forth under the caption “Ratification of Appointment of Independent Auditors” in the Apache Proxy Statement incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 16.
FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
APACHE OFFSHORE INVESTMENT PARTNERSHIP
By: Apache Corporation, Managing Partner
Dated: February 28, 2019
/s/ John J. Christmann IV
John J. Christmann IV
Chief Executive Officer and President
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 John J. Christmann IV, Stephen J. Riney 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.