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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, 2019



☐	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 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, 2019, there were 1,022 partnership units of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Apache Corporation’s proxy statement relating to its 2020 annual meeting of stockholders have been incorporated by reference into Part III hereof.

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

	PART III

10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	30
11.	EXECUTIVE COMPENSATION	30
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	30
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	30
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	30

	PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	31
16.	FORM 10-K SUMMARY	31

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.

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 our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2019, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:


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


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


•	pipeline and gathering system capacity 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;


•	legislative, regulatory, or policy changes, including environmental regulation;


•	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.

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

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.

The Investment Partnership does not maintain its own website. However, copies of this Form 10-K and the Investment Partnership’s periodic filings with the Securities and Exchange Commission (SEC) can be found on the Managing Partner’s website at www.apachecorp.com/Offshore_Investment_Partnership. The Investment Partnership will also provide paper copies of these filings, free of charge, to anyone so requesting. Included in the Investment Partnership’s Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q are the certifications of the Managing Partners’ principal executive officer and principal financial officer that are required by applicable laws and regulations. Any requests to the Partnership for copies of documents filed with the SEC should be made by mail to Apache Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas 77056, Attention: Investor Relations, or by telephone at 1-281-302-2286. Reports filed with the SEC are also made available on its website at www.sec.gov.

The Investing Partners purchased Units of Partnership Interests (Units) in the Investment Partnership at $150,000 per Unit, with five percent down and the balance in payments as called by the Investment Partnership. As of December 31, 2019, 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, 2019, 48 of those prospects have been surrendered or sold. As of December 31, 2019, the Partnership had 17 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.

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 allocable to the Partnership.

2019 Results and Business Development

The Partnership reported a net loss for 2019 of approximately $9 thousand, or approximately $39 per Investing Partner Unit. This represents a decrease of approximately $280 thousand from the $271 thousand net income reported in 2018. The decrease in net income compared to the prior year was primarily related to declining crude oil and natural gas production and lower realized prices for all products during 2019. The Partnership’s average realized crude oil prices decreased 13 percent from a year ago to $57.10 per barrel, while gas prices decreased 17 percent from 2018 to $2.73 per Mcf. Oil production averaged 48 barrels of oil per day in 2019, down 9 percent from 2018. Natural gas production averaged 94 Mcf per day in 2019, down 7 percent from 2018. The Partnership’s reduction in 2019 production was primarily the result of natural decline.

During 2019, the Partnership’s cash outlays for capital expenditures totaled approximately $18 thousand, primarily for completion of a pipeline project at South Timbalier 295. The Partnership did not participate in any new drilling projects during the year. Based on preliminary information available to the Partnership, it anticipates that 2020 capital expenditures will remain at similarly reduced levels.

Approximately $398 thousand of cash outlays were made during 2019 on abandonment and decommissioning activities at Ship Shoal 258/259 and North Padre Island 969/976. The Company estimates an additional, approximate $614 thousand of short-term abandonment and decommissioning activity for these areas in 2020. The abandonment activity at North Padre Island 969/976 was originally scheduled to be completed prior to 2018, but was deferred to 2019 when work began during the middle of the year. Abandonment activity at Ship Shoal 258/259 began upon cessation of the lease in 2018 and is expected to be completed in 2020. Such estimates may change based on realized oil and gas prices, rates charged by contractors, or changes by the operator to their development or abandonment plans.

The Partnership had estimated proved oil and gas reserves of 492,246 barrels of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas, at December 31, 2019.

For a more in-depth discussion of the Partnership’s 2019 results and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Marketing

The Partnership has historically marketed its oil and gas production under the joint operating agreements with the operators of its properties. Beginning in 2016, Apache, as Managing Partner of the Partnership, began marketing the Partnership’s share of oil production from South Timbalier 295, the Partnership’s largest source of production. The third-party operator continued to market all other production of the Partnership. The change in Apache’s marketing of oil production from South Timbalier 295 was made to improve the timing of cash receipts and reduce the credit risk from third-party purchasers and remitters. Apache primarily markets to major oil companies, marketing and transportation companies, and refiners at current index prices, adjusted for quality, transportation, and market-reflective differentials.

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

For a more in-depth discussion of the Partnership’s significant customers, see Note 5 — “Major Customer and Related Parties Information” to the Partnership’s financial statements under Item 8 of this Form 10-K. Because the Partnership’s oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse effect on the Partnership’s business or results of operations.

Environmental Compliance

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

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

ITEM 1A. RISK FACTORS

As a “smaller reporting company,” we are 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 our business, including those risk factors contained in our 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. Our 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

As of December 31, 2019, the Partnership did not have any unresolved comments from the staff of the SEC.


ITEM 2.	PROPERTIES

Acreage

Acreage is held by the Partnership pursuant to the terms of 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, 2019, 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, 2019, the Partnership did not have an interest in any undeveloped acreage.

The Partnership’s developed acreage on its Ship Shoal 258/259 lease block expired during the first quarter of 2018. The third-party operator determined that it was uneconomical to bring production back on-line after continued pipeline interruptions and production downtime. Upon lease expiration, approximately 10,141 gross acres and 638 net acres were relinquished and abandonment activities have commenced.

Productive Oil and Gas Wells

The number of productive oil and gas wells in which the Partnership had an interest as of December 31, 2019, is set forth below:



		Gas		Oil
Lease Block	State	Gross	Net	Gross	Net
South Timbalier 276, 295, 296	LA	1	0.07	16	1.13

Net Wells Drilled

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

Production, Pricing and Lease Operating Cost Data

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



	Production			Average Lease Operating Cost per Mcfe		Average Sales Price
Year Ended December 31,	Oil (Mbbls)	NGLs (Mbbls)	Gas (MMcf)	Average Lease Operating Cost per Mcfe		Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)
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
2018
South Timbalier 295	19	1	37	$	2.56	$	65.36	$	28.63	$	3.27
Other fields	—	—	—	NM		—		—		—
Total	19	1	37	$	3.17	$	65.36	$	28.63	$	3.27
2017
South Timbalier 295	17	1	39	$	3.80	$	48.00	$	22.89	$	3.51
Other fields	—	—	3	8.90		47.44		30.60		3.21
Total	17	1	42	$	3.93	$	48.00	$	23.61	$	3.49

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 natural gas liquids (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.

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

As of December 31, 2019, the Partnership had total estimated proved reserves of 360,527 barrels of crude oil and condensate, 27,386 barrels of NGLs and 626 MMcf of natural gas. Combined, these total estimated proved reserves are equivalent to 492,246 barrels of oil. The Partnership has elected not to disclose probable and possible reserves or reserve estimates based upon futures or other prices in this filing.

The following table shows proved oil, NGLs, and gas reserves as of December 31, 2019, based on commodity average prices in effect on the first day of each month in 2019, 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	361	27	626
Proved undeveloped	—	—	—
Total proved	361	27	626

The Partnership’s estimates of proved reserves and proved developed reserves at December 31, 2019, 2018, and 2017, 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 2019 Consolidated Financial Statements under Item 8 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and average commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms.

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

The Partnership’s estimate of proved oil and gas reserves is prepared by Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. A copy of Ryder Scott’s report on the Shell Offshore Venture, of which the Partnership owned 100 percent at December 31, 2019, 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

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

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II


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

As of December 31, 2019, there were 1,021.5 Units outstanding held by 926 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 2019, 2018, or 2017.

As further discussed in Item 7, 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

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


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 of this Form 10-K. This section of this Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 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 2018 Annual Report on Form 10-K filed with the SEC on March 1, 2019.

The Partnership derives its revenue from the production and sale of crude oil, natural gas and natural gas liquids (NGLs). With only modest levels of production from current wells, the Partnership sells its production at market prices and has not used derivative financial instruments or otherwise engaged in hedging activities. Prices in recent years have remained volatile and this volatility has caused the Partnership’s revenues and resulting cash flow from operating activities to fluctuate significantly. During 2019, the Partnership’s average realized oil price decreased 13 percent from 2018, while natural gas prices decreased 17 percent. Given the small number of producing wells owned by the Partnership and exposure to inclement weather and pipeline interruptions in the Gulf of Mexico, the Partnership’s production outlook for 2020 and beyond may be subject to more volatility than those companies with a larger or more diversified property portfolio. Extended downtime of the Partnership’s producing properties could materially impact any anticipated revenues, earnings and cash flow.

The Partnership participates in workover and recompletion activities as recommended by the operators of the properties in which the Partnership owns an interest. During 2019, the Partnership had minimal cash outlays for oil and gas property additions and did not participate in any new drilling projects. The Partnership’s primary cash outlay for 2019 was related to decommissioning and abandonment activities at Ship Shoal 258/259 and North Padre Island 969/976. The abandonment activity at North Padre Island 969/976 was originally scheduled to be completed prior to 2018, but was deferred to mid-2019. Abandonment activity at Ship Shoal 258/259 began upon cessation of the lease in 2018 and is expected to be completed in 2020.

Because of continued declines in production levels, lower 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 2019. 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 2020.

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 2019 and 2018.

Net Income and Revenue

The Partnership reported a net loss of approximately $9 thousand for 2019. This represents a decrease of approximately $280 thousand from the $271 thousand of net income reported for 2018. On a per Investing Partner Unit basis, the Partnership reported a net loss of approximately $39 per Unit in 2019 compared to net income of $170 per Unit in 2018. The decrease in net income was primarily related to declining crude oil and natural gas production and lower realized prices for all products during 2019.

Total revenues in 2019 of approximately $1.2 million decreased approximately $291 thousand, or 19 percent, from 2018 on lower realized commodity prices and lower production, primarily the result of natural depletion and a shut-in of two wells for repairs at South Timbalier 295 during the third quarter of 2019.

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

The Partnership’s oil, gas and NGL production volume and price information is summarized in the following table (gas volumes are presented in thousand cubic feet (Mcf) per day):



	For the Year Ended December 31,
	2019		Increase (Decrease)		2018		Increase (Decrease)		2017
Gas volume – Mcf per day	94		(7	)%	101		(11	)%	114
Average gas price – per Mcf	$	2.73	(17	)%	$	3.27	(6	)%	$	3.49
Oil volume – barrels per day	48		(9	)%	53		15	%	46
Average oil price – per barrel	$	57.10	(13	)%	$	65.36	36	%	$	48.00
NGL volume – barrels per day	3		(25	)%	4		33	%	3
Average NGL price – per barrel	$	15.48	(46	)%	$	28.63	21	%	$	23.61

Oil and Gas Sales

The Partnership’s crude oil sales in 2019 totaled approximately $991 thousand, down 21 percent from 2018 on lower realized prices and declining production. Oil production was down approximately 9 percent from the prior year, primarily the result of natural depletion and shut-in of two South Timbalier wells for repairs during the third quarter of 2019. The Partnership’s average realized oil price in 2019 was lower by 13 percent compared to 2018, decreasing to $57.10 per barrel in 2019.

Natural gas sales in 2019 decreased 22 percent from a year ago, totaling approximately $94 thousand on depleting production and lower realized natural gas prices.

The Partnership sold 3 barrels per day of natural gas liquids in 2019, down from 4 barrels per day in 2018 on natural depletion. Total NGL sales decreased approximately 63 percent from the prior year to approximately $16 thousand. The decrease was driven by NGL prices falling 46 percent from 2018, to $15.48 per barrel.

Operating Expenses

The Partnership’s depreciation, depletion and amortization (DD&A), expressed as a percentage of oil and gas sales, increased to approximately 24 percent in 2019 from approximately 21 percent in 2018. The dollar amount of recurring DD&A expense for 2019 decreased 11 percent from the comparable period a year ago as a result of decreased crude oil and natural gas production, which lowered the rate of depletion. For 2019 and 2018, the Partnership recognized asset retirement obligation (ARO) accretion expense of approximately $78 thousand and $97 thousand, respectively, as abandonment activities commenced at Ship Shoal 258/259 and North Padre Island 969/976 and reduced the Partnership’s remaining abandonment liability.

Lease operating expenses (LOE) for 2019 increased 8 percent from the same period a year ago to approximately $530 thousand in 2019. The increase reflects general cost increases in offshore production and higher repair and maintenance work incurred during the year resulting from platform inspections. Gathering and transportation costs for the delivery of oil and gas totaled approximately $16 thousand in 2019, a decrease of 10 percent from the same period a year ago as a result of lower production. Administrative expenses for 2019 increased 2 percent compared to 2018.

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 2019 or 2018. 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, which totaled a cash outflow of approximately $61 thousand for 2019 and a cash inflow of approximately $196 thousand for 2018. The decrease in cash flows from operating activities reflected the impact of lower net income in 2019 due to declining production and lower realized commodity prices compared to 2018. The decrease was slightly offset by lower abandonment spending during 2019 compared to the prior year period.

At December 31, 2019, the Partnership had approximately $5.0 million in cash and cash equivalents, down slightly from the end of 2018. 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 platforms and pipelines and for future recompletion operations.

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

The Partnership’s oil and gas reserves and production will also significantly impact future results of operations and cash from operating activities. The Partnership’s production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can generally be expected in future years as a result of normal depletion and the Partnership’s non-participation in acquisition or exploration activities. Based on available cash, production estimates from independent engineers and current market conditions, the Partnership forecasts it will be able to meet its liquidity needs for routine operations in 2020 and 2021.

Approximately 89 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.

The Partnership may reduce capital expenditures or distributions to partners, or both, to be in-line with cash from operating activities. In the event that future short-term operating cash requirements are greater than the Partnership’s financial resources, the Partnership may seek short-term, interest-bearing advances from the Managing Partner as needed. The Managing Partner, however, is not obligated to make loans to the Partnership. The Partnership does not intend to incur debt from banks or other outside sources or solicit capital from existing Unit holders or in the open market.

On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs. The Partnership did not sell any properties in 2019 or 2018.

Capital Commitments

The Partnership’s primary needs for cash are for operating expenses, recompletion expenditures, future dismantlement and abandonment costs, and distributions to Investing Partners. 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, 2019. The Partnership did not have any contractual obligations as of December 31, 2019, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for this asset retirement obligation as discussed in the notes to the financial statements included in this Annual Report on Form 10-K.

During each of the last three years, the Partnership had modest cash outlays for oil and gas property additions as it did not participate in any new drilling projects. The Partnership paid cash settlements for ARO liabilities totaling approximately $398 thousand in 2019 and approximately $430 thousand in 2018.

Based on preliminary information available to the Partnership, it anticipates minimal 2020 capital expenditure levels for recompletions and other capital projects at South Timbalier 295. Additionally, $614 thousand is estimated to be spent in 2020 to perform decommissioning activities at Ship Shoal 258/259 and to remove idle 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 low oil and gas prices, pipeline interruptions to production, and the need to reserve cash for future asset retirement obligations, no distributions were made to Investing Partners during 2019 or 2018.

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 2020.

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, 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 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 of partnership interests (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.

The Investment Partnership has 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 any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership.

Insurance

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

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

Critical Accounting Policies and Estimates

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

Reserve Estimates

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

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

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of production, except where prices are defined by contractual arrangements.

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

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

Asset Retirement Obligation (ARO)

The Partnership has obligations to remove tangible equipment and restore the land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership’s limited operations and estimate of remaining reserves. The Partnership’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable. This liability is offset by a corresponding increase in the carrying amount of the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with 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,” we are not required to provide the information required by this Item. We have chosen to disclose, however, that we have 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.


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	14

Statement of Consolidated Operations for each of the three years in the period ended December 31, 2019	15

Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2019	16

Consolidated Balance Sheet as of December 31, 2019 and 2018	17

Statement of Consolidated Changes in Partners’ Capital for each of the three years in the period ended December 31, 2019	18

Notes to Consolidated Financial Statements	19

Supplemental Oil and Gas Disclosures (Unaudited)	26

Supplemental Quarterly Financial Data (Unaudited)	28

Schedules –

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

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Partnership is responsible for the preparation and integrity of the consolidated financial statements appearing in this Annual Report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.

Management of the Partnership is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (Exchange Act). The Partnership’s and Managing Partner’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by the Managing Partner’s board of directors, applicable to all the Managing Partner’s directors, officers and employees.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2019. 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, 2019.

/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 27, 2020

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ ERNST & YOUNG LLP

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

Houston, Texas

February 27, 2020

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED OPERATIONS



	For the Year Ended December 31,
	2019			2018		2017
REVENUES:
Oil and gas sales	$	1,100,334		$	1,416,934	$	976,395
Interest income	106,787			81,368		32,104
	1,207,121			1,498,302		1,008,499
EXPENSES:
Depreciation, depletion and amortization
Recurring	264,031			297,328		261,228
Asset retirement obligation accretion	77,805			96,832		105,135
Lease operating expenses	530,206			492,713		581,718
Gathering and transportation costs	15,823			17,493		2,495
Administrative	328,536			323,200		315,392
	1,216,401			1,227,566		1,265,968
NET INCOME (LOSS)	$	(9,280	)	$	270,736	$	(257,469	)
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	$	30,385		$	96,704	$	(5,899	)
Investing Partners	(39,665		)	174,032		(251,570		)
	$	(9,280	)	$	270,736	$	(257,469	)
NET INCOME (LOSS) PER INVESTING PARTNER UNIT	$	(39	)	$	170	$	(246	)
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING	1,021.5			1,021.5		1,021.5

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CASH FLOWS



	For the Year Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(9,280	)	$	270,736		$	(257,469	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	264,031			297,328			261,228
Asset retirement obligation accretion	77,805			96,832			105,135
Changes in operating assets and liabilities:
Accrued revenues receivable	11,423			(27,235		)	30,211
Receivable from/payable to Apache Corporation	6,517			(2,329		)	8,200
Accrued operating expenses	(14,414		)	(9,441		)	3,641
Asset retirement expenditures	(397,542		)	(429,502		)	(12,259		)
Net cash provided by (used in) operating activities	(61,460		)	196,389			138,687
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(18,481		)	(158,444		)	(36,115		)
Net cash used in investing activities	(18,481		)	(158,444		)	(36,115		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from Managing Partner	—			—			—
Distributions to Managing Partner	(2,963		)	(52,094		)	(20,755		)
Net cash provided by (used in) financing activities	(2,963		)	(52,094		)	(20,755		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(82,904		)	(14,149		)	81,817
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	5,103,336			5,117,485			5,035,668
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	5,020,432		$	5,103,336		$	5,117,485

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

CONSOLIDATED BALANCE SHEET



	December 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,020,432		$	5,103,336
Accrued revenues receivable	108,693			120,116
	5,129,125			5,223,452
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties	195,401,395			195,327,296
Less – Accumulated depreciation, depletion and amortization	(191,459,215		)	(191,195,184		)
	3,942,180			4,132,112
	$	9,071,305		$	9,355,564
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation	$	7,589		$	1,072
Current asset retirement obligation	614,493			390,000
Accrued operating expenses	77,000			91,414
Accrued development costs	76,410			125,999
	775,492			608,485
ASSET RETIREMENT OBLIGATION	806,789			1,245,812
PARTNERS’ CAPITAL:
Managing Partner	491,608			464,186
Investing Partners (1,021.5 units outstanding)	6,997,416			7,037,081
	7,489,024			7,501,267
	$	9,071,305		$	9,355,564

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS’ CAPITAL



	Managing Partner			Investing Partners			Total
BALANCE, DECEMBER 31, 2016	$	446,230		$	7,114,619		$	7,560,849
Distributions	(20,755		)	—			(20,755		)
Net loss	(5,899		)	(251,570		)	(257,469		)
BALANCE, DECEMBER 31, 2017	$	419,576		$	6,863,049		$	7,282,625
Distributions	(52,094		)	—			(52,094		)
Net income	96,704			174,032			270,736
BALANCE, DECEMBER 31, 2018	$	464,186		$	7,037,081		$	7,501,267
Distributions	(2,963		)	—			(2,963		)
Net income	30,385			(39,665		)	(9,280		)
BALANCE, DECEMBER 31, 2019	$	491,608		$	6,997,416		$	7,489,024

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Nature of Operations

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

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 general partner of both the Investment and Operating partnerships, and held approximately five percent of the 1,021.5 Units outstanding at December 31, 2019. 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, 2019, 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.

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 have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. The Partnership did not offer to purchase any Units from Investing Partners in 2018, or 2017 as a result of the limited amount of cash available for discretionary purposes.

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 of partnership interests (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.

The Investment Partnership has 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 Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions.

Use of Estimates

The preparation of financial statements in conformity with GAAP and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom (see Note 10—Supplemental Oil and Gas Disclosures (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, 2019 and 2018, the Partnership had $5.0 million and $5.1 million, respectively, of cash and cash equivalents.

Oil and Gas Properties

The Partnership follows the full-cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method of accounting, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. All costs related to production and administrative functions are expensed in the period incurred. The Partnership includes the present value of its dismantlement, restoration, and abandonment costs within the capitalized oil and gas property balance as described in Note 8—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.

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 2019, 2018, or 2017. 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 production. Apache primarily markets to major oil companies, marketing and transportation companies, and refiners at current index prices, adjusted for quality, transportation, and market reflective differentials. The Partnership markets all other production under the joint operating agreements with the operator of its properties. The operator seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. These contracts provide for sales that are priced at prevailing market prices.

The Partnership records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Partnership routinely assesses the collectability of all material trade and other receivables. The Partnership accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2019, 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 $108,693 and $120,116 as of December 31, 2019 and 2018, 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, 2019, 2018 and 2017:



	For the Year Ended December 31,
	2019		2018		2017
Oil	$	990,659	$	1,253,490	$	806,620
Gas	94,057		120,763		145,562
NGLs	15,618		42,681		24,213
Total Oil and Gas Revenue	$	1,100,334	$	1,416,934	$	976,395

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Insurance Coverage

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

Net Income (Loss) Per Investing Unit

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

Income Taxes

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

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.

Recently Adopted Accounting Pronouncements

On January 1, 2019, the Partnership adopted Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842),” on a prospective basis. The Partnership elected to adopt two transitional expedients issued by the FASB during 2018: (i) ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02 and (ii) ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period in the consolidated financial statements. Under this transition option, comparative reporting would not be required and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The adoption of ASU 2016-02 did not have an impact on the Partnership’s consolidated financial statements.

3. COMPENSATION TO AFFILIATES

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



	Total Reimbursed by the Investing Partners for the Year Ended December 31,
	2019		2018		2017
	(In thousands)
a. Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business	$	263	$	259	$	252
b. Apache is reimbursed for development overhead costs incurred in the Partnership’s operations. These costs are based on development activities and are capitalized to oil and gas properties	$	—	$	—	$	—

Apache operated certain Partnership properties through September 30, 2013, at which time Fieldwood Energy LLC purchased Apache’s interest in South Timbalier 295 and Ship Shoal 258/259 and became operator of these properties. Billings to the Partnership were made on the same basis as to unaffiliated third parties or at prevailing industry rates.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. OIL AND GAS PROPERTIES

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



	2019		2018		2017
	(In thousands)
Oil and Gas Properties
Balance, beginning of year	$	195,327	$	195,005	$	194,893
Costs incurred during the year:
Development –
Investing Partners	67		291		104
Managing Partner	7		31		8
Balance, end of year	$	195,401	$	195,327	$	195,005

Development costs for 2019 and 2018 included upward revisions of approximately $56 thousand and $305 thousand, respectively, for estimated abandonment costs primarily related to revised cost estimates on its Ship Shoal 258/259 properties. Development costs for 2017 include negative revision of approximately $66 thousand for estimated abandonment costs and the deferral of final platform decommissioning at North Padre Island 969/976. Approximately $18 thousand, $17 thousand, and $178 thousand of capital costs were incurred in 2019, 2018, and 2017, respectively, 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, 2016	$	21,091	$	169,546	$	190,637
Provision	13		248		261
Balance, December 31, 2017	$	21,104	$	169,794	$	190,898
Provision	16		281		297
Balance, December 31, 2018	$	21,120	$	170,075	$	191,195
Provision	14		250		264
Balance, December 31, 2019	$	21,134	$	170,325	$	191,459

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2019, 2018, and 2017 was 24 percent, 21 percent and 27 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 Fieldwood Energy LLC accounted for 10 percent, 12 percent and 18 percent of the Partnership’s oil and gas sales for the years 2019, 2018 and 2017, respectively. Approximately 90 percent, 88 percent and 82 percent of the Partnership’s oil and gas sales in 2019, 2018 and 2017, respectively, were to Chevron Products Company.

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. FAIR VALUE MEASUREMENTS

Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. As of December 31, 2019 and December 31, 2018, 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.

With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued Notice to Lessees (NTL) No. 2016-N01 pertaining to the obligations of companies to provide supplemental assurances for performance with respect to plugging, abandonment, decommissioning, and site clearance obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. Under this NTL, implementation of which is currently suspended and which may be revised by the BOEM, the Partnership may be required to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Partnership’s current ownership interests in various Gulf of Mexico leases. The Partnership will likely satisfy such requirements through the provision of bonds or other forms of security.

8. ASSET RETIREMENT OBLIGATION

The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2019 and 2018:



	2019			2018
Asset retirement obligation at beginning of year	$	1,635,812		$	1,789,267
Accretion expense	77,805			96,832
Liabilities settled	(347,952		)	(555,500		)
Revisions in estimated liabilities	55,617			305,213
Asset retirement obligation at end of year	$	1,421,282		$	1,635,812
Less current portion	(614,493		)	(390,000		)
Asset retirement obligation, long-term	$	806,789		$	1,245,812

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.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Decommissioning and abandonment activities began at Ship Shoal 258/259 upon cessation of the lease in 2018 and are expected to be completed during 2020. The lease was relinquished earlier than previously estimated given unplanned third-party pipeline issues and the decision that returning the lease to production was uneconomic. The operator also experienced challenges related to the plugging of wells which resulted in revising the field’s estimated abandonment obligation based on projected costs. Both factors contributed to the upward cost revisions to previous ARO liability estimates.

9. TAX-BASIS FINANCIAL INFORMATION

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



	2019			2018			2017
Net partnership ordinary income (loss) for federal income tax reporting purposes	$	(80,046	)	$	(196,919	)	$	5,948
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost	113			16,859			33,479
Dismantlement and abandonment cost	347,952			555,501			2,849
Tax depreciation	64,537			289,455			66,618
	412,602			861,815			102,946
Less: full cost DD&A expense	(264,031		)	(297,328		)	(261,228		)
Less: asset retirement obligation accretion	(77,805		)	(96,832		)	(105,135		)
Net income (loss)	$	(9,280	)	$	270,736		$	(257,469	)

The Partnership’s tax basis in net oil and gas properties at December 31, 2019, and 2018 was $2,505,692 and $2,649,454, respectively, lower than the carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2019, and 2018.

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



	December 31,
	2019		2018
Liabilities for federal income tax purposes	$	160,999	$	218,485
Asset retirement liability	1,421,282		1,635,812
Liabilities under accounting principles generally accepted in the United States	$	1,582,281	$	1,854,297

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Reserve Information

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)



	2019						2018						2017
	Oil		NGL		Gas		Oil		NGL		Gas		Oil		NGL		Gas
Proved Reserves
Beginning of year	363		29		670		376		54		1,016		365		53		985
Extensions, discoveries and other additions	—		—		—		—		—		—		—		—		—
Revisions of previous estimates	15		(1	)	(10	)	6		(24	)	(309	)	28		2		73
Production	(17	)	(1	)	(34	)	(19	)	(1	)	(37	)	(17	)	(1	)	(42	)
End of year	361		27		626		363		29		670		376		54		1,016
Proved Developed
Beginning of year	363		29		670		376		54		1,016		365		53		985
End of year	361		27		626		363		29		670		376		54		1,016

Oil includes crude oil and condensate.

All the Partnership’s reserves as of December 31, 2019 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 89 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, 2019, 2018, and 2017 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

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

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Discounted Future Net Cash Flows Relating to Proved Reserves



	December 31,
	2019			2018			2017
	(In thousands)
Future cash inflows	$	24,158		$	28,707		$	25,968
Future production costs	(5,540		)	(5,937		)	(7,808		)
Future development costs⁽¹⁾	(3,483		)	(3,831		)	(3,957		)
Net cash flows	15,135			18,939			14,203
10 percent annual discount rate	(4,735		)	(7,316		)	(5,971		)
Discounted future net cash flows	$	10,400		$	11,623		$	8,232

(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,
	2019			2018			2017
	(In thousands)
Sales, net of production costs	$	(554	)	$	(907	)	$	(391	)
Net change in prices and production costs	(2,476		)	4,996			2,821
Revisions of quantities	273			(1,820		)	734
Accretion of discount	1,162			823			467
Changes in future development costs⁽¹⁾	(39		)	(257		)	147
Previously estimated development costs incurred during the period	416			584			36
Changes in production rates and other	(5		)	(28		)	(253		)
	$	(1,223	)	$	3,391		$	3,561

(1) This amount includes estimated abandonment costs.

APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)



	First		Second		Third			Fourth			Total
	(In thousands, except per Unit amounts)
2019
Revenues	$	327	$	331	$	255		$	294		$	1,207
Expenses	293		272		279			372			1,216
Net income (loss)	$	34	$	59	$	(24	)	$	(78	)	$	(9	)
Net income allocated to:
Managing Partner	$	15	$	21	$	2		$	(8	)	$	30
Investing Partners	19		38		(26		)	(70		)	(39		)
	$	34	$	59	$	(24	)	$	(78	)	$	(9	)
Net income (loss) per Investing Partner Unit ⁽¹⁾	$	18	$	37	$	(26	)	$	(68	)	$	(39	)
2018
Revenues	$	368	$	376	$	406		$	348		$	1,498
Expenses	320		310		290			307			1,227
Net income	$	48	$	66	$	116		$	41		$	271
Net income allocated to:
Managing Partner	$	23	$	25	$	33		$	16		$	97
Investing Partners	25		41		83			25			174
	$	48	$	66	$	116		$	41		$	271
Net income per Investing Partner Unit ⁽¹⁾	$	25	$	41	$	81		$	23		$	170


(1)	The sum of the individual net income per Investing Partner Unit may not agree with the year-to-date net income per Investing Partner Unit as each quarterly computation is based on the weighted average number of Investing Partner Units during that period.


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

The financial statements for the fiscal years ended December 31, 2019, 2018 and 2017, 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), and Stephen J. Riney, the Managing Partner’s Executive Vice President and Chief Financial Officer (in his capacity as principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of December 31, 2019, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified under the SEC’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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 14 of this report. This Annual Report does not include an attestation report of the Partnership’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this Annual Report.

Changes in Internal Control Over Financial Reporting

There was no change in the Partnership’s internal controls over financial reporting during the quarter ending December 31, 2019, that has materially affected, or is reasonably likely to materially affect the Partnership’s internal controls over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

All management functions are performed by Apache, the Managing Partner of the Partnership. The Partnership itself has no officers or directors. Information concerning the officers and directors of Apache set forth under the captions “Nominees for Election as Directors,” “Information About Our Executive Officers,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the 2020 annual meeting of stockholders of Apache (the Apache Proxy Statement) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 5610 of the NASDAQ, Apache was required to adopt a code of business conduct and ethics for its directors, officers, and employees. In February 2004, Apache’s Board of Directors adopted a Code of Business Conduct and Ethics (Code of Conduct), and revised it in September 2017. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access Apache’s Code of Conduct on the “Governance” page of Apache’s website at www.apachecorp.com. Changes in and any waivers to the Code of Conduct for Apache’s directors, chief executive officer and certain senior financial officers will be posted on Apache’s website within four business days and maintained for at least twelve months.


ITEM 11.	EXECUTIVE COMPENSATION

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


ITEM 12.	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, 2019. Apache owns a one-percent General Partner interest (15 equivalent Units). To the knowledge of the Partnership, no Investing Partner owns, of record or beneficially, more than five percent of the Partnership’s outstanding Units, except for Apache, as stated above. Apache did not acquire additional Units during the three years covered by these financial statements. Apache’s ownership percentage exceeds five percent due to the decrease in the number of outstanding units resulting from the right of presentment (see Note 1—Organization under Item 8 above).


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

See Note 3—Compensation to Affiliates of the Partnership’s financial statements, under Item 8 above, for information regarding compensation to Apache as Managing Partner. See Note 5—Major Customers and Related Parties Information of the Partnership’s financial statements, under Item 8 above, for amounts paid to subsidiaries of Apache, and for other related party information. The Partnership itself has no directors. Information concerning the directors of Apache set forth under the caption “Director Independence” in the Apache Proxy Statement is incorporated herein by reference.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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

PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



a.	(1)	Financial Statements – See accompanying index to financial statements in Item 8 above.
	(2)	Financial Statement Schedules – See accompanying index to financial statements in Item 8 above.
	(3)	Exhibits
	^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
	^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.
	*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.
*	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.

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 27, 2020	/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 27, 2020

/s/ Stephen J. Riney Stephen J. Riney	Executive Vice President and Chief Financial Officer (principal financial officer)	February 27, 2020

/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Senior Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 27, 2020

/s/ Annell R. Bay Annell R. Bay	Director	February 27, 2020

/s/ Juliet S. Ellis Juliet S. Ellis	Director	February 27, 2020

/s/ Chansoo Joung Chansoo Joung	Director	February 27, 2020

/s/ Rene R. Joyce Rene R. Joyce	Director	February 27, 2020

/s/ John E. Lowe John E. Lowe	Director, Non-Executive Chairman of the Board	February 27, 2020

/s/ William C. Montgomery William C. Montgomery	Director	February 27, 2020

/s/ Amy H. Nelson Amy H. Nelson	Director	February 27, 2020

/s/ Daniel W. Rabun Daniel W. Rabun	Director	February 27, 2020

/s/ Peter A. Ragauss Peter A. Ragauss	Director	February 27, 2020

Exhibit

Exhibit 4.1

DESCRIPTION OF APACHE OFFSHORE INVESTMENT PARTNERSHIP’S
SECURITIES REGISTERED PURSUANT TO SECTION 12 OF
THE SECURITIES EXCHANGE ACT OF 1934

Apache Offshore Investment Partnership, a Delaware general partnership (“AOIP” or the “Partnership”), has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended: partnership units representing limited partner interests in the Partnership (“Partnership Units”).

The following is a summary of the rights of the holders of Partnership Units. This summary should be read in conjunction with, and is qualified in its entirety by, the related provisions of the AOIP Partnership Agreement, dated as of October 31, 1983, as amended by Amendment No. 1 thereto, dated as of February 11, 1994 (the “Partnership Agreement”), and the Apache Offshore Petroleum Limited Partnership Limited Partnership Agreement, dated as of October 31, 1983 (the “Operating Partnership Partnership Agreement” and together with the Partnership Agreement, the “Partnership Agreements”), each of which is incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4.1 is a part; and applicable Delaware law, including the Delaware Revised Uniform Partnership Act (the “DRUPA”) and the Delaware Revised Uniform Limited Partnership Act (the “DRULPA”). Capitalized terms used but not otherwise defined herein have the meanings ascribed to such terms in the Partnership Agreement.

The Partnership Units

The Partnership Units represent limited partner interests in the Partnership that entitle the holders thereof to the rights and privileges specified to Investing Partners in our Partnership Agreement, including the right to participate in Partnership distributions. The Partnership Units are registered pursuant to Section 12(g) of the Exchange Act. As of December 31, 2019, there were 1,021.5 Partnership Units issued and outstanding held by 926 Investing Partners of record. The Partnership has no other class of securities authorized or outstanding. The Partnership Units are not listed for trading on any exchange.

Managing Partner Interest

Apache Corporation, a Delaware corporation (“Apache” or the “Managing Partner”), is the managing partner of the Partnership. The Managing Partner may acquire and hold Partnership Units or other equity securities issued by the Partnership for its own account and become entitled to receive distributions on any such acquired interests. As of December 31, 2019, the Managing Partner held approximately five percent of the Partnership’s issued and outstanding Partnership Units and owned a one-percent General Partner interest in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership (the “Operating Partnership”) of which the Managing Partner is the sole general partner and the Partnership is the sole limited partner. The Partnership’s primary business is to serve as the sole limited partner of the Operating Partnership.

Distributions to Partners

The Managing Partner shall, not less than quarterly, review the accounts of the Partners and shall distribute to the Managing Partner and the Investing Partners holding Partnership Units of record on the date of such distribution any cash that has been allocated to such accounts and is in excess of amounts reasonably needed in the opinion of the Managing Partner in the business of the Partnership. No distributions were made to Investing Partners during 2019, 2018, or 2017.

Under the terms of the Partnership Agreements, the Investing Partners generally receive 80 percent and Apache receives 20 percent of revenue, and the Investing Partners receive 100 percent of the interest income earned on short-term cash investments.

Capital Contributions

The Managing Partner shall not be required to make any contributions to the capital of the Partnership except in the amount of any negative balance in its capital account following any distributions in connection with the liquidation of the Partnership. Upon completion of the Partnership’s last subscription call in November 1989, the Managing Partner released the Investing Partners from all remaining liability for future capital calls.

Voting Rights

The Managing Partner has the sole and exclusive right and power to manage and operate the business of the Partnership. The Investing Partners may, by a vote of Investing Partners holding a majority of the then outstanding Partnership Units (excluding any Partnership Units held by the Managing Partner), either by written actions signed by such Partners or at any special meeting called for the following purposes:


(i)	Remove and replace the Managing Partner, elect a new Managing Partner if a Managing Partner withdraws or is expelled from the Partnership, and in the event of the removal, withdrawal, expulsion, bankruptcy, insolvency, liquidation, or dissolution of the Managing Partner, elect to continue the business of the Partnership with one or more substituted Managing Partners;


(ii)	Amend the Partnership Agreement, provided, however, that no amendment which would have the effect of reducing the interest of any Partner in the assets or revenues of the Partnership or increasing the obligations of any Partner to the Partnership may be made without the consent of the Partner or Partners whose interests or obligations would be affected;


(iii)	Dissolve the Partnership;


(iv)	Approve or disapprove the sale of all or substantially all of the Partnership’s assets; or


(v)	Terminate any contracts for services with the Managing Partner or any of its Affiliates without penalty upon sixty days’ advance written notice.

Additionally, a special meeting of the Partners may be called by the Managing Partner or by Investing Partners holding at least ten percent of the then outstanding Partnership Units (excluding Partnership Units held by the Managing Partner).

The Managing Partner shall not take any action or give any consent permitted or required by the Operating Partnership Partnership Agreement to be taken or given by the Partnership, without first obtaining, in the manner required by the Partnership Agreement, the approval of Investing Partners holding a majority of the then outstanding Partnership Units (excluding any Partnership Units held by the Managing Partner).

No Withdrawal or Dissolution

No Investing Partner may at any time withdraw from the Partnership, except as provided in the Partnership Agreement, and no Investing Partner shall have the right to have the Partnership dissolved or the right to a return of any contribution to the capital of the Partnership.

Withdrawal of Interests

An Investing Partner or assignee thereof that is a partnership of which the Managing Partner is the managing or general partner may, upon the consummation of an exchange offer in which such partnership acquires its interest in the Partnership in exchange for an interest in such partnership and upon written notice to the Managing Partner, request a withdrawal of all of its interest in the Partnership. The Managing Partner shall cause the Partnership to make a transfer to the withdrawing Investing Partner of a pro rata share of the assets (including, in the case of oil and gas properties, undivided fractional interests therein) of the Partnership.

Transfer or Assignment of Partnership Units

Except as set forth below, the interest of an Investing Partner in the Partnership may not be assigned, pledged, mortgaged, sold, or otherwise disposed of, and no Investing Partner shall have the right to substitute an assignee in his or her place.

No Investing Partner may sell or assign Partnership Units except to a member of such Investing Partner’s family or by will, without the prior written consent of the Managing Partner, which consent may be withheld in the Managing Partner’s sole discretion, and in no event shall an assignment of less than one-third of a Partnership Unit be made. Unless admitted as a substituted Investing Partner, any such assignee shall have only the right to receive from the Partnership a share of the profits, or other compensation by way of income, to which his or her assignor would otherwise be entitled, and to share in such net profits and losses, distributions, and other property upon dissolution and liquidation of the Partnership as his or her assignor would otherwise be entitled to receive.

Notice of Managing Partner Withdrawal and Right of Presentment

In accordance with the terms of the Partnership Agreement, the Managing Partner gave notice on March 22, 2019 of its intention to withdraw as Managing Partner of the 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 continue oversee the process of winding up and liquidating the business and affairs of the Partnership.

Rights Upon Liquidation

Upon liquidation of the Partnership, the Managing Partner (or other persons designated by a decree of court) shall liquidate the assets of the Partnership and apply and distribute the proceeds of such liquidation in the following order of priority:


(i)	payment to creditors of the Partnership, other than Partners, in order of priority provided by law;


(ii)	pro rata to Partners in repayment of any loans made by them to the Partnership; and


(iii)	pro rata payment to Partners in the amounts of their respective capital accounts.

Exhibit

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

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (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, 2019, and to the inclusion of our report, dated January 27, 2020, 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.

TBPE Firm Registration No. F-1580

Houston, Texas

February 27, 2020

SUITE 800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 FAX (403) 262-2790

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

Exhibit

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 27, 2020

/s/ John J. Christmann IV
John J. Christmann IV
Chief Executive Officer and President
(principal executive officer) of Apache Corporation, Managing Partner

Exhibit

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 27, 2020

/s/ Stephen J. Riney
Stephen J. Riney
Executive Vice President and Chief Financial Officer
(principal financial officer) of Apache Corporation, Managing Partner

Exhibit

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, 2019, 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 27, 2020

		/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, 2019, 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 27, 2020

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

Exhibit

Apache Corporation

February 11, 2011

Page 1

Exhibit 99.1

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, 2019

/s/ Ali A. Porbandarwala

Ali A. Porbandarwala, P.E.

TBPE License No. 107652

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

January 27, 2020

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, 2019. 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). The results of our third party study, completed on January 17, 2020, are 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, 2019.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2019, 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 that were used in this report. 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.

SUITE 800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 FAX (403) 262-2790

633 17TH STREET, SUITE 1700 DENVER, COLORADO 80202 TEL (303) 339-8110

Apache Corporation – Shell Offshore Venture

January 27, 2020

Page 2

SEC PARAMETERS

Apache Corporation

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests in the

Shell Offshore Venture

As of December 31, 2019



	Proved
	Developed				Total
	Producing		Non-Producing		Proved
Net Reserves
Oil/Condensate – Barrels	36,573		323,953		360,526
Plant Products – Barrels	3,259		24,127		27,386
Gas – MMCF	74		551		625

Income Data
Future Gross Revenue	$	2,492,784	$	21,665,171	$	24,157,955
Deductions	919,914		8,103,568		9,023,482
Future Net Income (FNI)	$	1,572,870	$	13,561,603	$	15,134,473

Discounted FNI @ 10%	$	1,351,336	$	9,049,737	$	10,401,073



	Probable
	Developed		Total
	Producing	Non-Producing	Probable
Net Reserves
Oil/Condensate – Barrels	8,352	26,061	34,413
Plant Products – Barrels	550	1,954	2,504
Gas – MMCF	13	45	58



	Possible
	Developed			Total
	Producing	Non-Producing	Undeveloped	Possible
Net Reserves
Oil/Condensate – Barrels	9,955	9,025	9,858	28,838
Plant Products – Barrels	638	779	748	2,165
Gas – MMCF	15	18	17	50

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 ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Apache.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation – Shell Offshore Venture

January 27, 2020

Page 3

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 93 percent and gas reserves account for the remaining 7 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, 2019
Discount Rate		Total
Percent		Proved

5		$12,453,209
15		$8,816,698
20		$7,577,140
25		$6,593,133

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. There are also certain abandonment costs associated with the proved depleted category and those costs are summarized in the non-producing category in the table above.

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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation – Shell Offshore Venture

January 27, 2020

Page 4

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation – Shell Offshore Venture

January 27, 2020

Page 5

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, probable and possible 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 2019 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 method,

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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 and undeveloped 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 2019. 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 constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce

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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 or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells or locations 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 or locations 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, 2019. 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.

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Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices
North America
	Oil/Condensate	WTI Cushing	$55.69/Bbl	$60.36/bbl
United States	NGLs	Mt. Belvieu Non-Tet Propane	$23.14/Bbl	$23.12/bbl
	Gas	Henry Hub	$2.63/MMBTU	$2.82/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 and possible undeveloped reserves in this report have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2019. 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, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

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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, which

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appears in the December 31, 2019 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.

TBPE Firm Registration No. F-1580

/s/ Ali A. Porbandarwala

Ali A. Porbandarwala, P.E.

TBPE License No. 107652

Senior Vice President

[SEAL]

AAP (FWZ)/pl

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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/Company/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 as the Treasurer for the Houston Chapter.

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 2019 continuing education hours, Mr. Porbandarwala attended 25 hours of formalized training including the 2019 RSC Reserves Conference and/or various 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 10 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 February 19, 2007.

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PETROLEUM RESERVES DEFINITIONS

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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. 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.

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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.

(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.

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(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.

(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.

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(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.

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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.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

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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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS