UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2015

OR

For the transition period from                      to                     

Commission File Number: 0-13546

APACHE OFFSHORE INVESTMENT PARTNERSHIP

(Exact name of registrant as specified in its charter)

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

(Address of principal executive offices)

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

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

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

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

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED INCOME

(Unaudited)

The accompanying notes to consolidated financial statements

are an integral part of this statement.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)

The accompanying notes to consolidated financial statements

are an integral part of this statement.

2

APACHE OFFSHORE INVESTMENT PARTNERSHIP

CONSOLIDATED BALANCE SHEET

(Unaudited)

The accompanying notes to consolidated financial statements

are an integral part of this statement.

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APACHE OFFSHORE INVESTMENT PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 the 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 accompanying financial statements include the accounts of both the Investment Partnership and the Operating Partnership. The term “Partnership”, as used herein, refers to the Investment Partnership or the Operating Partnership, as the case may be.

These financial statements have been prepared by the Partnership, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been omitted pursuant to such rules and regulations, although the Partnership believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

As of September 30, 2015, the Partnership’s significant accounting policies are consistent with those discussed in Note 2 of its consolidated financial statements contained in the Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and related present value estimates of future net cash flow therefrom and asset retirement obligations. Actual results could differ from those estimates.

New Pronouncements Issued But Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB announced a delay in the effective date of the revenue standard by one year. The deferral results in the new revenue standard becoming effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Partnership is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

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The receivable from/payable to Apache represents the net result of the Investing Partners’ revenue received and expenditures paid 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.

As provided in the Partnership Agreement, as amended (the “Amended Partnership Agreement”), a first right of presentment valuation was computed during the first quarter of 2015. The per-unit value was determined to be $9,765 based on the valuation date of December 31, 2014. A second right of presentment valuation was computed during October 2015 and the per-unit value was determined to be $9,831 based on a valuation date of June 30, 2015. The Partnership did not repurchase any Investing Partner Units (Units) during the first nine months of 2015, and is not expected to purchase any Units in the fourth quarter of 2015. The per-unit right of presentment value computed during the first quarter of 2014 was determined to be $16,020 based on the valuation date of December 31, 2013, and the second per-unit right of presentment in 2014 was $16,260 based on a valuation date of June 30, 2014. The Partnership did not repurchase any Units during the first nine months of 2014. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to purchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

The following table describes the changes to the Partnership’s asset retirement obligation liability for the first nine months of 2015:

Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. As of September 30, 2015, and December 31, 2014, the carrying amounts of the Partnership’s current assets and current liabilities approximated fair value because of the short-term nature or maturity of these instruments.

The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the nine months ended September 30, 2015, and 2014.

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This discussion relates to Apache Offshore Investment Partnership (the Partnership) and should be read in conjunction with the Partnership’s consolidated financial statements and accompanying notes included under Part I, Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, as well as its consolidated financial statements, accompanying notes and related Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

The Partnership’s business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas.

Financial Overview

The Partnership reported a net loss of $136,865 ($132 per Limited Partner Unit) for the third quarter of 2015 compared to net income of $266,433 ($179 per Limited Partner Unit) in the third quarter of 2014. Earnings for the current quarter were reduced by $82,640 for an anticipated gas balancing settlement with the operator of North Padre Island 969 for gas volumes delivered to the Partnership in excess of its ownership interest entitlement. The operator of the North Padre field is expected to commence abandonment operations on the field later in 2015. Lower oil and gas prices in 2015 also contributed to the decrease in earnings and net income per Investing Partner Unit from 2014.

For the nine months ending September 30, 2015, the Partnership reported a loss of $122,696 ($165 per Unit) compared to net income of $601,795 ($388 per Unit) for the nine months ending September 30, 2014. The decline in earnings and net income per Investing Partner Unit from 2014 reflected the impact of lower oil and gas prices in 2015 and the gas balancing provision recognized in 2015.

Results of Operations

Total revenues decreased 57 percent from the third quarter of 2014 to the third quarter of 2015 on lower oil and gas prices and the North Padre Island gas balancing provision noted above, while year-to-date revenues in 2015 decreased 42 percent from the first nine months of 2014 primarily on lower prices.

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

Oil and Gas Sales

Reflecting lower oil prices in 2015, the Partnership’s crude oil sales for the third quarter of 2015 totaled $335,088 compared to $680,467 of crude oil sales in the third quarter of 2014. The Partnership’s average realized price in the third quarter of 2015 decreased $53.25 per barrel from the third quarter of 2014, reducing sales by $345,379. Crude oil volumes held even at 71 barrels per day as recompletions at South Timbalier 295 offset the impact of depletion.

Natural gas sales in the third quarter of 2015 totaled $71,682 down 23 percent from the amount realized in 2014. The Partnership’s average realized natural gas price for the quarter decreased $1.21 per Mcf, or 29 percent, from the third quarter of 2014, reducing sales by $27,103 from a year ago. Natural gas volumes increased 9 percent from the third quarter of 2014, increasing sales by $6,076. Increased production from recompletions at South Timbalier 295 more than offset productions declines at Ship Shoal 258/259 and North Padre Island 969.

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During the third quarter of 2015, the Partnership sold 14 barrels per day of natural gas liquids, up from the third quarter of 2014 with the increased production at South Timbalier 295. The Partnership’s average NGL price for the current quarter decreased 65 percent from a year ago to $15.97 per barrel.

Crude oil sales for the nine months of 2015 totaled $1.1 million, down 39 percent from the same period in 2014. The Partnership’s average realized oil price for the first nine months of 2015 decreased 47 percent from the first nine months of 2014, dropping to $55.76 per barrel in 2015. The Partnership’s crude oil volumes increased from 63 barrels per day during the first nine months of 2014 to 73 barrels per day during the same period of 2015 as a result of recompletions at South Timbalier 295.

Natural gas sales for the first nine months of 2015 decreased 36 percent from a year ago, dropping to $236,594 in the current period from $369,879 during the first nine months of 2014. The Partnership’s average realized gas prices decreased from $4.91 per Mcf in the first nine months of 2014 to $2.88 per Mcf in 2015, reducing sales by $152,857. A 25 Mcf per day, or 9 percent increase in natural gas volumes during the first nine months of 2015 from the same period a year ago increased sales by $19,572. The Partnership’s increase in gas production in 2015 reflected the recompletions at South Timbalier 295.

The Partnership sold 14 barrels per day of natural gas liquids in the first nine months of 2015, up from 9 barrels per day in the first nine months of 2014. The increase reflected higher processed volumes at South Timbalier 295 in 2015. NGL prices for the first nine months decreased 56 percent from a year ago, dropping to $18.15 per barrel in 2015.

Since the Partnership does not anticipate acquiring additional acreage or conducting exploratory drilling on leases in which it currently holds an interest, declines in oil and gas production can be expected in future periods as a result of natural depletion. Also, 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 during the remainder of 2015 and beyond may be subject to more volatility than those companies with a larger or more diversified property portfolio.

On October 4, 2015, Ship Shoal 258/259 was shut-in so that the pipeline company that transports the natural gas and oil from the field could perform maintenance on their system. Approximately four days into the work, the pipeline company experienced an explosion and fire at one of their onshore natural gas facilities. While the Partnership does not anticipate incurring any cost related to repairing the pipeline’s facility, the incident will likely cause the Partnership’s production from the field to be shut-in for an indefinite period of time. The Partnership’s sales from Ship Shoal 258/259 at the end of the third quarter of 2015 averaged approximately 100 Mcf per day of natural gas and a small amount of liquids.

Operating Expenses

The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 31 percent for the third quarter of 2015 and 20 percent for the third quarter of 2014. DD&A, expressed as a percentage of oil and gas sales, for the first nine months of 2015 and 2014 was 26 percent and 20 percent, respectively. The increase in the rate as a percentage of oil and gas sales in 2015 reflected the impact of declining oil and gas prices. The dollar amount of DD&A expense for the first nine months of 2015 decreased from the comparable periods a year ago as a result of lower oil and gas sales in 2015.

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. If commodity prices do not recover significantly from current levels, the Partnership may be required to recognize a non-cash write-down of the carrying value of its oil and gas properties in the fourth quarter of 2015. The Partnership’s full cost ceiling limitation at the end of the current quarter was calculated using a historical 12-month pricing average that included oil prices from the fourth quarter of 2014. These prices were significantly higher than current commodity futures prices.

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The Partnership recognized $32,910 in asset retirement obligation accretion for the third quarter of 2015 compared to $29,413 for the third quarter of 2014. For the nine months ending September 30, 2015, and 2014, the Partnership recognized asset retirement obligation accretion of $97,440 and $93,782, respectively.

Lease operating expenses (LOE) for the third quarter of 2015 of $192,007 decreased 16 percent from the third quarter of 2014 on lower repair costs and the reduced cost resulting from shutting-in North Padre Island 969 and Matagorda Island 681/682. LOE for the first nine months of 2015 was down 20 percent from the same period a year ago, decreasing to $613,421 in the first nine months of 2015. The decline in costs for the first nine months reflected lower repair costs in 2015, and lower costs from the shut-in of North Padre Island 969 and Matagorda Island 681/682. The operators of the properties are delaying discretionary repair work and other costs in light of reduced oil and gas prices and cash flow.

In the third quarter of 2015, gathering and transportation costs for the delivery of oil and gas totaled $33,744. Gathering and transportation costs during the first nine months of 2015 totaled $102,151 compared to $77,281 for the first nine months of 2014. This increase of 32 percent from the same period in 2014 was primarily a result of higher oil, gas, and NGL volumes from South Timbalier 295 in 2015.

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $0.2 million for the first nine months of 2015, down from $0.9 million in the comparable period in 2014 as a result of lower oil and gas prices which negatively impacted the Partnership’s 2015 earnings and higher cash outlays for abandonment activities in 2015.

At September 30, 2015, the Partnership had approximately $5.4 million in cash and cash equivalents, up from approximately $5.3 million at December 31, 2014. The Partnership’s goal is to maintain cash and cash equivalents at least sufficient to cover the undiscounted value of its future asset retirement obligation liability. The Partnership also plans to reserve funds for repairs which may disrupt the Partnership’s production and for future recompletion operations.

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

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

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.

On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs.

Capital Commitments

The Partnership’s primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. To the extent there is 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 September 30, 2015. The Partnership did not have any

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contractual obligations as of September 30, 2015, other than the liability for dismantlement and abandonment costs of its oil and gas properties. The Partnership has recorded a separate liability for the present value of this asset retirement obligation as discussed in the notes to the financial statements included in the Partnership’s latest annual report on Form 10-K.

During the first nine months of 2015 the Partnership had cash outlays for capital expenditures of $17,552 for additions to oil and gas properties as it participated in two recompletion projects at South Timbalier 295 during the period. The Partnership’s cash outlays for capital expenditures during the first nine months of 2014 were minimal as the Partnership did not participate in any new drilling or recompletion projects during the first nine months of 2014. During the first nine months of 2015, the Partnership made cash outlays of $209,635 on abandonment costs, while funding $163,594 on abandonment projects during the first nine months of 2014. Based on information supplied by the operators of the properties, the Partnership anticipates capital expenditures of less than $0.1 million during the remainder of 2015 as no new drilling projects are currently planned for 2015. Capital estimates may change based on realized prices, changes by the operator to the development plan, pipeline construction or modifications, or changes in government regulations. The operator of Matagorda Island 681/682 has indicated that abandonment of the field is expected to be largely completed by the end of 2015, and the Partnership’s share of the total cost is estimated at approximately $0.3 million. Abandonment operations for North Padre Island 969 are currently expected to be performed over the next two years and cost the Partnership approximately $0.7 million.

Because of declining oil and gas prices during the first nine months of 2015 and the need to reserve cash for future asset retirement obligations, no distributions were made to Investing Partners during the first nine months of 2015. The Partnership also made no distribution to Investing Partners during the first nine months of 2014 as a result of the large amount of plugging costs funded by the Partnership during 2014.

The amount of future distributions will be dependent on actual and expected production levels, realized and anticipated oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations. The Partnership will review available cash balances, any development or abandonment plans submitted by the operators of the Partnership’s properties, and the factors noted above to determine whether there are sufficient funds to make a distribution to Investing Partners during the first half of 2016.

As provided in the Partnership Agreement, as amended (the “Amended Partnership Agreement”), a first right of presentment valuation was computed during the first quarter of 2015. The per-unit value was determined to be $9,765 based on the valuation date of December 31, 2014. A second right of presentment valuation was computed during October 2015 and the per-unit value was determined to be $9,831 based on a valuation date of June 30, 2015. The Partnership did not repurchase any Investing Partner Units (Units) during the first nine months of 2015, and is not expected to purchase any Units in the fourth quarter of 2015. The per-unit right of presentment value computed during the first quarter of 2014 was determined to be $16,020 based on the valuation date of December 31, 2013, and the second per-unit right of presentment in 2014 was $16,260 based on a valuation date of June 30, 2014. The Partnership did not repurchase any Units during the first nine months of 2014. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to purchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

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Commodity Risk

The Partnership’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for the Partnership’s crude oil, natural gas, and NGLs have historically been and continue to be very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the first nine months of 2015 or 2014.

The information set forth under “Commodity Risk” in Item 7A of the Partnership’s Form 10-K for the year ended December 31, 2014, is incorporated by reference. Information about market risks for the current quarter is not materially different.

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2014, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

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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.

Disclosure Controls and Procedures

John J. Christmann, 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 September 30, 2015, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified under the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the period covered by this quarterly report on Form 10-Q that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II - OTHER INFORMATION

None.

During the nine months ended September 30, 2015, there were no material changes from the risk factors as previously disclosed in the Partnership’s Form 10-K for the year ended December 31, 2014.

None.

None.

None.

None.

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SIGNATURES

Pursuant to the requirements 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.

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