pub09-10q_20160930.htm

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

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

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

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

	September 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash	$	-		$	-
Accounts receivable trade-affiliate		31,800			29,600
Current portion of derivative assets		-			13,400
Total current assets		31,800			43,000
Gas and oil properties, net		537,000			537,000
Long-term asset retirement receivable-affiliate		333,900			188,100
Total assets	$	902,700		$	768,100
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	624,500		$	302,300
Accrued liabilities		13,100			10,300
Put premiums payable-affiliate		-			6,200
Total current liabilities		637,600			318,800

Asset retirement obligations		1,931,100			1,879,800
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(264,300	)		(181,000	)
Limited partners’ deficit (1,500 units)		(1,401,700	)		(1,250,200	)
Accumulated other comprehensive income		-			700
Total partners’ deficit		(1,666,000	)		(1,430,500	)
Total liabilities and partners’ deficit	$	902,700		$	768,100

	Three Months Ended September 30,					Nine Months Ended September 30,
	Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015		2016			2015
REVENUES
Natural gas and oil	$	55,400		$	47,000	$	149,200		$	203,200
Gain (loss) on mark-to-market derivatives		-			4,500		(100	)		4,600
Total revenues		55,400			51,500		149,100			207,800
COSTS AND EXPENSES
Production		74,100			81,200		254,100			264,200
Depletion		-			8,400		-			27,600
Impairment		-			457,200		-			457,200
Accretion of asset retirement obligations		17,000			25,400		51,300			76,300
General and administrative		26,100			25,800		78,500			81,000
Total costs and expenses		117,200			598,000		383,900			906,300
Net loss	$	(61,800	)	$	(546,500)	$	(234,800	)	$	(698,500)
Allocation of net loss:
Managing general partner	$	(21,900	)	$	(221,100)	$	(83,300	)	$	(277,200)
Limited partners	$	(39,900	)	$	(325,400)	$	(151,500	)	$	(421,300)
Net loss per limited partnership unit	$	(27	)	$	(217)	$	(101	)	$	(281)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016				2015		2016			2015
Net loss	$		(61,800	)	$	(546,500)	$	(234,800	)	$	(698,500)
Other comprehensive loss:
Difference in estimated hedge gains receivable			-			(1,600)		-			200
Less: reclassification adjustment for realized (gain) loss of cash flow hedges in net loss			(300	)		900		(700	)		(2,200)
Total other comprehensive loss			(300	)		(700)		(700	)		(2,000)
Comprehensive loss		$	(62,100	)	$	(547,200)	$	(235,500	)	$	(700,500)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income			Total
Balance at December 31, 2015	$	(181,000	)	$	(1,250,200	)	$	700		$	(1,430,500	)
Participation in revenues, costs and expenses:
Net production expenses		(37,200	)		(67,700	)		-			(104,900	)
Loss on mark-to-market derivatives		-			(100	)		-			(100	)
Accretion of asset retirement obligations		(18,200	)		(33,100	)		-			(51,300	)
General and administrative		(27,900	)		(50,600	)		-			(78,500	)
Net loss		(83,300	)		(151,500	)		-			(234,800	)

Other comprehensive loss		-			-			(700	)		(700	)

Balance at September 30, 2016	$	(264,300	)	$	(1,401,700	)	$	-		$	(1,666,000	)

	Nine Months Ended September 30,
	2016			2015
Cash flows used in operating activities:
Net loss	$	(234,800	)	$	(698,500)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		-			27,600
Impairment		-			457,200
Non-cash loss (gain) on derivative value		6,500			(4,000)
Accretion of asset retirement obligations		51,300			76,300
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(2,200	)		65,500
Increase in asset retirement receivable-affiliate		(145,800	)		(129,600)
Increase in accounts payable trade-affiliate		322,200			202,000
Increase in accrued liabilities		2,800			3,300
Net cash used in operating activities		-			(200)

Cash flows from investing activities:
Net cash provided by investing activities		-			200
		-			200
Cash flows from financing activities:
Net cash used in financing activities		-			-
Net change in cash		-			-
Cash at beginning of period		-			-
Cash at end of period	$	-		$	-

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 Titan Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) is a publicly traded company and operates Titan and the MGP through a 2% preferred member interest in Titan.

The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group for administrative services. (See Item 11: “Executive Compensation”).

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 nine months ended September 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.

Atlas Resource Partners, L.P. Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, Atlas Resource Partners, L.P. (“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 reduced debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).

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 were being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

ARP and the MGP operated 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, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP and 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 was not a party to the Restructuring Support Agreement. The ARP Restructuring did not 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 would 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 was 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 did not have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

On August 26, 2016, an order confirming ARP’s Plan was entered by the Bankruptcy Court. On September 1, 2016, ARP’s Plan became effective and ARP emerged as Titan.

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 liquidation of the Partnership’s operations.

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, these conditions raise substantial doubt about the Partnership’s ability to continue as a going concern.

If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could occur without any further contributions from or distributions to the limited partners.

The significant risks and uncertainties related to the Partnership’s ability to fund its operations raise substantial doubt about the Partnership’s ability to continue as a going concern. The financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under its credit facilities. The MGP’s primary cash requirements are operating expenses, debt service including interest, and capital expenditures.

The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under its credit facilities and equity and debt offerings. The MGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. 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 MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, could negatively impact the MGP’s ability to remain in compliance with the covenants under its credit facilities.

If the MGP is unable to remain in compliance with the covenants under its credit facilities, absent relief from its lenders, as applicable, the MGP may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under the MGP’s credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If an event of default occurs (including if the MGPs’s borrowing base is redetermined below its current outstanding borrowings and they are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency), or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, the MGP will not have sufficient liquidity to repay all of its outstanding indebtedness, and as a result, there would be substantial doubt regarding the MGP’s ability to continue as a going concern.

The MGP continually monitors the capital markets and our capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, the MGP could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels.

The MGP also continues to implement various cost saving measures to reduce its capital, 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 opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. The MGP cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to the MGP’s plan and outlook may occur based on market conditions and its needs at that time, which could include selling assets, seeking additional partners to develop its assets, and/or reducing its planned capital program. In addition, to the extent commodity prices remain low or decline further, or the MGP experiences disruptions in its longer-term access to or cost of capital, the MGP’s ability to fund future capital expenditures, growth projects or the Partnership’s operations may be further impacted.

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.

	September 30, 2016			December 31, 2015
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 balance sheets at September 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

In February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for the Partnership as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements.

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.

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 $0 and $13,400 at September 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:

Pursuant to the Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016, which included the put contracts allocated to the Partnership. As of September 30, 2016, the value allocated to the Partnership is $1,000, net of put premiums of $2,500, which is recorded in accounts receivable trade-affiliate. The put contract value, net of the put premiums, was distributed to the partnership in October 2016.

The Partnership uses a market approach fair value methodology to value for its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of September 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for assets measured at fair value at September 30, 2016 and December 31, 2015 was as follows:

Level 1

Level 2

Level 3

Total

As of September 30, 2016

Derivative assets, gross

Commodity puts

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	13,400	$	-	$	13,400

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Administrative fees	$	12,300	$	11,700	$	37,000	$	39,000
Supervision fees		55,200		52,500		166,400		175,500
Transportation fees		6,800		6,200		18,700		23,700
Direct costs		25,900		36,600		110,500		107,000
Total	$	100,200	$	107,000	$	332,600	$	345,200

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.

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 September 30, 2016, the MGP has withheld $333,900 of net production revenue for future plugging and abandonment costs.

The Partnership and affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising out of the ordinary course of its business. The MGP’s management believes 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.

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

Atlas America Public #9 LTD. (“we”, “us” or 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 Titan Energy, LLC. Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) is a publicly traded company and operates Titan and the MGP through a 2% preferred member interest in Titan.

We have drilled and currently operate wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group, for administrative services.

We intend to continue to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

Atlas Resource Partners, L.P. Restructuring and Chapter 11 Bankruptcy Proceedings

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 were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

On August 26, 2016, an order confirming ARP’s Plan was entered by the Bankruptcy Court. On September 1, 2016, ARP’s Plan became effective and ARP emerged as Titan.

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2016, our MGP has withheld $333,900 of net production revenues for this purpose.

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas and oil producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2016 and 2015, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Production revenues (in thousands):
Gas	$	48		$	42		$	133		$	178
Oil		7			5			16			25
Total	$	55		$	47		$	149		$	203
Production volumes:
Gas (mcf/day) ⁽¹⁾		348			329			338			364
Oil (bbl/day) ⁽¹⁾		2			1			2			2
Total (mcfe/day) ⁽¹⁾		360			335			350			376
Average sales prices: ⁽²⁾
Gas (per mcf) ⁽¹⁾	$	1.48		$	1.39		$	1.43		$	1.80
Oil (per bbl) ⁽¹⁾	$	42.38		$	50.26		$	40.10		$	48.85
Production costs:
As a percent of revenues		134	%		173	%		170	%		130	%
Per mcfe ⁽¹⁾	$	2.23		$	2.63		$	2.67		$	2.58
Depletion per Mcfe	$	-		$	0.27		$	-		$	0.27

Natural Gas Revenues. Our natural gas revenues were $47,400 and $42,100 for the three months ended September 30, 2016 and 2015, respectively, an increase of $5,300 (13%). The $5,300 increase in natural gas revenues for the three months ended September 30, 2016 as compared to the prior year similar period was attributable to a $2,900 increase in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $2,400 increase in production volumes. Our production volumes increased to 348 mcf per day for the three months ended September 30, 2016 from 329 mcf per day for the three months ended September 30, 2015, an increase of 19 mcf per day (6%). The overall increase in natural gas production volumes for the three months ended September 30, 2016 as compared to the prior year similar period is due to additional wells producing during the current three month period.

Our natural gas revenues were $132,700 and $178,500 for the nine months ended September 30, 2016 and 2015, respectively, a decrease of $45,800 (26%). The $45,800 decrease in natural gas revenues for the nine months ended September 30, 2016 as compared to the prior year similar period was attributable to a $33,500 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $12,300 decrease in production volumes. Our production volumes decreased to 338 mcf per day for the nine months ended September 30, 2016 from 364 mcf per day for the nine months ended September 30, 2015, a decrease of 26 mcf per day (7%). The overall decrease in natural gas production volumes for the nine months ended September 30, 2016 as compared to the prior year similar period resulted primarily less wells producing during the current nine month period compared to the prior year and from the normal decline inherent in the life of a well.

Oil Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $8,000 and $4,900 for the three months ended September 30, 2016 and 2015, respectively, an increase of $3,100 (63%). The $3,100 increase in oil revenues for the three months ended September 30, 2016 as compared to the prior year similar period was attributable to a $4,500 increase in production volumes partially offset by a $1,400 decrease in oil prices. Our production volumes increased to 2.04 bbls per day for the three months ended September 30, 2016 from 1.06 bbls per day for the three months ended September 30, 2015, an increase of 0.98 bbls per day (92%).

Our oil revenues were $16,500 and $24,700 for the nine months ended September 30, 2016 and 2015, respectively, a decrease of $8,200 (33%). The $8,200 decrease in oil revenues for the nine months ended September 30, 2016 as compared to the prior year similar period was attributable to a $4,600 decrease in production volumes and a $3,600 decrease in oil prices. Our production volumes decreased to 1.50 bbls per day for the nine months ended September 30, 2016 from 1.86 bbls per day for the nine months ended September 30, 2015, a decrease of 0.36 bbls per day (19%).

(Loss) Gain on Mark-to-Market Derivatives. We recognize changes in fair value of our derivatives immediately within (loss) gain on mark-to-market derivatives on our condensed statements of operations.

We recognized a loss on mark-to-market derivatives of $100 for the nine months ended September 30, 2016 and a gain on mark-to-market derivatives of $4,500 and $4,600 for the three and nine months ended September 30, 2015, respectively. These changes were due to changes in mark-to-market values primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $74,100 and $81,200 for the three months ended September 30, 2016 and 2015, respectively, a decrease of $7,100 (9%). This decrease was primarily due to a decrease in direct costs during the three months ended September 30, 2016. Production expenses were $254,100 and $264,200 for the nine months ended September 30, 2016 and 2015, respectively, a decrease of $10,100 (4%). This decrease was primarily due to a combination of a decrease in transportation charges and supervision fees.

General and administrative expenses for the three months ended September 30, 2016 and 2015 were $26,100 and $25,800, respectively, an increase of $300 (1%). For the nine months ended September 30, 2016 and 2015, these expenses were $78,500 and $81,000, respectively, a decrease of $2,500 (3%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP.

For the three and nine months ended September 30, 2016, there was no depletion recorded due to the recent significant declines in commodity prices and associated previously recorded impairment charges. Therefore, the remaining net book value of gas and oil properties on our condensed balance sheet at September 30, 2016 was primarily related to the estimated salvage value of such properties. For the three and nine months ended September 30, 2015, depletion of gas and oil properties as a percentage of gas and oil revenues was 18% and 14%, respectively.

Cash used by operating activities for nine months ended September 30, 2016 decreased $200 to $0 as compared to $200 for the nine months ended September 30, 2015. This was mostly due to a decrease in the change in accounts receivable trade-affiliate of $67,700, a decrease in net earnings before depletion, impairment, accretion, and non-cash gain on derivative value of $35,600, a decrease in the asset retirement receivable-affiliate of $16,200, and a decrease in the change in accrued liabilities of $500. The decrease was offset by an increase in the change in accounts payable trade-affiliate of $120,200 for the nine months ended September 30, 2016 compared to the period ended September 30, 2015.

There was no cash provided by investing activities for the nine months ended September 30, 2016. Cash provided by investing activities for the nine months ended September 30, 2015 was $200 due to proceeds from the sale of tangible equipment.

There was no cash used in financing activities for the nine months ended September 30, 2016 or 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through September 30, 2016, our MGP has withheld $333,900 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

See Note 2 to our condensed financial statements for additional information related to recently issued accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in the Partnership’s internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pennsylvania		25-1867510
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One
1000 Commerce Drive, 4th Floor
Pittsburgh, PA		15275
(Address of principal executive offices)		(zip code)

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)

Item 1:

	Condensed Balance Sheets as of September 30, 2016 and December 31, 2015	3

	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2016 and 2015	4

	Condensed Statements of Comprehensive Loss for the Three and Nine Months ended September 30, 2016 and 2015	5

	Condensed Statement of Changes in Partners’ Deficit for the Nine Months ended September 30, 2016	6

	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2016 and 2015	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

Item 4:	Controls and Procedures	20

PART II	OTHER INFORMATION

Item 1:	Legal Proceedings	20

Item 6:	Exhibits	21

SIGNATURES		22

CERTIFICATIONS

Exhibit No.		Description
31.1		Certification Pursuant to Rule 13a-14/15(d)-14

31.2		Certification Pursuant to Rule 13a-14/15(d)-14

32.1		Section 1350 Certification

32.2		Section 1350 Certification

101		Interactive Data File


		ATLAS AMERICA PUBLIC #9 LTD.

	By:	Atlas Resources, LLC, its
		Managing General Partner

Date: November 21, 2016	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner

Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☑