Apache Offshore Investment Partnership (AOIP) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	AOIP
Entity Registrant Name	APACHE OFFSHORE INVESTMENT PARTNERSHIP
Entity Central Index Key	727,538
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0
Entity Public Float		$ 9,520,126

Statement of Consolidated Opera

Statement of Consolidated Operations - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil and gas sales	$ 1,707,495	$ 2,933,808	$ 3,555,970
Other revenue (loss)	(84,249)
Interest income	88	88	116
Total Revenues	1,623,334	2,933,896	3,556,086
EXPENSES:
Depreciation, depletion and amortization	478,748	577,830	727,861
Asset retirement obligation accretion	126,687	112,566	107,568
Lease operating expenses	756,598	947,111	1,256,031
Gathering and transportation costs	124,806	108,187	116,696
Administrative	364,000	376,000	382,000
Total Expenses	1,850,839	2,121,694	2,590,156
NET INCOME (LOSS)	(227,505)	812,202	965,930
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	47,101	270,751	326,207
Investing Partners	(274,606)	541,451	639,723
NET INCOME (LOSS)	$ (227,505)	$ 812,202	$ 965,930
Net income (loss) per Investing Partner Unit	$ (269)	$ 530	$ 626
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING	1,021.5	1,021.5	1,021.5

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (227,505)	$ 812,202	$ 965,930
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	478,748	577,830	727,861
Asset retirement obligation accretion	126,687	112,566	107,568
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables	161,566	(274,118)	83,551
Increase (decrease) in receivable from/payable to Apache Corporation	17,274	5,868	(83,356)
Increase (decrease) in other payables	84,249
Increase (decrease) in accrued operating expenses	(113,539)	190,563	28,183
Increase (decrease) in asset retirement obligations	(471,934)	(168,927)	(248,843)
Net cash provided by operating activities	55,546	1,255,984	1,580,894
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(30,013)	(35,402)	(19,361)
Net cash used in investing activities	(30,013)	(35,402)	(19,361)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Managing Partner	(54,584)	(265,297)	(360,104)
Net cash used in financing activities	(54,584)	(265,297)	(360,104)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(29,051)	955,285	1,201,429
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	5,275,503	4,320,218	3,118,789
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 5,246,452	$ 5,275,503	$ 4,320,218

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($)	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 5,246,452	$ 5,275,503
Accrued revenues receivable	147,848	309,414
Receivable from Apache Corporation		2,467
Total Current Assets	5,394,300	5,587,384
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties	195,037,054	194,691,102
Less - Accumulated depreciation, depletion and amortization	(187,256,397)	(186,777,649)
Total oil and gas properties, on the basis of full cost accounting	7,780,657	7,913,453
Total Assets	13,174,957	13,500,837
CURRENT LIABILITIES:
Payable to Apache Corporation	14,807
Current asset retirement obligation	524,166	274,921
Other payables	84,249
Accrued operating expenses	229,564	343,103
Accrued development costs	303,136	1,374
Total Current Liabilities	1,155,922	619,398
ASSET RETIREMENT OBLIGATION	1,327,947	1,908,262
PARTNERS' CAPITAL:
Managing Partner	406,879	414,362
Investing Partners (1,021.5 units outstanding)	10,284,209	10,558,815
Total Partners' Capital	10,691,088	10,973,177
Total liabilities and partners' capital	$ 13,174,957	$ 13,500,837

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Investing Partners, units outstanding	1,021.5	1,021.5	1,021.5	1,021.5

Statement of Consolidated Chang

Statement of Consolidated Changes in Partners Capital - USD ($)	Total	Managing Partner [Member]	Investing Partners [Member]
BEGINNING BALANCE at Dec. 31, 2012	$ 9,820,446	$ 442,805	$ 9,377,641
Distributions	(360,104)	(360,104)
Net income (loss)	965,930	326,207	639,723
ENDING BALANCE at Dec. 31, 2013	10,426,272	408,908	10,017,364
Distributions	(265,297)	(265,297)
Net income (loss)	812,202	270,751	541,451
ENDING BALANCE at Dec. 31, 2014	10,973,177	414,362	10,558,815
Distributions	(54,584)	(54,584)
Net income (loss)	(227,505)	47,101	(274,606)
ENDING BALANCE at Dec. 31, 2015	$ 10,691,088	$ 406,879	$ 10,284,209

Organization

Organization	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	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, 2015. 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. The Partnership’s working interests in the two remaining venture prospects at December 31, 2015 range from 6.29 percent to 7.08 percent. The two remaining venture prospects are both located offshore Louisiana. 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 2015, 2014, or 2013 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 2016; 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 Valuation Price Per Unit December 31, 2012 $ 15,743,540 $ 15,412 June 30, 2013 15,958,079 15,622 December 31, 2013 16,364,853 16,020 June 30, 2014 16,609,939 16,260 December 31, 2014 9,975,347 9,765 June 30, 2015 10,042,327 9,831 Investing Partner Units Outstanding: 2015 2014 2013 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, 2015. 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, 2015.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 GAAP 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 Note 10 - Supplemental Oil and Gas Disclosures) and the assessment of 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, 2015 and 2014, the Partnership had $5.2 million and $5.3 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. All costs related to 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 operations. 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. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. See Note 10 - Supplemental Oil and Gas Disclosures for a discussion on the calculation of estimated future net cash flows. Asset Retirement Costs and Obligation The initial estimated asset retirement obligation related to properties is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. 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. Accretion expense on the liability is recognized over the estimated productive life of the related assets. 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. At December 31, 2015, the Partnership carried a liability of $84,249 for gas 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. 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 (Loss) Per Investing Unit The net income (loss) 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, 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. New Pronouncements Issued But Not Yet Adopted In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB announced a delay in the effective date of the revenue standard by one year. The deferral results in the new revenue standard becoming effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Partnership is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

Compensation to Affiliates

Compensation to Affiliates	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Compensation to Affiliates	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, 2015 2014 2013 (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 $ 291 $ 301 $ 306 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 $ — $ — $ 1 Apache operated certain Partnership properties through September 30, 2013, at which time Fieldwood Energy LLC purchased Apache’s interest in South Timbalier 295, Ship Shoal 258/259 and Matagorda Island 681/682 and became operator of these properties. Billings to the Partnership were made on the same basis as to unaffiliated third parties or at prevailing industry rates.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Oil and Gas Properties	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. 2015 2014 2013 (In thousands) Oil and Gas Properties Balance, beginning of year $ 194,691 $ 194,635 $ 194,452 Costs incurred during the year: Development – Investing Partners 314 53 166 Managing Partner 32 3 17 Balance, end of year $ 195,037 $ 194,691 $ 194,635 Development cost for 2015 and 2013 included $0.3 million and $0.2 million, respectively, of asset retirement cost. The Partnership’s 2014 asset retirement cost additions were negligible. Managing Investing Total (In thousands) Accumulated Depreciation, Depletion and Amortization Balance, December 31, 2012 $ 21,012 $ 164,460 $ 185,472 Provision 23 705 728 Balance, December 31, 2013 $ 21,035 $ 165,165 $ 186,200 Provision 19 559 578 Balance, December 31, 2014 $ 21,054 $ 165,724 $ 186,778 Provision 15 463 478 Balance, December 31, 2015 $ 21,069 $ 166,187 $ 187,256 The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2015, 2014, and 2013 was 28 percent, 20 percent and 20 percent, respectively.

Major Customer and Related Part

Major Customer and Related Parties Information	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Major Customer and Related Parties Information	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. Remittances from Fieldwood Energy LLC accounted for 100 percent and 91 percent of the Partnership’s oil and gas sales for the years 2015 and 2014, respectively. Shell Trading Company and BP Products North America each accounted for 34 percent of the Partnership’s oil and gas sales for the year 2013. The Partnership paid an Apache subsidiary transportation fees totaling $3,086 in 2013 for the transportation of Partnership’s share of gas through a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The fees were at the same rates and terms as previously paid to Shell Oil Company before they sold the pipeline to the Apache subsidiary. Matagorda Island Blocks 681 and 682 have been off production since August 2013 and no fees have been paid by the Partnership since that time. 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	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 Receivable and Accounts Payable - As of December 31, 2015, and December 31, 2014, the carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	7. COMMITMENTS AND CONTINGENCIES Litigation – Environmental –

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	8. ASSET RETIREMENT OBLIGATION The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2015 and 2014: 2015 2014 Asset retirement obligation at beginning of year $ 2,183,183 $ 2,219,852 Accretion expense 126,687 112,566 Liabilities settled (773,696 ) (170,212 ) Revisions in estimated liabilities 315,939 20,977 Asset retirement obligation at end of year $ 1,852,113 $ 2,183,183 Less current portion (524,166 ) (274,921 ) Asset retirement obligation, long-term $ 1,327,947 $ 1,908,262 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. The current portion of the ARO liability represents the retirement obligation expected to be incurred in the next twelve months. During 2015, the operator of North Padre Island 969/976 initiated plugging operations on the field with final abandonment anticipated during 2016.

Tax-Basis Financial Information

Tax-Basis Financial Information	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Tax-Basis Financial Information	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: 2015 2014 2013 Net partnership ordinary income (loss) for federal income tax reporting purposes $ (589,078 ) $ 1,192,449 $ 1,395,278 Plus: Items of current expense for tax reporting purposes only – Intangible drilling cost 29,302 22,893 11,211 Dismantlement and abandonment cost 773,696 170,212 212,865 Abandonment expense 38,419 — — Tax depreciation 125,591 117,044 182,005 967,008 310,149 406,081 Less: full cost DD&A expense (478,748 ) (577,830 ) (727,861 ) Less: asset retirement obligation accretion (126,687 ) (112,566 ) (107,568 ) Net income (loss) $ (227,505 ) $ 812,202 $ 965,930 The Partnership’s tax bases in net oil and gas properties at December 31, 2015, and 2014 was $5,962,436 and $5,931,933, 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, 2015, and 2014. 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, 2015 2014 Liabilities for federal income tax purposes $ 631,756 $ 344,477 Asset retirement liability 1,852,113 2,183,183 Liabilities under accounting principles generally accepted in the United States $ 2,483,869 $ 2,527,660 Asset retirement liabilities for future dismantlement and abandonment costs are not recognized for federal income tax reporting purposes until settled.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	10. 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) 2015 2014 2013 Oil Gas Oil Gas Oil Gas Proved Reserves Beginning of year 502 1,250 507 1,224 497 1,331 Extensions, discoveries and other additions — — — — — — Revisions of previous estimates (25 ) (91 ) 21 122 36 144 Production (30 ) (95 ) (26 ) (96 ) (26 ) (251 ) End of year 447 1,064 502 1,250 507 1,224 Proved Developed Beginning of year 502 1,250 507 1,224 497 1,331 End of year 447 1,064 502 1,250 507 1,224 Oil includes crude oil, condensate and natural gas liquids. All the Partnership’s reserves as of December 31, 2015 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 87 percent of the Partnership’s current 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 is reflected in the Partnership’s standardized measure under Future Net Cash Flows. Future Net Cash Flows Future cash inflows as of December 31, 2015, 2014, and 2013 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, 2015 2014 2013 (In thousands) Future cash inflows $ 24,388 $ 51,536 $ 54,518 Future production costs (7,938 ) (9,233 ) (9,563 ) Future development costs (4,438 ) (5,121 ) (5,139 ) Net cash flows 12,012 37,182 39,816 10 percent annual discount rate (5,419 ) (18,456 ) (20,530 ) Discounted future net cash flows $ 6,593 $ 18,726 $ 19,286 The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Sales, net of production costs $ (826 ) $ (1,879 ) $ (2,183 ) Net change in prices and production costs (12,084 ) (1,543 ) 280 Revisions of quantities (532 ) 1,185 1,935 Discoveries and improved recoveries, net of cost — — — Accretion of discount 1,873 1,929 1,950 Changes in future development costs 198 9 (65 ) Changes in production rates and other (762 ) (261 ) (2,130 ) $ (12,133 ) $ (560 ) $ (213 )

Supplemental Quarterly Financia

Supplemental Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Data (Unaudited)	11. First Second Third Fourth Total (In thousands, except per Unit amounts) 2015 Revenues $ 482 $ 505 $ 344 $ 292 $ 1,623 Expenses 513 460 481 397 1,851 Net income (loss) $ (31 ) $ 45 $ (137 ) $ (105 ) $ (228 ) Net income (loss) allocated to: Managing Partner $ 15 $ 34 $ (2 ) $ — $ 47 Investing Partners (46 ) 11 (135 ) (105 ) (275 ) $ (31 ) $ 45 $ (137 ) $ (105 ) $ (228 ) Net income (loss) per Investing Partner Unit (1) $ (45 ) $ 11 $ (132 ) $ (103 ) $ (269 ) 2014 Revenues $ 730 $ 741 $ 807 $ 656 $ 2,934 Expenses 601 535 540 446 2,122 Net income $ 129 $ 206 $ 267 $ 210 $ 812 Net income allocated to: Managing Partner $ 53 $ 69 $ 84 $ 65 $ 271 Investing Partners 76 137 183 145 541 $ 129 $ 206 $ 267 $ 210 $ 812 Net income per Investing Partner Unit (1) $ 74 $ 134 $ 179 $ 142 $ 530 (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.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Statement Presentation	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	Use of Estimates The preparation of financial statements in conformity with GAAP 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 Note 10 - Supplemental Oil and Gas Disclosures) and the assessment of asset retirement obligations (see Note 8 – Asset Retirement Obligation).
Cash Equivalents	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, 2015 and 2014, the Partnership had $5.2 million and $5.3 million, respectively, of cash and cash equivalents.
Oil and Gas Properties	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. All costs related to 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 operations. 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. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. See Note 10 - Supplemental Oil and Gas Disclosures for a discussion on the calculation of estimated future net cash flows.
Asset Retirement Costs and Obligation	Asset Retirement Costs and Obligation The initial estimated asset retirement obligation related to properties is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to oil and gas properties on the consolidated balance sheet. 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. Accretion expense on the liability is recognized over the estimated productive life of the related assets.
Revenue Recognition	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. At December 31, 2015, the Partnership carried a liability of $84,249 for gas 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.
Insurance Coverage	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 (Loss) Per Investing Unit	Net Income (Loss) Per Investing Unit The net income (loss) 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	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	Receivable from / Payable to Apache Corporation The receivable from/payable to Apache Corporation, the Partnership’s 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 Maintenance and repairs are charged to expense as incurred.
New Pronouncements Issued But Not Yet Adopted	New Pronouncements Issued But Not Yet Adopted In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. On July 9, 2015, the FASB announced a delay in the effective date of the revenue standard by one year. The deferral results in the new revenue standard becoming effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Partnership is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

Organization (Tables)

Organization (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Total Repurchase Price for All Outstanding Units	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 Valuation Price Per Unit December 31, 2012 $ 15,743,540 $ 15,412 June 30, 2013 15,958,079 15,622 December 31, 2013 16,364,853 16,020 June 30, 2014 16,609,939 16,260 December 31, 2014 9,975,347 9,765 June 30, 2015 10,042,327 9,831
Repurchase Price Per Unit for All Outstanding Units	Investing Partner Units Outstanding: 2015 2014 2013 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

Compensation to Affiliates (Tab

Compensation to Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Compensation and Reimbursement for Costs and Expenses	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, 2015 2014 2013 (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 $ 291 $ 301 $ 306 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 $ — $ — $ 1

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Direct Cost Information	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. 2015 2014 2013 (In thousands) Oil and Gas Properties Balance, beginning of year $ 194,691 $ 194,635 $ 194,452 Costs incurred during the year: Development – Investing Partners 314 53 166 Managing Partner 32 3 17 Balance, end of year $ 195,037 $ 194,691 $ 194,635
Changes in Partnership's Oil and Gas Properties	Investing Total (In thousands) Accumulated Depreciation, Depletion and Amortization Balance, December 31, 2012 $ 21,012 $ 164,460 $ 185,472 Provision 23 705 728 Balance, December 31, 2013 $ 21,035 $ 165,165 $ 186,200 Provision 19 559 578 Balance, December 31, 2014 $ 21,054 $ 165,724 $ 186,778 Provision 15 463 478 Balance, December 31, 2015 $ 21,069 $ 166,187 $ 187,256

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Changes to Partnership's Asset Retirement Obligation Liability	The following table describes the changes to the Partnership’s asset retirement obligation (ARO) liability for the years ended December 31, 2015 and 2014: 2015 2014 Asset retirement obligation at beginning of year $ 2,183,183 $ 2,219,852 Accretion expense 126,687 112,566 Liabilities settled (773,696 ) (170,212 ) Revisions in estimated liabilities 315,939 20,977 Asset retirement obligation at end of year $ 1,852,113 $ 2,183,183 Less current portion (524,166 ) (274,921 ) Asset retirement obligation, long-term $ 1,327,947 $ 1,908,262

Tax-Basis Financial Informati23

Tax-Basis Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Reconciliation of Ordinary Income for Federal Income Tax Reporting Purposes	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: 2015 2014 2013 Net partnership ordinary income (loss) for federal income tax reporting purposes $ (589,078 ) $ 1,192,449 $ 1,395,278 Plus: Items of current expense for tax reporting purposes only – Intangible drilling cost 29,302 22,893 11,211 Dismantlement and abandonment cost 773,696 170,212 212,865 Abandonment expense 38,419 — — Tax depreciation 125,591 117,044 182,005 967,008 310,149 406,081 Less: full cost DD&A expense (478,748 ) (577,830 ) (727,861 ) Less: asset retirement obligation accretion (126,687 ) (112,566 ) (107,568 ) Net income (loss) $ (227,505 ) $ 812,202 $ 965,930
Reconciliation of Liabilities for Federal Income Tax Reporting Purposes	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, 2015 2014 Liabilities for federal income tax purposes $ 631,756 $ 344,477 Asset retirement liability 1,852,113 2,183,183 Liabilities under accounting principles generally accepted in the United States $ 2,483,869 $ 2,527,660

Supplemental Oil and Gas Disc24

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Proved Reserves and Projecting Future Rates of Production and Timing of Development Expenditures	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) 2015 2014 2013 Oil Gas Oil Gas Oil Gas Proved Reserves Beginning of year 502 1,250 507 1,224 497 1,331 Extensions, discoveries and other additions — — — — — — Revisions of previous estimates (25 ) (91 ) 21 122 36 144 Production (30 ) (95 ) (26 ) (96 ) (26 ) (251 ) End of year 447 1,064 502 1,250 507 1,224 Proved Developed Beginning of year 502 1,250 507 1,224 497 1,331 End of year 447 1,064 502 1,250 507 1,224
Discounted Future Net Cash Flows Relating to Proved Reserves	Discounted Future Net Cash Flows Relating to Proved Reserves December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 24,388 $ 51,536 $ 54,518 Future production costs (7,938 ) (9,233 ) (9,563 ) Future development costs (4,438 ) (5,121 ) (5,139 ) Net cash flows 12,012 37,182 39,816 10 percent annual discount rate (5,419 ) (18,456 ) (20,530 ) Discounted future net cash flows $ 6,593 $ 18,726 $ 19,286
Discounted Future Net Cash Flows	The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Sales, net of production costs $ (826 ) $ (1,879 ) $ (2,183 ) Net change in prices and production costs (12,084 ) (1,543 ) 280 Revisions of quantities (532 ) 1,185 1,935 Discoveries and improved recoveries, net of cost — — — Accretion of discount 1,873 1,929 1,950 Changes in future development costs 198 9 (65 ) Changes in production rates and other (762 ) (261 ) (2,130 ) $ (12,133 ) $ (560 ) $ (213 )

Supplemental Quarterly Financ25

Supplemental Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Quarterly Financial Data	SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) First Second Third Fourth Total (In thousands, except per Unit amounts) 2015 Revenues $ 482 $ 505 $ 344 $ 292 $ 1,623 Expenses 513 460 481 397 1,851 Net income (loss) $ (31 ) $ 45 $ (137 ) $ (105 ) $ (228 ) Net income (loss) allocated to: Managing Partner $ 15 $ 34 $ (2 ) $ — $ 47 Investing Partners (46 ) 11 (135 ) (105 ) (275 ) $ (31 ) $ 45 $ (137 ) $ (105 ) $ (228 ) Net income (loss) per Investing Partner Unit (1) $ (45 ) $ 11 $ (132 ) $ (103 ) $ (269 ) 2014 Revenues $ 730 $ 741 $ 807 $ 656 $ 2,934 Expenses 601 535 540 446 2,122 Net income $ 129 $ 206 $ 267 $ 210 $ 812 Net income allocated to: Managing Partner $ 53 $ 69 $ 84 $ 65 $ 271 Investing Partners 76 137 183 145 541 $ 129 $ 206 $ 267 $ 210 $ 812 Net income per Investing Partner Unit (1) $ 74 $ 134 $ 179 $ 142 $ 530 (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.

Organization - Additional Infor

Organization - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015LeaseVenture$ / sharesshares	Dec. 31, 2014shares	Dec. 31, 2013shares	Dec. 31, 2012shares
Schedule Of Organization [Line Items]
Percentage share held in partnership	5.00%
Investing Partners, units outstanding | shares	1,021.5	1,021.5	1,021.5	1,021.5
Percentage interest Purchased in offshore leasehold	85.00%
No. of federal lease tracts | Lease	87
Percentage of remaining interest purchased	15.00%
Percentage interest acquired in blocks	92.60%
Number of remaining ventures | Venture	2
Net revenue from proved reserves	70.00%
Discounted rate	1.50%
Investor subscription, units | $ / shares	$ 85,000
Percentage of Investor subscription	57.00%
Full purchase price | $ / shares	$ 150,000
Number of original units | shares	1,500
Investing Partners [Member]
Schedule Of Organization [Line Items]
Percent of revenues	80.00%
Percentage of interest income earned on short term cash investments	100.00%
Percentage of expenses incurred	90.00%
Percentage of expenses related to loans	99.00%
Percentage of partner's total amount equals to cost	90.00%
Managing Partner [Member]
Schedule Of Organization [Line Items]
Percent of revenues	20.00%
Percentage of expenses incurred	10.00%
Percentage of expenses related to loans	1.00%
Minimum [Member]
Schedule Of Organization [Line Items]
Working percentage interest	6.29%
Maximum [Member]
Schedule Of Organization [Line Items]
Working percentage interest	7.08%
Outstanding units	10.00%

Organization - Total Repurchase

Organization - Total Repurchase Price for All Outstanding Units (Detail) - USD ($)	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Total Valuation Price	$ 10,042,327	$ 9,975,347	$ 16,609,939	$ 16,364,853	$ 15,958,079	$ 15,743,540
Valuation Price Per Unit	$ 9,831	$ 9,765	$ 16,260	$ 16,020	$ 15,622	$ 15,412
Right of Presentment Valuation Date	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012

Organization - Repurchase Price

Organization - Repurchase Price Per Unit for All Outstanding Units (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Balance, beginning of year	1,021.5	1,021.5	1,021.5
Repurchase of Partnership Units	0	0	0
Balance, end of year	1,021.5	1,021.5	1,021.5

Summary of Significant Accoun29

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Cash and cash equivalents	$ 5,246,452	$ 5,275,503	$ 4,320,218	$ 3,118,789
Short term investment maturity period	Three months or less
Percentage of reserve volumes sold	25.00%
Estimated future net cash flows from proved oil and gas reserves	10.00%
Gas imbalance payable	$ 84,249

Compensation to Affiliates - Co

Compensation to Affiliates - Compensation and Reimbursement for Costs and Expenses (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership's business	$ 291	$ 301	$ 306
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			$ 1

Oil and Gas Properties - Direct

Oil and Gas Properties - Direct Cost Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Balance, beginning of year	$ 194,691	$ 194,635	$ 194,452
Development - Investing Partners	314	53	166
Managing Partner	32	3	17
Balance, end of year	$ 195,037	$ 194,691	$ 194,635

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Asset retirement expense	$ 0.3		$ 0.2
DD&A rate as percentage of oil and gas sales	28.00%	20.00%	20.00%

Oil and Gas Properties - Change

Oil and Gas Properties - Changes in Partnership's Oil and Gas Properties (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Properties [Line Items]
Balance	$ 186,778	$ 186,200	$ 185,472
Provision	478	578	728
Balance	187,256	186,778	186,200
Managing Partner [Member]
Oil and Gas Properties [Line Items]
Balance	21,054	21,035	21,012
Provision	15	19	23
Balance	21,069	21,054	21,035
Investing Partners [Member]
Oil and Gas Properties [Line Items]
Balance	165,724	165,165	164,460
Provision	463	559	705
Balance	$ 166,187	$ 165,724	$ 165,165

Major Customer and Related Pa34

Major Customer and Related Parties Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015mi	Dec. 31, 2014	Dec. 31, 2013USD ($)
Revenue, Major Customer [Line Items]
Major customer definition	Revenues received from major third party customers that equaled ten percent or more of oil and gas sales
Sales Revenue [Member] | Fieldwood Energy LLC [Member] | Customer Concentration Risk [Member]
Revenue, Major Customer [Line Items]
Partnership oil and gas sales	100.00%	91.00%
Sales Revenue [Member] | Shell Plc [Member] | Customer Concentration Risk [Member]
Revenue, Major Customer [Line Items]
Partnership oil and gas sales			34.00%
Sales Revenue [Member] | BP Products North America [Member] | Customer Concentration Risk [Member]
Revenue, Major Customer [Line Items]
Partnership oil and gas sales			34.00%
Fuel Transportation [Member]
Revenue, Major Customer [Line Items]
Miles of natural gas and condensate pipeline | mi	14.4
Transportation fees paid to Apache subsidiary | $			$ 3,086

Asset Retirement Obligation - C

Asset Retirement Obligation - Changes to Partnership's Asset Retirement Obligation Liability (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$ 2,183,183	$ 2,219,852
Accretion expense	126,687	112,566	$ 107,568
Liabilities settled	(773,696)	(170,212)
Revisions in estimated liabilities	315,939	20,977
Asset retirement obligation at end of year	1,852,113	2,183,183	2,219,852
Asset retirement obligation at end of year	$ 2,183,183	$ 2,219,852	$ 2,219,852	$ 1,852,113	$ 2,183,183
Less current portion				(524,166)	(274,921)
Asset retirement obligation, long-term				$ 1,327,947	$ 1,908,262

Tax - Basis Financial Informati

Tax - Basis Financial Information - Reconciliation of Ordinary Income for Federal Income Tax Reporting Purposes (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Net partnership ordinary income (loss) for federal income tax reporting purposes									$ (589,078)	$ 1,192,449	$ 1,395,278
Plus: Items of current expense for tax reporting purposes only - Intangible drilling cost									29,302	22,893	11,211
Dismantlement and abandonment cost									773,696	170,212	212,865
Abandonment expense									38,419
Tax depreciation									125,591	117,044	182,005
Non deductible expenses for federal income tax purposes									967,008	310,149	406,081
Less: full cost DD&A expense									(478,748)	(577,830)	(727,861)
Less: asset retirement obligation accretion									(126,687)	(112,566)	(107,568)
NET INCOME (LOSS)	$ (105,000)	$ (137,000)	$ 45,000	$ (31,000)	$ 210,000	$ 267,000	$ 206,000	$ 129,000	$ (227,505)	$ 812,202	$ 965,930

Tax - Basis Financial Informa37

Tax - Basis Financial Information - Additional Information (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Tax bases in net oil and gas properties	$ 5,962,436	$ 5,931,933
Capitalized syndication cost	$ 8,660,878	$ 8,660,878

Tax - Basis Financial Informa38

Tax - Basis Financial Information - Reconciliation of Liabilities for Federal Income Tax Reporting Purposes (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Liabilities for federal income tax purposes	$ 631,756	$ 344,477
Asset retirement liability	1,852,113	2,183,183	$ 2,219,852
Liabilities under accounting principles generally accepted in the United States	$ 2,483,869	$ 2,527,660

Supplemental Oil and Gas Disc39

Supplemental Oil and Gas Disclosures (Unaudited) - Proved Reserves and Projecting Future Rates of Production and Timing of Development Expenditures (Detail)	12 Months Ended
	Dec. 31, 2015MBblsMMcf	Dec. 31, 2014MBblsMMcf	Dec. 31, 2013MBblsMMcf
Oil [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Beginning of year | MBbls	502	507	497
Extensions, discoveries and other additions | MBbls	0	0	0
Revisions of previous estimates | MBbls	(25)	21	36
Production | MBbls	(30)	(26)	(26)
End of year | MBbls	447	502	507
Oil [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning of year | MBbls	502	507	497
End of year | MBbls	447	502	507
Gas [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Beginning of year | MMcf	1,250	1,224	1,331
Extensions, discoveries and other additions | MMcf	0	0	0
Revisions of previous estimates | MMcf	(91)	122	144
Production | MMcf	(95)	(96)	(251)
End of year | MMcf	1,064	1,250	1,224
Gas [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning of year | MMcf	1,250	1,224	1,331
End of year | MMcf	1,064	1,250	1,224

Supplemental Oil and Gas Disc40

Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015
Supplemental Oil And Gas Disclosures [Abstract]
Percentage of partnership's current proved developed reserves classified as proved not producing	87.00%

Supplemental Oil and Gas Disc41

Supplemental Oil and Gas Disclosures - Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Disclosures [Abstract]
Future cash inflows	$ 24,388	$ 51,536	$ 54,518
Future production costs	(7,938)	(9,233)	(9,563)
Future development costs	(4,438)	(5,121)	(5,139)
Net cash flows	12,012	37,182	39,816
10 percent annual discount rate	(5,419)	(18,456)	(20,530)
Discounted future net cash flows	$ 6,593	$ 18,726	$ 19,286

Supplemental Oil and Gas Disc42

Supplemental Oil and Gas Disclosures (Unaudited) - Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Disclosures [Abstract]
Sales, net of production costs	$ (826)	$ (1,879)	$ (2,183)
Net change in prices and production costs	(12,084)	(1,543)	280
Revisions of quantities	(532)	1,185	1,935
Discoveries and improved recoveries, net of cost	0	0	0
Accretion of discount	1,873	1,929	1,950
Changes in future development costs	198	9	(65)
Changes in production rates and other	(762)	(261)	(2,130)
Total	$ (12,133)	$ (560)	$ (213)

Supplemental Quarterly Financ43

Supplemental Quarterly Financial Data (Unaudited) - Quarterly Financial Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 292,000	$ 344,000	$ 505,000	$ 482,000	$ 656,000	$ 807,000	$ 741,000	$ 730,000	$ 1,623,334	$ 2,933,896	$ 3,556,086
Expenses	397,000	481,000	460,000	513,000	446,000	540,000	535,000	601,000	1,850,839	2,121,694	2,590,156
Net income (loss)	(105,000)	(137,000)	45,000	(31,000)	210,000	267,000	206,000	129,000	(227,505)	812,202	965,930
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner		(2,000)	34,000	15,000	65,000	84,000	69,000	53,000	47,101	270,751	326,207
Investing Partners	(105,000)	(135,000)	11,000	(46,000)	145,000	183,000	137,000	76,000	(274,606)	541,451	639,723
Net income (loss)	$ (105,000)	$ (137,000)	$ 45,000	$ (31,000)	$ 210,000	$ 267,000	$ 206,000	$ 129,000	$ (227,505)	$ 812,202	$ 965,930
Net income (loss) per Investing Partner Unit	$ (103)	$ (132)	$ 11	$ (45)	$ 142	$ 179	$ 134	$ 74	$ (269)	$ 530	$ 626