Apache Offshore Investment Partnership (AOIP) 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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		$ 5,898,618

Statement of Consolidated Opera

Statement of Consolidated Operations - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Oil and gas sales	$ 1,317,075	$ 1,707,495	$ 2,933,808
Other revenue (loss)	0	(84,249)	0
Interest income	7,639	88	88
Total Revenues	1,324,714	1,623,334	2,933,896
EXPENSES:
Depreciation, depletion and amortization	3,380,231	478,748	577,830
Asset retirement obligation accretion	79,661	126,687	112,566
Lease operating expenses	567,434	756,598	947,111
Gathering and transportation costs	84,617	124,806	108,187
Administrative	348,000	364,000	376,000
Total Expenses	4,459,943	1,850,839	2,121,694
NET INCOME (LOSS)	(3,135,229)	(227,505)	812,202
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	34,361	47,101	270,751
Investing Partners	(3,169,590)	(274,606)	541,451
NET INCOME (LOSS)	$ (3,135,229)	$ (227,505)	$ 812,202
NET INCOME (LOSS) PER INVESTING PARTNER UNIT (in USD per share)	$ (3,103)	$ (269)	$ 530
WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING (in shares)	1,021.5	1,021.5	1,021.5
Recurring [Member]
EXPENSES:
Depreciation, depletion and amortization	$ 507,051	$ 478,748	$ 577,830
Additional [Member]
EXPENSES:
Depreciation, depletion and amortization	$ 2,873,180	$ 0	$ 0

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (3,135,229)	$ (227,505)	$ 812,202
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	3,380,231	478,748	577,830
Asset retirement obligation accretion	79,661	126,687	112,566
Changes in operating assets and liabilities:
(Increase) decrease in accrued receivables	24,756	161,566	(274,118)
Increase (decrease) in receivable from/payable to Apache Corporation	(19,606)	17,274	5,868
Increase (decrease) in other payables	(84,249)	84,249	0
Increase (decrease) in accrued operating expenses	(132,350)	(113,539)	190,563
Increase (decrease) in asset retirement obligations	(290,757)	(471,934)	(168,927)
Net cash provided by (used in) operating activities	(177,543)	55,546	1,255,984
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(38,231)	(30,013)	(35,402)
Net cash used in investing activities	(38,231)	(30,013)	(35,402)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from Managing Partner	4,990	0	0
Distributions to Managing Partner	0	(54,584)	(265,297)
Net cash provided by (used in) financing activities	4,990	(54,584)	(265,297)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(210,784)	(29,051)	955,285
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	5,246,452	5,275,503	4,320,218
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 5,035,668	$ 5,246,452	$ 5,275,503

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($)	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 5,035,668	$ 5,246,452
Accrued revenues receivable	123,092	147,848
Receivable from Apache Corporation	4,799	0
Total Current Assets	5,163,559	5,394,300
OIL AND GAS PROPERTIES, on the basis of full cost accounting:
Proved properties	194,893,233	195,037,054
Less – Accumulated depreciation, depletion and amortization	(190,636,628)	(187,256,397)
Total oil and gas properties, on the basis of full cost accounting	4,256,605	7,780,657
Total Assets	9,420,164	13,174,957
CURRENT LIABILITIES:
Payable to Apache Corporation	0	14,807
Current asset retirement obligation	0	524,166
Other payables	0	84,249
Accrued operating expenses	97,214	229,564
Accrued development costs	9,410	303,136
Total Current Liabilities	106,624	1,155,922
ASSET RETIREMENT OBLIGATION	1,752,691	1,327,947
PARTNERS’ CAPITAL:
Managing Partner	446,230	406,879
Investing Partners (1,021.5 units outstanding)	7,114,619	10,284,209
Total Partners' Capital	7,560,849	10,691,088
Total liabilities and partners' capital	$ 9,420,164	$ 13,174,957

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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, 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
Contributions	4,990	4,990
Net income (loss)	(3,135,229)	34,361	(3,169,590)
ENDING BALANCE at Dec. 31, 2016	$ 7,560,849	$ 446,230	$ 7,114,619

Organization

Organization	12 Months Ended
	Dec. 31, 2016
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, 2016 . 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, 2016 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 2016 , 2015 , or 2014 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 2017 ; 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, 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 December 31, 2015 6,187,080 6,057 June 30, 2016 6,222,171 6,091 Investing Partner Units Outstanding: 2016 2015 2014 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, 2016 . 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, 2016 .

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 , the Partnership had $5.0 million and $5.2 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. As a result of the ceiling limitation, the Partnership recorded non-cash write-downs of the carrying value of its proved oil and gas properties totaling $2,873,180 during 2016. The Partnership did not record any write-downs of capitalized costs during 2015 or 2014. 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 property and equipment 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 changes in 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, 2016, the Partnership did not have any liability recorded for gas imbalances in excess of remaining reserves. 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 August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (“ASU”) 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Partnership is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses." The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership does not expect to adopt the guidance early. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Partnership will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Partnership is currently evaluating the impact of adopting this standard on its consolidated financial statements. In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-9. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, 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. The guidance is 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 will adopt the new standard utilizing the modified retrospective approach. Upon initial evaluation, the Partnership does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

Compensation to Affiliates

Compensation to Affiliates	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (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 $ 278 $ 291 $ 301 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 $ — $ — $ — 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, 2016
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. 2016 2015 2014 (In thousands) Oil and Gas Properties Balance, beginning of year $ 195,037 $ 194,691 $ 194,635 Costs incurred during the year: Development – Investing Partners (126 ) 314 53 Managing Partner (18 ) 32 3 Balance, end of year $ 194,893 $ 195,037 $ 194,691 Development costs for 2016 reflect a reduction of $179 thousand to record a negative revision in estimated abandonment cost and the deferral of final platform abandonment at North Padre Island 969/976 until 2018. Removal of the platforms and final abandonment activity was previously expected to occur during 2016. Approximately $35 thousand of capital costs were incurred in 2016 as the Partnership participated in a recompletion project at Ship Shoal 258/259. Development costs in 2015 included $0.3 million on recompletion costs and abandonment activity. The Partnership’s 2014 capital cost additions were negligible. Managing Partner Investing Partners Total (In thousands) Accumulated Depreciation, Depletion and Amortization 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 Provision 22 3,359 3,381 Balance, December 31, 2016 $ 21,091 $ 169,546 $ 190,637 The Partnership’s aggregate DD&A expense as a percentage of oil and gas sales for 2016 , 2015 , and 2014 was 38 percent , 28 percent and 20 percent , respectively. As more fully described in Footnote 2 above, as a result of the full-cost method of accounting ceiling limitation, the Partnership recorded non-cash write-downs of the carrying value of its proved oil and gas properties totaling $2,873,180 during 2016.

Major Customer and Related Part

Major Customer and Related Parties Information	12 Months Ended
	Dec. 31, 2016
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 43 percent , 100 percent , and 91 percent of the Partnership’s oil and gas sales for the years 2016 , 2015 , and 2014 , respectively. Approximately 57 percent of the Partnership's oil and gas sales in 2016 were to Chevron Products Company. 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, 2016
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, 2016 , and December 31, 2015 , 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, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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. With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued Notice to Lessees (NTL) No. 2016-N01 pertaining to the obligations of companies to provide supplemental assurances for performance with respect to plugging, abandonment, decommissioning, and site clearance obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. Under this NTL, the Partnership will likely be required to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Partnership’s current ownership interests in various Gulf of Mexico leases. The Partnership will likely satisfy such requirements through the provision of bonds or other forms of security.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : 2016 2015 Asset retirement obligation at beginning of year $ 1,852,113 $ 2,183,183 Accretion expense 79,661 126,687 Liabilities settled — (773,696 ) Revisions in estimated liabilities (179,083 ) 315,939 Asset retirement obligation at end of year $ 1,752,691 $ 1,852,113 Less current portion — (524,166 ) Asset retirement obligation, long-term $ 1,752,691 $ 1,327,947 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 estimates from property operators and current market 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. For 2016, a negative revision was recorded to reflect a reduction in estimated cost and the deferral of final platform abandonment at North Padre Island 969/976 until 2018. Removal of the platforms and final abandonment was previously expected to occur during 2016.

Tax-Basis Financial Information

Tax-Basis Financial Information	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 2014 Net partnership ordinary income (loss) for federal income tax reporting purposes $ 165,691 $ (589,078 ) $ 1,192,449 Plus: Items of current expense for tax reporting purposes only – Intangible drilling cost 36,920 29,302 22,893 Dismantlement and abandonment cost (2,969 ) 773,696 170,212 Abandonment expense — 38,419 — Tax depreciation 125,021 125,591 117,044 158,972 967,008 310,149 Less: full cost DD&A expense (3,380,231 ) (478,748 ) (577,830 ) Less: asset retirement obligation accretion (79,661 ) (126,687 ) (112,566 ) Net income (loss) $ (3,135,229 ) $ (227,505 ) $ 812,202 The Partnership’s tax bases in net oil and gas properties at December 31, 2016 , and 2015 was $2,562,093 and $5,962,436 , 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, 2016 , and 2015 . 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, 2016 2015 Liabilities for federal income tax purposes $ 106,624 $ 631,756 Asset retirement liability 1,752,691 1,852,113 Liabilities under accounting principles generally accepted in the United States $ 1,859,315 $ 2,483,869 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, 2016
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	10. 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) 2016 2015 2014 Oil NGL Gas Oil NGL Gas Oil NGL Gas Proved Reserves Beginning of year 389 58 1,064 425 77 1,250 430 77 1,224 Extensions, discoveries and other additions — — — — — — — — — Revisions of previous estimates 1 (2 ) 27 (10 ) (15 ) (91 ) 18 3 122 Production (25 ) (3 ) (106 ) (26 ) (4 ) (95 ) (23 ) (3 ) (96 ) End of year 365 53 985 389 58 1,064 425 77 1,250 Proved Developed Beginning of year 389 58 1,064 425 77 1,250 430 77 1,224 End of year 365 53 985 389 58 1,064 425 77 1,250 Oil includes crude oil and condensate. All the Partnership’s reserves as of December 31, 2016 are located on federal lease tracts in the Gulf of Mexico, offshore Louisiana. Approximately 89 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, 2016 , 2015 , and 2014 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, 2016 2015 2014 (In thousands) Future cash inflows $ 20,675 $ 24,388 $ 51,536 Future production costs (8,277 ) (7,938 ) (9,233 ) Future development costs (4,282 ) (4,438 ) (5,121 ) Net cash flows 8,116 12,012 37,182 10 percent annual discount rate (3,445 ) (5,419 ) (18,456 ) Discounted future net cash flows $ 4,671 $ 6,593 $ 18,726 The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2016 2015 2014 (In thousands) Sales, net of production costs $ (665 ) $ (826 ) $ (1,879 ) Net change in prices and production costs (1,900 ) (12,084 ) (1,543 ) Revisions of quantities 42 (532 ) 1,185 Discoveries and improved recoveries, net of cost — — — Accretion of discount 659 1,873 1,929 Changes in future development costs 61 198 9 Changes in production rates and other (119 ) (762 ) (261 ) $ (1,922 ) $ (12,133 ) $ (560 )

Supplemental Quarterly Financia

Supplemental Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Data (Unaudited)	11. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) First Second Third Fourth Total (In thousands, except per Unit amounts) 2016 Revenues $ 315 $ 381 $ 331 $ 298 $ 1,325 Expenses (2) 1,722 1,852 571 315 4,460 Net loss $ (1,407 ) $ (1,471 ) $ (240 ) $ (17 ) $ (3,135 ) Net loss allocated to: Managing Partner $ (3 ) $ 12 $ 14 $ 12 $ 35 Investing Partners (1,404 ) (1,483 ) (254 ) (29 ) (3,170 ) $ (1,407 ) $ (1,471 ) $ (240 ) $ (17 ) $ (3,135 ) Net income (loss) per Investing Partner Unit (1) $ (1,375 ) $ (1,452 ) $ (248 ) $ (28 ) $ (3,103 ) 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 ) (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. (2) In 2016, expenses include non-cash writedowns of the Partnership's oil and gas properties totaling $2.9 million . Approximately $1.3 million , $1.4 million , and $0.2 million were recognized in the first, second, and third quarters of 2016, respectively.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 , the Partnership had $5.0 million and $5.2 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. As a result of the ceiling limitation, the Partnership recorded non-cash write-downs of the carrying value of its proved oil and gas properties totaling $2,873,180 during 2016. The Partnership did not record any write-downs of capitalized costs during 2015 or 2014. 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 property and equipment 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 changes in 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, 2016, the Partnership did not have any liability recorded for gas imbalances in excess of remaining reserves. 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 August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (“ASU”) 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Partnership is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses." The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership does not expect to adopt the guidance early. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Partnership will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Partnership is currently evaluating the impact of adopting this standard on its consolidated financial statements. In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-9. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, 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. The guidance is 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 will adopt the new standard utilizing the modified retrospective approach. Upon initial evaluation, the Partnership does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

Organization (Tables)

Organization (Tables)	12 Months Ended
	Dec. 31, 2016
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 Price Valuation Price Per Unit 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 December 31, 2015 6,187,080 6,057 June 30, 2016 6,222,171 6,091
Repurchase Price Per Unit for All Outstanding Units	Investing Partner Units Outstanding: 2016 2015 2014 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, 2016
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, 2016 2015 2014 (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 $ 278 $ 291 $ 301 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 $ — $ — $ —

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
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. 2016 2015 2014 (In thousands) Oil and Gas Properties Balance, beginning of year $ 195,037 $ 194,691 $ 194,635 Costs incurred during the year: Development – Investing Partners (126 ) 314 53 Managing Partner (18 ) 32 3 Balance, end of year $ 194,893 $ 195,037 $ 194,691
Changes in Partnership's Oil and Gas Properties	Managing Partner Investing Partners Total (In thousands) Accumulated Depreciation, Depletion and Amortization 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 Provision 22 3,359 3,381 Balance, December 31, 2016 $ 21,091 $ 169,546 $ 190,637

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : 2016 2015 Asset retirement obligation at beginning of year $ 1,852,113 $ 2,183,183 Accretion expense 79,661 126,687 Liabilities settled — (773,696 ) Revisions in estimated liabilities (179,083 ) 315,939 Asset retirement obligation at end of year $ 1,752,691 $ 1,852,113 Less current portion — (524,166 ) Asset retirement obligation, long-term $ 1,752,691 $ 1,327,947

Tax-Basis Financial Informati23

Tax-Basis Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 2014 Net partnership ordinary income (loss) for federal income tax reporting purposes $ 165,691 $ (589,078 ) $ 1,192,449 Plus: Items of current expense for tax reporting purposes only – Intangible drilling cost 36,920 29,302 22,893 Dismantlement and abandonment cost (2,969 ) 773,696 170,212 Abandonment expense — 38,419 — Tax depreciation 125,021 125,591 117,044 158,972 967,008 310,149 Less: full cost DD&A expense (3,380,231 ) (478,748 ) (577,830 ) Less: asset retirement obligation accretion (79,661 ) (126,687 ) (112,566 ) Net income (loss) $ (3,135,229 ) $ (227,505 ) $ 812,202
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, 2016 2015 Liabilities for federal income tax purposes $ 106,624 $ 631,756 Asset retirement liability 1,752,691 1,852,113 Liabilities under accounting principles generally accepted in the United States $ 1,859,315 $ 2,483,869

Supplemental Oil and Gas Disc24

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Oil NGL Gas Oil NGL Gas Oil NGL Gas Proved Reserves Beginning of year 389 58 1,064 425 77 1,250 430 77 1,224 Extensions, discoveries and other additions — — — — — — — — — Revisions of previous estimates 1 (2 ) 27 (10 ) (15 ) (91 ) 18 3 122 Production (25 ) (3 ) (106 ) (26 ) (4 ) (95 ) (23 ) (3 ) (96 ) End of year 365 53 985 389 58 1,064 425 77 1,250 Proved Developed Beginning of year 389 58 1,064 425 77 1,250 430 77 1,224 End of year 365 53 985 389 58 1,064 425 77 1,250
Discounted Future Net Cash Flows Relating to Proved Reserves	Discounted Future Net Cash Flows Relating to Proved Reserves December 31, 2016 2015 2014 (In thousands) Future cash inflows $ 20,675 $ 24,388 $ 51,536 Future production costs (8,277 ) (7,938 ) (9,233 ) Future development costs (4,282 ) (4,438 ) (5,121 ) Net cash flows 8,116 12,012 37,182 10 percent annual discount rate (3,445 ) (5,419 ) (18,456 ) Discounted future net cash flows $ 4,671 $ 6,593 $ 18,726
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, 2016 2015 2014 (In thousands) Sales, net of production costs $ (665 ) $ (826 ) $ (1,879 ) Net change in prices and production costs (1,900 ) (12,084 ) (1,543 ) Revisions of quantities 42 (532 ) 1,185 Discoveries and improved recoveries, net of cost — — — Accretion of discount 659 1,873 1,929 Changes in future development costs 61 198 9 Changes in production rates and other (119 ) (762 ) (261 ) $ (1,922 ) $ (12,133 ) $ (560 )

Supplemental Quarterly Financ25

Supplemental Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 Revenues $ 315 $ 381 $ 331 $ 298 $ 1,325 Expenses (2) 1,722 1,852 571 315 4,460 Net loss $ (1,407 ) $ (1,471 ) $ (240 ) $ (17 ) $ (3,135 ) Net loss allocated to: Managing Partner $ (3 ) $ 12 $ 14 $ 12 $ 35 Investing Partners (1,404 ) (1,483 ) (254 ) (29 ) (3,170 ) $ (1,407 ) $ (1,471 ) $ (240 ) $ (17 ) $ (3,135 ) Net income (loss) per Investing Partner Unit (1) $ (1,375 ) $ (1,452 ) $ (248 ) $ (28 ) $ (3,103 ) 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 ) (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. (2) In 2016, expenses include non-cash writedowns of the Partnership's oil and gas properties totaling $2.9 million . Approximately $1.3 million , $1.4 million , and $0.2 million were recognized in the first, second, and third quarters of 2016, respectively.

Organization - Additional Infor

Organization - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016LeaseVenture$ / sharesshares	Dec. 31, 2015shares	Dec. 31, 2014shares	Dec. 31, 2013shares
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
Percentage of expenses related to loans	1.00%
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%
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, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Total Valuation Price	$ 6,222,171	$ 6,187,080	$ 10,042,327	$ 9,975,347	$ 16,609,939	$ 16,364,853
Valuation Price Per Unit	$ 6,091	$ 6,057	$ 9,831	$ 9,765	$ 16,260	$ 16,020

Organization - Repurchase Price

Organization - Repurchase Price Per Unit for All Outstanding Units (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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 ($)	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Cash and cash equivalents				$ 5,035,668	$ 5,246,452	$ 5,275,503	$ 4,320,218
Percentage of reserve volumes sold				25.00%
Estimated future net cash flows from proved oil and gas reserves				10.00%
Impairment of oil and gas properties	$ 200,000	$ 1,400,000	$ 1,300,000	$ 2,873,180	0	$ 0
Liability for gas imbalances in excess of remaining reserves				$ 0	$ 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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 278	$ 291	$ 301
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	$ 0	$ 0	$ 0

Oil and Gas Properties - Direct

Oil and Gas Properties - Direct Cost Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Balance, beginning of year	$ 195,037	$ 194,691	$ 194,635
Development - Investing Partners	(126)	314	53
Managing Partner	(18)	32	3
Balance, end of year	$ 194,893	$ 195,037	$ 194,691

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Detail) - USD ($)	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Decrease of development costs				$ 179,000
Development costs				$ 35,000	$ 300,000
DD&A rate as percentage of oil and gas sales				38.00%	28.00%	20.00%
Impairment of oil and gas properties	$ 200,000	$ 1,400,000	$ 1,300,000	$ 2,873,180	$ 0	$ 0

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Properties [Line Items]
Balance	$ 187,256	$ 186,778	$ 186,200
Provision	3,381	478	578
Balance	190,637	187,256	186,778
Managing Partner [Member]
Oil and Gas Properties [Line Items]
Balance	21,069	21,054	21,035
Provision	22	15	19
Balance	21,091	21,069	21,054
Investing Partners [Member]
Oil and Gas Properties [Line Items]
Balance	166,187	165,724	165,165
Provision	3,359	463	559
Balance	$ 169,546	$ 166,187	$ 165,724

Major Customer and Related Pa34

Major Customer and Related Parties Information - Additional Information (Detail) - Sales Revenue [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fieldwood Energy LLC [Member]
Revenue, Major Customer [Line Items]
Partnership oil and gas sales	43.00%	100.00%	91.00%
Chevron Products Company [Member]
Revenue, Major Customer [Line Items]
Partnership oil and gas sales	57.00%

Asset Retirement Obligation - C

Asset Retirement Obligation - Changes to Partnership's Asset Retirement Obligation Liability (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$ 1,852,113	$ 2,183,183
Accretion expense	79,661	126,687	$ 112,566
Liabilities settled	0	(773,696)
Revisions in estimated liabilities	(179,083)	315,939
Asset retirement obligation at end of year	1,752,691	1,852,113	2,183,183
Asset retirement obligation at end of year	$ 1,852,113	$ 2,183,183	$ 2,183,183	$ 1,752,691	$ 1,852,113
Less current portion				0	(524,166)
Asset retirement obligation, long-term				$ 1,752,691	$ 1,327,947

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Net partnership ordinary income (loss) for federal income tax reporting purposes									$ 165,691	$ (589,078)	$ 1,192,449
Intangible drilling cost									36,920	29,302	22,893
Dismantlement and abandonment cost									(2,969)	773,696	170,212
Abandonment expense									0	38,419	0
Tax depreciation									125,021	125,591	117,044
Non deductible expenses for federal income tax purposes									158,972	967,008	310,149
Less: full cost DD&A expense									(3,380,231)	(478,748)	(577,830)
Less: asset retirement obligation accretion									(79,661)	(126,687)	(112,566)
Net income (loss)	$ (17,000)	$ (240,000)	$ (1,471,000)	$ (1,407,000)	$ (105,000)	$ (137,000)	$ 45,000	$ (31,000)	$ (3,135,229)	$ (227,505)	$ 812,202

Tax - Basis Financial Informa37

Tax - Basis Financial Information - Additional Information (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Tax bases in net oil and gas properties	$ 2,562,093	$ 5,962,436
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Liabilities for federal income tax purposes	$ 106,624	$ 631,756
Asset retirement liability	1,752,691	1,852,113	$ 2,183,183
Liabilities under accounting principles generally accepted in the United States	$ 1,859,315	$ 2,483,869

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, 2016MMcfMBbls	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls
Oil [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Beginning of year	389	425	430
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	1	(10)	18
Production	(25)	(26)	(23)
End of year	365	389	425
Oil [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning of year	389	425	430
End of year	365	389	425
NGL [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Beginning of year	58	77	77
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	(2)	(15)	3
Production	(3)	(4)	(3)
End of year	53	58	77
NGL [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning of year	58	77	77
End of year	53	58	77
Gas [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Beginning of year | MMcf	1,064	1,250	1,224
Extensions, discoveries and other additions | MMcf	0	0	0
Revisions of previous estimates | MMcf	27	(91)	122
Production | MMcf	(106)	(95)	(96)
End of year | MMcf	985	1,064	1,250
Gas [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning of year | MMcf	1,064	1,250	1,224
End of year | MMcf	985	1,064	1,250

Supplemental Oil and Gas Disc40

Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016
Supplemental Oil And Gas Disclosures [Abstract]
Percentage of partnership's current proved developed reserves classified as proved not producing	89.00%

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Disclosures [Abstract]
Future cash inflows	$ 20,675	$ 24,388	$ 51,536
Future production costs	(8,277)	(7,938)	(9,233)
Future development costs	(4,282)	(4,438)	(5,121)
Net cash flows	8,116	12,012	37,182
10 percent annual discount rate	(3,445)	(5,419)	(18,456)
Discounted future net cash flows	$ 4,671	$ 6,593	$ 18,726

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Disclosures [Abstract]
Sales, net of production costs	$ (665)	$ (826)	$ (1,879)
Net change in prices and production costs	(1,900)	(12,084)	(1,543)
Revisions of quantities	42	(532)	1,185
Discoveries and improved recoveries, net of cost	0	0	0
Accretion of discount	659	1,873	1,929
Changes in future development costs	61	198	9
Changes in production rates and other	(119)	(762)	(261)
Total	$ (1,922)	$ (12,133)	$ (560)

Supplemental Quarterly Financ43

Supplemental Quarterly Financial Data (Unaudited) - Quarterly Financial Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 298,000	$ 331,000	$ 381,000	$ 315,000	$ 292,000	$ 344,000	$ 505,000	$ 482,000	$ 1,324,714	$ 1,623,334	$ 2,933,896
Expenses	315,000	571,000	1,852,000	1,722,000	397,000	481,000	460,000	513,000	4,459,943	1,850,839	2,121,694
Net income (loss)	(17,000)	(240,000)	(1,471,000)	(1,407,000)	(105,000)	(137,000)	45,000	(31,000)	(3,135,229)	(227,505)	812,202
NET INCOME (LOSS) ALLOCATED TO:
Managing Partner	12,000	14,000	12,000	(3,000)	0	(2,000)	34,000	15,000	34,361	47,101	270,751
Investing Partners	(29,000)	(254,000)	(1,483,000)	(1,404,000)	(105,000)	(135,000)	11,000	(46,000)	(3,169,590)	(274,606)	541,451
Net income (loss)	$ (17,000)	$ (240,000)	$ (1,471,000)	$ (1,407,000)	$ (105,000)	$ (137,000)	$ 45,000	$ (31,000)	$ (3,135,229)	$ (227,505)	$ 812,202
Net income (loss) per Investing Partner Unit	$ (28)	$ (248)	$ (1,452)	$ (1,375)	$ (103)	$ (132)	$ 11	$ (45)	$ (3,103)	$ (269)	$ 530
Writedowns of oil and gas properties		$ 200,000	$ 1,400,000	$ 1,300,000					$ 2,873,180	$ 0	$ 0