Apache Offshore Investment Partnership (AOIP) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

OR

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

For the transition period from         to         

Commission File Number: 0-13546

APACHE OFFSHORE INVESTMENT PARTNERSHIP

(Exact name of registrant as specified in its charter)

Delaware	41-1464066
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

(Address of principal executive offices)

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

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

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

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

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

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

Number of registrant’s units outstanding as of June 30, 2012 1,022

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

APACHE OFFSHORE INVESTMENT PARTNERSHIP

STATEMENT OF CONSOLIDATED INCOME

(Unaudited)

	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
REVENUES:
Oil and gas sales	$	914,436	$	1,078,328	$	2,309,202	$	1,816,470
Interest income		6		8		6		8
		914,442		1,078,336		2,309,208		1,816,478
EXPENSES:
Depreciation, depletion and amortization		189,944		220,211		467,565		374,025
Asset retirement obligation accretion		30,294		32,888		60,154		65,300
Lease operating expenses		299,208		241,549		637,006		481,911
Gathering and transportation costs		21,131		36,633		80,820		71,005
Administrative		99,250		100,750		198,500		201,500
		639,827		632,031		1,444,045		1,193,741
NET INCOME	$	274,615	$	446,305	$	865,163	$	622,737
NET INCOME ALLOCATED TO:
Managing Partner	$	90,251	$	129,523	$	258,497	$	194,352
Investing Partners		184,364		316,782		606,666		428,385
	$	274,615	$	446,305	$	865,163	$	622,737
NET INCOME PER INVESTING PARTNER UNIT	$	180	$	310	$	594	$	419
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 Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	865,163		$	622,737
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		467,565			374,025
Asset retirement obligation accretion		60,154			65,300
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables		217,512			(77,508	)
Increase (decrease) in receivable from/payable to Apache Corporation		(106,332	)		(118,440	)
Increase (decrease) in accrued operating expenses		(297,623	)		3,025
Net cash provided by operating activities		1,206,439			869,139
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties		(37,155	)		(2,391,635	)
Net cash used in investing activities		(37,155	)		(2,391,635	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Investing Partners		—			—
Distributions to Managing Partner		(316,523	)		(85,501	)
Net cash used in financing activities		(316,523	)		(85,501	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		852,761			(1,607,997	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		1,404,394			2,971,900
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,257,155		$	1,363,903

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, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,257,155		$	1,404,394
Accrued revenues receivable		71,683			289,195
		2,328,838			1,693,589
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties		194,380,830			194,492,252
Less – Accumulated depreciation, depletion and amortization		(185,041,760	)		(184,574,195	)
		9,339,070			9,918,057
	$	11,667,908		$	11,611,646
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Payable to Apache Corporation	$	56,099		$	162,431
Accrued operating expenses		108,857			406,480
Accrued development costs		—			148,577
		164,956			717,488
ASSET RETIREMENT OBLIGATION		2,095,803			2,035,649
PARTNERS’ CAPITAL:
Managing Partner		449,339			507,365
Investing Partners (1,021.5 units outstanding)		8,957,810			8,351,144
		9,407,149			8,858,509
	$	11,667,908		$	11,611,646

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, 2011, 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, 2012, 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, 2011.

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 2012. The per-unit value was determined to be $15,516 based on the valuation date of December 31, 2011. The Partnership did not repurchase any Investing Partner Units (Units) during the first half of 2012 as a result of the Partnership’s limited amount of cash available for discretionary purposes.

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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 2012 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 the changes to the Partnership’s asset retirement obligation liability for the first six months of 2012:

Asset retirement obligation at December 31, 2011	$	2,035,649
Accretion expense		60,154
Asset retirement obligation at June 30, 2012	$	2,095,803

5. FAIR VALUE MEASUREMENTS

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

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable -

As of June 30, 2012, and December 31, 2011, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the six months ended June 30, 2012, and 2011.

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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, 2012, 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, 2011, and the year then ended, and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

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 $274,615 for the second quarter of 2012, down from $446,305 in the second quarter of 2011. Net income per Investing Partner Unit decreased to $180 per Unit in the second quarter of 2012, down from $310 per Unit in the second quarter of 2011. Lower realized gas prices, lower gas production, and higher operating expenses in 2012 contributed to the decrease in earnings and net income per Investing Partner Unit from 2011.

Net income for the six months ending June 30, 2012, totaled $865,163 compared to $622,737 for the six months ending June 30, 2011. Net income per Investing Partner Unit for the six-month period ending June 30, 2012, of $594 was up from $419 per Unit in the first six months of 2011. The improved results reflected the resumption of production from South Timbalier 295 and higher realized oil prices in 2012. Further gains in earnings were offset by lower gas prices and gas production in 2012.

The Partnership’s production from South Timbalier 295 was shut-in from July 11, 2010, through June 14, 2011 as a result of a leak in a third-party pipeline, significantly reducing the Partnership’s revenues, earnings, cash flow from operating activities and liquidity in 2011. The Partnership’s oil production increased from 14 barrels per day during the first six months of 2011 to 82 barrels per day during the six months of 2012 as the Partnership’s largest source of revenue, South Timbalier, returned to production.

Total revenues decreased 15 percent from the second quarter of 2011 to the second quarter of 2012 on lower gas volumes and prices in the second quarter of 2012. Year-to-date revenues in 2012 increased 27 percent from the first half of 2011 on the higher oil production from South Timbalier 295 and a five percent increase in oil prices.

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

	For the Quarter Ended June 30,							For the Six Months Ended June 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
Gas volume – Mcf per day		996		1,931		(48	)%		1,195		1,756		(32	)%
Average gas price – per Mcf	$	2.30	$	4.31		(47	)%	$	2.51	$	4.31		(42	)%
Oil volume – barrels per day		70		24		192	%		82		14		486	%
Average oil price – per barrel	$	107.84	$	107.81		—		$	111.21	$	106.27		5	%
NGL volume – barrels per day		13		16		(19	)%		16		20		(20	)%
Average NGL price – per barrel	$	19.62	$	61.37		(68	)%	$	36.26	$	50.15		(28	)%

Oil and Gas Sales

Natural gas sales totaled $208,243 in the second quarter of 2012, decreasing $549,743 or 73 percent from the same period in 2011. The Partnership’s average realized natural gas price for the quarter decreased $2.01 per Mcf, or 47 percent, from the second quarter of 2011, reducing sales by $353,287 from a year ago. Natural gas volumes declined 48 percent from the second quarter of 2011, decreasing sales by $196,456. The decline in the Partnership’s

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production from 2011 was attributable to the shut-in of North Padre Island 969/976 and Matagorda 681/682 for repairs to third-party pipelines and to natural depletion which has reduced sales volumes from all of the Partnership’s properties. While North Padre Island 969/976 was back on production by the end of the quarter, the shut-in of the field for most of the second quarter of 2012 reduced sales for the period by approximately 200 Mcf per day. Matagorda 681/682 was shut-in for pipeline repairs for 22 days during the second quarter of 2012, reducing sales for the period by approximately 80 Mcf per day.

The Partnership’s crude oil sales for the second quarter of 2012 totaled $683,689 or nearly three times higher than the $232,821 of crude oil sales in the second quarter of 2011. Crude oil volumes on a per day basis were nearly three times the prior year period, increasing from 24 barrels per day in 2011 to 70 barrels per day in 2012. The increase in volumes in 2012 was attributable to the resumption of production after the shut-in of South Timbalier 295 for the construction of a new pipeline in 2011. Further gains in production in 2012 were tempered by the 2012 shut-in of South Timbalier 295 for a total of approximately 18 days during the second quarter of 2012 to investigate a possible oil leak and for repairs to a third-party pipeline. The average realized price in the second quarter of 2012 increased $0.03 per barrel from the second quarter of 2011.

During the second quarter of 2012, the Partnership sold 13 barrels per day of natural gas liquids, down from 16 barrels per day during the second quarter of 2011. The decrease reflected a decline in processed volumes at Ship Shoal 258/259 from 2011. The lower average realized NGL price for the second quarter of 2012 reflected declining product prices with an abundant supply of liquid products in the U.S. and adjustments from a plant operator to prior net processing revenues.

Natural gas sales for the first half of 2012 decreased 60 percent from a year ago, dropping to $546,977 in the current period. The Partnership’s average realized gas prices decreased from $4.31 per Mcf in the first six months of 2011 to $2.51 per Mcf in 2012, reducing sales by $572,184. A 32 percent decrease in natural gas volumes during the first six months of 2012 from the same period a year ago curtailed sales by $252,408. The Partnership’s gas production in 2012 was hindered by the shut-in of North Padre Island 969/976 during the second quarter of 2012 and declining production from Ship Shoal 258/259 and Matagorda Island 681/682.

Crude oil sales for the six months of 2012 of $1.7 million were more than six times the same period in 2011. The Partnership’s crude oil volumes increased from 14 barrels per day during the first six months of 2011 to 82 barrels per day during the same period of 2012 as a result of the shut-in of production at South Timbalier 295 in 2011. The Partnership’s average realized price for oil increased five percent between the first half of 2011 and 2012, rising to $111.21 per barrel in 2012.

The Partnership sold 16 barrels per day of natural gas liquids in the first half of 2012, down from 20 barrels per day in the first half of 2011. The decrease reflected lower processed volumes at Ship Shoal 258/259 in 2012.

Since the Partnership does not anticipate acquiring additional acreage or conducting exploratory drilling on leases in which it currently holds an interest, declines in oil and gas production can be expected in future periods as a result of natural depletion. Also, given the small number of producing wells owned by the Partnership and exposure to inclement weather in the Gulf of Mexico, the Partnership’s production in the second half of 2012 and beyond may be subject to more volatility than those companies with a larger or more diversified property portfolio.

Operating Expenses

The Partnership’s depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, was approximately 21 percent during the second quarter of 2012 compared to 20 percent for the same period in 2011. DD&A, expressed as a percentage of oil and gas sales, for the first six months of 2012 and 2011 was 20 percent and 21 percent, respectively. The dollar amount of DD&A expense for the first six months of 2012 increased from a year ago as a result of the higher sales from South Timbalier 295.

The Partnership recognized $30,294 in asset retirement obligation accretion for the second quarter of 2012 compared to $32,888 for the second quarter of 2011. For the six months ending June 30, 2012 and 2011, the Partnership recognized $60,154 and $65,300, respectively. The decline in accretion expense from a year ago reflected the decrease in the Partnership’s asset retirement obligation liability for plugging operations performed in 2011.

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Lease operating expenses (LOE) for the second quarter of 2012 of $299,208 increased 24 percent from the second quarter of 2011 on higher workover, maintenance, and transportation costs for personnel and materials. LOE for the first half of 2012 was up 32 percent from the same period a year ago, increasing to $637,006 in the first half of 2012, reflecting higher workover and transportation costs for personnel and materials during the first half of 2012.

In the second quarter of 2012, gathering and transportation costs for the delivery of oil and gas decreased 42 percent from the same period in 2011 on lower gas volumes and in the first half of 2012, gathering and transportation costs increased 14 percent from the same period in 2011. Administrative expense for 2012 decreased one percent for the six-month period compared to the same period in 2011.

Capital Resources and Liquidity

The Partnership’s primary capital resource is net cash provided by operating activities, which totaled $1.2 million for the first six months of 2012. Net cash provided by operating activities during the first six months of 2012 was up from $869,139 in 2011 when production from South Timbalier 295 was shut-in for the majority of the period.

At June 30, 2012, the Partnership had approximately $2.3 million in cash and cash equivalents, up from approximately $1.4 million at December 31, 2011. The Partnership’s goal of maintaining cash at least sufficient to cover the undiscounted value of its future asset retirement obligation (ARO) liability had to be temporarily suspended in 2011 as a result of the Partnership’s production from South Timbalier 295 being shut-in for nearly a year and the Partnership’s capital expenditures at Ship Shoal 258/259 and South Timbalier 295. The Partnership intends to replenish cash reserves in 2012 with cash from operating activities.

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

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

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

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

Capital Commitments

The Partnership’s primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. To the extent there is discretion, the Partnership allocates available capital to investment in the Partnership’s properties so as to maximize production and resultant cash flow. The Partnership had no outstanding debt or lease commitments at June 30, 2012. The Partnership did not have any contractual obligations as of June 30, 2012, 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.

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During the first six months of 2012 the Partnership had only small outlays for capital expenditures as it did not commence any new drilling or recompletion projects during the period. The Partnership’s capital expenditures during the first six months of 2011 totaled $2.4 million as the Partnership participated in drilling two wells at Ship Shoal 258/259 during the period and completed the construction of a new sales line from South Timbalier 295 . Based on information supplied by the operators of the properties, the Partnership anticipates capital expenditures of less than $1.0 million for 2012 as no new drilling projects are currently planned for 2012. Capital estimates may change based on realized prices, changes by the operator to the development plan, pipeline construction or modifications, or changes in government regulations.

Because of low natural gas prices during the first six months of 2012, the large amount of capital expenditures funded by the Partnership during 2011, the loss of revenue in 2011 from the shut-in of South Timbalier 295, and the need to replenish cash reserves for future asset retirement obligations, no distributions were made to Investing Partners during the first six months of 2012. The Partnership also made no distribution to Investing Partners during the first six months of 2011, as the Partnership increased cash reserves in anticipation of drilling activities during the second half of 2011.

The amount of future distributions will be dependent on actual and expected production levels, realized and anticipated oil and gas prices, expected drilling and recompletion expenditures, and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership’s reserves are depleted. The Partnership’s goal is to maintain cash and cash equivalents in the Partnership at least sufficient to cover the undiscounted value of its future asset retirement obligations. With continued low gas prices, declining production, and the need to replenish the Partnership’s cash reserves for future ARO expenditures, the Partnership may not fund a distribution to Investing Partners during the remainder of 2012. The Partnership will review available funds, production and pricing trends, capital commitments, and the need to reserve funds for potential pipeline interruptions, similar to recent interruptions which have adversely impacted the Partnership’s liquidity, to determine if sufficient funds are available for a distribution to the Investing Partners during the fourth quarter of 2012.

As provided in the Amended Partnership Agreement, a first right of presentment valuation was computed during the first quarter of 2012. The per-unit value was determined to be $15,516 based on the valuation date of December 31, 2011. The Partnership did not repurchase any Units during the first half of 2012, 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 2011 based on the valuation date of December 31, 2010, was $14,917. The Partnership did not repurchase any Units during the first half of 2011.

The Partnership is not in a position to predict how many Units will be presented for repurchase during the remainder of 2012 and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase any Units. Pursuant to the Amended Partnership Agreement, the Partnership has no obligation to repurchase any Units presented to the extent it determines that it has insufficient funds for such purchases.

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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 continue to be volatile and unpredictable. The Partnership has not used derivative financial instruments or otherwise engaged in hedging activities during 2011 or the first six months of 2012.

The information set forth under “Commodity Risk” in Item 7A of the Partnership’s Form 10-K for the year ended December 31, 2011, 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 Thomas P. Chambers, the Managing Partner’s Executive Vice President and Chief Financial Officer (in his capacity as principal financial officer), evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of June 30, 2012, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Partnership’s disclosure controls and procedures were effective, providing effective means to ensure that the information it is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified under the Commission’s rules and forms and communicated to our management, including the Managing Partner’s principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

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

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, 2011, 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;

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• capital expenditure and other contractual obligations;

• weather conditions;

• inflation rates;

• the availability of goods and services;

• legislative or regulatory changes;

• terrorism;

• occurrence of property acquisitions or divestitures;

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

• other factors disclosed under Items 1 and 2 – “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A – “Risk Factors,” Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A – “Quantitative and Qualitative Disclosures About Market Risk,” and elsewhere in our most recently filed Form 10-K.

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

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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, 2011 and as noted above in Part I, Item 3 of this Form 10-Q. For the six months ending June 30, 2012, the Partnership notes the following updated risk factor:

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:

• well blowouts, explosions, and cratering;

• pipeline ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions;

• hurricanes which could affect our operations on- and offshore the Gulf Coast, and other natural disasters; and

• surface spillage and water contamination from petroleum constituents or hydraulic fracturing chemical additives

Failure or loss of equipment, as the result of equipment malfunctions, cyber-attacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we 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, or water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout, or pipeline rupture or surface spillage and water contamination from petroleum constituents or hydraulic fracturing chemical additives could result in extensive 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 flows, and, in turn, our results of operations could be materially and adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY IN SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

a. Exhibits

*3.1	Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit (3)(i) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
*3.2	Amendment No. 1, dated February 11, 1994, to the Partnership Agreement of Apache Offshore Investment Partnership (incorporated by reference to Exhibit 3.3 to Partnership’s Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 0-13546).
*3.3	Limited Partnership Agreement of Apache Offshore Petroleum Limited Partnership (incorporated by reference to Exhibit (3)(ii) to Form 10 filed by Partnership with the Commission on April 30, 1985, Commission File No. 0-13546).
**31.1	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer
**31.2	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer
**32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer
***101.INS	XBRL Instance Document.
***101.SCH	XBRL Taxonomy Schema Document.
***101.CAL	XBRL Calculation Linkbase Document.
***101.LAB	XBRL Label Linkbase Document.
***101.PRE	XBRL Presentation Linkbase Document.

* Incorporated by reference herein.

** Filed herewith.

*** Furnished herewith.

12

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 7, 2012	/s/ Thomas P. Chambers
	Thomas P. Chambers
	Executive Vice President and Chief Financial Officer (principal financial officer) of Apache Corporation, Managing Partner
Dated: August 7, 2012	/s/ Rebecca A. Hoyt
	Rebecca A. Hoyt
	Vice President, Chief Accounting Officer and Controller (principal accounting officer) of Apache Corporation, Managing Partner