(1) ORGANIZATION

Nature of Operations

Apache Offshore Investment Partnership, a Delaware general partnership (the Investment Partnership), was formed on October 31, 1983, consisting of Apache Corporation (Apache or 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 primary business of the Operating Partnership is to conduct oil and gas exploration, development and production operations. The Operating Partnership conducts the operations of the Investment Partnership. The accompanying financial statements include the accounts of both the Investment Partnership and Operating Partnership. Apache is the general partner of both the Investment and Operating partnerships, and held approximately five percent of the 1,021.5 Investing Partner Units (Units) outstanding at December 31, 2011. The term “Partnership”, as used hereafter, refers to the Investment Partnership or the Operating Partnership, as the case may be.

The Partnership purchased, at cost, an 85 percent interest in offshore leasehold interests acquired by Apache as a co-venturer in a series of oil and gas exploration, development and production activities on 87 federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The remaining 15 percent interest was purchased by an affiliated partnership or retained by Apache. The Partnership acquired an increased net revenue interest in Matagorda Island Blocks 681 and 682 in November 1992, when the Partnership and Apache formed a joint venture to acquire a 92.6 percent working interest in the blocks.

Since inception, the Partnership has participated in 14 federal offshore lease sales in which 49 prospects were acquired (over the same period, 45 of those prospects have been surrendered/sold). The Partnership’s working interests in the four remaining venture prospects range from 6.29 percent to 7.08 percent. As of December 31, 2011, the Partnership held a remaining interest in nine tracts acquired through federal lease sales.

The Partnership’s future financial condition and results of operations will depend largely upon prices received for its oil and natural gas production and the costs of acquiring, finding, developing and producing reserves. 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.

Under the terms of the Partnership Agreements, the Investing Partners receive 80 percent and Apache receives 20 percent of revenue. Lease operating, gathering and transportation, and administrative expenses are allocated to the Investing Partners and Apache in the same proportion as revenues. The Investing Partners receive 100 percent of the interest income earned on short-term cash investments. The Investing Partners generally pay for 90 percent and Apache generally pays for 10 percent of exploration and development costs and expenses incurred by the Partnership. However, intangible drilling costs, interest costs and fees or expenses related to the loans incurred by the Partnership are allocated 99 percent to the Investing Partners and one percent to Apache until such time as the amount so allocated to the Investing Partners equals 90 percent of the total amount of such costs, including such costs incurred by Apache prior to the formation of the Partnership.

Right of Presentment

In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. The Partnership did not offer to purchase any Units from Investing Partners in 2011, 2010 or 2009 as a result of the limited amount of cash available for discretionary purposes.

The Partnership is not in a position to predict how many Units will be presented for repurchase during 2012; however, no more than 10 percent of the outstanding Units may be purchased under the right of presentment in any year. The Partnership has no obligation to purchase any Units presented to the extent that it determines that it has insufficient funds for such purchases.

The table below sets forth the total repurchase price and the repurchase price per Unit for all outstanding Units at each presentment period, based on the right of presentment valuation formula defined in the amendment to the Partnership Agreement. The right of presentment offers made twice annually are based on a discounted Unit value formula. The discounted Unit value will be not less than the Investing Partner’s share of: (a) the sum of (i) 70 percent of the discounted estimated future net revenues from proved reserves, discounted at a rate of 1.5 percent over prime or First National Bank of Chicago’s base rate in effect at the time the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv) accounts receivable less a reasonable reserve for doubtful accounts, (v) oil and gas properties other than proved reserves at cost less any amounts attributable to drilling and completion costs incurred by the Partnership and included therein, and (vi) the book value of all other assets of the Partnership, less the debts, obligations and other liabilities of all kinds (including accrued expenses) then allocable to such interest in the Partnership, all determined as of the valuation date, divided by (b) the number of Units, and fractions thereof, outstanding as of the valuation date. The discounted Unit value does not purport to be, and may be substantially different from, the fair market value of a Unit.

 

Right of Presentment Valuation Date		Total  Valuation Price				Valuation Price  Per Unit
December 31, 2008		$	9,701,665			$	9,497
June 30, 2009			8,864,008				8,677
December 31, 2009			15,742,174				15,411
June 30, 2010			16,477,118				16,130
December 31, 2010			15,237,383				14,917
June 30, 2011			13,790,742				13,500

 

Investing Partner Units Outstanding:		2011				2010				2009
Balance, beginning of year			1,021.5				1,021.5				1,021.5
Repurchase of Partnership Units			—				—				—
Balance, end of year			1,021.5				1,021.5				1,021.5

Capital Contributions

A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2011. The Partnership determined the full purchase price of $150,000 per Unit was not needed, and upon completion of the last subscription call in November 1989, released the Investing Partners from their remaining liability. As a result of investors defaulting on cash calls and repurchases under the presentment offer discussed above, the original 1,500 Units have been reduced to 1,021.5 Units at December 31, 2011.

 

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by the Partnership reflect industry practices and conform to accounting principles generally accepted in the United States (GAAP). Significant policies are discussed below.

Statement Presentation

The accompanying consolidated financial statements include the accounts of Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States and the disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. The Partnership evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. (see the unaudited “Supplemental Oil and Gas Disclosures” below) and assessing asset retirement obligations (see Note 8 — Asset Retirement Obligation).

Cash Equivalents

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2011 and 2010, the Partnership had $1.4 million and $3.0 million, respectively, of cash and cash equivalents.

Oil and Gas Properties

The Partnership follows the full-cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method of accounting, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. Costs associated with production and administrative functions are expensed in the period incurred. The Partnership includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance as described in Note 8. Unless a significant portion of the Partnership’s reserve volumes are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains or losses are not recognized.

Capitalized costs of oil and gas properties are amortized on the future gross revenue method whereby depreciation, depletion and amortization (DD&A) expense is computed quarterly by dividing current period oil and gas sales by estimated future gross revenue from proved oil and gas reserves (including current period oil and gas sales) and applying the resulting rate to the net cost of evaluated oil and gas properties, including estimated future development costs.

Under the full-cost method of accounting, the Partnership limits the capitalized costs of proved oil and gas properties, net of accumulated DD&A, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, if any. This ceiling test is performed each quarter. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional DD&A in the accompanying statement of consolidated income. In 2009, the Partnership adopted U.S. Securities and Exchange Commission (SEC) Release 33-8995 and the amendments to Accounting Standards Codification (ASC) Topic 932 “Extractive Industries—Oil and Gas” (the Modernization Rules). Under the Modernization Rules, estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements. Prior to December 31, 2009, estimated future net cash flows were calculated using commodity prices in effect at the end of each quarter. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. Please see “Future Net Cash Flows” in the Supplemental Oil and Gas Disclosures included in this Form 10-K for a discussion on calculation of estimated future net cash flows.

Asset Retirement Obligation

The initial estimated asset retirement obligation related to properties is recorded as a liability, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. Accretion expense on the liability is recognized over the estimated productive life of the related assets. If the fair value of the recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

Revenue Recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. The Partnership uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. As of December 31, 2011 and 2010, the Partnership did not have any liabilities for imbalances in excess of remaining reserves. No receivables are recorded for those wells where the Partnership has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas revenues and future cash flows in the unaudited supplemental oil and gas disclosures. Adjustments for gas imbalances totaled less than one percent of the Partnership’s proved gas reserves at December 31, 2011 and 2010.

Insurance Coverage

The Partnership recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

Net Income Per Investing Unit

The net income per Investing Partner Unit is calculated by dividing the aggregate Investing Partners’ net income for the period by the number of weighted average Investing Partner Units outstanding for that period.

Income Taxes

The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements.

Receivable from / Payable to Apache Corporation

The receivable from/payable to Apache Corporation, the Partnership’s Managing Partner (Apache or the Managing Partner), 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.

 

Maintenance and Repairs

Maintenance and repairs are charged to expense as incurred.

Recently Issued Accounting Standards Not Yet Adopted

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04, which amends ASC Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Partnership does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

(3) COMPENSATION TO AFFILIATES

Apache is entitled to the following types of compensation and reimbursement for costs and expenses.

 

		Total Reimbursed by the Investing Partners for the Year Ended December 31,
		2011				2010				2009
		(In thousands)
a.      Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership’s business		$	318			$	322			$	334
b.      Apache is reimbursed for development overhead costs incurred in the Partnership’s operations. These costs are based on development activities and are capitalized to oil and gas properties		$	61			$	53			$	30

Apache operates certain Partnership properties. Billings to the Partnership are made on the same basis as to unaffiliated third parties or at prevailing industry rates.

 

(4) OIL AND GAS PROPERTIES

The following tables contain direct cost information and changes in the Partnership’s oil and gas properties for each of the years ended December 31. All costs of oil and gas properties are currently being amortized.

 

		2011				2010				2009
		(In thousands)
Oil and Gas Properties
Balance, beginning of year		$	191,277			$	188,458			$	186,955
Costs incurred during the year:
Development –
Investing Partners			3,084				2,735				1,407
Managing Partner			131				84				96
Balance, end of year		$	194,492			$	191,277			$	188,458

Development cost for 2011, 2010 and 2009 includes $0.3 million, $0.2 million and $0.9 million, respectively, of asset retirement cost.

 

		Managing Partner				Investing Partners				Total
		(In thousands)
Accumulated Depreciation, Depletion and Amortization
Balance, December 31, 2008		$	20,913			$	160,825			$	181,738
Provision			18				942				960
Balance, December 31, 2009		$	20,931			$	161,767			$	182,698
Provision			21				801				822
Balance, December 31, 2010		$	20,952			$	162,568			$	183,520
Provision			33				1,021				1,054
Balance, December 31, 2011		$	20,985			$	163,589			$	184,574

The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2011, 2010 and 2009 was 20 percent, 19 percent and 22 percent, respectively.

(5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION

Revenues received from major third party customers that equaled ten percent or more of oil and gas sales are discussed below. No other third party customers individually accounted for ten percent or more of oil and gas sales.

In 2011, sales to Shell Trading Company accounted for 42 percent of the Partnership’s oil and gas sales for the year. In 2010, sales to Shell Trading Company, Florida Power Corporation and Sequent Energy Management LP accounted for 30 percent, 16 percent and 10 percent, respectively, of the Partnership’s oil and gas sales for the year. Sales to Shell Trading Company accounted for 48 percent of the Partnership’s oil and gas sales in 2009.

Effective November 1992, with Apache’s and the Partnership’s acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees totaling $26,553 in 2011, $40,562 in 2010 and $24,210 in 2009 for the Partnership’s share of gas. The fees were at the same rates and terms as previously paid to Shell.

All transactions with related parties were consummated at fair value.

 

The Partnership’s revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. The Partnership has not experienced material credit losses on such sales.

(6) 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 Receivables and Accounts Payable —

As of December 31, 2011 and 2010, 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 three-year period ended December 31, 2011.

(7) COMMITMENTS AND CONTINGENCIES

Litigation – The Partnership is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache’s management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations.

Environmental – The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. Apache maintains insurance coverage on the Partnership’s properties, which it believes is customary in the industry, although the Partnership is not fully insured against all environmental risks.

(8) ASSET RETIREMENT OBLIGATION

The following table describes changes to the Partnership’s ARO liability for the years ended December 31, 2011 and 2010:

 

		2011				2010
Asset retirement obligation at beginning of year		$	2,209,662			$	2,043,895
Accretion expense			132,120				118,557
Liabilities settled			(635,930	)			(180,941	)
Revisions in estimated liabilities			329,797				228,151
Asset retirement obligation at end of year		$	2,035,649			$	2,209,662

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

Liabilities settled primarily relate to individual wells plugged and abandoned during the periods presented. Revisions to estimated liabilities in 2011 reflected the Managing Partner’s updated estimates of the extent of the work required and cost involved in the dismantlement and site reclamation of offshore properties, and shorter reserve lives projected for certain of the Partnership’s properties.

 

(9) TAX-BASIS FINANCIAL INFORMATION

A reconciliation of ordinary income for federal income tax reporting purposes to net income under accounting principles generally accepted in the United States is as follows:

 

		2011				2010				2009
Net partnership ordinary income (loss) for federal income tax reporting purposes		$	(49,125	)		$	(25,363	)		$	1,464,728
Plus: Items of current expense for tax reporting purposes only –
Intangible drilling cost			2,058,342				2,142,424				579,318
Dismantlement and abandonment cost			635,930				180,941				37,720
Tax depreciation			344,080				197,479				278,246
			3,038,352				2,520,844				895,284
Less: full cost DD&A expense			(1,053,964	)			(822,053	)			(960,632	)
Less: asset retirement obligation accretion			(132,120	)			(118,557	)			(67,297	)
Net income		$	1,803,143			$	1,554,871			$	1,332,083

The Partnership’s tax bases in net oil and gas properties at December 31, 2011 and 2010 was $7,374,409 and $5,696,154, respectively, lower than the carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization, intangible drilling costs and dismantlement and abandonment costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2011 and 2010.

A reconciliation of liabilities for federal income tax reporting purposes to liabilities under accounting principles generally accepted in the United States is as follows:

 

		December 31,
		2011				2010
Liabilities for federal income tax purposes		$	717,488			$	1,299,317
Asset retirement liability			2,035,649				2,209,662
Liabilities under accounting principles generally accepted in the United States		$	2,753,137			$	3,508,979

Asset retirement liabilities for future dismantlement and abandonment costs are not recognized for federal income tax reporting purposes until settled.

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

Oil and Gas Reserve Information

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (NGLs) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact.

(Oil in Mbbls and gas in MMcf)

 

			$0000,000				$0000,000				$0000,000				$0000,000				$0000,000				$0000,000
		2011								2010								2009
		Oil				Gas				Oil				Gas				Oil				Gas
Proved Reserves
Beginning of year			561				2,354				555				2,427				492				2,422
Extensions, discoveries and other additions			4				354				15				111				—				—
Revisions of previous estimates			(25	)			11				11				417				105				536
Production			(27	)			(625	)			(20	)			(601	)			(42	)			(531	)
End of year			513				2,094				561				2,354				555				2,427
Proved Developed
Beginning of year			561				2,249				555				2,322				492				2,317
End of year			513				1,989				561				2,249				555				2,322

Oil includes crude oil, condensate and natural gas liquids.

All the Partnership’s reserves are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas.

Approximately 75 percent of the Partnership’s proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced or zones that have been produced in the past, but are not now producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital will have to be spent to access these reserves. The capital and economic impact of production timing are reflected in the Partnership’s standardized measure under Future Net Cash Flows.

Future Net Cash Flows

Future cash inflows were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

Discounted Future Net Cash Flows Relating to Proved Reserves

 

		December 31,
		2011				2010				2009
		(In thousands)
Future cash inflows		$	63,150			$	52,801			$	40,838
Future production costs			(9,578	)			(10,290	)			(7,499	)
Future development costs			(5,344	)			(5,689	)			(6,026	)
Net cash flows			48,228				36,822				27,313
10 percent annual discount rate			(22,296	)			(17,783	)			(12,760	)
Discounted future net cash flows		$	25,932			$	19,039			$	14,553

The following table sets forth the principal sources of change in the discounted future net cash flows:

 

		For the Year Ended December 31,
		2011				2010				2009
		(In thousands)
Sales, net of production costs		$	(3,386	)		$	(2,898	)		$	(2,778	)
Net change in prices and production costs			7,264				3,857				797
Revisions of quantities			(780	)			1,923				4,439
Discoveries and improved recoveries, net of cost			1,680				1,292				—
Accretion of discount			1,904				1,455				1,603
Changes in future development costs			341				336				(843	)
Changes in production rates and other			(130	)			(1,479	)			(4,696	)
		$	6,893			$	4,486			$	(1,478	)

 

APACHE OFFSHORE INVESTMENT PARTNERSHIP

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

(UNAUDITED)

 

			$00,00000				$00,00000				$00,00000				$00,00000				$00,00000
		First				Second				Third				Fourth				Total
		(In thousands, except per Unit amounts)
2011
Revenues		$	738			$	1,078			$	1,754			$	1,625			$	5,195
Expenses			562				632				836				1,362				3,392
Net income		$	176			$	446			$	918			$	263			$	1,803
Net income allocated to:
Managing Partner		$	65			$	129			$	248			$	110			$	552
Investing Partners			111				317				670				153				1,251
		$	176			$	446			$	918			$	263			$	1,803
Net income per Investing Partner Unit (1)		$	109			$	310			$	656			$	150			$	1,225
2010
Revenues		$	1,724			$	1,337			$	596			$	613			$	4,270
Expenses			787				653				558				717				2,715
Net income (loss)		$	937			$	684			$	38			$	(104	)		$	1,555
Net income (loss) allocated to:
Managing Partner		$	253			$	181			$	30			$	3			$	467
Investing Partners			684				503				8				(107	)			1,088
		$	937			$	684			$	38			$	(104	)		$	1,555
Net income (loss) per Investing Partner Unit (1)		$	669			$	493			$	8			$	(105	)		$	1,065

 

(1)	The sum of the individual net income per Investing Partner Unit may not agree with the year-to-date net income per Investing Partner Unit as each quarterly computation is based on the weighted average number of Investing Partner Units during that period.