UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

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

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)

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 þ No o

     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 þ No o

     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.

Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company þ

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

Number of registrant’s units outstanding as of September 30, 2011			1,022

 

 

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED INCOME
(Unaudited)

		For the Quarter								For the Nine Months
		Ended September 30,								Ended September 30,
		2011				2010				2011				2010
REVENUES:
Oil and gas sales		$	1,753,665			$	596,557			$	3,570,135			$	3,657,099
Interest income			8				14				16				25
			1,753,673				596,571				3,570,151				3,657,124
EXPENSES:
Depreciation, depletion and amortization			365,462				111,051				739,487				704,774
Asset retirement obligation accretion			33,370				29,507				98,670				88,623
Lease operating expenses			293,079				265,887				774,990				775,759
Gathering and transportation costs			43,093				42,970				114,098				101,213
Administrative			100,750				109,250				302,250				327,750
			835,754				558,665				2,029,495				1,998,119
NET INCOME		$	917,919			$	37,906			$	1,540,656			$	1,659,005
NET INCOME ALLOCATED TO:
Managing Partner		$	248,110			$	30,070			$	442,462			$	464,119
Investing Partners			669,809				7,836				1,098,194				1,194,886
		$	917,919			$	37,906			$	1,540,656			$	1,659,005
NET INCOME PER INVESTING PARTNER UNIT		$	656			$	8			$	1,075			$	1,170
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING			1,021.5				1,021.5				1,021.5				1,021.5

The accompanying notes to financial statements
are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)

		For the Nine Months
		Ended September 30,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	1,540,656			$	1,659,005
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			739,487				704,774
Asset retirement obligation accretion			98,670				88,623
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables			39,561				197,913
Increase (decrease) in receivable from/payable to Apache Corporation			(141,296	)			163,942
Increase (decrease) in accrued operating expenses			3,025				26,839
Increase (decrease) in deferred credits and other			(354,485	)			(91,849	)
Net cash provided by operating activities			1,925,618				2,749,247
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties			(2,254,133	)			(698,177	)
Net cash used in investing activities			(2,254,133	)			(698,177	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Investing Partners			—				—
Distributions to Managing Partner			(357,916	)			(224,193	)
Net cash used in financing activities			(357,916	)			(224,193	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(686,431	)			1,826,877
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			2,971,900				2,048,412
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	2,285,469			$	3,875,289

The accompanying notes to financial statements
are an integral part of this statement.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
(Unaudited)

		September 30,				December 31,
		2011				2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	2,285,469			$	2,971,900
Accrued revenues receivable			214,801				238,431
Accrued insurance receivable			8,518				24,449
Receivable from Apache Corporation			78,313				—
			2,587,101				3,234,780
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties			194,433,312				191,277,205
Less — Accumulated depreciation, depletion and amortization			(184,259,718	)			(183,520,231	)
			10,173,594				7,756,974
		$	12,760,695			$	10,991,754
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation		$	—			$	668,573
Accrued operating expenses			112,819				109,794
Accrued development costs			1,702,071				520,950
			1,814,890				1,299,317
ASSET RETIREMENT OBLIGATION			2,280,290				2,209,662
PARTNERS’ CAPITAL:
Managing Partner			467,551				383,005
Investing Partners (1,021.5 units outstanding)			8,197,964				7,099,770
			8,665,515				7,482,775
		$	12,760,695			$	10,991,754

The accompanying notes to financial statements
are an integral part of this statement.

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, 2010, and which contains a summary of the Partnership’s significant accounting policies and other disclosures.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     As of September 30, 2011, the Partnership’s significant accounting policies are consistent with those discussed in Note 2 of its consolidated financial statements contained in the Annual Report of Form 10-K for the fiscal year ended December 31, 2010.

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.

Fair Value Measurements

     Certain assets and liabilities are reported at fair value on a recurring basis in the Partnership’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable

     As of September 30, 2011 and December 31, 2010, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

New Pronouncements Issued But Not Yet Adopted

     In May 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, which amends FASB Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in

ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Partnership does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

2. RECEIVABLE FROM / PAYABLE TO APACHE CORPORATION

     The receivable from/payable to Apache 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.

3. RIGHT OF PRESENTMENT

     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 2011. The per-Unit value was determined to be $14,917 based on the valuation date of December 31, 2010. A second right of presentment valuation was computed during October 2011 and the per-Unit value was determined to be $13,500 based on a valuation date of June 30, 2011. The Partnership did not repurchase any Units during the first nine months of 2011, as a result of the Partnership’s limited amount of cash available for discretionary purposes and is not expected to purchase any Units in the fourth quarter of 2011. The per-Unit right of presentment value computed during the first quarter of 2010 based on the valuation date of December 31, 2009 was $15,411 and the second per-Unit right of presentment in 2010 was $16,130. The Partnership did not repurchase any Units during the first nine months of 2010. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to repurchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

4. ASSET RETIREMENT OBLIGATIONS

     The following table is a reconciliation of the asset retirement obligation for the nine months of 2011:

Asset retirement obligation at December 31, 2010		$	2,209,662
Liabilities incurred			576,074
Liabilities settled			(604,116	)
Accretion expense			98,670
Asset retirement obligation at September 30, 2011		$	2,280,290

ITEM 2 —		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     This discussion relates to Apache Offshore Investment Partnership (the Partnership) and should be read in conjunction with the Partnership’s consolidated financial statements as of September 30, 2011, and the period then ended, and accompanying notes included under Part I, Item 1, of this Quarterly Report on Form 10-Q, as well as its consolidated financial statement as of December 31, 2010, and the year then ended, and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

     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.

RESULTS OF OPERATIONS

Net Income and Revenue

     The Partnership reported net income of $917,919 for the third quarter of 2011, up from $37,906 in the third quarter of 2010. Net income per Investing Partner Unit increased to $656 per Unit in the third quarter of 2011, up from $8 per Unit in the third quarter of 2010. The increase in earnings and earnings per Unit was driven by a full quarter’s production from South Timbalier 295 during the third quarter of 2011 compared to approximately two weeks of production during the third quarter of 2010.

     Net income for the nine months ending September 30, 2011, totaled $1,540,656 compared to $1,659,005 for the nine months ending September 30, 2010. Net income per Investing Partner Unit for the nine-month period ending September 30, 2011 of $1,075 was down slightly from $1,170 per Unit in the first nine months of 2010. The decline in earnings and earnings per Unit was driven by a 13 percent decline in natural gas prices from the first nine months of 2010. While the Partnership experienced more downtime at South Timbalier 295 during the first nine months of 2011 than in the comparable period in 2010, higher oil prices in 2011 largely offset the impact of the downtime.

     The Partnership’s production from South Timbalier 295 was shut-in on July 11, 2010, as a result of a leak in a third-party pipeline and remained shut-in until mid-2011. After construction a new oil pipeline from the field, the operator resumed production from the South Timbalier 295 field on June 14, 2011, with production from two wells to test the field’s equipment and new pipeline. Production was resumed from other wells in the field over the course of the next two weeks as to not damage the field’s equipment or reservoir.

     Total revenues in the third quarter of 2011 were nearly three times the revenues realized in the third quarter of 2010 as a result of resuming production from South Timbalier 295 during 2011. Year-to-date revenues in 2011 decreased two percent from the first nine months of 2010 on lower natural gas prices. With the Partnership’s production from South Timbalier 295 shut-in for most of the first six months of 2011, it was not able to fully capitalize on the 39 percent increase in oil prices from a year ago.

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

		For the Quarter Ended September 30,												For the Nine Months Ended September 30,
										Increase												Increase
		2011				2010				(Decrease)				2011				2010				(Decrease)
Gas volume — Mcf per day			1,654				1,195				38	%			1,722				1,672				3	%
Average gas price — per Mcf		$	4.30			$	4.51				(5	)%		$	4.31			$	4.95				(13	)%
Oil volume — barrels per day			106				12				783	%			45				62				(27	)%
Average oil price — per barrel		$	106.18			$	68.29				55	%		$	106.20			$	76.64				39	%
NGL volume — barrels per day			8				6				33	%			16				8				100	%
Average NGL price — per barrel		$	89.45			$	43.70				105	%		$	56.63			$	48.79				16	%

Oil and Gas Sales

     Natural gas sales totaled $654,458 in the third quarter of 2011, increasing $158,432 or 32 percent from the same period in 2010. Natural gas volumes increased 38 percent from the third quarter of 2010, boosting sales by $181,591. Increased production at Ship Shoal 258/259 from 2011 drilling more than offset the natural depletion at North Padre Island 969/976 and Matagorda Island 681/682. The Partnership’s average realized natural gas price for the quarter decreased $.21 per Mcf, or five percent, from the third quarter of 2010, decreasing sales by $23,159 from a year ago.

     The Partnership’s crude oil sales for the third quarter of 2011 totaled $1,035,757 compared to $78,240 in the third quarter of 2010. Crude oil volumes on a per day basis during the quarter increased from 12 barrels per day in 2010 to 106 barrels per day in 2011 as the South Timbalier 295 field was on production for nearly the entire third quarter in 2011. The average realized price in the third quarter of 2011 increased $37.89 per barrel, or 55 percent, from the third quarter of 2010, further increasing sales.

     During the third quarter of 2011, the Partnership sold eight barrels per day of natural gas liquids, up from six barrels per day during the third quarter of 2010. The increase relates to processed volumes at Ship Shoal 258/259 from new wells in 2011.

     Natural gas sales for the first nine months of 2011 decreased 10 percent from a year ago, dropping to $2,026,026 in the current period. A three percent increase in natural gas volumes during the first nine months of 2011 from the same period a year ago increased sales by $59,514 while a 13 percent decrease in the Partnership’s average gas price decreased sales by $292,207. The Partnership’s gas production in 2011 was hindered by declining production from the North Padre Island 969/976 and Matagorda Island 681/682. The Partnership’s average realized gas prices decreased to $4.31 per Mcf in 2011 from $4.95 per Mcf in the first nine months of 2010.

     Crude oil sales for the nine months of 2011 was essentially even with a year ago at $1.3 million. The Partnership’s crude oil volumes decreased from 62 barrels per day during the first nine months of 2010 to 45 barrels per day during the same period of 2011 as a result of the shut-in of production at the South Timbalier 295 field. The 17 barrel per day decline in production reduced sales by approximately $484,280 but was more than offset by the impact of higher oil prices. The Partnership’s average realized price for the oil increased 39 percent between the first nine months of 2010 and 2011, rising to $106.20 per barrel in 2011.

     The Partnership sold 16 barrels per day of natural gas liquids in the first nine months of 2011, up from eight barrels per day in the first nine months of 2010. The increase reflected higher processed volumes at Ship Shoal 258/259 in 2011.

     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 in the Gulf of Mexico, the Partnership’s production may be subject to more volatility than those companies with a larger or more diversified property portfolio.

Operating Expenses

     The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 21 percent during the third quarter of 2011 compared to 19 percent for the same period in 2010. DD&A, expressed as a percentage of oil and gas sales, for the nine months was also 21 percent and 19 percent for the respective years. The higher rates as a percentage of sales reflected capital cost required to build a new pipeline from South Timablier 295 and higher drilling costs.

     The Partnership recognized $33,370 in asset retirement obligation (ARO) accretion for the third quarter of 2011 compared to $29,507 for the third quarter of 2010. For the nine months ending September 30, 2011 and 2010, the Partnership recognized $98,670 and $88,623, respectively. The increase reflected upward revisions in the Partnership’s ARO liability during the fourth quarter of 2010. Gathering and transportation costs for the third quarter of 2011 was even with a year ago while increasing 13 percent for the nine month period with increases in processed volumes at Ship Shoal 258/259 in 2011.

     Lease operating expenses (LOE) for the third quarter of 2011 of $293,079 increased ten percent from the third quarter of 2010 on higher maintenance costs. LOE for the first nine months of 2011 was even with the same period a year ago at approximately $775,000 in each year. Administrative expense for 2011 decreased eight percent for the nine-month period.

Capital Resources and Liquidity

     The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $1.9 million for the first nine months of 2011. Net cash provided by operating activities during the first nine months of 2011 was down from a year ago as a result of a decline in net income from last year and a reduction in operating liabilities during of the first nine months of 2011. Future cash flows will be primarily influenced by fluctuations in the Partnership’s production, realized prices and operating expenses.

     At September 30, 2011, the Partnership had approximately $2.3 million in cash and cash equivalents, down from approximately $3.0 million at December 31, 2010. The Partnership’s goal of maintaining cash at least sufficient to cover the undiscounted value of its future ARO liability had to be temporarily suspended in 2011 as a result of the Partnership’s production from South Timbalier 295 being shut-in for nearly a year and the Partnership’s capital expenditures at Ship Shoal 258/259 and South Timbalier 295. The Partnership intends to replenish cash reserves in 2011 and 2012 with cash from operating activities.

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

     The Partnership’s oil and gas reserves and production also will significantly impact future results of operations and cash from operating activities. The Partnership’s production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can be expected in future years as a result of normal depletion and the Partnership not participating in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership expects it will be able to meet its liquidity needs for routine operations in the foreseeable future. The Partnership will reduce capital expenditures and distributions to partners as cash from operating activities decline.

     In the event that future short-term operating cash requirements are greater than the Partnership’s financial resources, the Partnership may seek short-term, interest-bearing advances from the Managing Partner as needed. The Managing Partner, however, is not obligated to make loans to the Partnership.

     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, 2011. The Partnership did not have any contractual obligations as of September 30, 2011, 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 ARO as discussed in the notes to the financial statements included in the Partnership’s latest annual report on Form 10-K.

     The Partnership’s capital expenditures totaled $3.2 million during the first nine months of 2011, as the Partnership participated in drilling three wells at Ship Shoal 258/259 during the period and completed the construction of a new pipeline from the South Timablier 295 field. With the 2011 development activity and an increase in accrued drilling and development liabilities from December 31, 2010, the Partnership’s cash outlay during the first nine months of 2011 totaled $2.3 million. During the first nine months of 2010, the Partnership’s cash capital expenditures totaled $698,177 as it participated in recompletion projects at South Timbalier 295.

     The Partnership does not expect to participate in significant capital projects during the last quarter of 2011 other than the completion of the Ship Shoal 258 JB8 ST1 well. The well was completed as a producer in early October 2011. Based on information supplied by the operators of the properties, the Partnership anticipates capital expenditures of approximately $0.5 million for the remainder of 2011. Such estimates may change based on realized prices, drilling results, changes by the operator to the development plan, drilling rig availability, obtaining government permits or changes in government regulations.

     No distributions were made to Investing Partners during the first nine months of 2011, as cash was used to fund capital expenditures for the period. The Partnership made no distribution to Investing Partners during the first nine months of 2010 as cash was being accumulated to increase the reserve for future ARO and fund capital expenditures planned for the remainder of 2010.

     The amount of future distributions will be dependent on actual and expected production levels, realized and expected oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted. 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 ARO. With the large liability for development cost as of September 30, 2011, and the need to replenish the Partnership’s cash reserves for future ARO expenditures, the Partnership does not expect to make a distribution to Investing Partners during the remainder of 2011.

     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 2011. The per-Unit value was determined to be $14,917 based on the valuation date of December 31, 2010. A second right of presentment valuation was computed during October 2011 and the per-Unit value was determined to be $13,500 based on a valuation date of June 30, 2011. The Partnership did not repurchase any Units during the first nine months of 2011, as a result of the Partnership’s limited amount of cash available for discretionary purposes and is not expected to purchase any Units in the fourth quarter of 2011. The per-Unit right of presentment value computed during the first quarter of 2010 based on the valuation date of December 31, 2009 was $15,411 and the second per-Unit right of presentment in 2010 was $16,130. The Partnership did not repurchase any Units during the first nine months of 2010. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to repurchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

ITEM 3		— QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Partnership’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. The Partnership has not used derivative financial instruments or otherwise engaged in hedging activities during 2010 or the first nine months of 2011.

     The information set forth under “Commodity Risk” in Item 7A of the Partnership’s Form 10-K for the year ended December 31, 2010, is incorporated by reference. Information about market risks for the current quarter is not materially different from the disclosure in the Partnership’s most recently filed Form 10-K.

ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

     G. Steven Farris, the Managing Partner’s Chairman and Chief Executive Officer (in his capacity as principal executive officer), and Thomas P. Chambers, 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, 2011, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the 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.

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.

FORWARD-LOOKING STATEMENTS AND RISK

     This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2010, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

•

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

•

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

•

production and reserve levels;

•

drilling risks;

•

economic and competitive conditions;

•

the availability of capital resources;

•

capital expenditure and other contractual obligations;

•

weather conditions;

•

inflation rates;

•

the availability of goods and services;

	•		legislative or regulatory changes;
	•		terrorism;

•

occurrence of property acquisitions or divestitures;

•

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

•

other factors disclosed under Items 1 and 2 — “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A — “Risk Factors,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk,” and elsewhere in our most recently filed 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 II — OTHER INFORMATION

ITEM 1.		LEGAL PROCEEDINGS
		None.
ITEM 1A.		RISK FACTORS
		During the quarter ended September 30, 2011, there were no material changes from the risk factors as previously disclosed in the Partnership’s Form 10-K for the fiscal year ended December 31, 2010.
ITEM 2.		UNREGISTERED SALES OF EQUITY IN SECURITIES AND USE OF PROCEEDS
		None.
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES
		None.
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
		None.
ITEM 5.		OTHER INFORMATION
		None.
ITEM 6.		EXHIBITS

a.

Exhibits

*3.1		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).
*3.2		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).
*3.3		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).
**31.1		Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer
**31.2		Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer
**32.1		Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer

***  101.INS XBRL Instance Document.

***  101.SCH XBRL Taxonomy Schema Document.

***  101.CAL XBRL Calculation Linkbase Document.

***  101.LAB XBRL Label Linkbase Document.

***  101.PRE XBRL Presentation Linkbase Document.

*        Incorporated by reference herein.

**      Filed herewith.

***    Furnished herewith.

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.