Apache Offshore Investment Partnership (AOIP) 10-Q 2010 Q3 Quarterly report

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

For the quarterly period ended September 30, 2010

OR

o 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
(State or other jurisdiction of
incorporation or organization) 41-1464066
(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. Yesþ Noo

     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). Yeso Noo

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 filero	Accelerated filero	Non-accelerated filero	Smaller reporting companyþ
		(Do not check if a Smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Number of registrant’s units outstanding as of September 30, 2010 1,022

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	ITEM 1 — FINANCIAL STATEMENTS
	ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4 — CONTROLS AND PROCEDURES
PART II — OTHER INFORMATION
	ITEM 1. LEGAL PROCEEDINGS
	ITEM 1A. RISK FACTORS
	ITEM 2. UNREGISTERED SALES OF EQUITY IN SECURITIES AND USE OF PROCEEDS
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 5. OTHER INFORMATION
	ITEM 6. EXHIBITS
SIGNATURES
EX-31.1
EX-31.2
EX-32.1

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,
	2010		2009		2010		2009
REVENUES:
Oil and gas sales	$	596,557	$	1,073,780	$	3,657,099	$	2,964,222
Interest income		14		24		25		188
		596,571		1,073,804		3,657,124		2,964,410
EXPENSES:
Depreciation, depletion and amortization		111,051		207,443		704,774		685,833
Asset retirement obligation accretion		29,507		16,945		88,623		50,104
Lease operating expenses		265,887		356,059		775,759		1,119,256
Gathering and transportation costs		42,970		22,827		101,213		51,509
Administrative		109,250		112,500		327,750		337,500
		558,665		715,774		1,998,119		2,244,202
NET INCOME	$	37,906	$	358,030	$	1,659,005	$	720,208
NET INCOME ALLOCATED TO:
Managing Partner	$	30,070	$	111,322	$	464,119	$	274,696
Investing Partners		7,836		246,708		1,194,886		445,512
	$	37,906	$	358,030	$	1,659,005	$	720,208
NET INCOME PER INVESTING PARTNER UNIT	$	8	$	242	$	1,170	$	436
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.

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

	For the Nine Months
	Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,659,005		$	720,208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		704,774			685,833
Asset retirement obligation accretion		88,623			50,104
Dismantlement and abandonment cost		(91,849	)		—
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables		197,913			(5,230	)
Increase (decrease) in payable to Apache Corporation		163,942			(176,798	)
Increase (decrease) in accrued operating expenses		26,839			28,619
Net cash provided by operating activities		2,749,247			1,302,736
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(698,177	)		(609,560	)
Net cash used in investing activities		(698,177	)		(609,560	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Investing Partners		—			—
Distributions to Managing Partner		(224,193	)		(262,850	)
Net cash used in financing activities		(224,193	)		(262,850	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		1,826,877			430,326
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		2,048,412			1,131,615
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,875,289		$	1,561,941

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

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APACHE OFFSHORE INVESTMENT PARTNERSHIP
CONSOLIDATED BALANCE SHEET
(Unaudited)

	September 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,875,289		$	2,048,412
Accrued revenues receivable		121,821			319,734
Accrued insurance receivable		24,678			24,678
Receivable from Apache Corporation		—			82,902
		4,021,788			2,475,726
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties		189,496,674			188,458,320
Less — Accumulated depreciation, depletion and amortization		(183,402,952	)		(182,698,178	)
		6,093,722			5,760,142
	$	10,115,510		$	8,235,868
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation	$	81,040		$	—
Accrued operating expenses		133,244			106,405
Accrued exploration and development		340,177			—
		554,461			106,405
ASSET RETIREMENT OBLIGATION		2,040,669			2,043,895
PARTNERS’ CAPITAL:
Managing Partner		314,006			74,080
Investing Partners (1,021.5 units outstanding)		7,206,374			6,011,488
		7,520,380			6,085,568
	$	10,115,510		$	8,235,868

The accompanying notes to 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, 2009, 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, 2010, 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, 2009.

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.

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 2010. The per-unit value was determined to be $15,411 based on the valuation date of December 31, 2009. A second right of presentment valuation was computed during October 2010 and the per-unit value was determined to be $16,130 based on a valuation date of June 30, 2010. The Partnership did not repurchase any Units during the first nine months of 2010 as a result of the Partnership’s limited amount of cash available for discretionary purposes and is not expected to purchase any in the fourth quarter of 2010. The per-unit right of presentment value computed during the first quarter of 2009 based on the valuation date of December 31, 2008 was $9,497 and the second per-unit right of presentment in 2009 was $8,677. The Partnership did not repurchase any Units during the first nine months of 2009. The Partnership has no

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obligation to purchase any units presented to the extent it determines that it has insufficient funds for such purchases.

4. ASSET RETIREMENT OBLIGATIONS

     The following table describes changes to the Partnership’s asset retirement obligation liability for the first nine months of 2010:

Asset retirement obligation at December 31, 2009	$	2,043,895
Accretion expense		88,623
Liabilities settled		(91,849	)
Asset retirement obligation at September 30, 2010	$	2,040,669

     The asset retirement obligations reflect the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. To determine the current present value of this obligation, some key assumptions the Partnership must estimate include the ultimate productive life of properties, a risk adjusted discount rate, and an inflation factor. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and gas property balance.

     In September 2010 the Bureau of Ocean Management, Regulation and Enforcement (BOEMRE, formerly known as the Minerals Management Service), a division of the U.S. Department of the Interior, issued Notice to Lessees (NTL) No. 2010-G05, which includes guidelines for decommissioning idle infrastructure on active leases in the Gulf of Mexico within a specified period of time. The Partnership is currently evaluating the impact of these new guidelines on its financial statements.

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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, 2010, 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, 2009, 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 year ended December 31, 2009.

     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 $37,906 for the third quarter of 2010, down from $358,030 in the third quarter of 2009. Net income per Investing Partner Unit fell to $8 per Unit in the third quarter of 2010, down from $242 per Unit in the third quarter of 2009. Lower oil and gas production lead to the significant decline in net income from a year ago.

     The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the field may be shut-in until February or March of 2011 as a new sales line is built to restore production. Production from the field accounted for approximately 55 percent and 54 percent of the Partnership’s total oil and gas sales for the third quarter of 2009 and first nine months of 2009, respectively.

     During the current quarter, the Partnership also experienced intermittent downtime at Matagorda Island 681/682 and North Padre Island 969 for inclement weather, pipeline repairs and field operations. This downtime, combined with the South Timbalier 295 shut-in, contributed to a 25 percent decline in gas production from a year ago.

     Net income for the nine months ending September 30, 2010 totaled $1,659,005 compared to $720,208 for the nine months ending September 30, 2009. Net income per Investing Partner Unit for the nine-month period ending September 30, 2010 of $1,170 was up from $436 per Unit in the first nine months of 2009. Higher oil and gas prices, increased gas volumes and lower operating costs also contributed to the substantial increase in net income for the first nine months of 2010 compared to the same period a year ago.

     Total revenues dropped 44 percent from the third quarter of 2009 compared to the third quarter of 2010 on lower oil and gas production in the current period. Average daily oil volumes and gas volumes decreased 86 percent and 25 percent, respectively from the third quarter of 2009. South Timbalier 295 was shut-in July 11, 2010 as a result of a leak in a third party pipeline. Year-to-date revenues for the nine months ended September 30, 2010 increased 23 percent over the same period in 2009. Realized oil and gas prices increased 46 percent and 25 percent, respectively, offsetting the decrease in average daily oil production of 37 percent. Average daily gas production increased 29 percent over 2009. Interest income for the first nine months of 2010 dropped from a year ago as a result of the significant decline in interest rates paid on cash equivalents.

     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
	2010		2009		(Decrease)			2010		2009		(Decrease)
Gas volume — Mcf per day		1,195		1,603		(25	)%		1,672		1,295		29	%
Average gas price — per Mcf	$	4.51	$	3.20		41	%	$	4.95	$	3.97		25	%
Oil volume — barrels per day		12		88		(86	)%		62		99		(37	)%
Average oil price — per barrel	$	68.29	$	67.40		1	%	$	76.64	$	52.67		46	%
NGL volume — barrels per day		6		19		(68	%)		8		17		(53	)%
Average NGL price — per barrel	$	43.70	$	33.38		31	%	$	48.79	$	28.96		68	%

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Oil and Gas Sales

     Natural gas sales totaled $496,026 in the third quarter of 2010, increasing $24,083 or 5 percent from the same period in 2009. The Partnership’s average realized natural gas price for the quarter increased $1.31 per Mcf, or 41 percent, from the third quarter of 2009, increasing sales by $193,137 from a year ago. Natural gas volumes decreased 25 percent reflecting the shut-in production at South Timbalier 295, downtime at Matagorda 681/682 for inclement weather and pipeline repairs and downtime at North Padre Island 969 for field operations.

     The Partnership’s crude oil sales for the third quarter of 2010 totaled $78,240 or 86 percent less than the $543,829 of crude oil sales in the third quarter of 2009. Crude oil volumes on a per day basis decreased 86 percent from 88 barrels per day in the third quarter of 2009 to 12 barrels per day in the third quarter of 2010. South Timbalier 295, the Partnership’s primary source of oil sales, has been shut-in since July 11, 2010 for a leak in a third-party pipeline. The Partnership’s average realized price in the third quarter of 2010 of $68.29 per barrel was up slightly from the third quarter of 2009 price of $67.40 per barrel.

     Apache and the Partnership are currently planning to construct a new sales line to restore production from the South Timbalier 295 field. The new sales line, which will provide more operating flexibility to Apache and the Partnership, is expected to be completed in February or March 2011. Apache and the Partnership believe the new sales line is the best alternative given the age of the existing leaking pipeline, the timeline for initiating and completing repairs as projected by the operator of the leaking pipeline, the cost of repairs which will be have to be absorbed by the parties, the projected life of the South Timbalier 295 reserves and operational control of the sales line and related facilities.

     The Partnership sold 6 barrels per day of natural gas liquids (NGL) in the third quarter of 2010, down from 19 barrels per day in the third quarter of 2009. The decrease reflected lower production from South Timbalier 295 during the current quarter.

     Natural gas sales for the first nine months of 2010 increased 61 percent from a year ago, rising to $2,258,719 in the current period. A 29 percent increase in natural gas volumes during the first nine months of 2010 from the same period a year ago boosted sales by $509,589 while a 25 percent increase in the Partnership’s average gas price increased sales by $343,514. The Partnership’s gas production in 2009 was hindered by the shut-in of Matagorda Island 681/682 for repairs to a third-party pipeline. The impact of the Matagorda Island shut-in and natural declines was mitigated by increased production from workovers at North Padre Island 969/976 in 2009. The Partnership’s average realized gas prices increased to $4.95 per Mcf in 2010 from $3.97 per Mcf in the first nine months of 2009.

     Crude oil sales for the first nine months of 2010 decreased 10 percent from the same period in the prior year, decreasing from $1,424,508 in the first nine months of 2009 to $1,288,042 in the first nine months of 2010. A $23.97 per barrel increase in oil prices from a year ago raised sales by $648,299 which offset the 37 barrel per day decline in production. The Partnership’s average realized price for the oil during the first nine months of 2010 increased 46 percent from the comparable period in 2009, rising to $76.64 per barrel in 2010. The Partnership’s crude oil volumes decreased from 99 barrels per day during the first nine months of 2009 to 62 barrels per day during the same period of 2010 as a result of the third-party pipeline shut-in of South Timbalier 295.

     The Partnership sold 8 barrels per day of natural gas liquids in the first nine months of 2010, down from 17 barrels per day for the same period of 2009.

     Since the Partnership does not anticipate acquiring additional acreage or conducting exploratory drilling on leases in which it currently holds 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 future 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 19 percent during both the third quarters of 2010 and 2009. DD&A expressed as a percentage of oil and gas sales for the first nine months was 19 percent and 23 percent for 2010 and 2009, respectively. The lower rate as a percentage of sales reflected the higher oil and gas prices in 2010. On a per barrel of oil equivalent (boe)

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basis, DD&A increased to $6.35 per boe in the first nine months of 2010 from $5.28 per boe in the comparable period in 2009 on higher capitalized cost.

     The Partnership recognized $29,507 in asset retirement obligation accretion in the third quarter of 2010, compared to $16,945 for the third quarter of 2009. For the nine months ending September 30, 2010 and 2009 the Partnership recognized $88,623 and $50,104, respectively. The increases reflected the increase in the Partnership’s asset retirement obligation liability during the fourth quarter of 2009. Gathering and transportation costs for the third quarter and first nine months of 2010 nearly doubled from a year ago as a result of higher gas volumes at Matagorda Island 681/682 and new marketing arrangements for North Padre Island 969 where the Partnership pays for its transportation cost instead of receiving a gas sales price which is net of transportation.

     Lease operating expenses (LOE) for the third quarter of 2010 of $265,887 was down from the third quarter of 2009. During the third quarter of 2009, maintenance was performed on the Matagorda Island 681 platform while the field was shut-in for third-party pipeline repairs, and workovers were performed at North Padre Island 976 and Ship Shoal 259.

     LOE for the first nine months of 2010 was down 31 percent from the same period a year ago as a result of fewer workover and repair projects in 2010 compared to 2009. Administrative expense decreased three percent for the first nine months of 2010, as compared to the same period in 2009.

Capital Resources and Liquidity

     The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.7 million for the first nine months of 2010. Net cash provided by operating activities during the first nine months of 2010 was more than double a year ago as a result of increases in oil and gas prices and lower operating costs. Future cash flows will be influenced by fluctuations in product prices, production levels and operating costs. Cash provided by operating activities will be reduced in at least the next two quarters as a result of the shut-in production at South Timbalier 295.

     At September 30, 2010, the Partnership had approximately $3.9 million in cash and cash equivalents, up from approximately $2.0 million at December 31, 2009. 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 (ARO). The Partnership increased its cash balances during the nine months of 2010 to fully cover its ARO and help fund development cost planned for the remainder of 2010. In light of the Deepwater Horizon explosion and oil spill discussed below and the age of the Partnership’s properties, the Partnership believes it is prudent to increase its cash reserves to cover the undiscounted value of its ARO, up from the discounted ARO values utilized in recent years.

     The Partnership’s goal of maintaining cash at least sufficient to cover the undiscounted value of its future ARO liability may have to be temporarily suspended if the Partnership’s production at South Timbalier 295 continues to be shut-in for an extended period of time and drilling is initiated at Ship Shoal 258/259 with minimum delays for permitting and rig resourcing. If cash is drawn down below the Partnership’s goal threshold in order to pay for drilling expenditures, the cash will be replenished in 2011 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 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 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.

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     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, 2010. The Partnership did not have any contractual obligations as of September 30, 2010, 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.

     The Partnership’s cash capital expenditures totaled $698,177 for the first nine months of 2010, as it participated in three recompletions at South Timbalier 295 and two recompletions at North Padre Island 969. The Partnership is utilizing available funds to participate in development activities recommended by the operators and by the Managing Partner for maintaining the Partnership’s production and developing its proved undeveloped reserves.

     Based on information supplied by the operators of the properties, the Partnership anticipates capital expenditures of approximately $1.4 million for the remainder of 2010. The Partnership plans to participate in two drilling projects at Ship Shoal 258/259 during 2010. Apache has obtained permits from BOEMRE for the drilling of the Ship Shoal 259 #JA-3 sidetrack well and is currently seeking approval for two additional drilling permits for the field. It is anticipated that one of the wells pending approval would begin drilling in 2010 and one well in 2011. Drilling plans and estimates may change based on realized oil and gas prices, drilling results of the initial well, government regulations, or changes by the operator to the development plan. The Partnership also plans to participate in the construction of a new sales line from South Timbalier 295. The new sales line is necessary to restore production from the field after a third-party pipeline developed leaks.

     No distributions were made to Investing Partners during the first nine months of 2010, as cash was being accumulated to increase the reserve for future asset retirement obligations and fund capital expenditures planned for the remainder of 2010. The Partnership made no distribution to Investing Partners during the first nine months of 2009 as oil and gas prices were low and the Matagorda Island 681/682 field was shut-in for much of the first half of 2009.

     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 intends to maintain cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations. With the continued shut-in of production at South Timbalier 295 and the planned development projects noted above, the Partnership will most likely not be able to fund a distribution to Investing Partners during 2010.

     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 2010. The per-unit value was determined to be $15,411 based on the valuation date of December 31, 2009. A second right of presentment valuation was computed during October 2010 and the per-unit value was determined to be $16,130 based on a valuation date of June 30, 2010. The Partnership did not repurchase any Units during the first nine months of 2010 as a result of the Partnership’s limited amount of cash available for discretionary purposes and is not expected to purchase any in the fourth quarter of 2010. The per-unit right of presentment value computed during the first quarter of 2009 based on the valuation date of December 31, 2008 was $9,497 and the second per-unit right of presentment in 2009 was $8,677. The Partnership did not repurchase any Units during the first nine months of 2009. 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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Potential Impact of Deepwater Horizon Explosion and Oil Spill on Gulf of Mexico Operations

     In April 2010, a deepwater drilling rig, the Deepwater Horizon, operating in the Gulf of Mexico on Mississippi Canyon Block 252, sank after an apparent blowout and fire, resulting in a large oil spill. Although the well has been capped, remediation of the environmental impacts of the spill is ongoing. The Partnership does not own an interest in the field.

     As a result of the incident and spill, the U.S. Department of the Interior (DOI) issued a series of reforms to the oversight and management of offshore exploration drilling activities on the federal Outer Continental Shelf (the OCS). On May 30, 2010, the Bureau of Ocean Energy Management, Regulatory and Enforcement (the BOEMRE, formerly the Minerals Management Service) of the DOI announced, as a result of the Deepwater Horizon incidents, a Moratorium Notice to Lessees and Operators (Moratorium NTL), which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the OCS, and put oil and gas lessees and operators on notice that, with certain exceptions, the BOEMRE would not consider drilling permits for deepwater wells and related activities. On October 12, 2010, the DOI formally lifted the moratorium.

     In addition, the BOEMRE issued two Notice to Lessees (NTLs), NTL-05 and NTL-06, which focused on increased safety measures relating to activities involving use of blowout preventers and an operator’s plans for a blowout scenario and worst-case discharge scenario. These regulatory changes have significantly slowed the permitting activity in the Gulf of Mexico.

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.

     In light of the recent catastrophic accident in the Gulf of Mexico, the Managing Partner and the Partnership may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

Remediation Plans and Procedures

     The Managing Partner has in place for its Gulf of Mexico operations a Region Spill Response Plan, which details procedures for rapid and effective response to spill events that may occur as a result of Apache’s operations. The Partnership does not operate any properties for itself or others. Periodically, drills are conducted by Apache to measure and maintain the effectiveness of its plan. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache in the event of a spill is CGA. Apache has received approval for its plan from the Bureau of Ocean Energy Management, Regulatory and Enforcement (formerly, the Minerals Management Service). Apache personnel review the plan annually and update where necessary.

     As part of our Region Spill Response Plan, the Managing Partner is a member of, and has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine

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Preservation Association. MSRC maintains CGA’s equipment (including skimmers, fast response vessels, fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies which provide support services during spill response. In the event of a spill, MSRC will activate these contracts as necessary to provide additional resources or support services requested by its customers. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), which provides aircrafts and dispersant capabilities for CGA member companies.

     In the event that CGA and MSRC resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited is the world’s largest oil spill preparedness and response organization, dedicated to providing resources to respond to oil spills efficiently and effectively on a global basis. In addition, resources of other organizations are available to Apache as a non-member, such as those of National Response Corporation (NRC) and MSRC, albeit at a higher cost.

     In light of the current events in the Gulf of Mexico, Apache is participating in a number of industry-wide task forces, which are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

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 2009 or the first nine months of 2010.

     The information set forth under “Commodity Risk” in Item 7A of the Partnership’s Form 10-K for the year ended December 31, 2009, is incorporated by reference. Information about market risks for the current quarter is not materially different.

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 Roger B. Plank, the Managing Partner’s President (in his capacity as principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of September 30, 2010, 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 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.

     There was no change in the Partnership’s 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, the Partnership’s 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

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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, 2009, 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 Annual Report on 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.

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PART II — OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

None.

ITEM 1A.  RISK FACTORS

Please refer to the risk factors as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. For the nine months ending September 30, 2010, the Partnership notes the following additional risk factors:

Oil and gas operations involve a high degree of operational risk, particularly risk of personal injury, damage or loss of equipment and environmental accidents.

The Partnership’s operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:

• drilling well blowouts, explosions and cratering;

• pipeline ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions; and

• hurricanes which could affect our operations in the Gulf of Mexico, as well as other natural disasters.

Failure or loss of equipment, as the result of equipment malfunctions or natural disasters, could result in property damages, personal injury, environmental pollution and other damages for which the Partnership could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a well blowout or pipeline rupture could result in environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flow and, in turn, our results of operations could be materially and adversely affected.

The additional drilling laws and regulations, delays in processing of permits and other related developments resulting from the recently lifted deepwater drilling moratorium in the Gulf of Mexico could adversely affect the Partnership’s business.

As has been widely reported, in April 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, leading to the oil spill currently affecting the Gulf of Mexico. In response to this incident, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or “BOEM”) of the U.S. Department of the Interior issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the Gulf of Mexico. Implementation of the moratorium was blocked by a U.S. district court, which was subsequently affirmed on appeal, but on July 12, 2010, the BOEM issued a new moratorium that applies to drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities,rather than a moratorium based on water depths. The DOI lifted this moratorium on October 12, 2010. The BOEM is also expected to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. Although it is difficult to predict the ultimate impact of the moratorium or any new guidelines, regulations or legislation, a prolonged suspension of drilling activity in the Gulf of Mexico, new regulations and increased liability for companies operating in this sector could adversely affect the Partnership’s operations in the Gulf of Mexico.

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The shut-in of production from our South Timbalier 295 field could have a material adverse effect on our business, financial condition or results of operations.

The Partnership’s production from South Timbalier 295 has been shut-in since July 11, 2010, as a result of a leak in a third-party pipeline. It is anticipated that the shut-in may be for a lengthy period of time waiting on regulatory approvals for the required work and for completion of the repairs. The operator of the pipeline has indicated that the line is not economical to them and that they will expect Apache and the Partnership, as the only customers utilizing the pipeline, to pay for the repairs. If we are unable to receive regulatory approvals for the completion of the repairs in a timely manner or if the repairs are not completed for an extended period, this shut-in could have a material adverse effect on the Partnership’s financial position, results of operations and our cash flows.

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

*	Incorporated by reference herein.
**	Filed herewith.

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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.

APACHE OFFSHORE INVESTMENT PARTNERSHIP
By:	Apache Corporation, Managing Partner

Dated: November 9, 2010	/ s / Roger B. Plank
	Roger B. Plank President (principal financial officer) of Apache Corporation, Managing Partner

Dated: November 9, 2010	/ s / Rebecca A. Hoyt
	Rebecca A. Hoyt Vice President and Controller (principal accounting officer) of Apache Corporation, Managing Partner