Apache Offshore Investment Partnership (AOIP) 10-Q 2010 Q2 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 June 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 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). Yeso Noþ

Number of registrant’s units outstanding as of June 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
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 Six Months
	Ended June 30,					Ended June 30,
	2010			2009		2010		2009
REVENUES:
Oil and gas sales	$	1,336,569		$	759,274	$	3,060,541	$	1,890,442
Interest income		7			34		11		164
		1,336,576			759,308		3,060,552		1,890,606
EXPENSES:
Depreciation, depletion and amortization		233,350			182,858		593,723		478,390
Asset retirement obligation accretion		29,130			16,700		59,116		33,159
Lease operating expenses		256,827			375,362		509,872		763,197
Gathering and transportation costs		24,296			8,715		58,242		28,682
Administrative		109,250			112,500		218,500		225,000
		652,853			696,135		1,439,453		1,528,428
NET INCOME	$	683,723		$	63,173	$	1,621,099	$	362,178
			��
NET INCOME ALLOCATED TO:
Managing Partner	$	180,488		$	47,811	$	434,049	$	163,374
Investing Partners		503,235			15,362		1,187,050		198,804
	$	683,723		$	63,173	$	1,621,099	$	362,178
NET INCOME PER INVESTING PARTNER UNIT	$	493		$	15	$	1,162	$	195
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING		1021.5			1,021.5		1021.5		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 Six Months
	Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,621,099		$	362,178
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		593,723			478,390
Asset retirement obligation accretion		59,116			33,159
Dismantlement and abandonment cost		(91,849	)		—
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables		90,867			124,627
Increase (decrease) in receivable from/payable to Apache Corporation		120,254			(20,241	)
Increase (decrease) in accrued operating expenses		26,839			2,005
Net cash provided by operating activities		2,420,049			980,118
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(75,011	)		(585,864	)
Net cash used in investing activities		(75,011	)		(585,864	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Investing Partners		—			—
Distributions to Managing Partner		(173,673	)		(172,661	)
Net cash used in financing activities		(173,673	)		(172,661	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,171,365			221,593
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		2,048,412			1,131,615
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	4,219,777		$	1,353,208

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)

	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,219,777		$	2,048,412
Accrued revenues receivable		228,867			319,734
Accrued insurance receivable		24,678			24,678
Receivable from Apache Corporation		—			82,902
		4,473,322			2,475,726
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties		188,696,354			188,458,320
Less – Accumulated depreciation, depletion and amortization		(183,291,901	)		(182,698,178	)
		5,404,453			5,760,142
	$	9,877,775		$	8,235,868
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation	$	37,352		$	—
Accrued operating expenses		133,244			106,405
Accrued exploration and development		163,023			—
		333,619			106,405
ASSET RETIREMENT OBLIGATION		2,011,162			2,043,895
PARTNERS’ CAPITAL:
Managing Partner		334,456			74,080
Investing Partners (1,021.5 units outstanding)		7,198,538			6,011,488
		7,532,994			6,085,568
	$	9,877,775		$	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 June 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 of 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. The Partnership did not repurchase any Units during the first half of 2010 as a result of the Partnership’s limited amount of cash available for discretionary purposes. 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. The Partnership did not repurchase any Units during the first half of 2009.

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     The Partnership is not in a position to predict how many Units will be presented for repurchase during the remainder of 2010 and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase any Units. The Partnership has no 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 six months ended June 30, 2010:

Asset retirement obligation at December 31, 2009	$	2,043,895
Accretion expense		59,116
Liabilities settled		(91,849	)
Asset retirement obligation at June 30, 2010	$	2,011,162

     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.

5. SUBSEQUENT EVENTS

     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. Apache and the Partnership are currently reviewing their options for restoring production. Production from the field accounted for approximately 47 percent of the Partnership’s total second quarter oil and gas sales and 44 percent of oil and gas sales for the first six months of 2010.

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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 June 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 $683,723 for the second quarter of 2010, up from $63,173 in the second quarter of 2009. Net income per Investing Partner Unit increased to $493 per Unit in the second quarter of 2010, up from $15 per Unit in the second quarter of 2009. Higher oil and gas prices and gas volumes, along with lower lease operating expenses, lead to the significant increase in net income from a year ago. Oil and gas prices realized during the second quarter of 2010 increased 38 percent and 30 percent, respectively, from the comparable period a year ago.

     Net income for the six months ending June 30, 2010, totaled $1,621,099 compared to $362,178 for the six months ending June 30, 2009. Net income per Investing Partner Unit for the six-month period ending June 30, 2010 of $1,162 was up from $195 per Unit in the first six 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 six months of 2010 compared to the same period a year ago.

     Total revenues increased 76 percent from the second quarter of 2009 to the second quarter of 2010 on higher oil and gas prices and gas volumes in the second quarter of 2010. Year-to-date revenues in 2010 increased 62 percent from the first half of 2009. Realized oil prices during the first six months of 2010 increased 66 percent from a year ago, while realized gas prices increased 12 percent from the comparable period in 2009. Interest income 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 June 30,							For the Six Months Ended June 30,
	2010		2009		Increase (Decrease)			2010		2009		Increase (Decrease)
Gas volume – Mcf per day		1,793		696		157	%		1,915		1,139		68	%
Average gas price – per Mcf	$	4.46	$	3.42		30	%	$	5.09	$	4.53		12	%
Oil volume – barrels per day		81		97		(16	%)		87		105		(17	%)
Average oil price – per barrel	$	77.58	$	56.38		38	%	$	77.25	$	46.41		66	%
NGL volume – barrels per day		9		17		(47	%)		10		16		(38	%)
Average NGL price – per barrel	$	44.76	$	28.37		58	%	$	50.28	$	26.30		91	%

Oil and Gas Sales

     Natural gas sales totaled $727,559 in the second quarter of 2010, increasing $510,737 or 236 percent from the same period in 2009. Natural gas volumes increased 157 percent from the second quarter of 2009, boosting sales by $445,008. The Matagorda Island 681/682 field was shut-in for repairs to a third-party pipeline for all of the second-quarter 2009, while the field was on production for substantially all of the second quarter of 2010. The Partnership’s average realized natural gas price for the quarter increased $1.04 per Mcf, or 30 percent, from the second quarter of 2009, increasing sales by $65,729 from a year ago.

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     The Partnership’s crude oil sales for the second quarter of 2010 totaled $574,371 or 15 percent higher than the $497,406 of crude oil sales in the second quarter of 2009. The average realized price in the second quarter of 2010 increased $21.19 per barrel, or 38 percent, from the second quarter of 2009, increasing sales by $186,959. Crude oil volumes on a per day basis fell 16 percent during the quarter, dropping from 97 barrels per day in 2009 to 81 barrels per day in 2010. The decline in volumes in 2010 reflected downtime for third-party pipeline repairs and recompletion activities at SouthTimbalier 295.

     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. Apache and the Partnership are currently reviewing their options for restoring production. Production from the field accounted for approximately 47 percent of the Partnership’s total second quarter oil and gas sales and 44 percent of oil and gas sales for the first six months of 2010.

     During the second quarter of 2010, the Partnership sold 9 barrels per day of natural gas liquids, down from 17 barrels per day during the second quarter of 2009. The decrease reflected lower production from South Timbalier 295 during the current quarter compared to the second quarter of 2009.

     Natural gas sales for the first half of 2010 increased 89 percent from a year ago, rising to $1,762,693 in the current period. A 68 percent increase in natural gas volumes during the first six months of 2010 from the same period a year ago boosted sales by $714,774 while a 12 percent increase in the Partnership’s average gas price increased sales by $114,246. 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. The Partnership’s average realized gas prices increased to $5.09 per Mcf in 2010 from $4.53 per Mcf in the first six months of 2009.

     Crude oil sales for the six months of 2010 increased 37 percent from the same period in the prior year. Oil sales increased from $880,680 in the first six months of 2009 to $1,209,802 in the first six months of 2010. A $30.84 per barrel increase in oil prices from a year ago raised sales by $585,268 while an 18 barrel per day decline in production offset $256,146 of the gain from higher prices. The Partnership’s average realized price for the oil increased 66 percent between the second-quarter 2010 and 2009, rising to $77.25 per barrel in 2010. The Partnership’s crude oil volumes decreased from 105 barrels per day during the first six months of 2009 to 87 barrels per day during the same period of 2010 as a result of natural declines in the South Timbalier 295 field and downtime in the field during the second quarter of 2010.

     The Partnership sold 10 barrels per day of natural gas liquids in the first half of 2010, down from 16 barrels per day in the first half 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 17 percent during the second quarter of 2010 compared to 24 percent for the same period in 2009. DD&A, expressed as a percentage of oil and gas sales, for the six months was 19 percent and 25 percent for the respective years. The lower rates as a percentage of sales reflected higher oil and gas prices in 2010 and favorable reserve revisions recognized during the fourth quarter of 2009.

     The Partnership recognized $29,130 in asset retirement obligation accretion for the second quarter of 2010 compared to $16,700 for the second quarter of 2009. For the six months ending June 30, 2010 and 2009, the Partnership recognized $59,116 and $33,159, respectively. The increases reflected the increase in the Partnership’s asset retirement obligation liability during the fourth quarter of 2009. Gathering and transportation costs increased 179 percent for the quarterly period and 103 percent for the six month period with increases in gas sales volumes.

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     Lease operating expenses (LOE) for the second quarter of 2010 of $256,827 decreased 32 percent from the second quarter of 2009 on lower workover and repair and maintenance costs. Maintenance was performed on the Matagorda Island 681 platform during the first half of 2009 while the field was shut-in for third-party pipeline repairs and workovers were performed by an outside operator on North Padre 969/976 during the second quarter of 2009.

     LOE for the first half of 2010 was down 33 percent from the same period a year ago, dropping to $509,872 in the first half of 2010. During the first six months of 2009, the Partnership participated in workovers on three wells at North Padre Island and two wells at South Timbalier 295. LOE for the first six months of 2009 also included repairs to a compressor on the South Timbalier 295 platform and maintenance cost at Matagorda Island 681. The Partnership has not had any significant repair projects during the first half of 2010. Administrative expense for 2010 decreased three percent for the six-month period.

Capital Resources and Liquidity

     The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $2.4 million for the first six months of 2010. Net cash provided by operating activities during the first six months of 2010 was up 147 percent from a year ago as a result of an increase in oil and gas prices, increased gas volumes and lower operating costs. Future cash flows will be influenced by fluctuations in these same components.

     At June 30, 2010, the Partnership had approximately $4.2 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 first half 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.

     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.

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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 June 30, 2010. The Partnership did not have any contractual obligations as of June 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 capital expenditures totaled $238,034 during the six months of 2010, of which $75,011 was paid in cash during the period. During the second quarter, the Partnership participated in recompletions on the South Timbalier 295 A-17 and A-24 wells and those operations continued into the third quarter. During the first six months of 2009, the Partnership’s capital expenditures totaled $585,864 as it participated in two recompletion projects during the first half of 2009 and also participated in drilling a development well at North Padre Island 969.

     The Partnership expects to participate in drilling four wells at Ship Shoal 258/259 during second half of 2010, although the timing may be delayed for permitting and other issues stemming from the Deepwater Horizon incident discussed below. The Partnership also plans to participate in recompletions at North Padre Island 969/976 during 2010 to help maintain production and develop the Partnership’s proved undeveloped reserves. Based on information supplied by the operators of the properties, the Partnership anticipates capital expenditures of approximately $3.0 million for the remainder of 2010. 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 half 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 half 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. If commodity prices remain at or decline from levels realized during the first half of 2010 and the Partnership participates in 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. The Partnership did not repurchase any Units during the first half of 2010, as a result of the Partnership’s limited amount of cash available for discretionary purposes. 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. The Partnership did not repurchase any Units during the first half of 2009.

     The Partnership is not in a position to predict how many Units will be presented for repurchase during the remainder of 2010 and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase any Units. The Partnership has no obligation to purchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

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. As of the date of this filing it appears that the well has been contained as efforts to permanently cap the well proceed. Remediation of the environmental impacts of the spill is ongoing. The Partnership does not own an interest in the field.

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     As a result of the incident and spill, the U.S. Department of 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 BOEM, 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 BOEM would not consider drilling permits for deepwater wells and related activities for a period of six months. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the DOI has appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal is pending. On July 12, 2010, the Secretary of the DOI directed the BOEM to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities, rather than a moratorium based on water depths.

     In addition on June 8, 2010, the BOEM issued a Notice to Lessees, NTL-05, focusing on increased safety measures. This NTL specifically affects all drilling wells, workovers and anything with a blowout preventer. It requires:

• Third party review and certification of blowout preventers/shear rams

• Professional engineer certification of well plan and cement procedures

• Chief Executive Officer certification that the operator is in compliance with and is conducting all operations in accordance with all operating regulations found at 30 CFR 250

     On June 18, 2010, the BOEM issued a Notice to Lessees, NTL-06, focusing on operator’s plans for a blowout scenario and worst case discharge scenario. This NTL specifically affects all new drilling wells, and sidetracks that cross lease lines. It requires:

• Detailed response plans for a blowout event including relief well rig availability and timing to contract a rig, move it onsite and drill a relief well

• Calculation of Worst Case Discharge (WCD) scenario including all models, calculations and assumptions used to calculate daily discharge rate

• Measures that operator would propose to enhance the ability to prevent or reduce the likelihood of a blowout

     The drilling suspension, lack of certainty and continuing delays in approval of drilling permits may also result in an exodus of both deepwater and shallow-water drilling rigs as they seek opportunities outside the Gulf of Mexico, and potentially lead to cold stacking of shallow-water mat rigs that do not have an international option.

     The Partnership’s operations likely will be impacted in the future, by increased regulatory oversight, which may increase the cost of wells and delay drilling and production therefrom. There may be future changes in laws and regulations, increases in insurance costs or decreases in insurance availability, as well as further delays in offshore exploration and drilling activities in the Gulf of Mexico. Once drilling activities are permitted to resume, projects may face additional delays because of increased time for permitting and rig availability.

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.

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     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 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 six 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.

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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 June 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. We also made no changes in the Partnership’s internal controls over financial reporting during the quarter ending June 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Partnership’s 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, 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;

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• 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.

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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 and our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2010. For the quarter ending June 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.

A drilling moratorium in the Gulf of Mexico, or other regulatory initiatives in response to the current oil spill 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 new moratorium will last until November 30, 2010, or until such earlier time that the BOEM determines that drilling operations can proceed safely. 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

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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.

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: August 6, 2010	/s/ Roger B. Plank
	Roger B. Plank President (principal financial officer) of Apache Corporation, Managing Partner
Dated: August 6, 2010	/s/ Rebecca A. Hoyt
	Rebecca A. Hoyt Vice President and Controller (principal accounting officer) of Apache Corporation, Managing Partner