10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________________

FORM 10-K

________________________________________________________________

(Mark One)

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

For the fiscal year ended December 31, 2021

OR

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

For the transition period from              to             

Commission File Number: 0-13546

________________________________________________________________

APACHE OFFSHORE INVESTMENT PARTNERSHIP

(Exact name of registrant as specified in its charter)

________________________________________________________________

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

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

(Address of principal executive offices) (Zip Code)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

No market value for common equity held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter has been computed due to the fact there is no public market for the registrant’s common equity.

On December 31, 2021, there were 1,018.5 partnership units of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of APA Corporation’s proxy statement relating to its 2022 annual meeting of stockholders (the APA Proxy Statement) have been incorporated by reference into Part III hereof. On March 1, 2021, Apache Corporation (Apache) consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which, Apache became a wholly-owned subsidiary of APA Corporation (APA), APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Securities Exchange Act of 1934, as amended, and APA replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.”

TABLE OF CONTENTS

DESCRIPTION

Item		Page
	PART I
1.	BUSINESS	1
1A.	RISK FACTORS	3
1B.	UNRESOLVED STAFF COMMENTS	3
2.	PROPERTIES	3
3.	LEGAL PROCEEDINGS	5
4.	MINE SAFETY DISCLOSURES	5
	PART II
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	6
6.	SELECTED FINANCIAL DATA	6
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	6
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	11
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	12
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	29
9A.	CONTROLS AND PROCEDURES	29
9B.	OTHER INFORMATION	29
9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	29
	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	30
11.	EXECUTIVE COMPENSATION	31
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	31
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	31
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	32
	PART IV
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	33
16.	FORM 10-K SUMMARY	33

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily-prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf) or million cubic feet (MMcf). Oil is quantified in terms of barrels (bbls) and thousands of barrels (Mbbls). Oil and natural gas liquids (NGLs) are compared with natural gas in terms of thousand cubic feet equivalent (Mcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. With respect to information relating to the Partnership’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Apache Offshore Investment Partnership’s (as defined herein) working interest therein. Unless otherwise specified, all references to wells and acres are gross.

i

FORWARD-LOOKING STATEMENTS AND RISK

This Annual Report on Form 10-K (this Form 10-K) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Partnership’s (as defined below in the Notes to Consolidated Financial Statements) future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the Partnership’s examination of historical operating trends, the information that was used to prepare the Partnership’s estimate of proved reserves as of December 31, 2021, and other data in its possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “prospect,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “might,” “outlook,” “possibly,” “potential,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Partnership believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Partnership’s expectations include, but are not limited to, the Partnership’ assumptions about:

•the scope, duration, and reoccurrence of any epidemics or pandemics (including specifically the coronavirus disease 2019 (COVID-19) pandemic and any related variants) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;

•the mandate, availability, and effectiveness of vaccine programs and therapeutics related to the treatment of COVID-19;

•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

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

•pipeline and gathering system capacity and availability;

•production and reserve levels;

•drilling risks;

•economic and competitive conditions;

•the availability of capital resources;

•capital expenditure and other contractual obligations;

•weather conditions;

•inflation rates;

•the availability of goods and services;

•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Partnership operates;

•legislative, regulatory, or policy changes, including environmental regulations and initiatives addressing the impact of global climate change;

•terrorism or cyberattacks;

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

•other factors disclosed under Item 2—“Properties—Estimated Proved Reserves and Future Net Cash Flows,” Item 7 —“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this Form 10-K and other filings that the Partnership makes with the Securities and Exchange Commission.

Other factors or events that could cause the Partnership’s actual results to differ materially from the Partnership’s expectations may emerge from time to time, and it is not possible for the Partnership to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Partnership, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Form 10-K. Except as required by law, the Partnership disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.

ii

PART I

ITEM 1.    BUSINESS

General

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

On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which, Apache became a wholly-owned subsidiary of APA Corporation (APA), APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Securities Exchange Act of 1934, as amended (the Exchange Act), and APA replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” Following consummation of the Holding Company Reorganization, the Partnership’s executive management and governance functions are performed by the executive officers and directors of APA, respectively.

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 APA’s website at investor.apacorp.com/apache-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. Information on APA’s website or any other website is not incorporated by reference into, and does not constitute a part of this Form 10-K.

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, 2021, 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 remaining 15 percent interest was purchased by an affiliated partnership or retained by Apache.

Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2021, 48 of those prospects have been surrendered or sold. As of December 31, 2021, the Partnership had 14 productive wells on its remaining developed field, South Timbalier 295, offshore Louisiana, with a 7.08 percent working interest.

Notice of Withdrawal

Apache, as the Managing Partner of the Investment Partnership, gave notice on March 22, 2019 of its intention to withdraw as Managing Partner of the Investment Partnership. The notice described the withdrawal process and certain notice periods required by that process. No party assumed the role of Managing Partner within the 120-day notice period specified by the notice of intention to withdraw. Consequently, Apache will oversee the process of winding up and liquidating the business and affairs of the Investment Partnership. Apache has not made a decision as to when it will complete the process to withdraw as Managing Partner.

1

Apache will continue to manage the Partnership’s business activities during the winding up process. 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 allocated to the Partnership.

2021 Results

The Partnership reported a net loss for 2021 of approximately $657 thousand, or approximately $543 per Investing Partner Unit. This represents approximately $324 thousand of additional net loss compared to the $333 thousand net loss reported in 2020.

In late June 2021, the operator shut in wells at South Timbalier 295 in order to perform certain repairs to various piping and related equipment. The construction crew surveyed the facilities and identified additional deficiencies and necessary repairs, including platform and grating repairs required to be performed prior to returning the wells to production. The repair work commenced during the third quarter of 2021, but Hurricane Ida and global supply chain issues caused additional delays. Production returned at the end of December 2021, after a majority of the repairs were completed. As a result of the wells being shut-in at South Timbalier 295, the Partnership had de minimis production and associated revenues during the second half of 2021, as South Timbalier 295 is the only remaining operating field of the Partnership.

The increase in net loss compared to the prior year was primarily the result of lower production caused by the shut-in at South Timbalier 295 and natural decline, slightly offset by higher crude oil and natural gas realized prices. Oil production averaged 20 barrels of oil per day in 2021, down 49 percent from 2020. Natural gas production averaged 47 Mcf per day in 2021, down 40 percent from 2020. The Partnership’s average realized crude oil prices increased 49 percent from a year ago to $55.57 per barrel, while average gas prices increased 22 percent from the prior year to $3.05 per Mcf. The increase in realized prices was driven by increased economic activity during 2021 compared to 2020 when commodity prices collapsed as a result of economic uncertainty stemming from the COVID-19 pandemic.

During 2021, the Partnership did not have any cash outlay for capital expenditures. The Partnership did not participate in any new drilling projects during the year. The Partnership anticipates that 2022 capital expenditures will remain at minimal levels for recompletions at South Timbalier 295.

Approximately $232 thousand of cash outlays were spent during 2021 on abandonment and decommissioning activities, primarily at Ship Shoal 258/259. The spending incurred during 2021 was higher than previously estimated by the operator because of weather delays and unplanned infrastructure requirements for abandonment activity. The Partnership anticipates an additional $451 thousand of short-term abandonment and decommissioning activity, primarily at North Padre Island 258/259, in 2022. Such estimates may change based on realized oil and gas prices, rates charged by contractors, or changes by the operator to its development or abandonment plans.

The Partnership had estimated proved oil and gas reserves of 486,476 barrels of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas, at December 31, 2021.

For a more in-depth discussion of the Partnership’s 2021 results and its capital resources and liquidity, please see Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K.

Marketing

Apache, as Managing Partner of the Partnership, markets the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of revenue. 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 third-party operator of South Timbalier 295 markets all other production of the Partnership. 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 in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” 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.

2

Environmental Compliance

As an owner or lessee and prior 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, the Partnership does not believe that these requirements affect it differently, to any material degree, than other companies in its industry.

The Partnership has made and will continue to make expenditures in its efforts to comply with these requirements, which it believes 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 the Partnership is 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 1A.    RISK FACTORS

As a “smaller reporting company,” the Partnership is not required to provide the information required by this Item.

The above statement notwithstanding, unitholders and prospective investors should be aware that certain risks exist with respect to the Partnership and its business, including those risk factors contained in its previously filed Annual Report on Form 10-K for the year ended December 31, 2018. These risks include, among others: limited assets, lack of significant revenues, industry risks, dependence on third-party operators, and the need for additional capital. The Partnership’s management is aware of these risks and has established controls and procedures necessary to ensure adequate risk assessment and execution to reduce loss exposure.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

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, 2021, is set forth below:

		Developed Acreage
Lease Block	State	Gross Acres	Net Acres
South Timbalier 276, 295, 296	LA	15,000	1,063

At December 31, 2021, the Partnership did not have an interest in any undeveloped acreage.

Productive Oil and Gas Wells

The number of productive oil and gas wells in which the Partnership had an interest as of December 31, 2021, is set forth below:

		Gas		Oil
Lease Block	State	Gross	Net	Gross	Net
South Timbalier 276, 295, 296	LA	1	0.07	13	0.92

Net Wells Drilled

The Partnership did not drill any new oil and gas wells during each of the last three fiscal years.

3

Production, Pricing and Lease Operating Cost Data

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

	Production			Average Lease Operating Cost per Mcfe		Average Sales Price
Year Ended December 31,	Oil (Mbbls)	NGLs (Mbbls)	Gas (MMcf)			Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)
2021
South Timbalier 295	7	1	17	$	8.84	$	55.57	$	20.84	$	3.05
Other fields	—	—	—	NM		—		—		—
Total	7	1	17	$	9.55	$	55.57	$	20.84	$	3.05
2020
South Timbalier 295	14	1	28	$	3.03	$	37.26	$	12.59	$	2.50
Other fields	—	—	—	NM		—		—		—
Total	14	1	28	$	3.31	$	37.26	$	12.59	$	2.50
2019
South Timbalier 295	17	1	34	$	2.82	$	57.10	$	15.48	$	2.73
Other fields	—	—	—	NM		—		—		—
Total	17	1	34	$	3.78	$	57.10	$	15.48	$	2.73

NM — Not Meaningful

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs that 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.

As of December 31, 2021, the Partnership had total estimated proved reserves of 354,114 barrels of crude oil and condensate, 23,362 barrels of NGLs and 654 MMcf of natural gas. Combined, these total estimated proved reserves are equivalent to 486,476 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.

4

The following table shows proved developed and undeveloped oil, NGLs, and gas reserves as of December 31, 2021, based on commodity average prices in effect on the first day of each month in 2021, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

	Oil (Mbbls)	NGLs (Mbbls)	Gas (MMcf)
Proved developed	354	23	654
Proved undeveloped	—	—	—
Total proved	354	23	654

The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2021, 2020, and 2019, 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 Notes to the Consolidated Financial Statements set forth in Part II, Item 8— “Financial Statements and Supplementary Data” 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, which presents the Partnership’s ownership interest at December 31, 2021, 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 over reservoir engineering.

ITEM 3.    LEGAL PROCEEDINGS

The information set forth in Note 7—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8— “Financial Statements and Supplementary Data” of this Form 10-K is incorporated herein by reference.

ITEM 4.    MINE SAFETY DISCLOSURES

None.

5

PART II

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

As of December 31, 2021, there were 1,018.5 Units outstanding held by 927 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 2021, 2020, or 2019.

As further discussed in Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Apache, as the Managing Partner of the Investment Partnership, gave notice on March 22, 2019, of its intention to withdraw as Managing Partner of the Investment Partnership. The notice described the withdrawal process and certain notice periods required by that process. No party assumed the role of Managing Partner within the 120-day notice period specified by the notice of intention to withdraw. Consequently, Apache will oversee the process of winding up and liquidating the business and affairs of the Investment Partnership. Apache has not made a decision as to when it will complete the process to withdraw as Managing Partner.

ITEM 6.    SELECTED FINANCIAL DATA

Omitted.

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 focusing primarily on production activities on remaining leases and dismantlement and abandonment activities on surrendered 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—“Financial Statements and Supplementary Data” of this Form 10-K. This section of this Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Form 10-K are incorporated by reference to Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 26, 2021.

The Partnership derives its revenue from the production and sale of crude oil, natural gas and 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. 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 is subject to higher 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 workover and recompletion activities as recommended by the operator of the properties in which the Partnership owns an interest. During 2021, the Partnership had no cash outlay for oil and gas property additions and did not participate in any new drilling projects or completions. The Partnership’s primary cash outlay for 2021 was related to completion of decommissioning and abandonment activities at Ship Shoal 258/259. Platform removal and decommissioning activity at North Padre Island 969/976 was deferred to 2022.

Because of continued declines in production levels, volatility in commodity prices in recent years, and the need to reserve cash for future asset retirement obligations, the Partnership did not make any distributions to the Investing Partners during 2021. 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 2022.

6

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 2021 and 2020.

Net Income and Revenue

The Partnership reported a net loss of approximately $657 thousand for 2021. This represents an increased loss of approximately $324 thousand from the $333 thousand of net loss reported for 2020. On a per Investing Partner Unit basis, the Partnership reported a net loss of $543 per Unit in 2021 compared to a net loss of $291 per Unit in 2020. Total revenues in 2021 of approximately $469 thousand decreased approximately $174 thousand, or 27 percent, from 2020.

In late June 2021, the operator shut-in wells at South Timbalier 295 in order to perform certain repairs to various piping and related equipment. The construction crew surveyed the facilities and identified additional deficiencies and necessary repairs, including platform and grating repairs required to be performed prior to returning the wells to production. The repair work commenced during the third quarter of 2021, but Hurricane Ida and global supply chain issues delayed the timing of repairs. Production returned at the end of December, after a majority of the repairs were completed. As a result of the wells being shut in at South Timbalier 295, the Partnership had de minimis production and associated revenues during the second half of 2021, as South Timbalier 295 is the only remaining operating field of the Partnership. The Partnership operated at a loss during 2021 as a result of the reduced production levels and the increased repair and maintenance costs incurred over the second half of 2021.

Oil and gas prices in recent years have been volatile, and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate significantly. During 2021, commodity prices rebounded as a result of increased economic activity compared to 2020, when commodity prices collapsed as a result of economic uncertainty stemming from the COVID-19 pandemic. The Partnership’s average realized oil prices increased 49 percent from 2020, while natural gas prices increased 22 percent from the prior year. Comparative changes in net loss and revenues were driven by the shut-in of production during the second half of the year, offset by higher realized commodity prices.

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):

	For the Year Ended December 31,
	2021		Increase (Decrease)		2020		Increase (Decrease)		2019
Gas volume – Mcf per day	47		(40)	%	78		(17)	%	94
Average gas price – per Mcf	$	3.05	22	%	$	2.50	(8)	%	$	2.73
Oil volume – barrels per day	20		(49)	%	39		(19)	%	48
Average oil price – per barrel	$	55.57	49	%	$	37.26	(35)	%	$	57.10
NGL volume – barrels per day	2		(33)	%	3		—	%	3
Average NGL price – per barrel	$	20.83	65	%	$	12.59	(19)	%	$	15.48

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 the faster decline in production from offshore wells compared to 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.

Oil and Gas Sales

The Partnership’s crude oil sales in 2021 totaled approximately $400 thousand, down 25 percent from 2020 as a result of lower production partially offset by higher realized prices. Oil production was down approximately 49 percent from the prior year, primarily the result of repair-related shut-ins at South Timbalier 295 during the second half of 2021. The Partnership’s average realized oil price in 2021 was 49 percent higher than in 2020, increasing to $55.57 per barrel in 2021.

Natural gas sales in 2021 decreased 26 percent from a year ago, totaling approximately $52 thousand with shut-in production, offset by higher realized natural gas prices.

The Partnership sold an average of 2 barrels per day of NGLs in 2021, down slightly from 3 barrels per day in 2020. Total NGL sales of approximately $16 thousand remained flat from the prior year as lower production was offset by higher realized NGL prices.

7

Operating Expenses

The Partnership’s depreciation, depletion and amortization (DD&A), expressed as a percentage of oil and gas sales, increased to approximately 35 percent in 2021 from approximately 32 percent in 2020. The dollar amount of recurring DD&A expense for 2021 decreased 19 percent from the comparable period a year ago as a result of decreased crude oil and natural gas production. In each of 2021 and 2020, the Partnership recognized asset retirement obligation (ARO) accretion expense of approximately $53 thousand. Abandonment activities continued during 2021, primarily at Ship Shoal 258/259. Spending on abandonment activity at Ship Shoal 258/259 was higher than previously estimated because of weather delays and unplanned infrastructure requirements for abandonment activity.

Lease operating expenses (LOE) for 2021 increased 57 percent from the same period a year ago to approximately $613 thousand in 2021. The increase reflects higher direct operating costs that are trending with commodity prices and increased repair and maintenance work during 2021 related to equipment repairs and damage resulting from Hurricane Ida. Gathering and transportation costs for the delivery of oil and gas totaled approximately $7 thousand in 2021, a decrease of 36 percent from the same period a year ago as a result of lower production. Administrative expenses for 2021 decreased 10 percent compared to 2020.

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 any write-downs for the carrying value of its oil and gas properties during 2021 or 2020. Write-downs, if any, 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.

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities; however, cash from operating activities resulted in cash outflows of approximately $415 thousand and $573 thousand for 2021 and 2020, respectively. Cash flows from operating activities reflect the impact of a net operating loss in 2021 due to lower production from wells being shut-in partially offset by higher realized commodity prices. Cash outflows were also significantly impacted by plugging and abandonment spending of $232 thousand and $492 thousand during 2021 and 2020, respectively.

At December 31, 2021, the Partnership had approximately $4.2 million in cash and cash equivalents, down 8 percent from the end of 2020, primarily as a result of plugging and abandonment spending during the year and fixed overhead costs. 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 anticipated repairs on aging infrastructure 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 well performance, workovers, and recompletions. Declines in oil and gas production can be expected in future years as a result of normal depletion and the non-participation in acquisition or exploration activities by the Partnership.

Based on production estimates from independent engineers and existing cash balances reserved for platform dismantlement and abandonment activities, current market conditions resulting from the COVID-19 pandemic are not expected to materially impact the Partnership’s liquidity. The Partnership forecasts it will be able to meet its liquidity needs for routine operations in 2022 and 2023, although continued volatility in oil and gas prices and consumer demand resulting from the impacts of the COVID-19 pandemic could affect revenues, and further repair and maintenance work could require the Partnership to further reduce its cash and cash equivalents.

8

Approximately 92 percent of the Partnership’s total proved reserves on a barrels of oil equivalent basis 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.

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 2021 or 2020.

Capital Commitments and Contingencies

The Partnership’s primary needs for cash are for operating expenses, recompletion expenditures, and dismantlement and abandonment costs. 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, 2021. The Partnership did not have any contractual obligations as of December 31, 2021, 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 Note 8—Asset Retirement Obligations in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” of this 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 approximately $232 thousand in 2021 and approximately $492 thousand in 2020.

Based on preliminary information available to the Partnership, it anticipates minimal 2022 capital expenditure levels for recompletions and other capital projects at South Timbalier 295. Additionally, $451 thousand is estimated to be spent in 2022 to decommission platforms at North Padre Island 969/976. Such estimates may change based on realized oil and gas prices, recompletion results, rates charged by contractors or changes by the operator to their development or abandonment plans.

Because of continued declines in production levels and pipeline interruptions, volatility in commodity prices in recent years, and the need to reserve cash for future asset retirement obligations, the Partnership did not make any distributions to the Investing Partners during 2021 or 2020.

The amount of future distributions will be dependent on actual and expected production levels, realized and anticipated oil and gas prices, expected 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 recompletion activity to determine whether there are sufficient funds to make a distribution to Investing Partners in 2022.

On August 3, 2020, Fieldwood Energy LLC, the operator of the Partnership’s producing lease, and certain of its affiliated debtors (collectively, Fieldwood) filed for protection under Chapter 11 of the United States Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, Fieldwood separated its ownership in, and operatorship of, the Partnership’s producing lease, together with several of Fieldwood’s other leases, into a standalone company, which will continue to perform Fieldwood’s obligations with respect to the Partnership’s properties. The reorganization of Fieldwood under the plan is not expected to have any material adverse effect on the Partnership’s operations.

9

With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (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, the 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.

Notice of Withdrawal and Right of Presentment

On March 22, 2019, Apache, as the Managing Partner of the Investment Partnership, gave notice of its intention to withdraw as Managing Partner of the Investment Partnership. The notice described the withdrawal process and certain notice periods required by that process. No party assumed the role of Managing Partner within the 120-day notice period specified by the notice of intention to withdraw. Consequently, Apache will oversee the process of winding up and liquidating the business and affairs of the Investment Partnership. Apache has not made a decision as to when it will complete the process to withdraw as Managing Partner.

On April 26, 2019, the Managing Partner determined that, during the withdrawal and dissolution process, it would be inconsistent with the Managing Partner’s fiduciary duties to purchase (or to cause the Investment Partnership to purchase) outstanding Units from the holders thereof pursuant to the right of presentment provided for in Sections 6.9 through 6.14 of the Partnership Agreement of the Investment Partnership (the Partnership Agreement). As a result of this determination by the Managing Partner, pursuant to Section 6.12 of the Partnership Agreement, the right of presentment has been terminated and Sections 6.9 through 6.14 have “become null and void and of no further force or effect” as provided in Section 6.12 of the Partnership Agreement.

Prior to terminating the right of presentment, the Investment Partnership had not made a repurchase under the right of presentment since 2008.

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 for 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 the Partnership 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 (GAAP), 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 the Partnership’s most critical accounting policies:

10

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.

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 its proved reserves. These reserves are also the basis for the Partnership’s 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 the Partnership’s oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a “smaller reporting company,” the Partnership is not required to provide the information required by this Item. The Partnership has chosen to disclose, however, that it has not engaged in any transactions, issued or bought any financial instruments, or entered into any contracts that are required to be disclosed in response to this Item.

11

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

APACHE OFFSHORE INVESTMENT PARTNERSHIP

INDEX TO FINANCIAL STATEMENTS

	Page Number
Report of Management on Internal Control over Financial Reporting	13
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)	14
Statement of Consolidated Operations for each of the three years in the period ended December 31, 2021	16
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2021	17
Consolidated Balance Sheet as of December 31, 2021 and 2020	18
Statement of Consolidated Changes in Partners’ Capital for each of the three years in the period ended December 31, 2021	19
Notes to Consolidated Financial Statements	20
Supplemental Oil and Gas Disclosures (Unaudited)	27

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.

12

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 Form 10-K. The financial statements were prepared in conformity with GAAP 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, as amended (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 APA’s board of directors, applicable to all directors, officers, employees, and other individuals working for APA and its affiliates.

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, 2021. 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, 2021.

/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 22, 2022

13

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depreciation, depletion and amortization of oil and gas properties

Description of the Matter

At December 31, 2021, the carrying value of the Partnership’s oil and gas properties was $4,627,575 and depreciation, depletion and amortization (DD&A) expense was $162,564 for the year then ended. As described in Note 2, the Partnership follows the full-cost method of accounting for its investment in oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the future gross revenue method based on proved oil and gas reserves, as estimated by independent petroleum engineers.

14

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids, 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. Significant judgment is required by the independent petroleum engineers in evaluating geological and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates, among others. Because of the complexity involved in estimating proved oil and gas reserves, management engaged independent petroleum engineers to prepare the proved oil and gas reserve estimates as of December 31, 2021. Auditing the Partnership’s DD&A calculation is complex because of the use of the work of the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and gas reserves.

How We Addressed the Matter in Our Audit

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the independent petroleum engineers used to prepare the proved oil and gas reserve estimates. In addition, in assessing whether we can use the work of the independent petroleum engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating proved oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. We also tested the mathematical accuracy of the DD&A calculation, including comparing the proved oil and gas reserve amounts used in the calculation to the Partnership’s reserve report.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2002.

Houston, Texas

February 22, 2022

15

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2021		2020		2019
REVENUES:
Oil and gas sales	$	468,438	$	619,161	$	1,100,334
Interest income	341		24,034		106,787
	468,779		643,195		1,207,121
EXPENSES:
Depreciation, depletion and amortization
Recurring	162,564		200,045		264,031
Asset retirement obligation accretion	52,858		52,943		77,805
Lease operating expenses	613,284		391,751		530,206
Gathering and transportation costs	6,879		10,736		15,823
Administrative	289,925		320,704		328,536
	1,125,510		976,179		1,216,401
NET LOSS	$	(656,731)	$	(332,984)	$	(9,280)
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	$	(103,179)	$	(35,828)	$	30,385
Investing Partners	(553,552)		(297,156)		(39,665)
	$	(656,731)	$	(332,984)	$	(9,280)
NET LOSS PER INVESTING PARTNER UNIT	$	(543)	$	(291)	$	(39)
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING	1,020.2		1,021.5		1,021.5

The accompanying notes to consolidated financial statements

are an integral part of this statement.

16

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CASH FLOWS

	For the Year Ended December 31,
	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(656,731)	$	(332,984)	$	(9,280)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	162,564		200,045		264,031
Asset retirement obligation accretion	52,858		52,943		77,805
Changes in operating assets and liabilities:
Accrued revenues receivable	95,590		13,103		11,423
Receivable from/Payable to Apache Corporation	2,805		(12,419)		6,517
Accrued operating expenses	160,100		(1,152)		(14,414)
Asset retirement expenditures	(232,456)		(492,120)		(397,542)
Net cash used in operating activities	(415,270)		(572,584)		(61,460)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	—		(9)		(18,481)
Net cash used in investing activities	—		(9)		(18,481)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from Managing Partner	61,587		67,627		—
Distributions to Managing Partner	—		—		(2,963)
Net cash provided by (used in) financing activities	61,587		67,627		(2,963)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(353,683)		(504,966)		(82,904)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	4,515,466		5,020,432		5,103,336
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	4,161,783	$	4,515,466	$	5,020,432

The accompanying notes to consolidated financial statements

are an integral part of this statement.

17

APACHE OFFSHORE INVESTMENT PARTNERSHIP

CONSOLIDATED BALANCE SHEET

	December 31, 2021		December 31, 2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,161,783	$	4,515,466
Accrued revenues receivable	—		95,590
Receivable from Apache Corporation	2,025		4,830
	4,163,808		4,615,886
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties	196,449,399		195,727,413
Less – Accumulated depreciation, depletion and amortization	(191,821,824)		(191,659,260)
	4,627,575		4,068,153
	$	8,791,383	$	8,684,039
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Current asset retirement obligation	$	450,996	$	526,440
Accrued operating expenses	235,948		75,848
Accrued decommissioning, abandonment, and development costs	112,852		—
	799,796		602,288
ASSET RETIREMENT OBLIGATION	1,363,064		858,084
PARTNERS’ CAPITAL:
Managing Partner	481,815		523,407
Investing Partners (1,018.5 units outstanding)	6,146,708		6,700,260
	6,628,523		7,223,667
	$	8,791,383	$	8,684,039

The accompanying notes to consolidated financial statements

are an integral part of this statement.

18

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL

	Managing Partner		Investing Partners		Total
BALANCE, DECEMBER 31, 2018	$	464,186	$	7,037,081	$	7,501,267
Distributions	(2,963)		—		(2,963)
Net income (loss)	30,385		(39,665)		(9,280)
BALANCE, DECEMBER 31, 2019	$	491,608	$	6,997,416	$	7,489,024
Contributions	67,627		—		67,627
Net loss	(35,828)		(297,156)		(332,984)
BALANCE, DECEMBER 31, 2020	$	523,407	$	6,700,260	$	7,223,667
Contributions	61,587		—		61,587
Net loss	(103,179)		(553,552)		(656,731)
BALANCE, DECEMBER 31, 2021	$	481,815	$	6,146,708	$	6,628,523

The accompanying notes to consolidated financial statements

are an integral part of this statement.

19

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.

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. 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.

Apache is the managing partner of the Investment Partnership and the general partner of the Operating Partnership, and held approximately five percent of the 1,018.5 Units outstanding at December 31, 2021. As used hereafter, the term “Partnership” refers to the Investment Partnership or the Operating Partnership, as the case may be.

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 an 85 percent interest in offshore properties 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. As of December 31, 2021, 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 Agreement of the Investment Partnership (the Partnership Agreement), 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.

Notice of Withdrawal

On March 22, 2019, Apache, as the Managing Partner of the Investment Partnership, gave notice of its intention to withdraw as Managing Partner of the Investment Partnership. The notice described the withdrawal process and certain notice periods required by that process. No party assumed the role of Managing Partner within the 120-day notice period specified by the notice of intention to withdraw. Consequently, Apache will oversee the process of winding up and liquidating the business and affairs of the Investment Partnership. Apache has not made a decision as to when it will complete the process to withdraw as Managing Partner.

20

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Right of Presentment

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

On April 26, 2019, the Managing Partner determined that, during the withdrawal and dissolution process noted above, it would be inconsistent with the Managing Partner’s fiduciary duties to purchase (or to cause the Investment Partnership to purchase) outstanding Units from the holders thereof pursuant to the right of presentment provided for in Sections 6.9 through 6.14 of the Partnership Agreement. As a result of this determination by the Managing Partner, pursuant to Section 6.12 of the Partnership Agreement, the right of presentment was terminated for 2019 and future periods. Sections 6.9 through 6.14 have “become null and void and of no further force or effect” as provided in Section 6.12 of the Partnership Agreement.

Prior to terminating the right of presentment, the Investment Partnership had not made a repurchase under the right of presentment since 2008.

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 the Investment Partnership and the Operating 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 (Unaudited)) and the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation).

Cash Equivalents

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2021 and 2020, the Partnership had $4.2 million and $4.5 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—Asset Retirement Obligation. 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.

21

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The Partnership did not record any write-downs of capitalized costs during 2021, 2020, or 2019. See Note 10—Supplemental Oil and Gas Disclosures (Unaudited) 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

The Partnership applies the provisions of Accounting Standards Codification 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, as Managing Partner of the Partnership, markets the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of revenue. 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. As of December 31, 2021, the carrying amounts of trade accounts receivables approximate fair value because of the short-term nature of these instruments. Receivables from contracts with customers totaled nil and $95,590 as of December 31, 2021 and 2020, 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, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
Oil	$	400,224	$	532,261	$	990,659
Gas	$	52,273	70,999		94,057
NGLs	$	15,941	15,901		15,618
Total Oil and Gas Revenue	$	468,438	$	619,161	$	1,100,334

22

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership did not have any revenue from non-customers.

Net Income (Loss) Per Investing Unit

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

Income Taxes

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

Receivable from/Payable to Apache Corporation

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

Maintenance and Repairs

Maintenance and repairs are charged to expense as incurred.

3. COMPENSATION TO AFFILIATES

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

	Total Reimbursed by the Investing Partners for the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business	$	232	$	257	$	263

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.

	2021		2020		2019
	(In thousands)
Oil and Gas Properties
Balance, beginning of year	$	195,727	$	195,401	$	195,327
Costs incurred during the year:
Development –
Investing Partners	653		293		67
Managing Partner	69		33		7
Balance, end of year	$	196,449	$	195,727	$	195,401

Development costs for 2021 included upward revisions of approximately $671 thousand, primarily related to revised abandonment cost estimates for South Timbalier 295 properties and approximately $51 thousand for recent capital projects accrued at year end. During 2020 and 2019, development costs included upward revisions of approximately $326 thousand and $56 thousand, respectively, for estimated abandonment costs primarily related to revised cost estimates on the Ship Shoal 258/259 properties. Approximately $18 thousand of capital costs were incurred in 2019 for participation in pipeline and recompletion projects at South Timbalier 295.

23

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Managing Partner		Investing Partners		Total
	(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 2018	$	21,120	$	170,075	$	191,195
Provision	14		250		264
Balance, December 31, 2019	$	21,134	$	170,325	$	191,459
Provision	11		189		200
Balance, December 31, 2020	$	21,145	$	170,514	$	191,659
Provision	10		153		163
Balance, December 31, 2021	$	21,155	$	170,667	$	191,822

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2021, 2020, and 2019 was 35 percent, 32 percent and 24 percent, respectively.

5. MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

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

Remittances from QuarterNorth Energy LLC (formerly Fieldwood Energy LLC) accounted for 15 percent, 14 percent and 10 percent of the Partnership’s oil and gas sales for the years 2021, 2020 and 2019, respectively. Approximately 85 percent, 86 percent and 90 percent of the Partnership’s oil and gas sales in 2021, 2020 and 2019, 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.

6. FAIR VALUE MEASUREMENTS

Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. As of December 31, 2021 and December 31, 2020, the carrying amounts of cash, cash equivalents, accounts receivable, and accounts payable were determined to 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 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.

24

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 3, 2020, Fieldwood Energy LLC, the operator of the Partnership’s producing lease, and certain of its affiliated debtors (collectively, Fieldwood) filed for protection under Chapter 11 of the United States Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, Fieldwood separated its ownership in, and operatorship of, the Partnership’s producing lease, together with several of Fieldwood’s other leases, into a standalone company, which will continue to perform Fieldwood’s obligations with respect to the Partnership’s properties. The reorganization of Fieldwood under the plan is not expected to have any material adverse effect on the Partnership’s operations.

With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (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, the 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, 2021 and 2020:

	2021		2020
Asset retirement obligation at beginning of year	$	1,384,524	$	1,421,282
Accretion expense	52,858		52,943
Liabilities settled	(294,218)		(415,710)
Revisions in estimated liabilities	670,896		326,009
Asset retirement obligation at end of year	$	1,814,060	$	1,384,524
Less current portion	(450,996)		(526,440)
Asset retirement obligation, long-term	$	1,363,064	$	858,084

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 and platform decommissioning during the periods presented. The current portion of the ARO liability represents the retirement obligation expected to be incurred in the next twelve months.

During 2021, the upward revision in abandonment liabilities primarily represented higher estimated costs and increased inflation assumptions for South Timbalier 295.

Decommissioning and abandonment activities began at Ship Shoal 258/259 upon cessation of the lease in 2018 and were effectively completed in 2021. The lease was relinquished earlier than previously estimated given unplanned third-party pipeline issues and the decision that returning the lease to production was not economical for the Partnership. The operator also experienced challenges related to the plugging of wells and weather-related delays which resulted in revising the field’s estimated abandonment obligation based on projected costs. Both factors contributed to the upward cost revisions to ARO liability estimates for 2020.

25

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. TAX-BASIS FINANCIAL INFORMATION

A reconciliation of ordinary income for federal income tax reporting purposes to net income under GAAP is as follows:

	2021		2020		2019
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	(801,635)	$	(549,623)	$	(80,046)
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost	38,318		9		113
Dismantlement and abandonment cost	294,218		415,710		347,952
Tax depreciation	27,790		53,908		64,537
	360,326		469,627		412,602
Less: full cost DD&A expense	(162,564)		(200,045)		(264,031)
Less: asset retirement obligation accretion	(52,858)		(52,943)		(77,805)
Net income (loss)	$	(656,731)	(332,984)		(9,280)

The Partnership’s tax basis in net oil and gas properties at December 31, 2021, and 2020 was $3,260,012 and $2,685,573, 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 each of December 31, 2021 and 2020.

A reconciliation of liabilities for federal income tax reporting purposes to liabilities under GAAP is as follows:

	December 31,
	2021		2020
Liabilities for federal income tax purposes	$	348,800	$	75,848
Asset retirement liability	1,814,060		1,384,524
Liabilities under GAAP	$	2,162,860	$	1,460,372

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

26

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 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)

	2021			2020			2019
	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL	Gas
Proved Reserves
Beginning of year	350	26	597	361	27	626	363	29	670
Extensions, discoveries and other additions	—	—	—	—	—	—	—	—	—
Revisions of previous estimates	11	(2)	74	3	—	(1)	15	(1)	(10)
Production	(7)	(1)	(17)	(14)	(1)	(28)	(17)	(1)	(34)
End of year	354	23	654	350	26	597	361	27	626
Proved Developed
Beginning of year	350	26	597	361	27	626	363	29	670
End of year	354	23	654	350	26	597	361	27	626

Oil includes crude oil and condensate.

All the Partnership’s reserves as of December 31, 2021 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 92 percent of the Partnership’s current proved developed reserves on a barrels of oil equivalent basis 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, 2021, 2020, and 2019 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.

27

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Discounted Future Net Cash Flows Relating to Proved Reserves

	December 31,
	2021		2020		2019
	(In thousands)
Future cash inflows	$	26,244	$	15,329	$	24,158
Future production costs	(6,117)		(5,116)		(5,540)
Future development costs(1)	(5,426)		(3,204)		(3,483)
Net cash flows	14,701		7,009		15,135
10 percent annual discount rate	(6,492)		(2,267)		(4,735)
Discounted future net cash flows	$	8,209	$	4,742	$	10,400

(1) This amount includes estimated abandonment costs.

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

	For the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Sales, net of production costs	$	152	$	(217)	$	(554)
Net change in prices and production costs	6,044		(5,668)		(2,476)
Revisions of quantities	577		43		273
Accretion of discount	474		1,040		1,162
Changes in future development costs(1)	(1,270)		(122)		(39)
Previously estimated development costs incurred during the period	294		492		416
Changes in production rates and other	(2,804)		(1,226)		(5)
	$	3,467	$	(5,658)	$	(1,223)

(1) This amount includes estimated abandonment costs.

28

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

The financial statements for the fiscal years ended December 31, 2021, 2020 and 2019, 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.    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 of the Managing Partner), and Stephen J. Riney, the Managing Partner’s Executive Vice President and Chief Financial Officer (in his capacity as principal financial officer of the Managing Partner), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2021, 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 the Partnership is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified under the SEC’s rules and forms and communicated to the Partnership’s management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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 13 of this Form 10-K. This Form 10-K 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 Form 10-K.

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, 2021, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

29

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Partnership has no officers or directors. All of the Partnership’s management functions are performed by Apache, the Managing Partner of the Partnership. On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which, Apache became a direct, wholly-owned subsidiary of APA Corporation (APA), all of Apache’s outstanding shares were automatically converted into equivalent corresponding shares of APA, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Securities Exchange Act of 1934, as amended (the Exchange Act), and APA replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.”

Executive Officers of Apache

Following consummation of the Holding Company Reorganization, the executive officers of APA also serve as executive officers of Apache, with each officer having the same title at both companies. Information concerning the executive officers of APA set forth under the caption “Information About Our Executive Officers” in the proxy statement relating to the 2022 annual meeting of stockholders of APA (the APA Proxy Statement) is incorporated herein by reference.

Directors of Apache

Biographical information, as of February 22, 2022, for the directors of Apache is set forth below. All references to positions held at APA mean such positions held at Apache for all periods prior to March 1, 2021 (the effective date of the Holding Company Reorganization) and means such positions held at both Apache and APA for all periods after March 1, 2021. Each of the directors named below, with the exception of John J. Christmann IV, was appointed to the board of directors of Apache on March 1, 2021, immediately following the effective time of the Holding Company Reorganization.

D. CLAY BRETCHES, 57, has served as APA’s executive vice president of Operations since January 1, 2020, having been senior vice president, U.S. Midstream Operations, since January 2019. He also serves as Chief Executive Officer and President and a member of the board of directors of Altus Midstream Company since January 2019. He previously served as the president and CEO of Sendero Midstream since 2014. Prior to that, Mr. Bretches served at Anadarko Petroleum Corporation as vice president, E&P Services and Minerals from 2010 to 2014, and as vice president, Marketing and Minerals from 2005 to 2010. He was instrumental in the formation of Western Gas Partners, a midstream MLP. Earlier in his career, Mr. Bretches led the crude oil marketing and midstream operations for Vastar Resources and worked as an engineer for ARCO.

JOHN J. CHRISTMANN IV, 55, has served as APA’s chief executive officer and president, and as a member of APA’s Board of Directors since January 20, 2015. Mr. Christmann previously served as APA’s executive vice president and chief operating officer, North America, since January 2014. From January 2010 through December 2013, he served as APA’s region vice president, Permian Region. From January 2004 through December 2009, he served as APA’s vice president, Business Development, and from April through December 2003, he served as APA’s production manager for the Gulf Coast Region. Prior to that, Mr. Christmann held various positions of increasing responsibility in the business development area since joining APA in 1997. Previously, Mr. Christmann was employed by Vastar Resources/ARCO Oil and Gas Company in business development, crude oil marketing, and various production, operational, and reservoir engineering assignments.

MARK D. MADDOX, 55 , has served as APA’s senior vice president of Administration since April 2020 and oversees the global functions of human resources, supply chain, and information technology. Previously, Mr. Maddox served as APA’s vice president and chief information officer since January 1, 2017. He joined APA in June 2015 as vice president, Information Technology. Mr. Maddox was previously with Ernst & Young LLP, where he was a principal of Oil & Gas Advisory Services since February 2014. Prior to Ernst & Young, Mr. Maddox worked at Deloitte LLP from 2010 to 2014 as director of Energy and Resources. He also held various roles of increasing responsibility at SAP America from 1998 to 2009, including vice president of Oil, Gas & Chemicals from 2007 to 2009. He began his career at Tenneco Energy in 1989, where he held positions in accounting, operations, and information technology.

DAVID A. PURSELL, 58, has served as APA’s executive vice president of Development since April 2020, having previously served as APA’s senior vice president, Planning, Reserves, and Fundamentals since March 2018. Before joining APA, Mr. Pursell served as managing director of Investment Banking for Tudor, Pickering, Holt & Co. (TPH), having previously served as head of Macro Research at TPH after serving as one of the founders of Pickering Energy Partners, Inc. in 2004. Prior to TPH, Mr. Pursell was director of Upstream Research at Simmons & Company International. Earlier in his career, he worked in various production and reservoir engineering assignments at S.A. Holditch and Associates, which is now part of Schlumberger. Mr. Pursell began his career at ARCO Alaska in Anchorage with production and operations engineering assignments in South Alaska and the North Slope.

30

STEPHEN J. RINEY, 61, has served as APA’s executive vice president since February 2015 and as chief financial officer since March 2015. Prior to joining APA, he was with Amoco Corporation and BP p.l.c. from 1991 to 2015. He served as chief financial officer for BP Exploration and Production from July 2012 to January 2015, and global head of mergers and acquisitions for BP p.l.c. from January 2007 to June 2012.

Code of Business Conduct

Pursuant to Nasdaq Rule 5610, Apache, the Managing Partner of the Partnership, was required to adopt a code of business conduct and ethics for its directors, officers, and employees. In February 2004, the board of directors of Apache, APA’s predecessor registrant, adopted a Code of Business Conduct and Ethics. In March 2021, as part of the Holding Company Reorganization, Apache’s Code of Business Conduct and Ethics was adopted and revised by APA’s board of directors (as adopted and revised, the Code of Conduct). The Code of Conduct, which also meets the requirements of a code of ethics under Item 406 of Regulation S-K, applies to all directors, officers, employees, and other individuals working for APA and its affiliates.

You can access the Code of Conduct on the “Governance” page of APA’s website at www.apacorp.com. Any unitholder who so requests may obtain a printed copy of the Code of Conduct without charge by submitting a request to the Investment Partnership’s corporate secretary at the address on the cover of this Form 10-K. Changes in and any waivers to the Code of Conduct for APA’s directors, chief executive officer and certain senior financial officers will be posted on APA’s website within four business days and maintained for at least twelve months. Information on APA’s website or any other website is not incorporated by reference into, and does not constitute a part of this Form 10-K.

Corporate Governance

Pursuant to the Holding Company Reorganization, Apache became a direct, wholly-owned subsidiary of APA. Following consummation of the Holding Company Reorganization, the board of directors of Apache is appointed by, and serves at the discretion of, the board of directors of APA. The standing committees of the board of directors of APA include an Audit Committee, a Corporate Responsibility, Governance, and Nominating Committee, and a Management Development and Compensation Committee. Information concerning the Audit Committee of the board of directors of APA set forth under the caption “Standing Committees and Meetings of the Board—Audit Committee” in the APA Proxy Statement is incorporated herein by reference.

ITEM 11.    EXECUTIVE COMPENSATION

Executive Compensation

The Partnership has no officers. All of the Partnership’s management functions are performed by Apache, the Managing Partner of the Partnership. Following consummation of the Holding Company Reorganization, the executive officers of Apache also serve as executive officers of APA and perform responsibilities for APA and its affiliates that are unrelated to our business. None of APA’s executive officers receive any cash (or non-cash) compensation for the services they provide to the Partnership. See Note 3—Compensation to Affiliates in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” of this Form 10-K, for information regarding the compensation paid to Apache as Managing Partner.

Director Compensation

The Partnership has no directors. All of the Partnership’s management functions are performed by Apache, the Managing Partner of the Partnership. Following consummation of the Holding Company Reorganization, each member of the board of directors of Apache also serves as an executive officer of APA and Apache. None of Apache’s directors receive any cash (or non-cash) compensation for the services they provided as directors of Apache.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER 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, 2021. Apache also owns a one-percent General Partner interest in the Partnership (15 equivalent Units). To the knowledge of the Partnership, no Investing Partner (other than Apache) owns, of record or beneficially, more than five percent of the Partnership’s outstanding Units. Apache did not acquire additional Units during the three years covered by these financial statements. Apache’s ownership percentage exceeds five percent due to the decrease in the number of outstanding units resulting from the right of presentment (See Note 1—Organization in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” of this Form 10-K).

31

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

See Note 3—Compensation to Affiliates in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” of this Form 10-K, for information regarding the compensation paid to Apache as Managing Partner. See Note 5—Major Customers and Related Parties Information in the Notes to the Consolidated Financial Statements set forth in Part II, Item 8—“Financial Statements and Supplementary Data” of this Form 10-K, for amounts paid to subsidiaries of Apache, and for other related party information.

The Partnership itself has no directors. Pursuant to the Holding Company Reorganization, Apache became a direct, wholly-owned subsidiary of APA. Following consummation of the Holding Company Reorganization, each member of the board of directors of Apache also serves as an executive officer of APA and Apache and is appointed by, and serves at the discretion of, the board of directors of APA. Information concerning the directors of APA set forth under the caption “Director Independence” in the APA Proxy Statement is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

Accountant fees and services paid to Ernst & Young LLP, the Partnership’s independent auditors, are included in amounts paid by APA on behalf of Apache. Information on APA’s principal accountant fees and services is set forth under the caption “Ratification of Appointment of Independent Auditors” in the APA Proxy Statement incorporated herein by reference.

32

PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

a.	(1)	Financial Statements – See accompanying index to financial statements set forth in Part II, Item 8 of this Form 10-K.
	(2)	Financial Statement Schedules – See accompanying index to financial statements set forth in Part II, Item 8 of this Form 10-K.
	(3)	Exhibits
	P3.1		Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit (3)(i) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
	P3.2		Amendment No. 1, dated February 11, 1994, to the Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit 3.3 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).
	P3.3		Limited Partnership Agreement of Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit (3)(ii) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
	4.1		Description of Registrant’s Securities (incorporated by reference to Exhibit 4.1 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019, Commission File No. 0-13546).
	P10.1		Form of Assignment and Assumption Agreement between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.2 to Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, Commission File No. 0-13546).
	P10.2		Joint Venture Agreement, dated as of November 23, 1992, between Apache Corporation and Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit 10.6 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).
	P10.3		Matagorda Island 681 Field Purchase and Sale Agreement with Option to Exchange, dated November 24, 1992, between Apache Corporation, Shell Offshore, Inc. and SOI Royalties, Inc. (incorporated by reference to Exhibit 10.7 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 0-13546).
	*23.1		Consent of Ryder Scott Company, L.P., Petroleum Consultants.
	*24.1		Power of Attorney (included as part of the signature pages to this report).
	*31.1		Certification of Principal Executive Officer.
	*31.2		Certification of Principal Financial Officer.
	*32.1		Certification of Principal Executive Officer and Principal Financial Officer.
	*99.1		Report of Ryder Scott Company, L.P., Petroleum Consultants.
	*101.INS		Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
	*101.SCH		Inline XBRL Taxonomy Schema Document.
	*101.CAL		Inline XBRL Calculation Linkbase Document.
	*101.DEF		Inline XBRL Definition Linkbase Document.
	*101.LAB		Inline XBRL Label Linkbase Document.
	*101.PRE		Inline XBRL Presentation Linkbase Document.
	*104		Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*	Filed herewith.
P	Filed previously in paper format.
b.	See a (3) above.
c.	See a (2) above.

ITEM 16.    FORM 10-K SUMMARY

None.

33

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 22, 2022	/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.

Name	Title	Date
/s/ John J. Christmann IV John J. Christmann IV	Director, Chief Executive Officer and President (principal executive officer)	February 22, 2022
/s/ Stephen J. Riney Stephen J. Riney	Director, Executive Vice President and Chief Financial Officer (principal financial officer)	February 22, 2022
/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Senior Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 22, 2022
/s/ D. Clay Bretches D. Clay Bretches	Director	February 22, 2022
/s/ Mark D. Maddox Mark D. Maddox	Director	February 22, 2022
/s/ David A. Pursell David A. Pursell	Director	February 22, 2022

34

EX-23.1

TBPE REGISTERED ENGINEERING FIRM F-1580FAX (713) 651-0849

1100 LOUISIANA SUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191

EXHIBIT 23.1

Consent of Ryder Scott Company, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Offshore Investment Partnership to our Firm’s name and our Firm’s review of the proved oil and gas reserve quantities of Apache Offshore Investment Partnership as of December 31, 2021, and to the inclusion of our report, dated February 1, 2022, as an exhibit to this Form 10-K filed with the Securities and Exchange Commission.

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

TBPELS Firm Registration No. F-1580

Houston, Texas

February 22, 2022

SUITE 2800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    

635 17TH STREET, SUITE 1700         DENVER, COLORADO 80202    TEL (303) 339-8110    

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

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

Date: February 22, 2022

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President 

(principal executive officer) of Apache Corporation, Managing Partner

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

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

Date: February 22, 2022

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer) of Apache Corporation, Managing Partner

EX-32.1

Exhibit 32.1

APACHE OFFSHORE INVESTMENT PARTNERSHIP

by Apache Corporation, Managing Partner

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the Annual Report on Form 10-K of Apache Offshore Investment Partnership for the period ending December 31, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.

Date:	February 22, 2022
	/s/ John J. Christmann IV
By:	John J. Christmann IV
Title:	Chief Executive Officer and President (principal executive officer)
	of Apache Corporation, Managing Partner

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the Annual Report on Form 10-K of Apache Offshore Investment Partnership for the period ending December 31, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Offshore Investment Partnership.

Date:	February 22, 2022
	/s/ Stephen J. Riney
By:	Stephen J. Riney
Title:	Executive Vice President and Chief Financial Officer (principal financial officer)
	of Apache Corporation, Managing Partner

EX-99.1

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS APACHE CORPORATION Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests In The Shell Offshore Venture SEC Parameters As of December 31, 2021 /s/ Ali A. Porbandarwala Ali A. Porbandarwala, P.E. TBPELS License No. 107652 Senior Vice President [SEAL] RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580 SUITE 2800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 633 17TH STREET, SUITE 1700 DENVER, COLORADO 80202 TEL (303) 339-8110 TBPELS REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849 1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191 February 1, 2022 Apache Corporation 2000 Post Oak Boulevard, Suite 100 Houston, Texas 77056 Ladies and Gentlemen: At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production and income attributable to certain leasehold and royalty interests in the Shell Offshore Venture for Apache Corporation (Apache) as of December 31, 2021. Additionally, at Apache’s request, this report includes an estimate of the probable and possible reserves volumes; however, this report does not address the future production or income or economic producibility attributable to the probable and possible reserves quantities contained herein. The subject properties are located in the federal waters offshore Louisiana and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 21, 2022 and presented herein, was prepared for public disclosure by Apache in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves and 100 percent of the total net proved, probable and possible gas reserves of the Shell Offshore Venture for Apache as of December 31, 2021. The estimated reserves and future net income amounts presented in this report, as of December 31, 2021, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized in the following table. Apache Corporation – Shell Offshore Venture February 1, 2022 Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS SEC PARAMETERS Apache Corporation Estimated Net Reserves and Income Data Certain Leasehold and Royalty Interests in the Shell Offshore Venture As of December 31, 2021 Proved Developed Total Producing Non-Producing Proved Net Reserves Oil/Condensate – Barrels 30,033 324,081 354,114 Plant Products – Barrels 1,947 21,415 23,362 Gas – MMcf 55 599 654 Income Data Future Gross Revenue $2,220,863 $24,023,426 $26,244,289 Deductions 1,602,779 9,939,957 11,542,736 Future Net Income (FNI) $ 618,084 $14,083,469 $14,701,553 Discounted FNI @ 10% $ 566,929 $ 7,642,742 $ 8,209,671 Probable Developed Total Producing Non-Producing Probable Net Reserves Oil/Condensate – Barrels 3,504 26,061 29,565 Plant Products – Barrels 175 1,676 1,851 Gas – MMcf 5 47 52 Total Possible Developed Non-Producing Net Reserves Oil/Condensate – Barrels 1,930 Plant Products – Barrels 205 Gas – MMcf 6 Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of 60º Fahrenheit and 14.73 psia. In this report, the revenues, deductions, and income data are expressed as U.S. dollars. The estimates of the proved reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Apache Corporation – Shell Offshore Venture February 1, 2022 Page 3 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Apache. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties summarized. Furthermore, oneline economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, transportation costs (incorporated as other costs in the cash flow projections) and certain abandonment costs net of salvage. Since the properties involved are all located on federal leases, there are no production, severance, or ad valorem taxes to be considered. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 90.8 percent and gas reserves account for the remaining 9.2 percent of total future gross revenue from proved reserves. The proved discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Proved future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows. Discounted Future Net Income As of December 31, 2021 Discount Rate Total Percent Proved 5 $10,873,043 15 $ 6,336,367 20 $ 4,996,304 25 $ 4,019,228 The results shown above are presented for your information and should not be construed as our estimate of fair market value. Reserves Included in This Report The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report. The various reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved, probable and possible developed non-producing reserves included herein consist of the behind pipe status category. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Apache Corporation – Shell Offshore Venture February 1, 2022 Page 4 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Apache’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein. Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low. The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable. Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities. In the case of the proved reserves presented herein, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. Apache’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved, probable and possible reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities. The estimates of reserves presented herein were based upon a detailed study of the properties in which Apache owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any Apache Corporation – Shell Offshore Venture February 1, 2022 Page 5 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Estimates of Reserves The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved, probable and possible reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved and probable producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis and/or material balance which utilized extrapolations of historical production and pressure data available through November 2021 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Apache or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the producing reserves were estimated by the volumetric Apache Corporation – Shell Offshore Venture February 1, 2022 Page 6 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate. Approximately 100 percent of the proved, probable and possible developed non-producing reserves included herein were estimated by the volumetric method or analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Apache or which we have obtained from public data sources that were available through November 2021. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Apache has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, and probable and possible production, we have relied upon data furnished by Apache with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Apache. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations, except as noted for the probable and possible reserves volumes. Future Production Rates For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held Apache Corporation – Shell Offshore Venture February 1, 2022 Page 7 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. Apache furnished us with the above mentioned average prices in effect on December 31, 2021. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the- month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. The product prices which were actually used to determine the proved future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Apache. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache to determine these differentials. In addition, the following table summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total proved future gross revenue before production taxes and the total proved net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Apache Corporation – Shell Offshore Venture February 1, 2022 Page 8 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Geographic Area Product Price Reference Average Benchmark Prices Average Proved Realized Prices North America Oil/Condensate WTI Cushing $66.56/bbl $64.85/bbl United States NGLs Mt. Belvieu Non-Tet Propane $44.06/bbl $36.66/bbl Gas Henry Hub $3.61/MMBTU $3.70/Mcf The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations. Costs Operating costs for the leases and wells in this report were furnished by Apache and are based on the operating expense reports of Apache and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Transportation costs are included as deductions and incorporated as other costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Apache. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. Development costs were furnished to us by Apache and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Apache were accepted without independent verification. The proved, probable and possible developed non-producing reserves in this report have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2021. The implementation of Apache’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Apache’s management. As the result of our inquiries during the course of preparing this report, Apache has informed us that the development activities included herein have been subjected to and received the internal approvals required by Apache’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Apache. Apache has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Apache has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Apache Corporation – Shell Offshore Venture February 1, 2022 Page 9 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Current costs used by Apache were held constant throughout the life of the properties. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above. We are independent petroleum engineers with respect to Apache. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Apache Corporation. Apache makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Apache has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3, Form S-4, and Form S-8 of Apache, of the references to our name, as well as to the references to our third party report for Apache, Apache Corporation – Shell Offshore Venture February 1, 2022 Page 10 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS which appears in the December 31, 2021 annual report on Form 10-K of Apache. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Apache. We have provided Apache with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Apache and the original signed report letter, the original signed report letter shall control and supersede the digital version. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580 /s/ Ali A. Porbandarwala Ali A. Porbandarwala, P.E. TBPELS License No. 107652 Senior Vice President [SEAL] AAP (FWZ)/pl RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Professional Qualifications of Primary Technical Person The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Ali A. Porbandarwala was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein. Mr. Porbandarwala, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2008, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Porbandarwala served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Porbandarwala’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Employees. Mr. Porbandarwala earned a Bachelor of Science degree in Chemical Engineering from The University of Kansas in 2001 and a Masters in Business Administration from The University of Texas at Austin in 2007 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers. Mr. Porbandarwala also served as the Chairman of the annual Ryder Scott Reserves Conference in Houston, completing its seventeenth year in the industry. In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Porbandarwala fulfills. As part of his 2021 continuing education hours, Mr. Porbandarwala attended 20 hours of formalized training including the 2021 Virtual Ryder Scott Reserves Conference and various other professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Based on his educational background, professional training and more than 13 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Porbandarwala has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein). Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. PETROLEUM RESERVES DEFINITIONS Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. Reserves do not include quantities of petroleum being held in inventory. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. PETROLEUM RESERVES DEFINITIONS Page 3 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. PROBABLE RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows: Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. PETROLEUM RESERVES DEFINITIONS Page 4 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. POSSIBLE RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows: Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and 2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA) EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4- 10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals that are open at the time of the estimate but which have not yet started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves of any category 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. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can 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 the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

XML

Cover	12 Months Ended
	Dec. 31, 2021 USD ($) shares
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	0-13546
Entity Registrant Name	APACHE OFFSHORE INVESTMENT PARTNERSHIP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-1464066
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100,
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Title of 12(g) Security	Partnership Units
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float | $	$ 0
Entity Common Stock, Shares Outstanding | shares	1,018.5
Documents Incorporated by Reference	Portions of APA Corporation’s proxy statement relating to its 2022 annual meeting of stockholders (the APA Proxy Statement) have been incorporated by reference into Part III hereof. On March 1, 2021, Apache Corporation (Apache) consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which, Apache became a wholly-owned subsidiary of APA Corporation (APA), APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Securities Exchange Act of 1934, as amended, and APA replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.”
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0000727538

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Firm ID	42
Auditor Location	Houston, Texas
Auditor Name	Ernst & Young LLP

XML

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
REVENUES:
Oil and gas sales	$ 468,438	$ 619,161	$ 1,100,334
Interest income	341	24,034	106,787
Total Revenues	468,779	643,195	1,207,121
EXPENSES:
Depreciation, depletion and amortization recurring	162,564	200,045	264,031
Asset retirement obligation accretion	52,858	52,943	77,805
Lease operating expenses	613,284	391,751	530,206
Gathering and transportation costs	6,879	10,736	15,823
Administrative	289,925	320,704	328,536
Total Expenses	1,125,510	976,179	1,216,401
NET LOSS	(656,731)	(332,984)	(9,280)
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	(103,179)	(35,828)	30,385
Investing Partners	(553,552)	(297,156)	(39,665)
NET LOSS	$ (656,731)	$ (332,984)	$ (9,280)
NET INCOME (LOSS) PER INVESTING PARTNER UNIT - Basic (in USD per share)	$ (543)	$ (291)	$ (39)
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING - Basic (in shares)	1,020.2	1,021.5	1,021.5

XML

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (656,731)	$ (332,984)	$ (9,280)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	162,564	200,045	264,031
Asset retirement obligation accretion	52,858	52,943	77,805
Changes in operating assets and liabilities:
Accrued revenues receivable	95,590	13,103	11,423
Receivable from/Payable to Apache Corporation	2,805	(12,419)	6,517
Accrued operating expenses	160,100	(1,152)	(14,414)
Asset retirement expenditures	(232,456)	(492,120)	(397,542)
Net cash used in operating activities	(415,270)	(572,584)	(61,460)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	0	(9)	(18,481)
Net cash used in investing activities	0	(9)	(18,481)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from Managing Partner	61,587	67,627	0
Distributions to Managing Partner	0	0	(2,963)
Net cash provided by (used in) financing activities	61,587	67,627	(2,963)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(353,683)	(504,966)	(82,904)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	4,515,466	5,020,432	5,103,336
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 4,161,783	$ 4,515,466	$ 5,020,432

XML

CONSOLIDATED BALANCE SHEET - USD ($)	Dec. 31, 2021	Dec. 31, 2020
CURRENT ASSETS:
Cash and cash equivalents	$ 4,161,783	$ 4,515,466
Accrued revenues receivable	0	95,590
Receivable from Apache Corporation	2,025	4,830
Total Current Assets	4,163,808	4,615,886
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties	196,449,399	195,727,413
Less – Accumulated depreciation, depletion and amortization	(191,821,824)	(191,659,260)
Total oil and gas properties, on the basis of full cost accounting	4,627,575	4,068,153
Total Assets	8,791,383	8,684,039
CURRENT LIABILITIES:
Current asset retirement obligation	450,996	526,440
Accrued operating expenses	235,948	75,848
Accrued decommissioning, abandonment, and development costs	112,852	0
Total Current Liabilities	799,796	602,288
ASSET RETIREMENT OBLIGATION	1,363,064	858,084
PARTNERS’ CAPITAL:
Managing Partner	481,815	523,407
Investing Partners (1,018.5 units outstanding)	6,146,708	6,700,260
Total Partners' Capital	6,628,523	7,223,667
Total liabilities and partners' capital	$ 8,791,383	$ 8,684,039

XML

CONSOLIDATED BALANCE SHEET (Parenthetical) - shares	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Investing partners, units outstanding (in shares)	1,018.5	1,018.5

XML

STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS' CAPITAL - USD ($)	Total	Managing Partner	Investing Partners
BEGINNING BALANCE at Dec. 31, 2018	$ 7,501,267	$ 464,186	$ 7,037,081
Increase (Decrease) in Partners' Capital [Roll Forward]
Contributions (Distributions)	(2,963)	(2,963)
Net income (loss)	(9,280)	30,385	(39,665)
ENDING BALANCE at Dec. 31, 2019	7,489,024	491,608	6,997,416
Increase (Decrease) in Partners' Capital [Roll Forward]
Contributions (Distributions)	67,627	67,627
Net income (loss)	(332,984)	(35,828)	(297,156)
ENDING BALANCE at Dec. 31, 2020	7,223,667	523,407	6,700,260
Increase (Decrease) in Partners' Capital [Roll Forward]
Contributions (Distributions)	61,587	61,587
Net income (loss)	(656,731)	(103,179)	(553,552)
ENDING BALANCE at Dec. 31, 2021	$ 6,628,523	$ 481,815	$ 6,146,708

XML

ORGANIZATION

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION

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.

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. 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.

Apache is the managing partner of the Investment Partnership and the general partner of the Operating Partnership, and held approximately five percent of the 1,018.5 Units outstanding at December 31, 2021. As used hereafter, the term “Partnership” refers to the Investment Partnership or the Operating Partnership, as the case may be.

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 an 85 percent interest in offshore properties 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. As of December 31, 2021, 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 Agreement of the Investment Partnership (the Partnership Agreement), 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.

Notice of Withdrawal

On March 22, 2019, Apache, as the Managing Partner of the Investment Partnership, gave notice of its intention to withdraw as Managing Partner of the Investment Partnership. The notice described the withdrawal process and certain notice periods required by that process. No party assumed the role of Managing Partner within the 120-day notice period specified by the notice of intention to withdraw. Consequently, Apache will oversee the process of winding up and liquidating the business and affairs of the Investment Partnership. Apache has not made a decision as to when it will complete the process to withdraw as Managing Partner.

Right of Presentment

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

On April 26, 2019, the Managing Partner determined that, during the withdrawal and dissolution process noted above, it would be inconsistent with the Managing Partner’s fiduciary duties to purchase (or to cause the Investment Partnership to purchase) outstanding Units from the holders thereof pursuant to the right of presentment provided for in Sections 6.9 through 6.14 of the Partnership Agreement. As a result of this determination by the Managing Partner, pursuant to Section 6.12 of the Partnership Agreement, the right of presentment was terminated for 2019 and future periods. Sections 6.9 through 6.14 have “become null and void and of no further force or effect” as provided in Section 6.12 of the Partnership Agreement.

Prior to terminating the right of presentment, the Investment Partnership had not made a repurchase under the right of presentment since 2008.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 the Investment Partnership and the Operating 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 (Unaudited)) and the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation).

Cash Equivalents

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2021 and 2020, the Partnership had $4.2 million and $4.5 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—Asset Retirement Obligation. 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. The Partnership did not record any write-downs of capitalized costs during 2021, 2020, or 2019. See Note 10—Supplemental Oil and Gas Disclosures (Unaudited) 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

The Partnership applies the provisions of Accounting Standards Codification 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, as Managing Partner of the Partnership, markets the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of revenue. 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. As of December 31, 2021, the carrying amounts of trade accounts receivables approximate fair value because of the short-term nature of these instruments. Receivables from contracts with customers totaled nil and $95,590 as of December 31, 2021 and 2020, 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, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
Oil	$	400,224	$	532,261	$	990,659
Gas	$	52,273	70,999		94,057
NGLs	$	15,941	15,901		15,618
Total Oil and Gas Revenue	$	468,438	$	619,161	$	1,100,334

The Partnership did not have any revenue from non-customers.

Net Income (Loss) Per Investing Unit

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

Income Taxes

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

Receivable from/Payable to Apache Corporation

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

Maintenance and Repairs

Maintenance and repairs are charged to expense as incurred.

XML

COMPENSATION TO AFFILIATES

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

COMPENSATION TO AFFILIATES

COMPENSATION TO AFFILIATES

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

	Total Reimbursed by the Investing Partners for the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business	$	232	$	257	$	263

XML

OIL AND GAS PROPERTIES

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

OIL AND GAS PROPERTIES

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.

	2021		2020		2019
	(In thousands)
Oil and Gas Properties
Balance, beginning of year	$	195,727	$	195,401	$	195,327
Costs incurred during the year:
Development –
Investing Partners	653		293		67
Managing Partner	69		33		7
Balance, end of year	$	196,449	$	195,727	$	195,401

Development costs for 2021 included upward revisions of approximately $671 thousand, primarily related to revised abandonment cost estimates for South Timbalier 295 properties and approximately $51 thousand for recent capital projects accrued at year end. During 2020 and 2019, development costs included upward revisions of approximately $326 thousand and $56 thousand, respectively, for estimated abandonment costs primarily related to revised cost estimates on the Ship Shoal 258/259 properties. Approximately $18 thousand of capital costs were incurred in 2019 for participation in pipeline and recompletion projects at South Timbalier 295.

	Managing Partner		Investing Partners		Total
	(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 2018	$	21,120	$	170,075	$	191,195
Provision	14		250		264
Balance, December 31, 2019	$	21,134	$	170,325	$	191,459
Provision	11		189		200
Balance, December 31, 2020	$	21,145	$	170,514	$	191,659
Provision	10		153		163
Balance, December 31, 2021	$	21,155	$	170,667	$	191,822

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2021, 2020, and 2019 was 35 percent, 32 percent and 24 percent, respectively.

XML

MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

12 Months Ended

Dec. 31, 2021

Risks and Uncertainties [Abstract]

MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

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 QuarterNorth Energy LLC (formerly Fieldwood Energy LLC) accounted for 15 percent, 14 percent and 10 percent of the Partnership’s oil and gas sales for the years 2021, 2020 and 2019, respectively. Approximately 85 percent, 86 percent and 90 percent of the Partnership’s oil and gas sales in 2021, 2020 and 2019, 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.

XML

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTSCertain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. As of December 31, 2021 and December 31, 2020, the carrying amounts of cash, cash equivalents, accounts receivable, and accounts payable were determined to approximate fair value because of the short-term nature or maturity of these instruments.

XML

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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 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.

On August 3, 2020, Fieldwood Energy LLC, the operator of the Partnership’s producing lease, and certain of its affiliated debtors (collectively, Fieldwood) filed for protection under Chapter 11 of the United States Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, Fieldwood separated its ownership in, and operatorship of, the Partnership’s producing lease, together with several of Fieldwood’s other leases, into a standalone company, which will continue to perform Fieldwood’s obligations with respect to the Partnership’s properties. The reorganization of Fieldwood under the plan is not expected to have any material adverse effect on the Partnership’s operations.

With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (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, the 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.

XML

ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2021 and 2020:

	2021		2020
Asset retirement obligation at beginning of year	$	1,384,524	$	1,421,282
Accretion expense	52,858		52,943
Liabilities settled	(294,218)		(415,710)
Revisions in estimated liabilities	670,896		326,009
Asset retirement obligation at end of year	$	1,814,060	$	1,384,524
Less current portion	(450,996)		(526,440)
Asset retirement obligation, long-term	$	1,363,064	$	858,084

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 and platform decommissioning during the periods presented. The current portion of the ARO liability represents the retirement obligation expected to be incurred in the next twelve months.

During 2021, the upward revision in abandonment liabilities primarily represented higher estimated costs and increased inflation assumptions for South Timbalier 295.

Decommissioning and abandonment activities began at Ship Shoal 258/259 upon cessation of the lease in 2018 and were effectively completed in 2021. The lease was relinquished earlier than previously estimated given unplanned third-party pipeline issues and the decision that returning the lease to production was not economical for the Partnership. The operator also experienced challenges related to the plugging of wells and weather-related delays which resulted in revising the field’s estimated abandonment obligation based on projected costs. Both factors contributed to the upward cost revisions to ARO liability estimates

XML

TAX-BASIS FINANCIAL INFORMATION

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

TAX-BASIS FINANCIAL INFORMATION

TAX-BASIS FINANCIAL INFORMATION

A reconciliation of ordinary income for federal income tax reporting purposes to net income under GAAP is as follows:

	2021		2020		2019
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	(801,635)	$	(549,623)	$	(80,046)
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost	38,318		9		113
Dismantlement and abandonment cost	294,218		415,710		347,952
Tax depreciation	27,790		53,908		64,537
	360,326		469,627		412,602
Less: full cost DD&A expense	(162,564)		(200,045)		(264,031)
Less: asset retirement obligation accretion	(52,858)		(52,943)		(77,805)
Net income (loss)	$	(656,731)	(332,984)		(9,280)

The Partnership’s tax basis in net oil and gas properties at December 31, 2021, and 2020 was $3,260,012 and $2,685,573, 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 each of December 31, 2021 and 2020.

A reconciliation of liabilities for federal income tax reporting purposes to liabilities under GAAP is as follows:

	December 31,
	2021		2020
Liabilities for federal income tax purposes	$	348,800	$	75,848
Asset retirement liability	1,814,060		1,384,524
Liabilities under GAAP	$	2,162,860	$	1,460,372

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

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

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 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)

	2021			2020			2019
	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL	Gas
Proved Reserves
Beginning of year	350	26	597	361	27	626	363	29	670
Extensions, discoveries and other additions	—	—	—	—	—	—	—	—	—
Revisions of previous estimates	11	(2)	74	3	—	(1)	15	(1)	(10)
Production	(7)	(1)	(17)	(14)	(1)	(28)	(17)	(1)	(34)
End of year	354	23	654	350	26	597	361	27	626
Proved Developed
Beginning of year	350	26	597	361	27	626	363	29	670
End of year	354	23	654	350	26	597	361	27	626

Oil includes crude oil and condensate.

All the Partnership’s reserves as of December 31, 2021 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 92 percent of the Partnership’s current proved developed reserves on a barrels of oil equivalent basis 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, 2021, 2020, and 2019 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

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

Discounted Future Net Cash Flows Relating to Proved Reserves

	December 31,
	2021		2020		2019
	(In thousands)
Future cash inflows	$	26,244	$	15,329	$	24,158
Future production costs	(6,117)		(5,116)		(5,540)
Future development costs(1)	(5,426)		(3,204)		(3,483)
Net cash flows	14,701		7,009		15,135
10 percent annual discount rate	(6,492)		(2,267)		(4,735)
Discounted future net cash flows	$	8,209	$	4,742	$	10,400

(1) This amount includes estimated abandonment costs.

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

	For the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Sales, net of production costs	$	152	$	(217)	$	(554)
Net change in prices and production costs	6,044		(5,668)		(2,476)
Revisions of quantities	577		43		273
Accretion of discount	474		1,040		1,162
Changes in future development costs(1)	(1,270)		(122)		(39)
Previously estimated development costs incurred during the period	294		492		416
Changes in production rates and other	(2,804)		(1,226)		(5)
	$	3,467	$	(5,658)	$	(1,223)

(1) This amount includes estimated abandonment costs.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Statement Presentation

Statement Presentation

The accompanying consolidated financial statements include the accounts of the Investment Partnership and the Operating Partnership after elimination of intercompany balances and transactions.

Use of Estimates

Use of EstimatesThe 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

Cash Equivalents

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, 2021 and 2020, the Partnership had $4.2 million and $4.5 million, respectively, of cash and cash equivalents.

Oil and Gas Properties

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—Asset Retirement Obligation. 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. The Partnership did not record any write-downs of capitalized costs during 2021, 2020, or 2019.

Asset Retirement Costs and Obligation

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

Revenue Recognition

The Partnership applies the provisions of Accounting Standards Codification 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, as Managing Partner of the Partnership, markets the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of revenue. 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. As of December 31, 2021, the carrying amounts of trade accounts receivables approximate fair value because of the short-term nature of these instruments.

Net Income (Loss) Per Investing Unit

Net Income (Loss) Per Investing Unit

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

Income Taxes

Income Taxes

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

Receivable from / Payable to Apache Corporation

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

Maintenance and repairs are charged to expense as incurred.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Schedule of Disaggregation of Revenue

The table below presents the total oil, gas, and NGLs revenues of the Partnership for the years ended December 31, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
Oil	$	400,224	$	532,261	$	990,659
Gas	$	52,273	70,999		94,057
NGLs	$	15,941	15,901		15,618
Total Oil and Gas Revenue	$	468,438	$	619,161	$	1,100,334

XML

COMPENSATION TO AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Schedule of Compensation and Reimbursement for Costs and Expenses

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

	Total Reimbursed by the Investing Partners for the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business	$	232	$	257	$	263

XML

OIL AND GAS PROPERTIES (Tables)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Schedule of Direct Cost Information

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.

	2021		2020		2019
	(In thousands)
Oil and Gas Properties
Balance, beginning of year	$	195,727	$	195,401	$	195,327
Costs incurred during the year:
Development –
Investing Partners	653		293		67
Managing Partner	69		33		7
Balance, end of year	$	196,449	$	195,727	$	195,401

Schedule of Changes in Partnership's Oil and Gas Properties

	Managing Partner		Investing Partners		Total
	(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 2018	$	21,120	$	170,075	$	191,195
Provision	14		250		264
Balance, December 31, 2019	$	21,134	$	170,325	$	191,459
Provision	11		189		200
Balance, December 31, 2020	$	21,145	$	170,514	$	191,659
Provision	10		153		163
Balance, December 31, 2021	$	21,155	$	170,667	$	191,822

XML

ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Changes to Partnership's Asset Retirement Obligation Liability

The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2021 and 2020:

	2021		2020
Asset retirement obligation at beginning of year	$	1,384,524	$	1,421,282
Accretion expense	52,858		52,943
Liabilities settled	(294,218)		(415,710)
Revisions in estimated liabilities	670,896		326,009
Asset retirement obligation at end of year	$	1,814,060	$	1,384,524
Less current portion	(450,996)		(526,440)
Asset retirement obligation, long-term	$	1,363,064	$	858,084

XML

TAX-BASIS FINANCIAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Reconciliation of Ordinary Income for Federal Income Tax Reporting Purposes

A reconciliation of ordinary income for federal income tax reporting purposes to net income under GAAP is as follows:

	2021		2020		2019
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	(801,635)	$	(549,623)	$	(80,046)
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost	38,318		9		113
Dismantlement and abandonment cost	294,218		415,710		347,952
Tax depreciation	27,790		53,908		64,537
	360,326		469,627		412,602
Less: full cost DD&A expense	(162,564)		(200,045)		(264,031)
Less: asset retirement obligation accretion	(52,858)		(52,943)		(77,805)
Net income (loss)	$	(656,731)	(332,984)		(9,280)

Schedule of Reconciliation of Liabilities for Federal Income Tax Reporting Purposes

A reconciliation of liabilities for federal income tax reporting purposes to liabilities under GAAP is as follows:

	December 31,
	2021		2020
Liabilities for federal income tax purposes	$	348,800	$	75,848
Asset retirement liability	1,814,060		1,384,524
Liabilities under GAAP	$	2,162,860	$	1,460,372

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Schedule 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)

	2021			2020			2019
	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL	Gas
Proved Reserves
Beginning of year	350	26	597	361	27	626	363	29	670
Extensions, discoveries and other additions	—	—	—	—	—	—	—	—	—
Revisions of previous estimates	11	(2)	74	3	—	(1)	15	(1)	(10)
Production	(7)	(1)	(17)	(14)	(1)	(28)	(17)	(1)	(34)
End of year	354	23	654	350	26	597	361	27	626
Proved Developed
Beginning of year	350	26	597	361	27	626	363	29	670
End of year	354	23	654	350	26	597	361	27	626

Schedule of Discounted Future Net Cash Flows Relating to Proved Reserves

Discounted Future Net Cash Flows Relating to Proved Reserves

	December 31,
	2021		2020		2019
	(In thousands)
Future cash inflows	$	26,244	$	15,329	$	24,158
Future production costs	(6,117)		(5,116)		(5,540)
Future development costs(1)	(5,426)		(3,204)		(3,483)
Net cash flows	14,701		7,009		15,135
10 percent annual discount rate	(6,492)		(2,267)		(4,735)
Discounted future net cash flows	$	8,209	$	4,742	$	10,400

(1) This amount includes estimated abandonment costs.

Schedule of Discounted Future Net Cash Flows

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

	For the Year Ended December 31,
	2021		2020		2019
	(In thousands)
Sales, net of production costs	$	152	$	(217)	$	(554)
Net change in prices and production costs	6,044		(5,668)		(2,476)
Revisions of quantities	577		43		273
Accretion of discount	474		1,040		1,162
Changes in future development costs(1)	(1,270)		(122)		(39)
Previously estimated development costs incurred during the period	294		492		416
Changes in production rates and other	(2,804)		(1,226)		(5)
	$	3,467	$	(5,658)	$	(1,223)

(1) This amount includes estimated abandonment costs.

XML

ORGANIZATION (Detail)		12 Months Ended
	Mar. 22, 2019	Dec. 31, 2021 Venture Lease shares	Dec. 31, 1989 $ / shares	Dec. 31, 1988 $ / shares	Dec. 31, 2020 shares
Schedule Of Organization [Line Items]
Full purchase price (in USD per share)			$ 150,000	$ 150,000
Discount percentage on full purchase price				5.00%
Investor subscription units (in USD per share)			$ 85,000
Investing partners, units outstanding (in shares) | shares		1,018.5			1,018.5
Percentage interest Purchased in offshore leasehold		85.00%
Number of federal lease tracts | Lease		87
Percentage of remaining interest purchased		15.00%
Number of remaining ventures | Venture		1
Working percentage interest		7.08%
Percentage of exploration and development costs incurred paid by Company		10.00%
Percentage of expenses related to loans		1.00%
Notice of intention to withdrawal, notice period	120 days
Apache
Schedule Of Organization [Line Items]
Percentage share held in partnership		5.00%
Investing Partners
Schedule Of Organization [Line Items]
Percent of revenues		80.00%
Percentage of interest income earned on short term cash investments		100.00%
Percentage of exploration and development costs incurred paid by Partners		90.00%
Percentage of expenses related to loans		99.00%
Percentage of partner's total amount equals to cost		90.00%
Managing Partner
Schedule Of Organization [Line Items]
Percent of revenues		20.00%

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Cash and cash equivalents	$ 4,161,783	$ 4,515,466
Percentage of reserve volumes sold	25.00%
Estimated future net cash flows from proved oil and gas reserves	10.00%
Non-cash write-downs of carrying value of proved oil and gas properties	$ 0	0	$ 0
Receivables from contracts with customers	$ 0	$ 95,590

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Disaggregation of Revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Oil and gas sales	$ 468,438	$ 619,161	$ 1,100,334
Oil
Disaggregation of Revenue [Line Items]
Oil and gas sales	400,224	532,261	990,659
Gas
Disaggregation of Revenue [Line Items]
Oil and gas sales	52,273	70,999	94,057
NGLs
Disaggregation of Revenue [Line Items]
Oil and gas sales	$ 15,941	$ 15,901	$ 15,618

XML

COMPENSATION TO AFFILIATES (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business	$ 232	$ 257	$ 263

XML

OIL AND GAS PROPERTIES - Direct Cost Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Direct Cost Changes In Partnership's Oil And Gas Properties [Roll Forward]
Balance, beginning of year	$ 195,727	$ 195,401	$ 195,327
Development - Investing Partners	653	293	67
Development - Managing Partner	69	33	7
Balance, end of year	$ 196,449	$ 195,727	$ 195,401

XML

OIL AND GAS PROPERTIES - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Development costs, revision of abandonment cost estimates	$ 671		$ 56
Development costs incurred		$ 326
Development costs, capital projects accrued	$ 51		$ 18
DD&A rate as percentage of oil and gas sales	35.00%	32.00%	24.00%

XML

OIL AND GAS PROPERTIES - Changes in Partnership's Oil and Gas Properties (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Depreciation, Depletion and Amortization
Beginning Balance	$ 191,659	$ 191,459	$ 191,195
Provision	163	200	264
Ending Balance	191,822	191,659	191,459
Managing Partner
Accumulated Depreciation, Depletion and Amortization
Beginning Balance	21,145	21,134	21,120
Provision	10	11	14
Ending Balance	21,155	21,145	21,134
Investing Partners
Accumulated Depreciation, Depletion and Amortization
Beginning Balance	170,514	170,325	170,075
Provision	153	189	250
Ending Balance	$ 170,667	$ 170,514	$ 170,325

XML

MAJOR CUSTOMER AND RELATED PARTIES INFORMATION (Detail) - Customer Concentration Risk - Sales	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fieldwood Energy LLC
Revenue, Major Customer [Line Items]
Concentration risk percentage	15.00%	14.00%	10.00%
Chevron Products Company
Revenue, Major Customer [Line Items]
Concentration risk percentage	85.00%	86.00%	90.00%

XML

ASSET RETIREMENT OBLIGATION (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of year	$ 1,384,524	$ 1,421,282
Accretion expense	52,858	52,943	$ 77,805
Liabilities settled	(294,218)	(415,710)
Revisions in estimated liabilities	670,896	326,009
Asset retirement obligation at end of year	1,814,060	1,384,524	1,421,282
Asset retirement obligation at end of year	1,814,060	1,384,524	$ 1,421,282
Less current portion	(450,996)	(526,440)
Asset retirement obligation, long-term	$ 1,363,064	$ 858,084

XML

TAX-BASIS FINANCIAL INFORMATION - Reconciliation of Ordinary Income for Federal Income Tax Reporting Purposes (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Net partnership ordinary income (loss) for federal income tax reporting purposes	$ (801,635)	$ (549,623)	$ (80,046)
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost	38,318	9	113
Dismantlement and abandonment cost	294,218	415,710	347,952
Tax depreciation	27,790	53,908	64,537
Non deductible expenses for federal income tax purposes	360,326	469,627	412,602
Less: full cost DD&A expense	(162,564)	(200,045)	(264,031)
Less: asset retirement obligation accretion	(52,858)	(52,943)	(77,805)
Net income (loss)	$ (656,731)	$ (332,984)	$ (9,280)

XML

TAX-BASIS FINANCIAL INFORMATION - Additional Information (Detail) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Tax bases in net oil and gas properties	$ 3,260,012	$ 2,685,573
Capitalized syndication cost	$ 8,660,878	$ 8,660,878

XML

TAX-BASIS FINANCIAL INFORMATION - Reconciliation of Liabilities for Federal Income Tax Reporting Purposes (Detail) - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Liabilities for federal income tax purposes	$ 348,800	$ 75,848
Asset retirement liability	1,814,060	1,384,524	$ 1,421,282
Liabilities under GAAP	$ 2,162,860	$ 1,460,372

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Proved Reserves and Projecting Future Rates of Production and Timing of Development Expenditures (Detail)	12 Months Ended
	Dec. 31, 2021 MBbls MMcf	Dec. 31, 2020 MBbls MMcf	Dec. 31, 2019 MMcf MBbls
Proved Developed and Undeveloped Reserves [Roll Forward]
Percentage of estimated proved developed reserves classified as proved not producing	92.00%
Oil | Proved Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year	350	361	363
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	11	3	15
Production	(7)	(14)	(17)
End of year	354	350	361
Oil | Proved Developed
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year	350	361	363
End of year	354	350	361
NGLs | Proved Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year	26	27	29
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	(2)	0	(1)
Production	(1)	(1)	(1)
End of year	23	26	27
NGLs | Proved Developed
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year	26	27	29
End of year	23	26	27
Gas | Proved Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year | MMcf	597	626	670
Extensions, discoveries and other additions | MMcf	0	0	0
Revisions of previous estimates | MMcf	74	(1)	(10)
Production | MMcf	(17)	(28)	(34)
End of year | MMcf	654	597	626
Gas | Proved Developed
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of year | MMcf	597	626	670
End of year | MMcf	654	597	626

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil And Gas Disclosures [Abstract]
Future cash inflows	$ 26,244	$ 15,329	$ 24,158
Future production costs	(6,117)	(5,116)	(5,540)
Future development costs	(5,426)	(3,204)	(3,483)
Net cash flows	14,701	7,009	15,135
10 percent annual discount rate	(6,492)	(2,267)	(4,735)
Discounted future net cash flows	$ 8,209	$ 4,742	$ 10,400

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil And Gas Disclosures [Abstract]
Sales, net of production costs	$ 152	$ (217)	$ (554)
Net change in prices and production costs	6,044	(5,668)	(2,476)
Revisions of quantities	577	43	273
Accretion of discount	474	1,040	1,162
Changes in future development costs	(1,270)	(122)	(39)
Previously estimated development costs incurred during the period	294	492	416
Changes in production rates and other	(2,804)	(1,226)	(5)
Total	$ 3,467	$ (5,658)	$ (1,223)