ATLAS AMERICA Public #9 10-Q 15 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	6 Months Ended
	Jun. 30, 2016shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Entity Registrant Name	ATLAS AMERICA Public #9 LTD.
Entity Central Index Key	1,121,745
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED BALANCE SHEETS (Unaud

CONDENSED BALANCE SHEETS (Unaudited) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash	$ 0	$ 0
Accounts receivable trade-affiliate	31,300	29,600
Current portion of derivative assets	5,200	13,400
Total current assets	36,500	43,000
Gas and oil properties, net	537,000	537,000
Long-term asset retirement receivable-affiliate	285,200	188,100
Total assets	858,700	768,100
Current liabilities:
Accounts payable trade-affiliate	534,400	302,300
Accrued liabilities	10,600	10,300
Put premiums payable-affiliate	3,500	6,200
Total current liabilities	548,500	318,800
Asset retirement obligations	1,914,100	1,879,800
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit	(242,400)	(181,000)
Limited partners’ deficit (1,500 units)	(1,361,800)	(1,250,200)
Accumulated other comprehensive income	300	700
Total partners’ deficit	(1,603,900)	(1,430,500)
Total liabilities and partners’ deficit	$ 858,700	$ 768,100

CONDENSED BALANCE SHEETS (Unau3

CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical)	Jun. 30, 2016shares
Statement Of Financial Position [Abstract]
Limited partners' units	1,500

CONDENSED STATEMENTS OF OPERATI

CONDENSED STATEMENTS OF OPERATIONS (Unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES
Natural gas and oil	$ 52,200	$ 55,200	$ 93,800	$ 156,200
(Loss) gain on mark-to-market derivatives	(2,400)	(1,900)	(100)	100
Total revenues	49,800	53,300	93,700	156,300
COSTS AND EXPENSES
Production	104,900	83,900	180,000	183,000
Depletion		8,900		19,200
Accretion of asset retirement obligations	17,200	25,500	34,300	50,900
General and administrative	26,800	26,800	52,400	55,200
Total costs and expenses	148,900	145,100	266,700	308,300
Net loss	(99,100)	(91,800)	(173,000)	(152,000)
Allocation of net loss:
Managing general partner	(34,300)	(33,000)	(61,400)	(56,100)
Limited partners	$ (64,800)	$ (58,800)	$ (111,600)	$ (95,900)
Net loss per limited partnership unit	$ (43)	$ (39)	$ (74)	$ (64)

CONDENSED STATEMENTS OF COMPREH

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS (Unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (99,100)	$ (91,800)	$ (173,000)	$ (152,000)
Other comprehensive loss:
Difference in estimated hedge gains receivable		900		1,800
Less: reclassification adjustment for realized (gain) loss of cash flow hedges in net loss	(200)	(1,500)	(400)	(3,100)
Total other comprehensive loss	(200)	(600)	(400)	(1,300)
Comprehensive loss	$ (99,300)	$ (92,400)	$ (173,400)	$ (153,300)

CONDENSED STATEMENT OF CHANGES

CONDENSED STATEMENT OF CHANGES IN PARTNERS' DEFICIT (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income
Beginning balance at Dec. 31, 2015	$ (1,430,500)	$ (181,000)	$ (1,250,200)	$ 700
Participation in revenues, costs and expenses:
Net production expenses	(86,200)	(30,600)	(55,600)	0
Loss on mark-to-market derivatives	(100)	0	(100)	0
Accretion of asset retirement obligations	(34,300)	(12,200)	(22,100)	0
General and administrative	(52,400)	(18,600)	(33,800)	0
Net loss	(173,000)	(61,400)	(111,600)	0
Other comprehensive loss	(400)	0	0	(400)
Ending balance at Jun. 30, 2016	$ (1,603,900)	$ (242,400)	$ (1,361,800)	$ 300

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net loss	$ (173,000)	$ (152,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		19,200
Non-cash loss (gain) on derivative value	5,100	(1,600)
Accretion of asset retirement obligations	34,300	50,900
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate	(1,700)	55,100
Increase in asset retirement receivable-affiliate	(97,100)	(81,000)
Increase in accounts payable trade-affiliate	232,100	114,200
Increase (decrease) in accrued liabilities	300	(4,800)
Net cash provided by operating activities	0	0
Cash flows from investing activities:
Net cash provided by investing activities	0	0
Cash flows from financing activities:
Net cash used in financing activities	0	0
Net change in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	$ 0	$ 0

Description of Business

Description of Business	6 Months Ended
	Jun. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
DESCRIPTION OF BUSINESS	NOTE 1 - DESCRIPTION OF BUSINESS Atlas America Public #9 LTD. (the “Partnership”) is a Pennsylvania limited partnership, formed on July 27, 2000 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (OTC: ARPJ). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our” refer to Atlas America Public #9 LTD. Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) manages ARP’s operations and activities through its ownership of ARP’s general partner interest. The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling. The condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015. The results of operations for the three and six months ended June 30, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016. The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues. The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically. Liquidity and Capital Resources The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations. If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be further impacted. ARP Restructuring and Chapter 11 Bankruptcy Proceedings On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program. On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016. The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business. The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership. Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates. Gas and Oil Properties The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Total natural gas and oil properties 18,976,300 18,976,300 Accumulated depletion and impairment (18,439,300) (18,439,300 ) Gas and oil properties, net $ 537,000 $ 537,000 As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our condensed Recently Issued Accounting Standards In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	NOTE 3 - DERIVATIVE INSTRUMENTS The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts, in connection with the Partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings. The Partnership enters into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. These contracts have been recorded at their fair values. The Partnership reflected net derivative assets on its condensed balance sheets of $5,200 and $13,400 at June 30, 2016 and December 31, 2015, respectively. The following table summarizes the commodity derivative activity and presentation in the condensed statements of operations for the periods indicated: Three Months Ended Six Months Ended 2016 2015 2016 2015 Gain reclassified from accumulated other comprehensive income into natural gas and oil revenues $ 200 $ 1,500 $ 400 $ 3,100 (Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ (2,400) $ (1,900 ) $ (100) $ 100 At June 30, 2016, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Volumes (3) Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2016 4,600 4.15 $ 5,200 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable. (3) The production volumes for 2016 includes the remaining six months of 2016 beginning July 1, 2016. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and six months ended June 30, 2016 and 2015 for hedge ineffectiveness.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS The Partnership uses a market approach fair value methodology to value for its outstanding derivative contracts Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2016 Derivative assets, gross Commodity puts $ - $ 5,200 $ - $ 5,200 Level 1 Level 2 Level 3 Total As of December 31, 2015 Derivative assets, gross Commodity puts $ - $ 13,400 $ - $ 13,400

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s condensed statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s condensed statements of operations, are payable at $337 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s condensed statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s condensed statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. The following table provides information with respect to these costs and the periods incurred: Three Months Ended Six Months Ended 2016 2015 2016 2015 Administrative fees $ 13,100 $ 13,000 $ 24,700 $ 27,300 Supervision fees 59,000 58,500 111,200 123,000 Transportation fees 6,200 6,000 11,900 17,500 Direct costs 53,400 33,200 84,600 70,400 Total $ 131,700 $ 110,700 $ 232,400 $ 238,200 The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s condensed balance sheets includes the net production expenses due to the MGP.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 6 - COMMITMENTS AND CONTINGENCIES General Commitments Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation. Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of June 30, 2016, the MGP has withheld $285,200 of net production revenue for future plugging and abandonment costs. Legal Proceedings The Partnership and affiliates of the MGP and their subsidiaries are a party to various routine legal proceedings arising out of the ordinary course of its business. Management and the MGP’s management believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s or the MGP’s financial condition or results of operations.

Summary of Significant Accoun14

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.
Gas and Oil Properties	Gas and Oil Properties The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Total natural gas and oil properties 18,976,300 18,976,300 Accumulated depletion and impairment (18,439,300) (18,439,300 ) Gas and oil properties, net $ 537,000 $ 537,000 As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our condensed
Recently Issued Accounting Standards	Recently Issued Accounting Standards In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

Summary of Significant Accoun15

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Summary of Gas and Oil Properties	The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Total natural gas and oil properties 18,976,300 18,976,300 Accumulated depletion and impairment (18,439,300) (18,439,300 ) Gas and oil properties, net $ 537,000 $ 537,000

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Commodity Derivative Activity and Presentation in the Condensed Statements of Operations	The following table summarizes the commodity derivative activity and presentation in the condensed statements of operations for the periods indicated: Three Months Ended Six Months Ended 2016 2015 2016 2015 Gain reclassified from accumulated other comprehensive income into natural gas and oil revenues $ 200 $ 1,500 $ 400 $ 3,100 (Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ (2,400) $ (1,900 ) $ (100) $ 100
Commodity Derivatives	At June 30, 2016, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Volumes (3) Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2016 4,600 4.15 $ 5,200 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable. (3) The production volumes for 2016 includes the remaining six months of 2016 beginning July 1, 2016.

Fair Value of Financial Instr17

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Assets Measured at Fair Value on a Recurring Basis	Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2016 Derivative assets, gross Commodity puts $ - $ 5,200 $ - $ 5,200 Level 1 Level 2 Level 3 Total As of December 31, 2015 Derivative assets, gross Commodity puts $ - $ 13,400 $ - $ 13,400

Certain Relationships and Rel18

Certain Relationships and Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	The following table provides information with respect to these costs and the periods incurred: Three Months Ended Six Months Ended 2016 2015 2016 2015 Administrative fees $ 13,100 $ 13,000 $ 24,700 $ 27,300 Supervision fees 59,000 58,500 111,200 123,000 Transportation fees 6,200 6,000 11,900 17,500 Direct costs 53,400 33,200 84,600 70,400 Total $ 131,700 $ 110,700 $ 232,400 $ 238,200

Description of Business (Detail

Description of Business (Details)	6 Months Ended
	Jun. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Atlas America Public #9 LTD. Formation Date	Jul. 27, 2000

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 18,976,300	$ 18,976,300
Accumulated depletion and impairment	(18,439,300)	(18,439,300)
Gas and oil properties, net	537,000	537,000
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	254,600	254,600
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 18,721,700	$ 18,721,700

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net derivative assets	$ 5,200		$ 13,400
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	$ 0	$ 0

Derivative Instruments (Summary

Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in the Condensed Statements of Operations) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gain reclassified from accumulated other comprehensive income into natural gas and oil revenues	$ 200	$ 1,500	$ 400	$ 3,100
(Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$ (2,400)	$ (1,900)	$ (100)	$ 100

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivatives) (Details)		6 Months Ended
		Jun. 30, 2016USD ($)MMBTU$ / MMBTU	Dec. 31, 2015USD ($)
Derivative [Line Items]
Fair Value Asset		$ 5,200	$ 13,400
Natural Gas Put Options Production Period Ending December 31, 2016 | Designated as Hedging Instrument
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[1],[2]	4,600
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[3]	$ 5,200
[1]	The production volumes for 2016 includes the remaining six months of 2016 beginning July 1, 2016.
[2]	“MMBtu” represents million British Thermal Units.
[3]	Fair value based on forward NYMEX natural gas prices, as applicable.

Fair Value of Financial Instr24

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 5,200	$ 13,400
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	5,200	13,400
Commodity Puts | Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 5,200	$ 13,400

Certain Relationships and Rel25

Certain Relationships and Related Party Transactions (Narrative) (Details) - MGP and Affiliates	6 Months Ended
	Jun. 30, 2015$ / mo
Administrative costs
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Supervision fees
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	337
Transportation fees
Related Party Transaction [Line Items]
Transportation Fees Rate As Percentage Of Natural Gas Sales Price	13.00%

Certain Relationships and Rel26

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 131,700	$ 110,700	$ 232,400	$ 238,200
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	13,100	13,000	24,700	27,300
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	59,000	58,500	111,200	123,000
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	6,200	6,000	11,900	17,500
Direct costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 53,400	$ 33,200	$ 84,600	$ 70,400

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details)	6 Months Ended
	Jun. 30, 2016USD ($)$ / mo
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly | $ / mo	200
Net production revenue for future plugging and abandonment costs | $	$ 285,200