UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________________________________________________________________________

FORM 10-K

_______________________________________________________________________________________________

(Mark One)



☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2016~~2017



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 000-49776

_______________________________________________________________________________________________

ATLAS AMERICA PUBLIC #9 LTD.

(Exact name of registrant as specified in its charter)

Pennsylvania		25-1867510
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA		15275
(Address of principal executive offices)		Zip code

_______________________________________________________________________________________________



Pennsylvania		25-1867510
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)
1100 Corporate Drive Birmingham, AL		35242
(Address of principal executive offices)		Zip code

Registrant’s telephone number, including area code: (412) 489-0006

_______________________________________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
None		None

Securities registered pursuant to Section 12(g) of the ~~Exchange~~ Act:

Common Units representing Limited Partnership Interests

(Title of Class)

_______________________________________________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

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



Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☒
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS AMERICA PUBLIC #9 LTD.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

			Page	~~Page~~
PART I	Item 1:	~~Item 1:~~Business	~~Business~~7	7
	Item 2:	~~Item 2:~~Properties	~~Properties~~14	16
	Item 3:	~~Item~~Legal 3:Proceedings	~~Legal Proceedings~~15	18
	Item 4:	~~Item~~Mine 4:Safety Disclosures (Not Applicable)	~~Mine Safety Disclosures (Not Applicable)~~15	18
PART II	Item 5:	~~Item~~Market 5:for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	~~Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities~~16	18
	Item 7:	~~Item~~Management’s 7:Discussion and Analysis of Financial Condition and Results of Operations	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~17	19
	Item 8:	~~Item~~Financial 8:Statements and Supplementary Data	~~Financial Statements and Supplementary Data~~20	26
	Item 9:	~~Item~~Changes 9:in and Disagreements with Accountants on Accounting and Financial Disclosure	~~Changes in and Disagreements with Accountants on Accounting and Financial Disclosure~~33	44
	Item 9A:	~~Item~~Controls ~~9A:~~and Procedures	~~Controls and Procedures~~33	44
PART III	Item 10:	~~Item~~Directors, ~~10:~~Executive Officers and Corporate Governance	~~Directors, Executive Officers and Corporate Governance~~35	45
	Item 11:	~~Item~~Executive ~~11:~~Compensation	~~Executive Compensation~~36	46
	Item 12:	~~Item~~Security ~~12:~~Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	~~Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters~~36	46
	Item 13:	~~Item~~Certain ~~13:~~Relationships and Related Transactions	~~Certain Relationships and Related Transactions~~36	47
	Item 14:	~~Item~~Principal ~~14:~~Accountant Fees and Services	~~Principal Accountant Fees and Services~~37	47
PART IV	Item 15:	~~Item 15:~~Exhibits	~~Exhibits~~38	48
SIGNATURES			39	49

GLOSSARY OF TERMS

Bbl. One barrel of crude oil, condensate, or other liquid hydrocarbons equal to 42 United States gallons.



Key Term		Definition
Bbl		One barrel of oil, condensate, or other liquid hydrocarbons equal to 42 United States gallons.
Bpd		Barrels per day.
Condensate		Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Developed acreage		The number of acres which are allocated or assignable to producing wells or wells capable of production
Development well		A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well		A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
FASB		Financial Accounting Standards Board.
Field		An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
Fractionation		The process used to separate a natural gas liquid stream into its individual components.
GAAP		Generally Accepted Accounting Principles in the United States of America.
Gross acres or gross wells		The total acres or wells, as the case may be, in which a working interest is owned.
MBbl		One thousand barrels of oil, condensate, or other liquid hydrocarbons.
Mcf		One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.
Mcfe		One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.
Mcfd		One thousand cubic feet per day.
Mcfed		One Mcfe per day.
Net acres or net wells		A new well or net acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions of whole numbers.
Natural Gas Liquids or NGLs		A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).
NYMEX		The New York Mercantile Exchange.
NYSE		The New York Stock Exchange.
Oil		Oil and condensate.
Productive well		A producing well or a well that is found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil and natural gas well.
Proved developed reserves		Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Bpd. Barrels per day.

Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Fractionation. The process used to separate a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles in the United States of America.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of crude oil, condensate, or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

Net acres or net wells. A new well or net acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions of whole numbers.

Natural Gas Liquids or NGLs —A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

Oil. Crude oil and condensate.

Productive well. A producing well or a well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Proved developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved gas and oil reserves are those quantities of gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:



Key Term		Definition
Proved reserves		Proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
		(i) The area of the reservoir considered as proved includes:
		(a) The area identified by drilling and limited by fluid contacts, if any, and
		(b) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.
		(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
		(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
		(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
		(a) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
		(b) The project has been approved for development by all necessary parties and entities, including governmental entities.
		(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves or PUDs		Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
PV-10		Present value of future net revenues. See the definition of “standardized measure”.
Reserves		Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

(a) The area identified by drilling and limited by fluid contacts, if any, and

(b) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(a) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(b) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure”.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful well. A well capable of producing gas and/or oil in commercial quantities.



Key Term		Definition
Reservoir		A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
SEC		Securities Exchange Commission.
Standardized Measure		Standardized measure, or standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Successful well		A well capable of producing natural gas and/or oil in commercial quantities.
Undeveloped acreage		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest		An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas and oil regardless of whether such acreage contains proved reserves.

Working interest. An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

FORWARD-LOOKING STATEMENTS

~~The~~This ~~matters~~Form ~~discussed~~10-K ~~within~~includes ~~this report include~~ “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be ~~identified~~materially different from any future results, performance or achievements expressed or implied by the ~~use~~forward-looking ofstatements. In some cases, you can identify forward-looking ~~terminology~~statements in this Form 10-K by words such as “anticipate,” “~~believe~~project,” “~~continue~~intend,” “~~could,” “~~estimate,” “expect,” “~~intend~~believe,” “~~may~~predict,” “~~might~~budget,” “~~plan~~projection,” “~~potential~~goal,” “~~predict~~plan,” “~~should~~forecast,” or “~~will,~~target” or ~~the~~similar ~~negative~~expressions. ~~thereof~~Readers orare ~~other~~cautioned ~~variations~~not ~~thereon~~to orplace ~~comparable~~undue ~~terminology.~~reliance Inon ~~particular,~~these ~~statements~~forward-looking ~~about our expectations~~statements, ~~beliefs,~~which ~~plans,~~speak ~~objectives,~~only ~~assumptions~~as orof ~~future~~the ~~events~~date orhereof. ~~performance~~We ~~contained~~undertake inno ~~this~~obligation ~~report~~to ~~are~~publicly ~~forward-looking~~release ~~statements.~~the Weresults ~~have~~of ~~based~~any ~~these~~revisions to forward-looking statements onwhich ~~our~~we ~~current~~may ~~expectations,~~make ~~assumptions,~~to ~~estimates,~~reflect ~~and~~events ~~projections.~~or ~~While~~circumstances weafter ~~believe~~the ~~these~~date ~~expectations,~~of ~~assumptions,~~this ~~estimates,~~Form ~~and projections are reasonable, such forward~~10-~~looking~~K ~~statements~~or ~~are~~to ~~only~~reflect ~~predictions~~the ~~and~~occurrence ~~involve known and unknown risks and uncertainties, many~~ of ~~which~~unanticipated ~~are beyond our control~~events. The following and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:


•	the demand for natural gas, oil, NGLs and condensate;


•	the price volatility of natural gas, oil, NGLs and condensate;


•	changes in the differential between benchmark prices for oil and natural gas and wellhead prices that we receive;


•	future financial and operating results;


•	resource potential;


•	economic conditions and instability in the financial markets;


•	the accuracy of estimated natural gas and oil reserves;


•	the financial and accounting impact of hedging transactions;


•	the limited payment of distributions, or failure to declare a distribution;


•	the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations at a reasonable cost and within applicable environmental rules;


•	the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;


•	impact fees and severance taxes;


•	changes and potential changes in the regulatory and enforcement environment in the areas in which we conduct business;


•	the effects of intense competition in the natural gas and oil industry;


•	general market, labor and economic conditions and uncertainties;


•	the ability to retain certain key customers;


•	dependence on the gathering and transportation facilities of third parties;


•	the availability of drilling rigs, equipment and crews;


•	potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;


•	uncertainties with respect to the success of drilling wells at identified drilling locations;


•	uncertainty regarding leasing operating expenses, general and administrative expenses and funding and development costs;


•	exposure to financial and other liabilities of the managing general partner;


•	the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our business and operations;


•	restrictions on hydraulic fracturing;


•	exposure to new and existing litigation;


•	development of alternative energy resources; and


•	the effects of a cyber-event or terrorist attack.

~~Given~~The ~~these~~Partnership cautions you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, ~~you~~many of which are ~~cautioned~~beyond ~~not~~our control, incident to ~~place~~the ~~undue~~exploration ~~reliance~~for onand ~~these~~development, ~~forward-looking~~production ~~statements~~and sale of oil and natural gas. ~~The~~These ~~forward-looking~~risks ~~statements~~include, ~~included~~but are not limited to, the risks described in this report. ~~are~~Should ~~made~~one ~~only~~or asmore of the ~~date~~risks ~~hereof.~~or Weuncertainties dodescribed ~~not~~above ~~undertake~~occur, or should underlying assumptions prove incorrect, our actual results and ~~specifically~~plans ~~decline~~could ~~any~~differ ~~obligation~~materially tofrom ~~update~~those expressed in any ~~such~~forward-looking statements. orWe specifically disclaim all responsibility to publicly ~~announce~~update ~~the~~any ~~results~~information ofcontained ~~any~~in ~~revisions~~a toforward-looking ~~any~~statement ofor ~~these~~any ~~statements~~forward-looking tostatement ~~reflect~~in ~~future~~its ~~events~~entirety orand ~~developments~~therefore ~~except~~disclaim asany ~~may~~resulting beliability ~~required~~for bypotentially ~~law~~related damages.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

PART I.

ITEM 1: BUSINESS

Overview

Atlas America Public #9 LTD. (the “Partnership”) is a Pennsylvania limited partnership, formed on July 27, 2000. ~~with~~DGOC ~~Atlas~~Partnership ~~Resources~~Holdings, LLC ~~serving~~serves as its Managing General Partner ~~and Operator~~ (“~~Atlas~~DGOC ~~Resources~~Holdings” or the “MGP”). ~~Atlas~~and ~~Resources~~certain isaffiliates anof ~~indirect~~the ~~subsidiary~~MGP ofserve ~~Titan~~as ~~Energy,~~our ~~LLC~~Operators (~~“Titan”~~"Operators"). ~~Titan~~DGOC Holdings is an ~~independent~~indirect ~~developer~~subsidiary ~~and producer~~ of ~~natural~~Diversified ~~gas,~~Gas ~~crude~~& ~~oil~~Oil, ~~and~~PLC natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“~~ARP~~Diversified”),; aAIM: ~~Delaware limited partnership organized in 2012~~DGOC). Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas America Public #9 LTD.

~~Atlas~~Until ~~Energy~~June ~~Group~~30, 2017, Atlas Resources, LLC served as our Managing General Partner and Operator (“Atlas ~~Energy Group~~Resources”; ~~OTCQX:~~or ~~ATLS~~“Previous MGP”). Atlas Resources is aan ~~publicly~~indirect ~~traded~~subsidiary ~~company~~of ~~and~~Titan ~~manages~~Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, oil, and natural gas liquids, with operations in basins across the ~~MGP~~United ~~through~~States. On May 4, 2017, Titan entered into a 2%definitive ~~preferred~~agreement ~~member~~to sell, among other conventional assets, its general and limited partnership equity interest (“Equity Interest”) in ~~Titan~~the Partnership to Diversified (the “Purchase and Sale Agreement” or “PSA”). The transaction was subject to customary closing conditions, had an effective date of April 1, 2017 and closed on June 30, 2017. Upon closing the PSA, the Previous MGP’s Equity Interest in the Partnership was transferred to DGOC Holdings and DGOC Holdings was admitted as a substitute MGP of the Partnership.

~~The~~For ~~Partnership~~additional ~~has~~information, ~~drilled~~see ~~and~~Part ~~currently operates wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management~~II, ~~which~~Item ~~in turn~~8, ~~relies~~Note ~~on Atlas Energy Group for administrative services~~1.

~~The~~Historical ~~Partnership’s~~Drilling 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. Activity

~~The~~During ~~economic~~2000 ~~viability~~and of2001, ~~the~~we ~~Partnership’s~~drilled ~~production~~85 isgross ~~based~~wells, on80.75 anet ~~variety of factors including proved developed reserves that it can expect to recover through existing~~ wells, ~~with~~within ~~existing~~the ~~equipment~~Clinton/Medina and ~~operating~~Upper ~~methods~~Devonian orSandstones ingeological ~~which~~formations ~~the~~in ~~cost~~Pennsylvania ofand ~~additional~~Ohio. ~~required~~We ~~extraction~~intend ~~equipment is relatively minor compared~~ to ~~the~~produce ~~cost~~our ofwells auntil ~~new~~they ~~well;~~are ~~and~~depleted ~~through~~or ~~currently~~become ~~installed~~uneconomical ~~extraction~~to ~~equipment~~produce, ~~and~~at ~~related infrastructure~~ which ~~is operational at the~~ time ofthey ~~the~~will ~~reserves~~be ~~estimate~~plugged ~~(if~~and ~~the~~abandoned ~~extraction is by means not involving drilling, completing~~ or ~~reworking a well)~~sold. ~~There~~No ~~are~~other ~~numerous~~wells ~~uncertainties~~will ~~inherent~~be indrilled ~~estimating~~and ~~quantities~~no ofadditional ~~proven~~funds ~~reserves~~will ~~and~~be inrequired ~~projecting~~for ~~future net revenues~~drilling.

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.

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 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~~Natural ~~Partnership~~Gas ~~was not a party to the Restructuring Support Agreement. The ARP Restructuring did not materially impact the MGP’s ability to perform as the managing general partner~~ and ~~operator~~Oil 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.Production

~~Atlas~~Production ~~Energy~~Revenues, ~~Group~~Volumes, ~~was~~Prices ~~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.~~Costs

OnThe ~~August 26,~~MGP ~~2016,~~markets anthe ~~order~~majority ~~confirming~~of ~~ARP’s~~our ~~Plan~~natural ~~was~~gas ~~entered~~production byto natural gas marketers directly or to third-party plant operators who process and market the ~~Bankruptcy~~natural ~~Court~~gas. On ~~September~~Our 1,oil ~~2016~~production is sold to crude oil processors, ~~ARP’s~~transporters ~~Plan~~and ~~became~~refining ~~effective~~and marketing companies in the area. The sales price of natural gas and ~~ARP~~oil ~~emerged~~produced asis ~~Titan~~a function of the market in the area and typically tied to a regional index.

~~Liquidity~~Our production revenues and estimated natural gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents our production revenues, ~~Capital~~volumes ~~Resources~~and average sales prices for our natural gas and ~~Ability~~oil toproduction ~~Continue~~for asthe aperiods ~~Going~~indicated, ~~Concern~~along with our average production costs in each of the reported periods:

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 continued to 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.



	Years Ended December 31,
	2017		2016		$ Change			% Change
Production revenues (in thousands):
Natural gas revenue	$	252	$	185	67			36	%
Oil revenue	34		31		3			10	%
Total revenues	$	286	$	216	70			32	%

Production:
Natural gas (Mcf)	98,163		117,749		(19,586		)	(17	)%
Oil (Bbl)	718		743		(25		)	(3	)%
Total (Mcfe)	102,471		122,207		(19,736		)	(16	)%

Average sales price:
Natural gas (per Mcf)	$	2.57	$	1.58	$	0.99		63	%
Oil (per Bbl)	$	47.02	$	41.55	$	5.47		13	%

Production costs (per Mcfe)	$	3.21	$	2.69	$	0.52		19	%

~~Historically,~~Our ~~there~~ongoing ~~has~~operating ~~been~~and nomaintenance ~~need~~costs tohave ~~borrow~~been ~~funds~~or ~~from~~are ~~the~~expected ~~MGP~~ to ~~fund~~be ~~operations~~fulfilled asthrough ~~the~~revenues ~~cash flow~~ from the ~~Partnership’s~~sale ~~operations~~of ~~had~~our ~~been~~natural ~~adequate~~gas toand ~~fund~~oil ~~its~~production ~~obligations~~ and ~~distributions~~through ~~to its partners. However,~~ the ~~recent~~subsidization ~~significant~~of ~~declines~~our inMGP. ~~commodity~~Our ~~prices~~MPG ~~have~~charges ~~challenged~~a ~~the~~monthly ~~Partnership’s~~well ~~ability~~supervision tofee ~~fund~~of ~~its~~$337 ~~operations~~per ~~and~~well ~~may~~per ~~make~~month itas ~~uneconomical~~outlined ~~for~~in ~~the~~our ~~Partnership~~drilling toand ~~produce~~operating ~~its~~agreement. ~~wells~~This ~~until~~well ~~they~~supervision ~~are~~fee ~~depleted~~covers asall ~~the~~normal ~~Partnership~~and ~~originally~~regularly ~~intended.~~recurring ~~Accordingly,~~operating ~~these~~expenses ~~conditions~~for ~~raise~~the ~~substantial~~production ~~doubt~~and ~~about~~sale ~~the~~of ~~Partnership’s~~natural ~~ability~~gas toand ~~continue~~oil assuch ~~a going concern.~~as:

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 MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations; however, the uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which further raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended. 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.

MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern

The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for 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 Titan’s 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 continued to 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, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern.

Titan expects to finalize an amendment to its first lien credit facility on April 19, 2017 in an attempt to ameliorate some of its liquidity concerns, subject to receiving the remaining lenders’ consent. The amendment is expected to provide for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility.

Unless Titan is able to obtain an amendment or waiver, the lenders under Titan’s second lien credit facility may declare a default with respect to Titan’s failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under Titan’s second lien credit facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under Titan’s second lient credit facility have not yet given notice of any default.

Titan continually monitors the capital markets and the MGP’s 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, Titan 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. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility.

Gas and Oil Production

Production Volumes

The following table presents our total net natural gas and oil production volumes for the periods indicated:

	Years Ended December 31,
	2016		2015
Production: (1)
Natural gas (Mcf)		117,749		135,581
Oil (Bbl)		743		765
Total (Mcfe)		122,207		140,171

(1) Production quantities consist of the sum of our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells.

Production Revenues, Prices and Costs

The MGP markets the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline and Transco Leidy Line.

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas. The following table presents our production revenues and average sales prices for our natural gas and oil production for the periods indicated, along with our average production costs in each of the reported periods:

	Years Ended December 31,
	2016		2015
Production revenues (in thousands):
Natural gas revenue	$	185	$	230
Oil revenue		31		35
Total revenues	$	216	$	265
Average sales price: (1)
Natural gas (per Mcf)	$	1.58	$	1.70
Oil (per Bbl)	$	41.55	$	45.08
Production costs (per Mcfe)	$	2.69	$	2.47

(1) Average sales prices represent accrual basis pricing.

Our ongoing operating and maintenance costs have been or are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We are charged by our MGP a monthly well supervision fee of $337 per well per month as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:


•	Well tending, routing maintenance and adjustment;


•	Reading meters, recording production, pumping, maintaining appropriate books and records; and


•	Preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment and materials and brine disposal. If these expenses are incurred, we are charged the costs 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 cost of the well. As of December 31, ~~2016~~2017, our MGP and the Previous MGP withheld $~~382~~576,~~500~~900 of net production revenue for this purpose. For additional information, see Part II, Item 8, Note 1.

108

Drilling Activity

We received total cash subscriptions from investors of $14,905,500 which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $6,256,300. We have drilled 85 development wells within the Clinton/Medina and Upper Devonian Sandstones geological formations in Pennsylvania and Ohio. We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by the Partnership:

	Gross		Net
Gas and/or oil wells drilled		83.00		78.75
Dry hole		2.00		2.00
Total wells drilled		85.00		80.75

Natural Gas and Oil Leases

The MGP has contributed all the undeveloped leases or lease interests necessary to drill each of the partnership’s wells. The MGP has received a credit to its capital account equal to the cost of each lease or the fair market value of each lease if the MGP has reason to believe that cost is materially more than the fair market value.

Contractual Revenue Arrangements

~~Natural~~We ~~Gas.~~have ~~The~~no ~~MGP~~delivery ~~markets~~commitments ~~the~~for ~~majority~~fixed ~~of our natural gas production to gas purchasers directly or to third party midstream companies who gather, treat,~~ and ~~process,~~determinable asquantities ~~necessary, and market the gas. The sales price~~ of natural gas ~~produced~~and isoil ~~a function of the market~~ in ~~the~~any ~~area~~future ~~and~~periods ~~typically~~under ~~linked~~existing tocontracts aor ~~regional index~~agreements. ~~The pricing indices for the majority of our production areas are as follows:~~

•Natural ~~Appalachian~~Gas. ~~Basin~~The -MGP ~~Dominion~~markets ~~South~~the ~~Point,~~majority ~~Tennessee~~of ~~Gas~~our ~~Pipeline~~natural ~~Zone~~gas 4production ~~(200~~to ~~Leg)~~natural gas purchasers directly or to third- party midstream companies who gather, ~~Transco~~treat, ~~Leidy~~and ~~Line~~process, ~~Columbia~~as ~~Appalachia~~necessary, ~~NYMEX~~and market the natural gas. The sales price of natural gas produced is a function of the market in the area and ~~Transco~~typically ~~Zone~~linked 5to a regional index. The pricing indices for the majority of our production include:

We• ~~attempt~~Dominion toSouth sell the majority of our natural gas at monthly, fixed index prices and a smaller portion at index daily prices. We do not have delivery commitments for fixed and determinable quantities of natural gas in any future periods under existing contracts or agreements.Point

~~Crude~~• Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil purchaser either directly or thru a common carrier acting on behalf of the oil purchaser. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.NYMEX

~~For~~• ~~the~~Tetco year ended December 31, 2016, Chevron Natural Gas, Hess Corporation, Castleton Commodities Merchant Trading, LLC, and Ergon Oil Purchasing, Inc. accounted for approximately 28%, 23%, 16% and 15%, respectively of our total natural gas and oil production revenues, with no other single customer accounting for more than 10% of revenues for this period. M2

Oil. Oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil purchaser either directly or through a common carrier acting on behalf of the oil purchaser. The oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges.

The following table summarizes our customers accounting for at least 10% of total natural gas and oil production revenues for the year ended December 31, 2017:



Direct Energy Business LLC	55	%
Castleton Commodities Merchant Trading, LLC	21	%
Ergon Oil Purchasing, Inc.	12	%
Other (no single customer accounts for more than 10% of revenues)	12	%
Total	100	%

Natural Gas Gathering Agreements

~~Virtually~~Substantially all natural gas produced is gathered through one or more pipeline systems before sale or delivery to a purchaser or an interstate pipeline. AEach ~~gathering~~separate ~~fee~~company ~~can~~providing begathering ~~charged~~services ~~for~~charges ~~each~~a gathering ~~activity~~fee ~~that~~for ~~is utilized and by~~ each ~~separate~~gathering ~~gatherer~~activity ~~providing the service~~provided. Fees will vary depending on the distance the gas travels and whether additional services such as compression, blending, or treating are provided.

InWe ~~Appalachia, we~~ have gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”). Under these agreements, we dedicate our natural gas production in certain areas within southwest Pennsylvania to Laurel Mountain for transportation to interstate pipeline systems or local distribution companies, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas subject to certain conditions. ~~The~~For its services, Laurel Mountain charges the greater of $0.35 per mcf or 16% of the gross sales price of the natural gas, isthough ~~charged~~it bydoes ~~Laurel~~charge ~~Mountain~~a ~~for the majority of the gas. A~~ lesser fee ~~does apply~~ to a small number of specific wells in the area.

11Competition and Markets

~~Competition~~We operate entirely within the Appalachian Basin of the United States. The oil and natural gas industry is affected by many factors that we cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on our operations and profitability. The impact of these factors is extremely difficult to accurately predict or anticipate. It is difficult for us to predict the occurrence of events that may affect commodity prices or the degree to which these prices will be affected; however, the prices we receive for the commodities we produce will generally approximate current market prices in the geographic region of the production.

WeNatural ~~operate~~gas inprices aare ~~highly~~primarily ~~competitive~~determined ~~environment~~by ~~for~~North ~~acquiring~~American ~~properties~~supply and ~~other~~demand ~~energy~~and ~~companies,~~to ~~attracting~~a ~~capital~~lesser extent, ~~contracting~~natural ~~for~~gas ~~drilling~~exports ~~equipment~~ and ~~securing~~are ~~trained~~heavily ~~personnel.~~influenced Weby ~~also~~weather ~~compete with the exploration~~ and ~~production~~storage ~~divisions of public utility companies for mineral property acquisitions~~levels. ~~Competition~~Natural isgas ~~intense~~prices ~~for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. Our competitors~~ may becontinue ~~able~~ to ~~pay~~be ~~more~~under ~~for~~pressure ~~hydrocarbon~~largely ~~properties~~due ~~and~~ to ~~evaluate,~~excess ~~bid~~supply ~~for and purchase a greater number~~ of ~~properties~~natural ~~than~~gas ~~our~~caused ~~financial~~by orthe ~~personnel~~high ~~resources~~productivity ~~permit. Furthermore, competition arises not only from numerous domestic and foreign sources~~ of ~~hydrocarbons~~shale ~~but~~plays ~~also~~in ~~from~~the ~~other~~United ~~industries~~States ~~that~~which ~~supply~~has ~~alternative~~outpaced ~~sources of energy~~demand. ~~Product~~Depressed ~~availability~~natural ~~and~~gas ~~price~~futures ~~are~~prices reflect the ~~principal~~expectation ~~means~~there ofwill ~~competition~~be inan ~~selling~~oversupply ~~natural~~of ~~gas, crude oil, and~~ natural gas ~~liquids.~~in ~~Many~~the ~~of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their hydrocarbon production more effectively than we do~~future.

~~Markets~~ 9

~~The~~Significant ~~availability~~factors ofthat awill ~~ready~~impact ~~market~~2018 ~~for natural gas and~~ oil ~~and~~prices ~~the~~include ~~price~~worldwide ~~obtained~~economic conditions, ~~depends~~political ~~upon~~and ~~numerous~~economic ~~factors~~developments ~~beyond~~in ~~our~~the ~~control.~~Middle ~~Product~~East, ~~availability~~Africa and ~~price~~South ~~are~~America, ~~the~~demand ~~principal means of competition~~ in ~~selling~~Asian ~~natural gas~~ and ~~oil.~~European ~~During~~markets and the ~~years~~extent ~~ended~~to ~~December~~which ~~31,~~members ~~2016~~of ~~and~~the ~~2015,~~Organization weof ~~did~~Petroleum ~~not~~Exporting ~~experience~~Countries ~~problems~~and inother ~~selling~~oil ~~our~~exporting ~~natural~~nations ~~gas~~choose ~~and~~to manage oil, ~~although~~supply ~~prices~~through ~~have~~export ~~varied significantly during those periods~~quotas.

Natural gas and oil prices affect:


•	our revenues, profitability and cash flow;


•	the quantity of natural gas and oil that we can economically produce; and


•	the quantity of natural gas and oil shown as proved reserves.

Any continued or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, and cash flows.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the ~~summer~~spring and fall months and increases during the winter months and, in some areas, also increases during the summer months. Seasonal anomalies such as mild winters or hot summers ~~sometimes~~also ~~lessen~~may impact this ~~fluctuation~~demand. In addition, ~~certain~~pipelines, ~~natural~~utilities, ~~gas~~local distribution companies and industrial end-users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also ~~lessen~~impact ~~seasonal~~the ~~demand~~seasonality ~~fluctuations.~~of ~~In addition, seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas~~demand. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations.

Environmental Matters and Regulation

Our operations ~~relating to drilling and waste disposal~~ are subject to ~~stringent~~numerous federal, state and ~~complex~~local laws and regulations ~~pertaining~~governing tooccupational health, ~~safety~~ and safety, the ~~environment.~~discharge Asof ~~operators~~materials ~~within~~into the ~~complex~~environment ~~natural~~or ~~gas~~otherwise ~~and~~relating ~~oil~~to ~~industry~~environmental protection, wesome ~~must~~of ~~comply~~which ~~with~~carry ~~laws~~substantial ~~and~~administrative, ~~regulations~~civil atand ~~the~~criminal ~~federal,~~penalties ~~state~~for ~~and~~failure ~~local~~to ~~levels~~comply. These laws and regulations ~~can~~may ~~restrict~~include orbut ~~affect~~are ~~our~~not ~~business~~limited ~~activities in many ways, such as by~~to:

• ~~restricting~~ the ~~way~~acquisition ~~waste~~of ~~disposal~~a ispermit ~~handled~~before construction commences;

• ~~limiting~~restriction orof ~~prohibiting~~the ~~drilling~~types, ~~construction~~quantities and ~~operating~~concentrations ~~activities~~of invarious ~~sensitive~~substances ~~areas~~that ~~such~~can asbe ~~wetlands,~~released ~~coastal~~into ~~regions,~~the ~~non-attainment~~environment ~~areas,~~in ~~tribal~~connection ~~lands~~with orproduction ~~areas~~and ~~inhabited~~transporting bythrough ~~threatened or endangered species~~pipelines;

• ~~requiring~~governing the ~~acquisition~~sourcing and disposal of ~~various~~water ~~permits~~used ~~before~~in the ~~commencement~~drilling ofand ~~drilling~~completion process;

• requiring ~~the~~some ~~installation~~form of ~~expensive~~remedial action to prevent or mitigate pollution ~~control~~from ~~equipment~~existing and ~~water~~former ~~treatment~~operations ~~facilities~~such as plugging abandoned wells or closing earthen impoundments; and

• ~~restricting~~imposing ~~the~~substantial ~~types,~~liabilities ~~quantities~~for ~~and~~pollution ~~concentration~~resulting offrom ~~various~~operations ~~substances~~or ~~that~~failure ~~can~~to becomply ~~released into the environment in connection~~ with ~~siting,~~regulatory ~~drilling, completion, production, and plugging activities;~~filings.

•These ~~requiring~~laws ~~remedial~~and ~~measures~~regulations toalso ~~reduce~~may restrict the rate of production. Moreover, ~~mitigate~~changes in environmental laws and/ regulations often occur, and any changes that result in more stringent and costly well construction, drilling, water management or ~~respond~~completion toactivities ~~releases~~or ofmore ~~pollutants~~restrictive waste handling, storage, transport, disposal or ~~hazardous~~cleanup requirements for any substances ~~from~~used ~~existing~~or ~~and~~produced ~~former~~in our operations could materially adversely affect our operations and financial position, ~~such~~as well as ~~pit~~those ~~closure~~of the oil and ~~plugging~~natural ofgas ~~abandoned~~industry ~~wells;~~in general.

•Oil ~~enjoining~~and ~~some~~natural gas activities have increasingly faced opposition from environmental organizations and, in certain areas, have been, restricted or ~~all~~banned by governmental authorities in response to concerns regarding the prevention of pollution or the ~~operations~~protection of ~~facilities~~the ~~deemed~~environment. inMoreover, ~~non-compliance~~some ~~with~~environmental ~~permits~~laws ~~issued~~and ~~pursuant~~regulations may impose strict liability regardless of fault or knowledge, which could subject us to ~~such~~liability ~~environmental~~for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties at sites we currently own or where we have sent wastes for disposal. To the extent future laws ~~and~~or regulations; are implemented or other governmental action is taken that prohibits, restricts or materially increases the costs of drilling, or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected. The following is a summary of some of the environmental laws to which our operations are subject.

•Comprehensive ~~imposing~~Environmental ~~substantial~~Response, ~~liabilities~~Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for ~~pollution~~the ~~resulting~~release ~~from~~of ~~operations;~~a “hazardous substance” into the environment. These persons may include owners or operators of the disposal site or sites where the hazardous substance release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, all of these persons may be subject to joint

~~• requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.~~10

~~Failure~~and toseveral ~~comply~~liability ~~with~~for ~~these~~the ~~laws~~costs ~~and~~of ~~regulations~~cleaning ~~may~~up ~~result~~the inhazardous ~~the~~substances ~~assessment~~that ofhave ~~administrative,~~been ~~civil~~released orinto ~~criminal~~the ~~penalties~~environment, ~~the~~for ~~imposition~~damages ofto ~~remedial~~natural ~~requirements,~~resources and for the ~~issuance~~costs of ~~orders~~certain ~~enjoining~~health ~~future operations~~studies. ~~Certain~~In ~~environmental statutes impose strict~~addition, ~~joint~~it ~~and~~is ~~several~~not ~~liability~~uncommon for ~~costs~~neighboring ~~required~~landowners ~~to clean up~~ and ~~restore~~other ~~sites~~third ~~where~~parties, ~~pollutants~~pursuant orto ~~wastes~~environmental ~~have~~statutes, ~~been~~common ~~disposed~~law or ~~otherwise~~both, ~~released.~~to ~~Neighboring landowners and other third parties can~~ file claims for personal injury orand property ~~damage~~damages allegedly caused by ~~noise and/or~~ the release of ~~pollutants~~hazardous substances or ~~wastes~~other pollutants into the environment. ~~These~~Although ~~laws~~petroleum, ~~rules~~including crude oil and ~~regulations~~natural ~~may~~gas, ~~also~~is ~~restrict~~not ~~the~~a ~~rate~~“hazardous ofsubstance” ~~natural~~under ~~gas~~CERCLA, ~~and~~at ~~oil~~least ~~production~~two ~~below~~courts ~~the~~have ~~rate~~ruled that ~~would~~certain ~~otherwise~~wastes beassociated ~~possible.~~with ~~The~~the ~~regulatory~~production ~~burden~~of oncrude ~~the~~oil ~~natural~~may ~~gas~~be ~~and~~classified ~~oil~~as ~~industry~~“hazardous ~~increases~~substances” ~~the~~under ~~cost~~CERCLA and that releases of ~~doing~~such ~~business~~wastes inmay ~~the~~therefore ~~industry~~give ~~and~~rise ~~consequently~~to ~~affects~~liability ~~profitability~~under CERCLA. ~~Additionally,~~While ~~Congress~~we ~~and~~generate ~~federal~~materials ~~and~~in ~~state~~the ~~agencies~~course ~~frequently~~of ~~enact~~our ~~new,~~operations ~~and~~that ~~revise~~may ~~existing,~~be ~~environmental~~regulated ~~laws~~as ~~and~~hazardous ~~regulations~~substances, ~~and~~we ~~any~~have ~~new~~not ~~laws~~received ornotification ~~changes~~that towe ~~existing~~may ~~laws~~be ~~that~~potentially ~~result~~responsible infor ~~more~~cleanup ~~stringent~~costs ~~and~~under ~~costly~~CERCLA. ~~waste~~In ~~handling~~addition, ~~disposal~~certain ~~and~~state ~~clean-up~~laws ~~requirements~~also ~~for~~regulate the disposal of oil and natural gas wastes. New state and ~~oil~~federal ~~industry~~regulatory initiatives that could have a significant adverse impact on ~~our~~us ~~operating~~may ~~costs~~periodically be proposed and enacted.

Waste handling. We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental Protection Agency (“EPA”) and state agencies under RCRA’s less stringent non-hazardous solid waste provisions. It is possible that these solid wastes could in the future be reclassified as hazardous wastes, whether by amendment of RCRA or adoption of new laws, which could significantly increase our costs to manage and dispose of such wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies in our industry. Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We currently own or lease, and have in the past owned or leased, properties that have been used for many years for the exploration and production of oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

Water discharges and use. The Federal Water Pollution Control Act, as amended (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. We regularly review our natural gas and oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans, the costs of which are not expected to be substantial.

The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in substantial compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

The Underground Injection Control (“UIC”) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. In connection with our operations, the Partnership may dispose of produced water in underground wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. However, because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal. For example, in January 2016, Ohio lawmakers proposed new legislation that would, among other things, require injection wells be located more than 2,000 feet from any occupied dwelling. While that particular legislation did not become law, should

similar onerous regulations or bans relating to underground wells be placed in effect in areas where the Partnership has significant operations, there could be an impact on the Partnership's ability to operate.

Hydraulic fracturing. Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This process is typically regulated by state environmental agencies and oil and natural gas commissions; however, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act (as defined below) regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; proposed effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Additionally, while the Federal Bureau of Land Management (“BLM”) released a final rule setting forth disclosure requirements and other regulatory mandates for hydraulic fracturing on federal lands in March 2015, on December 29, 2017, the U.S. Department of Interior rescinded the 2015 rule that would have set new environmental limitations on hydraulic fracturing, or fracking, on public lands because it believed the 2015 rule imposed administrative burdens and compliance costs that were not justified. Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition to any actions by Congress, certain states in which we operate, including Pennsylvania, have adopted, and other states are considering adopting, regulations imposing or that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing operations. States could also elect to prohibit hydraulic fracturing altogether, such as in the State of New York. Local governments also may seek to adopt ordinances within their jurisdiction regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional, more significant, costs to comply with such requirements and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

In addition, certain government reviews are underway that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA issued its final report on the potential of hydraulic fracturing to impact drinking water resources through water withdrawals, spills, fracturing directly into such resources, underground migration of liquids and gases, and inadequate treatment and discharge of wastewater which did not find evidence that these mechanisms have led to widespread, systematic impacts on drinking water resources. However, the EPA’s report did identify future efforts that could be taken to further understand the potential of hydraulic fracturing to impact drinking water resources, including ground water and surface water monitoring in areas with hydraulically fractured oil and gas production wells. Based on the EPA’s study, existing regulations and our practices, we do not believe our hydraulic fracturing operations are likely to impact drinking water resources but the EPA study could result in initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

We believe that our hydraulic fracturing activities follow applicable industry practices and legal requirements for groundwater protection and that our hydraulic fracturing operations have not resulted in material environmental liabilities. We do not maintain insurance policies intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our existing insurance policies would cover any alleged third-party bodily injury and property damage caused by hydraulic fracturing including sudden and accidental pollution coverage.

Air emissions. The Clean Air Act of 1963 (as amended, the “Clean Air Act”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals for emissions of pollutants. For example, pursuant to then President Obama’s Strategy to Reduce Methane Emissions in August 2015, the EPA proposed new regulations that would set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. The EPA finalized these new regulations on June 3, 2016 to be effective August 2, 2016; however on June 12, 2017 the EPA announced a proposed 2 year stay on these fugitive emissions standards “while the agency reconsiders them”. Therefore, the date when and if these standards may become implemented is still not known. In a second example, in October 2015, the EPA finalized a rulemaking proposal that revises the National Ambient Air Quality Standard for ozone to 70 parts per billion for both the 8-hour primary and secondary standards. Compliance with one or both of these regulatory initiatives could directly impact us by requiring

Weinstallation ~~believe~~of ~~that~~new ~~our~~emission ~~operations~~controls are in substantial compliance with applicable environmental laws and regulations, and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on ~~our~~some ~~business, financial position or results~~ of ~~operations.~~our ~~Nevertheless~~equipment, ~~the~~resulting ~~trend~~ in ~~environmental~~longer ~~regulation~~permitting istimelines, ~~to place more restrictions~~ and ~~limitations~~significantly onincreasing ~~activities~~our ~~that~~capital ~~may affect the environment. As a result, there can be no assurance as to the amount or timing of future~~ expenditures ~~for environmental compliance or remediation,~~ and ~~actual~~operating ~~future expenditures may be different from the amounts we currently anticipate. Moreover~~costs, wewhich ~~cannot~~could ~~assure~~adversely ~~future~~impact ~~events,~~our ~~such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs~~business.

~~Environmental~~Climate ~~laws~~change. In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. We could ~~have~~become asubject ~~material~~to ~~impact~~these Title V and PSD permitting reviews and be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels. The EPA has also adopted rules requiring the reporting of GHG emissions from specified emission sources in the United States on ~~our~~an ~~operations~~annual basis, including certain oil and natural gas production facilities, which include ~~the~~several ~~following:~~of our facilities. We believe that our monitoring activities and reporting are in substantial compliance with applicable obligations.

~~National~~Congress ~~Environmental~~has ~~Policy~~from ~~Act.~~time ~~Natural~~to ~~gas~~time ~~and~~considered ~~oil~~legislation ~~exploration and production activities on federal lands are subject~~ to ~~the~~reduce ~~National~~emissions ~~Environmental~~of ~~Policy~~GHGs ~~Act,~~and orthere ~~“NEPA.”~~have ~~NEPA~~been ~~requires~~a ~~federal~~number ~~agencies, including the Department~~ of ~~Interior, to evaluate major~~ federal ~~agency~~regulatory ~~actions~~initiatives ~~having~~to ~~the~~address ~~potential~~GHG toemissions ~~significantly~~in ~~affect~~recent ~~the~~years, ~~environment.~~such Inas the ~~course~~establishing of ~~such~~Title ~~evaluations,~~V anand ~~agency~~PSD ~~will~~permitting ~~typically~~reviews ~~require~~for anGHG ~~Environmental~~emissions ~~Assessment~~as todescribed ~~assess~~in ~~the~~more ~~potential~~detail ~~direct~~above. Additionally, ~~indirect~~a ~~and~~number ~~cumulative impacts~~ of astate ~~proposed project~~ and, ifregional ~~necessary,~~efforts ~~will~~have ~~prepare~~emerged ~~a more detailed Environmental Impact Statement~~ that ~~will~~are beaimed ~~made~~at ~~available~~tracking ~~for~~and/or ~~public~~reducing ~~review~~GHG ~~and~~emissions ~~comment.~~by ~~All~~means of ~~our~~cap ~~proposed exploration~~ and ~~production~~trade ~~activities~~programs onthat ~~federal~~typically ~~lands,~~require ifmajor ~~any,~~sources ~~require~~of ~~governmental~~GHG ~~permits~~emissions, ~~many~~such ofas ~~which~~electric ~~are~~power ~~subject~~plants, to ~~the~~acquire ~~requirements~~and ofsurrender ~~NEPA.~~emission ~~This~~allowances ~~process~~in ~~has~~return ~~the~~for ~~potential~~emitting tothose ~~delay the development of natural gas and oil projects~~GHGs.

~~Hydraulic~~Although ~~Fracturing. In~~it ~~recent~~is ~~years,~~not ~~federal,~~possible ~~state,~~at ~~and~~this ~~local~~time ~~scrutiny~~to ofpredict ~~hydraulic~~how ~~fracturing~~legislation ~~has~~or ~~increased. Regulation~~new ofregulations ~~the~~that ~~practice~~may ~~remains~~be ~~largely~~adopted ~~the~~to ~~province~~address ofGHG ~~state~~emissions ~~governments,~~would ~~except~~impact ~~for~~our abusiness, ~~Bureau~~any ofsuch ~~Land~~future ~~Management~~federal ~~rule~~or ~~that~~state ~~would~~laws ~~have~~and ~~imposed~~regulations, ~~conditions~~or oninternational ~~fracturing operations on federal lands~~compacts, ~~which~~could ~~was~~require ~~enjoined~~us byto aincur ~~federal~~increased ~~court~~operating ~~holding~~costs, ~~BLM~~such ~~lacked~~as ~~the~~costs ~~authority~~ to ~~adopt~~purchase ~~the~~and ~~rule. Common~~operate ~~elements~~emissions ofcontrol ~~state regulations governing hydraulic fracturing may include~~systems, ~~but~~to ~~not~~acquire beemission ~~limited~~allowances ~~to,~~or ~~the~~comply ~~following:~~with ~~requirement~~new ~~that~~regulatory ~~logs~~or ~~and~~reporting ~~pressure~~requirements. ~~test~~On ~~results~~an ~~are~~international ~~included~~level, inthe ~~disclosures~~United toStates ~~state~~was ~~authorities;~~one ~~disclosure~~ of ~~hydraulic~~almost ~~fracturing~~200 ~~fluids~~nations ~~and chemicals~~that, ~~potentially~~in ~~subject~~December ~~to trade secret/confidential proprietary information protections~~2015, ~~and~~agreed ~~the~~to ~~ratios~~an ofinternational ~~same~~climate ~~used~~change agreement in ~~operations;~~Paris, ~~specific~~France ~~disposal~~that ~~regimens~~calls for ~~hydraulic~~countries ~~fracturing~~to ~~fluids;~~set ~~replacement/remediation~~their ofown ~~contaminated~~GHG ~~water~~emissions ~~assets;~~targets and ~~minimum~~be ~~depth~~transparent ofabout ~~hydraulic~~the ~~fracturing. In~~measures ~~December~~each ~~2016,~~country ~~EPA~~will ~~released~~use ~~the~~to ~~final~~achieve ~~report~~its ofGHG ~~its~~emissions ~~study~~targets, ofwhich ~~the~~agreement ~~impacts~~formally ofentered ~~hydraulic~~into ~~fracturing~~force on ~~drinking~~November ~~water~~4, ~~in the U~~2016.S. ~~finding~~While ~~that~~ the ~~hydraulic~~United ~~fracturing~~States ~~water~~formally ~~cycle~~accepted ~~can~~that ~~impact~~agreement ~~drinking~~in ~~water~~September ~~resources~~2016, ~~under~~on ~~some~~June ~~circumstances. Those~~1, ~~circumstances~~2017, ~~included~~President ~~where~~Trump ~~(1)~~determined ~~there~~to ~~are~~withdraw ~~water~~the ~~withdrawals~~United ~~for~~States ~~hydraulic~~from ~~fracturing~~the inParis ~~times~~Agreement. orUnder ~~areas~~the term of ~~low~~the ~~water~~Paris ~~availability~~Agreement, ~~(2)~~the ~~hydraulic~~earliest ~~fracturing~~possible ~~fluids~~effective ~~and~~date ~~chemicals~~for orwithdrawal ~~produced~~by ~~water~~the ~~are~~United ~~spilled,~~States ~~(3)~~is ~~hydraulic~~November ~~fracturing~~4, ~~fluids~~2020, ~~are~~four ~~injected~~years ~~into~~after ~~wells~~the ~~with~~agreement ~~inadequate~~came ~~mechanical~~into ~~integrity,~~effect. ~~and~~Future ~~(4)~~United ~~hydraulic~~States ~~fracturing~~regulations ~~wastewater~~on isGHG ~~stored~~emissions ordesigned ~~disposed~~to inmeet ~~unlined~~the ~~pits. If~~Paris ~~new~~Agreement ~~federal~~goals ~~regulations~~could ~~were~~impact ~~adopted~~us asin aways ~~result~~that ofcannot ~~these~~be ~~findings,~~determined ~~they~~at ~~could~~this ~~increase our cost to operate~~time.

~~Oil~~While ~~Spills. The~~it ~~Oil~~is ~~Pollution~~unclear ~~Act~~at this time whether President Trump or Congress will pursue legislation or regulation to address GHG emissions in light of ~~1990,~~the aswithdrawal ~~amended~~of ~~(“OPA”)~~the Paris Agreement, ~~contains~~any ~~numerous~~such ~~requirements~~legislation ~~relating~~or toregulatory programs could also increase the ~~prevention~~cost of consuming, and ~~response~~thereby tocould reduce demand for the oil ~~spills~~and ~~into~~natural ~~waters~~gas that we produce. However, President Trump has taken certain actions since taking office that have begun to establish a national policy in favor of energy independence and economic growth. For example, on March 28, 2017, President Trump issued an Executive Order for the purpose of facilitating the development of United States. ~~The~~energy ~~OPA~~resources ~~subjects~~and ~~owners~~reducing unnecessary regulatory burdens associated with the development of ~~facilities~~those toresources. ~~strict~~Through the Executive Order, ~~joint~~President ~~and~~Trump ~~several~~has ~~liability~~directed ~~for~~agencies ~~all~~to ~~containment~~review ~~and~~existing ~~cleanup~~regulations ~~costs~~that ~~and~~potentially ~~certain~~burden ~~other~~the ~~damages~~development ~~arising~~of ~~from~~domestic aenergy ~~spill~~resources, ~~including~~and appropriately suspend, ~~but~~revise, ~~not~~or ~~limited~~rescind ~~to,~~regulations that unduly burden the ~~costs~~development of ~~responding~~United toStates aenergy ~~release~~resources ofbeyond ~~oil~~what is necessary to ~~surface~~protect ~~waters~~the public interest or otherwise comply with the law. ~~While~~Finally, weit ~~believe~~should webe noted that some scientists have ~~been~~concluded that increasing concentrations of GHGs in ~~compliance~~the ~~with~~Earth’s ~~OPA~~atmosphere may produce climate changes that have significant physical effects, ~~noncompliance~~such ~~could~~as ~~result~~increased infrequency ~~varying~~and ~~civil~~severity of storms, droughts and ~~criminal~~floods ~~penalties~~and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and ~~liabilities~~results of operations.

~~Water~~Endangered ~~Discharges~~species. The ~~Federal~~federal ~~Water~~Endangered ~~Pollution~~Species ~~Control~~ Act, ~~also~~of ~~known~~1973, as amended (the ~~Clean Water Act~~“ESA”), ~~the~~restricts ~~federal~~activities ~~regulations~~ that ~~implement~~may ~~the~~affect ~~Clean~~endangered ~~Water Act,~~ and ~~analogous~~threatened ~~state~~species ~~laws~~or ~~and~~their ~~regulations~~habitats. aIf ~~number~~endangered ofspecies ~~different~~are ~~types~~located ofin ~~requirements~~an onarea ~~our~~where ~~operations. First,~~we ~~these~~wish ~~laws~~to ~~and~~conduct ~~regulations~~seismic ~~impose~~surveys, ~~restrictions~~development ~~and~~activities ~~strict~~or ~~controls~~abandonment ~~on the discharge of pollutants~~operations, ~~including~~or ~~produced~~are ~~waters~~located ~~and~~in ~~other~~an ~~natural~~area ~~gas~~where ~~and~~new ~~oil~~pipelines ~~wastes,~~are ~~into~~planned; ~~navigable~~the ~~waters~~work ofcould ~~the~~be ~~United~~prohibited ~~States.~~or ~~The~~delayed ~~discharge~~or ofexpensive ~~pollutants~~mitigation ~~into~~may ~~regulated~~be ~~waters~~required. ~~is prohibited~~Moreover, ~~except in accordance with~~ the ~~terms~~designation of apreviously ~~permit~~unidentified ~~issued~~endangered ~~by the EPA~~ or ~~the~~threatened ~~relevant~~species ~~state.~~could ~~These~~cause ~~permits~~us ~~may~~to ~~require~~incur ~~pretreatment~~additional ofcosts ~~produced~~or ~~waters~~become ~~before~~subject ~~discharge.~~to ~~Compliance~~operating ~~with~~restrictions ~~such~~or ~~permits~~bans ~~and~~in ~~requirements~~the ~~may~~affected ~~be costly~~areas. ~~Second,~~As ~~the~~a ~~Clean~~result ~~Water Act also prohibits the discharge~~ of ~~dredge and fill material in regulated waters, including wetlands, unless authorized by~~ a ~~permit~~settlement ~~issued~~approved by the U.S. ~~Army~~District ~~Corps~~Court offor ~~Engineers. The~~the ~~precise~~District ~~definition~~ of ~~waters~~Columbia ~~and~~in ~~wetland~~September ~~subject~~2011, to the ~~dredge-and-fill~~U.S. ~~permit~~Fish ~~requirement~~and ~~has~~Wildlife ~~been~~Service ~~enormously~~(“FWS”) ~~complicated~~was ~~and~~required ~~is subject~~ to ~~on-going~~make ~~litigation. A~~a ~~broader~~determination ~~definition~~on ~~could~~the ~~result~~listing inof ~~more~~numerous ~~water~~species ~~and~~as ~~wetlands~~endangered ~~being~~or ~~subject~~threatened tounder ~~protection creating~~ the ~~possibility~~Endangered ofSpecies ~~additional~~Act ~~permitting~~prior ~~requirements~~to ~~for~~the ~~some~~completion of ~~our~~the ~~existing~~agency’s or2017 ~~future~~fiscal ~~facilities~~year. ~~Third~~ For example, while the ~~Clean~~lesser ~~Water~~prairie ~~Act~~chicken ~~also~~is ~~requires~~not ~~specified~~currently ~~facilities~~designated toas ~~maintain~~threatened ~~and~~or ~~implement~~endangered, ~~spill~~in ~~prevention~~November 2016, ~~control~~the ~~and~~FWS ~~countermeasure~~issued ~~plans~~its ~~and~~90-day tofindings ~~take~~in ~~measures~~response to ~~minimize~~a ~~the~~petition ~~risks~~to ofreclassify ~~petroleum~~the ~~spills. Federal~~lesser ~~and~~prairie ~~state~~chicken ~~regulatory~~under ~~agencies~~the ~~can~~ESA. ~~impose~~In ~~administrative~~those findings, ~~civil~~FWS ~~and~~found ~~criminal~~that ~~penalties~~the ~~for~~petition ~~failure~~presented tosubstantial ~~obtain~~information orthat ~~non-compliance~~the ~~with~~petitioned ~~discharge~~action ~~permits~~may orbe ~~other~~warranted, ~~requirements~~prompting ofa ~~the~~thorough ~~federal~~status ~~Clean~~review. ~~Water~~We ~~Act~~cannot ~~and~~predict ~~analogous~~the ~~state~~outcome ~~laws~~of ~~and~~this ~~regulations~~review process. WeThe ~~believe~~designation ~~that~~of ~~our~~currently ~~operations~~unprotected ~~are~~species, inincluding ~~substantial compliance with~~ the ~~requirements~~lesser ofprairie ~~the Clean Water Act.~~

~~Air Emissions. Our operations are subject to the federal Clean Air Act~~chicken, as ~~amended,~~threatened ~~the~~or ~~federal~~endangered ~~regulations~~in ~~that~~areas ~~implement~~where ~~the~~we ~~Clean~~operate Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as ~~fuel,~~threatened ~~and~~or ~~may~~endangered ~~increase~~could ~~the~~cause ~~costs~~us ~~of customer compliance~~ to the point where demand for natural gas is affected. Clean Air Act rules impose additional emissions control requirements and practices on some of our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur ~~capital~~increased costs inarising ~~order~~from tospecies ~~comply~~protection ~~with~~measures ~~new~~ or ~~revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements~~ could ~~subject~~result usin tolimitations ~~monetary penalties, injunctions, conditions or restrictions~~ on ~~operations, and potentially criminal enforcement actions. We believe that~~ our ~~operations~~exploration ~~are in substantial compliance with the requirements of the Clean Air Act~~ and ~~comparable~~production ~~state~~activities ~~laws~~that ~~and~~could ~~regulations. While~~have wean ~~will~~adverse ~~likely~~impact beon ~~required~~our toability ~~incur certain capital expenditures in the future for air pollution control equipment~~ to ~~comply~~develop ~~with applicable regulations~~ and toproduce obtain and maintain operating permits and approvals for air emissions, we believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companiesreserves.

~~Greenhouse~~The ~~Gas~~Migratory ~~Regulation~~Bird ~~and~~Treaty ~~Climate~~Act ~~Change.~~(“MBTA”) Toimplements ~~date,~~various ~~legislative~~treaties and ~~regulatory~~conventions ~~initiatives~~between ~~relating~~the toUnited ~~greenhouse~~States ~~gas~~and ~~emissions~~certain ~~have~~other ~~not~~nations ~~had~~for athe ~~material~~protection ~~impact~~of onmigratory ~~our business~~birds. ~~Under~~ ~~the~~In ~~past~~accordance ~~eight~~with ~~years~~this ~~during~~law, the ~~Obama~~taking, ~~Administration~~killing ~~several,~~or ~~Clean~~possessing ~~Air~~of ~~Act~~migratory ~~regulations~~birds ~~were~~covered ~~adopted~~under tothis ~~reduce~~act ~~carbon~~is ~~emissions,~~unlawful ~~and~~without a ~~couple prominent Supreme Court decisions upheld those regulations~~permit. As ~~President~~If ~~Trump~~there ~~pledged,~~is ~~during~~ the ~~election~~potential ~~campaign,~~ to ~~suspend~~adversely oraffect ~~reverse~~migratory ~~many~~birds ifas ~~not~~a ~~all~~result of ~~the~~our ~~Obama~~operations, ~~Administration’s~~we ~~initiatives~~may tobe ~~reduce~~required ~~the~~to ~~nation’s~~obtain ~~emissions~~necessary ofpermits ~~carbon~~to ~~dioxide,~~conduct itthose ~~is difficult to predict~~operations, ~~however,~~which ~~how~~may ~~federal~~result ~~policy~~in ~~will~~specified ~~unfold~~operating ~~over~~restrictions ~~the~~on ~~coming~~a ~~years. Some~~temporary, ofseasonal, ~~the~~or ~~Obama~~permanent ~~Administration~~basis ~~initiatives~~in ~~appear~~affected ~~unyielding. It~~areas ~~would~~and bean aadverse ~~significant~~impact ~~departure~~on ~~from~~our ~~the~~ability ~~principle~~to ofdevelop ~~stare~~and ~~decisis~~produce ~~for~~our ~~the~~reserves. ~~Supreme~~However, ~~Court to reverse its decision~~ in ~~Massachusetts~~December ~~v. EPA~~2017, ~~549~~the U.S. ~~497~~Department ~~(2007)~~of ~~holding~~Interior ~~that~~stated ~~greenhouse~~in ~~gases~~a ~~are “air pollutants” covered by the Clean Air Act. Similarly, reversing EPA~~solicitor’s ~~final~~opinion ~~determination~~ that ~~greenhouse~~it ~~gases~~will ~~“endangered”~~no ~~public~~longer ~~health~~prosecute oil and ~~welfare~~gas, 74wind ~~Fed.~~and ~~Reg.~~solar ~~66,496~~operators ~~(Dec. 15, 2009), would seem to require development of new scientific evidence~~ that ~~runs~~accidentally ~~counter~~kill tobirds ~~general~~based ~~discoveries~~on ~~since that determination. President Trump’s expressed disagreement with the Obama Administration’s climate change policy, however, casts~~ a ~~question~~reinterpretation ~~over a whole series~~ of ~~other EPA rules: (1)~~ the ~~so-called~~MBTA ~~“Tailoring~~that ~~Rule”~~it ~~which~~does ~~established~~not ~~emission~~prohibit ~~thresholds~~accidental ~~for~~takings ~~greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010), see also Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014); (2) the Reporting~~ of ~~Greenhouse~~migratory ~~Gases rule specifically addressing the natural gas industry, 80 Fed~~birds. ~~Reg. 64262 (Oct. 22, 2015); (3) standards for venting, flaring, and equipment leaks from oil and gas production activities on onshore Federal and Indian leases.~~

~~Waste~~We ~~Handling.~~believe ~~The~~we ~~Solid~~are ~~Waste~~in ~~Disposal~~substantial ~~Act,~~compliance ~~including~~with ~~RCRA,~~currently ~~and~~applicable ~~comparable~~environmental ~~state~~laws ~~statutes regulate the generation, transportation, treatment, storage, disposal~~ and ~~cleanup of “hazardous wastes” and the disposal of non-hazardous wastes~~regulations. ~~With~~Although ~~authority~~we ~~granted~~have bynot ~~federal~~experienced ~~EPA,~~any ~~individual~~material ~~states~~adverse ~~administer~~effect ~~some~~from orcompliance ~~all of the provisions of RCRA, sometimes in conjunction~~ with ~~their~~environmental ~~own more stringent~~ requirements~~. Drilling fluids~~, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no ~~guarantee~~assurance that ~~the~~this ~~EPA~~will orcontinue. ~~individual~~We ~~states~~did ~~will~~ not ~~adopt~~have ~~more~~any ~~stringent~~material ~~requirements~~capital ~~for the handling of non-hazardous wastes~~ or ~~categorize~~other ~~some~~ non-~~hazardous~~recurring ~~wastes~~expenditures ~~as hazardous~~ in ~~the~~connection ~~future.~~with ~~Moreover,~~complying ~~ordinary~~with ~~industrial~~environmental ~~wastes~~laws ~~such~~or asenvironmental ~~paint~~remediation ~~wastes,~~matters ~~waste~~in ~~solvents~~2017, ~~laboratory~~nor ~~wastes,~~do ~~and~~we ~~waste~~anticipate ~~compressor~~that ~~oils~~such ~~may~~expenditures will be ~~regulated~~material asin ~~“solid waste~~2018.” ~~The~~However, ~~transportation~~we ofregularly ~~natural~~have ~~gas~~expenditures ~~in pipelines may also generate some “hazardous wastes” that are subject~~ to ~~RCRA~~comply ~~or comparable state law requirements. We believe that our operations are currently in substantial compliance~~ with ~~the~~environmental ~~requirements of RCRA and related state and local~~ laws and ~~regulations. More~~we ~~stringent~~anticipate ~~regulation~~those ofcosts ~~natural~~will ~~gas~~continue ~~and~~to ~~oil~~be ~~exploration~~incurred ~~and~~in ~~production wastes could increase~~ the ~~costs to manage and dispose of such wastes~~future.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” (but excluding petroleum) into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. We are not presently aware the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition.

OSHA and Chemical Reporting Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. On March 25, 2016, OSHA published its final Occupational Exposure to Respirable Crystalline Silica final rule, which imposes specific requirements to protect workers engaged in hydraulic fracturing. 81 Fed. Reg. 16,285. The requirements of that final rule as it applies to hydraulic fracturing become effective June 23, 2018, except for the engineering controls component of the final rule, which has a compliance date of June 23, 2021. We expect implementation of the rule to result in significant costs. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. We employ numerous safety precautions at our operations to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our or its wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2015, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.

States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced, a regulatory tax of $.001875 and the oil field clean-up fee of $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax of up to 0.24% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 7% per Mcf of natural gas and a petroleum excise tax of .095% on the gross production of oil and gas.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

We do not directly employ any of the persons responsible for our management or operation. ~~In general~~Rather, ~~personnel~~through ~~employed~~December by31, ~~Atlas~~2017 ~~Energy Group manage and operate~~ our ~~business.~~Former ~~Some~~MGP ofemployed the ~~officers~~personnel ofnecessary ~~our~~to ~~general~~manage ~~partner~~and ~~may~~operated ~~spend~~our ~~a substantial amount of time managing the~~ business ~~and~~through ~~affairs~~a ofTransition ~~our~~Services ~~general~~Agreement ~~partner~~("TSA"). ~~and~~Beginning ~~its~~January ~~affiliates~~1, ~~other~~2018 ~~than us~~ and ~~may~~following ~~face~~the aexpiration ~~conflict~~of ~~regarding~~ the ~~allocation~~TSA, ofour ~~their~~MGP ~~time~~employs ~~between~~the ~~our~~personnel ~~business~~needed ~~and~~to ~~affairs~~manage and ~~their~~operate ~~other~~our ~~business interests~~wells.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our MGP’s website at www.~~titanenergyllc~~diversifiedgasandoil.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). ~~To view these reports, click on “Investment Programs”, then “Drilling Program SEC Filings” and finally the respective program of your inquiry.~~ You may also receive, without charge, a paper copy of any such filings by request to us at ~~Park~~PO ~~Place~~Box ~~Corporate Center One~~381087, ~~1000 Commerce Drive~~Birmingham, ~~Suite~~AL ~~400~~35238, ~~Pittsburgh, Pennsylvania 15275,~~ telephone number (~~800~~844) ~~251~~378-~~0171~~1168. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 2: PROPERTIES

Natural Gas and Oil Reserves

~~The~~For ~~following~~additional ~~tables summarize~~ information regarding our estimated proved natural gas and oil reserves. Proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, ~~i.e.,~~see ~~prices~~Part ~~and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements~~II, ~~but~~Item not on escalations based upon future conditions. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company8, ~~Inc.,~~Note ~~an independent third-party reserve engineer~~9. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2016 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the periods indicated and are adjusted for basis differentials:

	December 31,
	2016		2015
Natural gas (per MMbtu)	$	2.48	$	2.59
Oil (per Bbl)	$	42.75	$	50.28

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. Our MGP’s internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s senior engineering staff and management, with final approval by our MGP’s President.

Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced. You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There were no proved reserves as of December 31, 2016 and 2015.

There were no proved reserves as of December 31, 2016 and 2015. We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2016 and 2015 due to the significant declines in commodity prices. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Productive Wells

Productive wells consist of producing wells and wells capable of production~~, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities~~. ~~Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells.~~ The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, ~~2016~~2017:

	Number of productive wells
	Gross	~~Gross~~	Net	~~Net~~
Gas and/or oil wells		81.00		76.75
Wells drilled at inception	85.00		80.75
Less:
Dry holes	2.00		2.00
Plugged and abandoned	2.00		2.00
Sold	6.00		4.50
Productive natural gas and/or oil wells	75.00		72.25

Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, ~~2016~~2017:

	Developed Acreage
	Gross		Net	~~Net~~
Pennsylvania	1,833	~~1,833.23~~	1,800		~~1,800.08~~
Ohio	837	~~837.24~~	764		~~763.92~~
Total	2,670	~~2,670.47~~	2,564		~~2,564.00~~

17The leases for our developed acreage generally have terms that extend for the life of the wells. We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commenced drilling operations, we conducted an extensive title examination and we performed curative work on defects that we deemed significant. We or our predecessors obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

~~The~~Our ~~leases~~properties ~~for~~are ~~our~~subject ~~developed~~to ~~acreage~~royalty, ~~generally~~overriding ~~have~~royalty ~~terms~~and ~~that~~other ~~extend~~outstanding ~~for~~interests ~~the~~customary ~~life~~in of the ~~wells~~industry. WeOur ~~believe~~properties ~~that~~are wealso ~~hold~~subject ~~good and indefeasible title~~ to ~~our~~burdens ~~producing~~such ~~properties,~~as inliens ~~accordance~~incident ~~with~~to ~~standards~~operating ~~generally~~agreements, ~~accepted~~taxes, indevelopment ~~the~~obligations under natural gas ~~industry,~~and ~~subject~~oil toleases, ~~exceptions~~farm-out ~~stated~~arrangements inand ~~the~~other ~~opinions~~encumbrances, ofeasements ~~counsel~~and ~~employed by us in the various areas in which we conduct our activities~~restrictions. We do not believe that ~~these~~any ~~exceptions detract substantially from our use~~ of ~~any~~these ~~property.~~burdens Asmaterially isinterfere ~~customary~~with in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our ~~predecessors~~use ~~have obtained title examinations for substantially all~~ of our ~~managed producing~~ properties. ~~No single property represents a material portion of our holdings.~~

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

ITEM 3: LEGAL PROCEEDINGS

WeFrom ~~are~~time to time, we may be party to various routine legal proceedings arising out of the ordinary course of our business. ~~Management~~Our MGP believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. As ~~(See~~of ~~Item~~December 31, 8:2017, ~~Note~~there 9were ~~Commitments~~no ~~and~~outstanding ~~Contingencies).~~legal proceedings.

~~Affiliates~~For ofadditional ~~the~~information, ~~MGP~~see ~~and~~Part ~~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~~II, ~~individually~~Item ~~or in the aggregate~~8, ~~will~~Note ~~have a material adverse effect on the MGP’s financial condition or results of operations~~8.

ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)

PART II

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our units, and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our ~~Partnership~~partnership ~~Agreement~~agreement which requires:


•	our MGP’s consent;


•	the transfer not result in materially adverse tax consequences to us; and


•	the transfer does not violate federal or state securities laws.

An assignee of a unit may become a substituted partner only upon meeting the following conditions:


•	the assignor gives the assignee the right;


•	our MGP consents to the substitution;


•	the assignee pays to us all costs and expenses incurred in connection with the substitution; and


•	the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the term of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. As of December 31, ~~2016~~2017, we had ~~505~~503 limited partners.

Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute ~~those~~any funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. ~~There~~Because operating expenses exceeded revenues, there were no distributions during ~~the~~either years ended December 31, ~~2016~~2017 and ~~2015~~2016.

1816

ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. ~~This~~You ~~discussion~~ should be read this in conjunction with “Item 8:, ~~Financial~~which ~~Statements~~contains our financial statements and ~~Supplementary~~notes ~~Data”~~thereto. Our operating cash flows are generated from the sale of our wells' production, which ~~contains~~produce primarily natural gas, but also some oil. We deliver our ~~financial~~produced ~~statements~~natural gas to market through affiliated and/or third-party gas gathering systems.

~~The~~Our ~~following~~ongoing ~~discussion~~operating ~~may~~and ~~contain~~maintenance ~~forward-looking~~costs ~~statements~~are ~~that~~fulfilled ~~reflect~~through revenues from the sale of our ~~plans,~~natural ~~estimates~~gas production and ~~beliefs.~~through ~~Forward-looking~~subsidies ~~statements~~provided ~~speak~~by ~~only~~our asMGP. ofOur ~~the~~results ~~date~~of ~~the~~operations ~~statements~~are ~~were~~dependent ~~made.~~upon ~~The~~the ~~matters~~difference ~~discussed~~between inprices ~~these~~received ~~forward-looking~~for ~~statements~~our ~~are~~oil ~~subject~~and tonatural ~~risks,~~gas ~~uncertainties~~production and ~~other~~the ~~factors~~costs ~~that~~to ~~could~~find ~~cause~~and ~~actual~~produce ~~results~~such tooil ~~differ~~and ~~materially~~natural ~~from~~gas. ~~those~~Oil ~~made,~~and ~~projected~~natural orgas ~~implied~~prices inhave ~~the~~been ~~forward-looking~~volatile ~~statements.~~and Wesubject ~~believe~~to ~~the~~fluctuations ~~assumptions~~based ~~underlying~~on ~~the~~a ~~financial~~number ~~statements~~of ~~are~~factors ~~reasonable.~~beyond ~~However,~~ our ~~financial~~control. ~~statements~~We ~~included~~currently ~~herein~~have ~~may~~no ~~not~~derivative ~~necessarily~~contracts ~~reflect~~to ~~our~~hedge ~~results~~against ofdeclines ~~operations,~~in ~~financial~~commodity ~~position~~prices, and ~~cash~~we ~~flows~~do not expect to hedge in the future.

BUSINESS OVERVIEW

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 also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas America Public #9 LTD.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: 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.

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 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.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired and were 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.

Liquidity, Capital Resources and Ability to Continue as a Going Concern

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.

MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas and oil commodity price markets have suffered significant declines during the fourth quarter of 2014 and continued to remain low throughout 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas and oil production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas and oil reserves.

Our future gas and oil reserves, production, cash flow and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decreases.

RESULTS OF OPERATIONS

The following ~~discussion~~table ~~provides~~sets forth information torelated assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which primarily produce 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~~revenues, ~~as operator~~volumes, asales ~~monthly well supervision fee~~prices, ~~which~~production ~~covers~~costs ~~all normal~~ and ~~regularly~~depletion ~~recurring~~during ~~operating expenses for~~ the ~~production~~periods ~~and sale of natural gas and oil such as~~indicated:

• Well tending, routine maintenance and adjustment;



	Years Ended December 31,
	2017			2016			$ Change			% Change
Production revenues (in thousands):
Natural gas	$	252		$	185		67			36	%
Oil	34			31			3			10	%
Total	$	286		$	216		70			32	%

Production volumes:
Natural gas (mcf/day)	269			322			(53		)	(16	)%
Oil (bbls/day)	2			2			—			—	%
Total (mcfe/day)	281			334			(53		)	(16	)%

Average sales price:
Natural gas (per mcf)	$	2.57		$	1.58		$	0.99		63	%
Oil (per bbl)	$	47.02		$	41.55		$	5.47		13	%

Production costs:
Production costs (in thousands)	$	329		$	329		$	—		—	%
As a percent of revenues	115		%	152		%	(37		)%	(24	)%
Per mcfe	$	3.21		$	2.69		$	0.52		19	%

Depletion per mcfe	$	—		$	0.30		$	(0.30	)	(100	)%

~~• Reading meters, recording production, pumping, maintaining appropriate books and records; and~~17

•Revenues ~~Preparation~~(in ~~of reports for us and government agencies.~~thousands)

The ~~well~~following ~~supervision~~table ~~fees,~~reconciles ~~however, do not include costs and expenses related to~~ the ~~purchase~~changes ofin ~~certain~~natural ~~equipment~~gas, ~~materials,~~oil and ~~brine~~total ~~disposal.~~revenues ~~If these expenses are incurred, we pay cost~~ for ~~third-party~~the ~~services,~~respective ~~materials,~~periods ~~and~~presented ~~a competitive charge for service performed directly~~ by ~~our~~reflecting ~~MGP~~the oreffect ~~its affiliates. Also, beginning one year after each~~ of ~~our~~changes ~~wells~~in ~~has~~volumes ~~been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging~~ and ~~abandonment~~in ~~costs of~~ the ~~well.~~underlying Ascommodity ~~of December 31, 2016, our MGP withheld $382,500 of net production revenue for this purpose~~prices.



	Natural gas			Oil			Total
Revenues for the year ended December 31, 2016	$	185		$	31		$	216
Volume decrease	(31		)	(1		)	(32		)
Price increase	98			4			102
Net increase	67			3			70
Revenues for the year ended December 31, 2017	$	252		$	34		$	286

~~GAS AND OIL PRODUCTION:~~ The ~~following~~natural ~~table~~gas ~~sets~~and ~~forth~~oil ~~information~~volume ~~related~~variances toreflected ~~our~~for ~~production~~the ~~revenues,~~periods ~~volumes,~~presented ~~sales~~in ~~prices,~~the ~~production~~tables ~~costs~~above ~~and~~relate ~~depletion during the periods indicated~~to:

	Years Ended December 31,
	2016			2015
Production revenues (in thousands):
Gas	$	185		$	230
Oil		31			35
Total	$	216		$	265
Production volumes:
Gas (mcf/day)		322			371
Oil (bbls/day)		2			2
Total (mcfe/day)		334			383
Average sales price: (1)
Gas (per mcf)	$	1.58		$	1.70
Oil (per bbl)	$	41.55		$	45.08
Production costs:
As a percent of revenues		152	%		131	%
Per mcfe	$	2.69		$	2.47
Depletion per mcfe	$	0.30		$	0.20

•wells being temporarily shut-in;

~~(1)~~• ~~Average~~timing ~~sales~~differences ~~prices~~associated ~~represent~~with ~~accrual~~the ~~basis~~production ~~pricing.~~from those wells depending upon when they are placed back into production; and

~~Natural~~•normal ~~Gas Revenues. Our natural gas revenues were $185,500~~ and ~~$230,300~~expected ~~for~~declines the years ended December 31, 2016 and 2015, respectively, a decrease of $44,800 (19%). The $44,800 decrease in natural gas revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $30,300 decrease in production volumes and a $14,500 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 322 mcf per day for the year ended December 31, 2016 from 371 mcf per day for the year ended December 31, 2015, a decrease of 49 mcf per day (13%). The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: “Business-Contractual Revenue Arrangements”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volumes is mostly due to the normal decline inherent in the life of ~~the~~a ~~wells~~well.

~~Oil~~Costs ~~Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $30,900~~ and ~~$34,500~~Expenses ~~for the years ended December 31, 2016 and 2015, respectively, a decrease of $3,600~~ (~~10%). The $3,600 decrease~~ in oil revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $2,600 decrease in oil prices and a $1,000 decrease in production volumes. Our production volumes decreased to 2.03 bbl per day for the year ended December 31, 2016 from 2.10 bbl per day for the year ended December 31, 2015, a decrease of 0.07 bbl per day (3%thousands).

(Loss) Gain on Mark-to-Market Derivatives. On January 1, 2015, we discontinued hedge accounting for our qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within (loss) gain on mark-to-market derivatives on our statements of operations.



	Years Ended December 31,
	2017		2016		$ Change		% Change
Production	$	329	$	329	—		—	%
Depletion	—		36		(36	)	(100	)%
Impairment	273		162		111		69	%
Accretion of asset retirement obligations	71		68		3		4	%
General and administrative	129		105		24		23	%
Total costs and expenses	$	802	$	700	102		15	%

WeProduction ~~recognized~~expenses awere ~~loss~~relatively onflat ~~mark-to-market~~primarily ~~derivatives of $100 for the year ended December 31, 2016. This loss was~~ due ~~primarily~~ to ~~mark-to-market~~an ~~gains~~increase in ~~the~~transportation ~~current~~expenses ~~year~~and ~~primarily~~supervision ~~related~~fees tooffset ~~the~~by ~~change in natural gas prices during the year. We recognized~~ a ~~gain~~decrease onin ~~mark-to-market~~repairs ~~derivatives~~and ofmaintenance ~~$8,500 for the year ended December 31, 2015~~costs.

~~Costs~~Impairment ~~and~~of ~~Expenses.~~gas ~~Production~~and ~~expenses~~oil ~~were~~properties was $~~328,500~~269 and $~~346,100~~162 for the years ended December 31, ~~2016~~2017 and ~~2015,~~2016. The ~~respectively,~~impairment awas ~~decrease~~due to the deterioration of ~~$17,600~~salvage ~~(5%)~~values. ~~This~~At ~~decrease~~least ~~was~~annually, ~~primarily~~we ~~due~~compare tothe acarrying ~~combination~~value of aour ~~decrease~~proved indeveloped ~~transportation~~gas ~~charges~~ and ~~supervision~~oil ~~fees~~producing properties to their estimated fair market value.

General and administrative expenses increased $24 (23%), primarily due to an increase in audit expenses and tax preparation fees.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 17% and 10% for the years ended December 31, 2016 and 2015, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent, revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties. Liquidity

~~General~~We ~~and~~have ~~administrative~~no ~~expenses~~net ~~were~~cash ~~$104~~flows from operating,~~900~~ investing and ~~$106,800~~financing ~~for~~activities during the years ended December 31, ~~2016~~2017 and ~~2015,~~2016. ~~respectively~~Cash flows from operations have been negative during the years ended December 31, a2017 ~~decrease~~and of2016 $1but have been subsidized by the MGP,~~900~~ ~~(2%)~~even though the MGP is not required to do so. The Partnership has an accumulated deficit and lacks the financial resources to pay its current liabilities. These ~~expenses~~conditions ~~include~~raise ~~third-party~~substantial ~~costs~~doubt ~~for~~about ~~services~~the asPartnership’s ~~well~~ability to continue as a going concern. While we limited control over the ~~monthly~~price ~~administrative~~we ~~fees~~receive ~~charged~~for byour production, our MGP ~~and~~actively ~~vary~~manages ~~from~~our ~~period~~operations toin ~~period~~an ~~due~~effort to ~~the~~increase ~~costs~~production and ~~services~~reduce ~~provided~~expenses tothrough usinnovative operating techniques and enhanced vendor management. For additional information, see Part II, Item 8, Note 2.

Impairment of gas and oil properties was $162,100 and $457,200 for the years ended December 31, 2016 and 2015. At least annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2016 and 2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices.

Cash Flows Overview.

Cash provided by operating activities increased $200 for the year ended December 31, 2016 to $0 as compared to cash used by operating activities of $200 for the year ended December 31, 2015. This increase was due to an increase in accounts payable trade-affiliate of $113,500, an increase in a non-cash loss (gain) on derivative value of $13,000, and an increase in the change in accrued liabilities of $1,000. Partially offsetting this increase was a decrease in the change in accounts receivable trade-affiliate of $73,600, a decrease in net loss before depletion, impairment, and accretion of $37,500, and a decrease in the change in asset retirement receivable-affiliate of $16,200 for the year ended December 31, 2016 compared to the year ended December 31, 2015.

There was no cash provided by investing activities during the year ended December 31, 2016. Cash provided by investing activities was $200 during the year ended December 31, 2015 resulting from the sale of tangible equipment.

There was no cash used in financing activities for the years ended December 31, 2016 and 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2016, our MGP has withheld $382,500 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP requires ~~making~~that we make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion and amortization, and impairment. We summarize our significant accounting policies within our financial statements (See “Item 8: Financial Statements”) included in this report. The critical accounting policies and estimates we have identified are discussed below.

~~Depletion and Impairment of Long-Lived Assets~~ 18

~~Long-Lived~~on ~~Assets~~historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. ~~The~~Changes ~~cost~~in these estimates could materially affect our financial position, results of ~~natural~~operations ~~gas~~or cash flows. Significant items that are subject to such estimates and ~~oil~~assumptions ~~properties~~include revenue and expense accruals, ~~less~~depletion ~~estimated~~and ~~salvage~~amortization, ~~value~~and impairment. We summarize our significant accounting policies within our financial statements (See Part II, isItem ~~generally~~8, ~~depleted~~Note on1) ~~the~~included ~~units-of-production~~in ~~method~~this report. Our identified critical accounting policies and estimates are discussed below.

Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions.

During the years ended December 31, 2016 and 2015, we recognized $162,100 and $457,200 of impairment within natural gas and oil properties, respectively. 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 balance sheet at December 31, 2016 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on our MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.

Reserve Estimates

Our ~~estimates~~reserve ofanalysis ~~proved~~is ~~natural gas and oil reserves and future net revenues from them are~~ based upon ~~reserve analyses that rely upon~~ various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the ~~following: the~~ quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. We engaged Wright & Company, Inc., anour MGP's independent, third-party reserve engineer, to prepare a report of our proved reserves. ~~(See~~For “additional information see Item 2:II, ~~Properties”).~~Item 8, Note 9.

Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of natural gas and oil properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2016 and 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2016, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Asset Retirement Obligations

We ~~recognize and~~ estimate the liability for the plugging and abandonment of our natural gas and oil wells based on our historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset. The liability is discounted using our MGP’s assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our natural gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets. For additional information see Part II, Item 8, Notes 1 and 5.

The estimated liability is based on our historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using our MGP’s assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets. 19

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ToGeneral ~~the~~ Partners ofand Unitholders

Atlas America Public #9 LTD.

WeOpinion ~~have~~on ~~audited~~ the accompanying balance sheets of Atlas America Public #9 LTD. (a Pennsylvania limited partnership) (the “Partnership”) as of December 31, 2016 and 2015, and the related statements of operations, comprehensive loss, changes in partners’ deficit, and cash flows for each of the two years in the period ended December 31, 2016. These financial statements ~~are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.~~

We ~~conducted~~have ~~our~~audited ~~audits~~the inaccompanying ~~accordance~~balance ~~with~~sheets ~~the standards~~ of ~~the~~Atlas America Public ~~Company~~#9 ~~Accounting~~LTD. ~~Oversight~~(a ~~Board~~Pennsylvania ~~(United~~Limited ~~States~~Partnership) ~~and~~(the in“Partnership”) ~~accordance~~as ~~with~~of ~~auditing~~December ~~standards~~31, ~~generally~~2017 ~~accepted~~and in2016, the ~~United~~related ~~States~~statements of ~~America. Those~~operations, ~~standards~~comprehensive ~~require~~loss, ~~that~~changes wein ~~plan~~partners’ capital, and ~~perform~~cash ~~the~~flows ~~audit~~for toeach ~~obtain~~of ~~reasonable~~the ~~assurance~~two ~~about~~years ~~whether~~in the ~~financial~~period ~~statements~~ended ~~are~~December ~~free~~31, of2017, ~~material~~and ~~misstatement.~~the Werelated ~~were~~notes ~~not~~(collectively ~~engaged~~referred to ~~perform~~as ~~an audit of~~ the ~~Partnership’s internal control over~~ “financial ~~reporting~~statements”). ~~Our~~In ~~audits~~our ~~included~~opinion, ~~consideration~~the ~~of internal control over~~ financial ~~reporting~~statements aspresent afairly, ~~basis for designing audit procedures that are appropriate~~ in ~~the~~all ~~circumstances~~material respects, ~~but not for~~ the ~~purpose~~financial ofposition ~~expressing an opinion on the effectiveness~~ of the Partnership’s ~~internal~~as ~~control~~of ~~over~~December ~~financial reporting. Accordingly~~31, we2017 ~~express~~and no2016, ~~such~~and ~~opinion.~~the Anresults ~~audit~~of ~~also~~its ~~includes~~operations ~~examining,~~and onits acash ~~test~~flows ~~basis,~~for ~~evidence~~each ~~supporting~~of the ~~amounts~~two ~~and~~years ~~disclosures~~ in the ~~financial~~period ~~statements,~~ended ~~assessing~~December ~~the~~31, ~~accounting~~2017, ~~principles~~in ~~used~~conformity ~~and~~with ~~significant~~accounting ~~estimates~~principles ~~made~~generally byaccepted ~~management,~~in ~~as well as evaluating~~ the ~~overall~~United ~~financial~~States ~~statement~~of ~~presentation~~America. ~~We believe that our audits provide a reasonable basis for our opinion.~~

InBasis ~~our~~for opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Public #9 LTD. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

~~The~~These ~~accompanying~~ financial statements ~~have~~are ~~been~~the ~~prepared~~responsibility ~~assuming~~of ~~that~~ the Partnership’s ~~will continue as a going concern~~management. AsOur ~~disclosed~~responsibility inis ~~Note 1~~ to ~~the~~express ~~financial~~an ~~statements,~~opinion ason ~~of December 31, 2016,~~ the Partnership’s ~~Managing~~financial ~~General~~statements ~~Partner~~based ~~was~~on inour ~~violation~~audits. ofWe ~~certain~~are ~~debt~~a ~~covenants~~public ~~under~~accounting ~~its~~firm ~~credit~~registered ~~agreements~~with ~~and~~the ~~there~~Public ~~are~~Company ~~uncertainties~~Accounting ~~regarding~~Oversight ~~its~~Board ~~liquidity~~(United ~~and~~States) ~~capital~~(“PCAOB”) ~~resources.~~and ~~The~~are ~~ability~~required ofto ~~the~~be ~~Managing~~independent ~~General~~with ~~Partner~~respect to ~~continue~~the asPartnership ain ~~going~~accordance ~~concern~~with ~~also raises substantial doubt regarding~~ the ~~Partnership’s~~U.S. ~~ability~~federal tosecurities ~~continue~~laws asand athe ~~going~~applicable ~~concern. The~~rules ~~financial~~and ~~statements~~regulations doof ~~not~~the ~~include~~Securities ~~any~~and ~~adjustments~~Exchange ~~that~~Commission ~~might~~and ~~result from~~ the ~~outcome of this uncertainty~~PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2000.

Cleveland, Ohio

~~April~~March 1728, ~~2017~~2018

2620

ATLAS AMERICA PUBLIC #9 LTD.

BALANCE SHEETS

DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

	2016			2015
	2017			2016
ASSETS
Current assets:
Cash	$	-—		$	-—
Accounts receivable trade–affiliate	35,500	~~41,700~~		41,700	~~29,600~~
Current portion of derivative assets		-			13,400
Total current assets	35,500			41,700
Total current assets		41,700			43,000
Natural gas and oil properties, net	65,500			338,500
Gas and oil properties, net		338,500			537,000
Long-term asset retirement receivable-affiliate	576,900			382,500
Long-term asset retirement receivable-affiliate		382,500			188,100
Total assets	$	677,900		$	762,700
Total assets	$	762,700		$	768,100
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	~~718~~1,~~100~~080,300		$	~~302~~718,~~300~~100
Accrued liabilities	9,900	~~11,600~~		11,600	~~10,300~~
Current portion put premiums payable-affiliate		-			6,200
Total current liabilities	1,090,200			729,700
Total current liabilities		729,700			318,800
Asset retirement obligations	1,900,900			1,948,300
Asset retirement obligations		1,948,300			1,879,800
Total long-term liabilities	1,900,900			1,948,300
Commitments and contingencies (Note 9)
Total liabilities	2,991,100			2,678,000
Partners’ (deficit) capital:
Commitments and contingencies (Note 8)
Managing general partner’s deficit		(480,800	)		(181,000	)
Partners’ deficit:
Limited partners’ deficit (1,500 units)		(1,434,500	)		(1,250,200	)
Managing general partner’s deficit	(798,100		)	(480,800		)
Accumulated other comprehensive income		-			700
Limited partners’ deficit (1,500 units)	(1,515,100		)	(1,434,500		)
Total partners’ deficit	(2,313,200	~~(1,915,300~~	)	(1,915,300	~~(1,430,500~~	)
Total liabilities and partners’ deficit	$	~~762~~677,~~700~~900		$	~~768~~762,~~100~~700

See accompanying notes to financial statements.

2721

ATLAS AMERICA PUBLIC #9 LTD.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

	2016			2015
	2017			2016
REVENUES
Natural gas and oil	$	~~216~~285,~~400~~900		$	~~264~~216,~~800~~400
(Loss) gain on mark-to-market derivatives		(100	)		8,500
Loss on mark-to-market derivatives	—			(100		)
Total revenues		216,300			273,300
Gain on sale of natural gas and oil properties	118,400			—
Total revenues	404,300			216,300
COSTS AND EXPENSES
Production	329,100	~~328,500~~		328,500	~~346,100~~
Depletion	—	~~36,400~~		36,400	~~27,600~~
Impairment	273,000	~~162,100~~		162,100	~~457,200~~
Accretion of asset retirement obligations	71,000	~~68,500~~		68,500	~~101,700~~
General and administrative	129,100	~~104,900~~		104,900	~~106,800~~
Total costs and expenses	802,200	~~700,400~~		700,400	~~1,039,400~~
Net loss	$	(~~484~~397,~~100~~900	)	$	(~~766~~484,100	)
Allocation of net loss:
Managing general partner	$	(~~299~~317,~~800~~300	)	$	(~~302~~299,~~700~~800	)
Limited partners	$	(~~184~~80,~~300~~600	)	$	(~~463~~184,~~400~~300	)
Net loss per limited partnership unit	$	(~~123~~54	)	$	(~~309~~123	)

See accompanying notes to financial statements.

2822

ATLAS AMERICA PUBLIC #9 LTD.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

	2016			2015
	2017			2016
Net loss	$	(~~484~~397,~~100~~900	)	$	(~~766~~484,100	)
Other comprehensive loss:
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges	—			(700		)
Difference in estimated hedge gains receivable		-			(600	)
Total other comprehensive loss	—			(700		)
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		(700	)		(1,900	)
Comprehensive loss	$	(397,900	)	$	(484,800	)
Total other comprehensive loss		(700	)		(2,500	)
Comprehensive loss	$	(484,800	)	$	(768,600	)

See accompanying notes to financial statements.

2923

ATLAS AMERICA PUBLIC #9 LTD.

STATEMENTS OF CHANGES IN PARTNERS’ DEFICIT

YEARS ENDED DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

	ManagingGeneralPartner			LimitedPartners			AccumulatedOtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2014	$	121,700		$	(786,800	)	$	3,200		$	(661,900	)
Balance at December 31, 2015	$	(181,000	)	$	(1,250,200	)	$	700		$	(1,430,500	)
Participation in revenues and costs and expenses:
Net production expenses	(39,800	~~(29,600~~	)	(72,300	~~(51,700~~	)	—	-		(112,100	~~(81,300~~	)
Gain on mark-to-market derivatives	—	-		(100	~~8,500~~	)	—	-		(100	~~8,500~~	)
Depletion	(36,400	~~(11,300~~	)	—	~~(16,300~~	)	—	-		(36,400	~~(27,600~~	)
Impairment	(162,100	~~(187,800~~	)	—	~~(269,400~~	)	—	-		(162,100	~~(457,200~~	)
Accretion of asset retirement obligations	(24,300	~~(36,100~~	)	(44,200	~~(65,600~~	)	—	-		(68,500	~~(101,700~~	)
General and administrative	(37,200	~~(37,900~~	)	(67,700	~~(68,900~~	)	—	-		(104,900	~~(106,800~~	)
Net loss	(299,800	~~(302,700~~	)	(184,300	~~(463,400~~	)	—	-		(484,100	~~(766,100~~	)
Other comprehensive loss	—	-		—	-		(700	~~(2,500~~	)	(700	~~(2,500~~	)
Balance at December 31, 2015		(181,000	)		(1,250,200	)		700			(1,430,500	)
Balance at December 31, 2016	(480,800		)	(1,434,500		)	—			(1,915,300		)
Participation in revenues and costs and expenses:
Net production expenses	(15,300	~~(39,800~~	)	(27,900	~~(72,300~~	)	—	-		(43,200	~~(112,100~~	)
Loss on mark-to-market derivatives		-			(100	)		-			(100	)
Gain on sale of natural gas and oil properties	42,000			76,400			—			118,400
Depletion		(36,400	)		-			-			(36,400	)
Impairment	(273,000		)	—			—			(273,000		)
Impairment		(162,100	)		-			-			(162,100	)
Accretion of asset retirement obligations	(25,200		)	(45,800		)	—			(71,000		)
Accretion of asset retirement obligations		(24,300	)		(44,200	)		-			(68,500	)
General and administrative	(45,800		)	(83,300		)	—			(129,100		)
General and administrative		(37,200	)		(67,700	)		-			(104,900	)
Net loss	(317,300		)	(80,600		)	—			(397,900		)
Net loss		(299,800	)		(184,300	)		-			(484,100	)
Other comprehensive loss	—			—			—			—
Other comprehensive loss		-			-			(700	)		(700	)
Balance at December 31, 2017	$	(798,100	)	$	(1,515,100	)	$	—		$	(2,313,200	)
Balance at December 31, 2016	$	(480,800	)	$	(1,434,500	)	$	-		$	(1,915,300	)

See accompanying notes to financial statements.

3024

ATLAS AMERICA PUBLIC #9 LTD.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

	2016			2015
	2017			2016
Cash flows from operating activities:
Net loss	$	(~~484~~397,~~100~~900	)	$	(~~766~~484,100	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	—	~~36,400~~		36,400	~~27,600~~
Non-cash loss (gain) on derivative value		6,500			(6,500	)
Non-cash loss on derivative value	—			6,500
Impairment	273,000	~~162,100~~		162,100	~~457,200~~
Accretion of asset retirement obligations	71,000	~~68,500~~		68,500	~~101,700~~
Gain on sale of natural gas and oil properties	(118,400		)	—
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(12,100	)		61,500
Decrease (increase) in accounts receivable trade-affiliate	6,200			(12,100		)
Increase in asset retirement receivable-affiliate	(194,400	~~(194,400~~	)	(194,400	~~(178,200~~	)
Increase in accounts payable trade-affiliate	362,200	~~415,800~~		415,800	~~302,300~~
Increase in accrued liabilities		1,300			300
(Decrease) increase in accrued liabilities	(1,700		)	1,300
Net cash provided by (used in) operating activities		-			(200	)
Net cash provided by operating activities	—			—
Cash flows from investing activities:
Proceeds from sale of tangible equipment		-			200
Net cash provided by investing activities	—			—
Net cash provided by investing activities		-			200
Cash flows from financing activities:
Distributions to partners		-			-
Net cash provided by financing activities	—			—
Net cash used in financing activities		-			-
Net change in cash	—			—
Net change in cash		-			-
Cash at beginning of year	—			—
Cash at beginning of year		-			-
Cash at end of year	$	—		$	—
Cash at end of year	$	-		$	-

See accompanying notes to financial statements.

3125

ATLAS AMERICA PUBLIC #9 LTD.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, ~~2016~~2017 AND ~~2015~~2016

NOTE 1—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Atlas America Public #9 LTD. (the “Partnership”) is a Pennsylvania limited partnership, formed on July 27, 2000. ~~with~~DGOC ~~Atlas~~Partnership ~~Resources~~Holdings, LLC ~~serving~~serves as its Managing General Partner ~~and Operator~~ (“~~Atlas~~DGOC ~~Resources~~Holdings” or the “MGP”). ~~Atlas~~and ~~Resources~~certain isaffiliates anof ~~indirect~~the ~~subsidiary~~MGP ofserves ~~Titan~~as ~~Energy,~~our ~~LLC~~Operators (~~“Titan”~~"Operators"). ~~Titan~~DGOC Holdings is an ~~independent~~indirect ~~developer~~subsidiary ~~and producer~~ of ~~natural~~Diversified ~~gas,~~Gas ~~crude~~& ~~oil~~Oil, ~~and~~PLC natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“~~ARP~~Diversified”),; aAIM: ~~Delaware limited partnership organized in 2012~~DGOC). Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas America Public #9 LTD.

~~Atlas~~Until ~~Energy~~June ~~Group~~30, 2017, Atlas Resources, LLC previously served as our Managing General Partner and Operator (“Atlas ~~Energy~~Resources” ~~Group~~or “Previous MGP”;). ~~OTCQX:~~Atlas ~~ATLS~~Resources is an indirect subsidiary of Titan Energy, LLC (“Titan”). Titan is aan ~~publicly~~independent ~~traded~~developer ~~company~~and producer of natural gas, oil, and ~~manages~~natural gas liquids, with operations in basins across the United States. On May 4, 2017, Titan entered into a definitive agreement to sell, among other conventional assets, its general and limited partnership equity interest (“Equity Interest”) in the Partnership to Diversified (the “Purchase and Sale Agreement” or “PSA”). The transaction was subject to customary closing conditions, had an effective date of April 1, 2017 and closed on June 30, 2017. Upon closing the PSA, the Previous MGP’s ~~through~~Equity Interest in the Partnership was transferred to DGOC Holdings and DGOC Holdings was admitted as a 2%substitute ~~preferred~~managing ~~member~~general ~~interest~~partner inof ~~Titan~~the Partnership.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

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 were 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’s 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.

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.

Liquidity, Capital Resources and Ability to Continue as a Going Concern

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had 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.

MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

~~The~~Preparation ~~preparation~~ of the Partnership’s financial statements in conformity with U.S. GAAP requires ~~management~~the MGP to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, ~~depreciation and amortization, asset~~ impairments, ~~fair value of derivative instruments,~~ and the probability of forecasted transactions. The ~~oil~~natural ~~and~~ 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.

Receivables

Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, ~~2016~~2017 and ~~2015~~2016, the Partnership had ~~recorded~~ no allowance for uncollectible accounts receivable on its balance sheets.

Asset retirement receivable – -affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnership’s wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells. For additional information, see Note 8. The following is a reconciliation of the Partnership’s asset retirement receivable-affiliate for the periods indicated:

The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the periods indicated:



	2017		2016
Asset retirement receivable-affiliate, beginning of year	$	382,500	$	188,100
Asset retirement estimates withheld	194,400		194,400
Asset retirement receivable-affiliate, end of year	$	576,900	$	382,500

	December 31,
	2016		2015
Asset retirement receivable – affiliate, beginning of year	$	188,100	$	9,900
Asset retirement estimates withheld		194,400		178,200
Asset retirement receivable –affiliate, end of year	$	382,500	$	188,100

Natural Gas and Oil Properties

~~Gas~~Natural gas and oil properties are stated at cost. ~~Maintenance~~The Partnership follows the successful efforts method of accounting for natural gas and oil producing activities. The Partnership expenses maintenance and repairs as incurred that generally do not extend the useful life or enhance the productivity of an asset for two years or more through the replacement of critical components. ~~are~~The ~~expensed~~Partnership ascapitalizes ~~incurred.~~major ~~Major~~ renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components ~~are capitalized~~.

The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets.

35In the current year, the partnership recognized a gain on the sale of natural gas and oil properties of $118,400. This gain resulted from the relief of the asset retirement obligation associated with the sale of 6 gross (4.5 net) partnership wells. There were no cash proceeds associated with the sale. Although the sale did not relate to a complete field of proved property, a gain was recognized as a result of the remaining net book value of natural gas and oil properties at December 31, 2017 relating entirely to estimated salvage value.

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of natural gas and oil properties on our balance sheets at December 31, 2017 and 2016 was entirely related to the estimated salvage value of such properties. The estimated salvage values were based upon the MGP's and the Previous MGP's historical experience in determining such values. For additional information, see Note 4.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value ~~(see Note 4)~~.

The ~~review~~MGP ofreviews the Partnership’s natural gas and oil properties ~~is done~~ on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The MGP estimates the expected future cash flows ~~are estimated~~ based on the Partnership’s plans to continue to produce and develop proved reserves. ~~Expected~~The MGP calculates the expected future cash flow from the sale of the production of reserves ~~is calculated~~ based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, anwe recognize impairment loss ~~is recognized~~ for the difference between the estimated fair market value (as determined by the discounted cash flows) and the carrying value of the assets.

~~The~~Determination ~~determination~~ of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. For additional information, see Note 4.

InDerivative ~~addition,~~Instruments ~~reserve~~and ~~estimates~~Other ~~for~~Comprehensive wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. Loss

~~Derivative~~The ~~Instruments~~Partnership’s Previous MGP entered into certain financial derivative contracts to manage the Partnership’s exposure to changes in commodity prices. The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value were recognized in the Partnership’s statements of operations unless specific hedge accounting criteria were met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2015 of these derivatives were recognized immediately within loss on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive loss as of December 31, 2015 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. For the year ended December 31, 2016, the loss reclassified from accumulated other comprehensive loss into

The Partnership’s MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.27

natural gas and oil revenues was $700 and the loss subsequent to hedge accounting recognized in loss on mark-to-market derivatives was $100.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its natural gas and oil wells and related facilities (~~See~~For additional information see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. ~~The~~Accordingly, no federal ~~and~~or state deferred income ~~taxes~~tax ~~related~~has tobeen ~~the~~provided ~~Partnership~~for ~~were~~in ~~immaterial to~~ the financial statements. ~~and~~The ~~are~~Partnership ~~recorded~~files inPartnership ~~pre-tax~~Returns ~~income~~of onIncome ain ~~current~~the ~~basis~~U.S. ~~only~~and various state jurisdictions. ~~Accordingly~~With few exceptions, nothe ~~federal~~Partnership oris ~~state~~no ~~deferred~~longer subject to income tax ~~has~~examinations ~~been~~by ~~provided~~major tax authorities for inyears ~~the~~prior ~~financial~~to ~~statements~~2012. The Company’s tax returns are generally subject to possible examination by the taxing authorities for a period of three years from the date they are filed, though the Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2017.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2016 and 2015.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2016.

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, ~~2016~~2017 and ~~2015~~2016.

Concentration of Credit Risk

The Partnership sells natural gas and ~~crude~~ oil, under contracts to various purchasers in the normal course of business. For the ~~year~~years ended December 31, ~~2016,~~2017 ~~the Partnership had four customers that individually accounted for approximately 28%, 23%, 16%~~ and ~~15% of the Partnership’s natural gas and oil combined revenues~~2016, ~~excluding~~ the ~~impact of all financial derivative activity. For the year ended December 31, 2015, the~~ Partnership had ~~four~~the following customers that individually accounted for ~~approximately~~greater ~~27%,~~than 1710%, ~~12% and 12%~~ of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.



	Percentage of Revenue
Customer	2017		2016
Direct Energy Business LLC	55	%	—	%
Castleton Commodities Merchant Trading, LLC	21	%	16	%
Ergon Oil Purchasing, Inc.	12	%	15	%
Chevron Natural Gas	—	%	28	%
Hess Energy Marketing, LLC	—	%	23	%
Other (no single customer accounts for more than 10% of revenues)	12	%	18	%
Total	100	%	100	%

Revenue Recognition

The Partnership generally sells natural gas and ~~crude~~ oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines for natural gas and the quality of its natural gas and oil. Generally, the market index is fixed two business days prior to the commencement of the production month. ~~Revenue~~The MGP recognizes revenue and the related accounts receivable ~~are~~when ~~recognized~~the ~~when~~MGP delivers the produced quantities ~~are delivered~~ to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. ~~Revenues~~The Partnership recognizes revenues from the production of natural gas and ~~crude~~ oil in which the ~~Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.~~

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $41,700 and $29,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. 28

37Partnership has an interest with other producers on the basis of its percentage ownership of the working interest and/or overriding royalty.

~~Comprehensive~~The ~~Income~~MGP ~~(Loss)~~and its affiliates perform all administrative and management functions for the Partnership including billing and collecting revenues and paying expenses. Accounts Receivable Trade-Affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and oil, and the receipt of a delivery statement. The MGP records revenues based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices.

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2016, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In ~~August~~May 2014, the FASB ~~updated~~issued ~~the~~ASU ~~accounting~~No. ~~guidance~~2014-09, ~~related~~Revenue tofrom ~~the~~Contracts ~~evaluation~~with ofCustomers ~~whether~~(“ASU ~~there~~2014-09”). isThe ~~substantial~~standard ~~doubt~~requires ~~about~~ an entity’s ~~ability~~ to ~~continue~~recognize asrevenue in a ~~going~~manner ~~concern.~~that ~~The~~depicts ~~updated~~the ~~accounting~~transfer ~~guidance~~of ~~requires~~goods or services to customers at an amount that reflects the consideration to which the entity’s ~~management~~expects to ~~evaluate~~be ~~whether~~entitled ~~there~~in ~~are~~exchange ~~conditions~~for those goods or ~~events~~services. ~~that~~ASU ~~raise~~2014-09 ~~substantial~~will ~~doubt~~replace ~~about~~most ~~its~~of ~~ability~~the toexisting ~~continue~~revenue asrecognition arequirements ~~going~~in ~~concern~~GAAP ~~within~~when ~~one~~it ~~year~~becomes ~~from~~effective. In August 2015, the ~~date~~FASB issued ASU No. 2015-14, deferring the ~~financial~~effective ~~statements~~date ~~are~~of ~~issued~~ASU ~~and~~2014-09 ~~provide~~by ~~footnote~~one ~~disclosures~~year. As a result, ifthe ~~necessary.~~standard Weis ~~adopted~~effective ~~this~~for ~~accounting~~annual ~~guidance~~periods beginning on or after December 1531, ~~2016~~2017, ~~and~~including ~~provided~~interim ~~enhanced~~periods ~~disclosures,~~within asthat ~~applicable,~~reporting ~~within~~period. ~~our~~The ~~financial~~standard ~~statements~~can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.

InAt ~~May~~December ~~2014~~31, ~~the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single~~2017, ~~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~~MGP ~~of standards to which an entity~~ has tocompleted ~~refer. In July 2015,~~ the ~~FASB~~evaluation ~~voted~~of tosources ~~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.~~revenue Weand ~~are evaluating~~ the impact of this ~~updated~~ accounting ~~guidance~~standards update on our ~~consolidated~~results ~~financial~~of ~~statements.~~operations, ~~This~~financial ~~accounting~~position, ~~guidance~~cash ~~will~~flows ~~require~~and ~~that~~financial ~~our revenue recognition policy~~ disclosures, ~~include~~in ~~further~~addition ~~detail~~to ~~regarding~~developing ~~our~~and ~~performance~~implementing ~~obligations~~any asprocess toor ~~the~~control ~~nature,~~changes ~~amount,~~necessary. ~~timing,~~We ~~and~~do ~~estimates~~not ofexpect ~~revenue~~to ~~and~~record ~~cash~~a ~~flows~~cumulative ~~generated~~effect ~~from~~adjustment ~~our~~on ~~contracts~~date ~~with~~of ~~customers~~adoption. WeThe ~~are~~Partnership ~~still~~adopted in the ~~process~~new ofstandard ~~determining~~on ~~whether~~January or1, ~~not~~2018 weusing ~~will use~~ the modified retrospective method orat the ~~modified~~date ~~retrospective~~of ~~approach to implementation~~adoption.

NOTE 32—~~PARTICIPATION~~ABILITY INTO ~~REVENUES~~CONTINUE ~~AND~~AS ~~COSTS~~A GOING CONCERN

~~Working~~The ~~Interest~~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 twelve months from the date the financial statements are issued. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership's ability to continue as a going concern.

~~The~~NOTE ~~Partnership~~3—PARTICIPATION ~~Agreement~~IN ~~establishes~~REVENUES ~~that~~AND ~~revenues~~COSTS ~~and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions~~ (~~“working~~WORKING ~~interest”~~INTEREST). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

The MGP allocates revenues and expenses to the MGP and limited partners based on their proportion of capital contributions to total contributions ("working interest") per the partnership agreement. The MGP has provided an additional working interest of 7% as provided in the partnership agreement. The MGP determined the final working interest ownership of the partners once the wells were producing. The MGP and the limited partners generally participated in revenues and costs in the following manner:

	ManagingGeneralPartner		LimitedPartners	~~LimitedPartners~~
Organization and offering costs	100%	~~100%~~	—%		0%
Lease costs	100%	~~100%~~	—%		0%
Intangible drilling costs	—%	0%	100%		~~100%~~
Tangible equipment costs	100%	~~100%~~	—%		0%
Revenues (1)	35%	~~35%~~	65%		~~65%~~
Operating costs, administrative costs, direct and all other costs (2)	35%	~~35%~~	65%		~~65%~~

(1) Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues.___________________________________________________________


(1)	All partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP received an additional 7% of the partnership revenues.


(2)	These costs will be charged to the partners in the same ratio as the related production revenues are credited.

3829

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

The following is a summary of proved natural gas and oil properties at the dates indicated:

	December 31,
	2016			2015
	2017			2016
Proved properties:
Leasehold interest	$	254,600		$	254,600
Wells and related equipment	18,721,700	~~18,721,700~~		18,721,700	~~18,721,700~~
Total natural gas and oil properties	18,976,300	~~18,976,300~~		18,976,300	~~18,976,300~~
Accumulated depletion and impairment	(18,910,800	~~(18,637,800~~	)	(18,637,800	~~(18,439,300~~	)
Gas and oil properties, net	$	338,500		$	537,000
Natural gas and oil properties, net	$	65,500		$	338,500

~~The~~As ~~Partnership~~a ~~recorded~~result ~~depletion~~of ~~expense~~the onrecent ~~natural~~significant ~~gas~~declines ~~and~~in ~~oil~~commodity ~~properties~~prices ofand ~~$36,400~~associated ~~and~~recorded ~~$27~~impairment charges,~~600~~ ~~for~~remaining ~~the~~net ~~years~~book ~~ended~~value ~~December~~of ~~31,~~natural ~~2016~~gas and ~~2015,~~oil ~~respectively.~~properties ~~The~~on ~~depletion~~our ~~expense~~balance ~~recorded~~sheet ~~for~~at ~~the year ended~~ December 31, ~~2016~~2017 ~~was~~represents amanagement’s ~~result~~estimated salvage value of asuch ~~decrease~~properties. The inestimated ~~management~~salvage values were based on the MGP’s ~~estimated~~historical ~~salvage~~experience ~~value~~in determining such values.

~~During~~The ~~the~~Partnership ~~years~~recorded ~~ended~~depletion ~~December~~expense ~~31,~~on ~~2016~~natural gas and ~~2015,~~oil ~~the~~properties ~~Partnership~~of ~~recognized~~ $~~162,100~~0 and $~~457~~36,~~200,~~400 ~~respectively,~~for ofthe ~~impairment~~years ~~related~~ended toDecember 31, ~~gas~~2017 and ~~oil~~2016, ~~properties~~respectively, onand ~~its~~natural ~~balance sheet. This impairment relates to the carrying amount of these~~ gas and oil properties ~~being~~impairment incharges ~~excess~~ of ~~the Partnership’s estimate of their fair value at December 31~~$273,000 ~~2016~~ and ~~2015~~$162,100, respectively. At December 31, 2017 and 2016, the MGP redetermined estimated salvage values to be lower than previous estimates~~. This~~ ~~redetermination~~which resulted in the impairment of natural gas and oil properties. ~~Due~~ toEstimated ~~the change in estimated~~ salvage values ofwere ~~tangible~~redetermined ~~equipment,~~based ~~all~~upon lower ~~impairment~~scrap ~~expense~~material ~~was~~prices ~~allocated~~and due to the ~~MGP~~decline ~~(See~~of ~~Note~~natural 3:gas ~~Participation~~drilling in ~~revenues and Costs). At December 31, 2015,~~ the ~~estimate~~Appalachia ofbasin ~~fair~~in ~~value~~recent ofyears. Due ~~these~~to ~~gas~~the ~~and~~change ~~oil~~in ~~properties~~estimated ~~was~~salvage ~~impacted~~values ~~by,~~of ~~among~~tangible ~~other factors~~equipment, ~~the~~all ~~deterioration~~impairment ofexpense ~~natural~~was ~~gas~~allocated ~~and~~to ~~oil prices at~~ the ~~date of measurement~~MGP.

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 balance sheet at December 31, 2016 represents management’s estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

NOTE 5—ASSET RETIREMENT OBLIGATIONS

The estimated liability for asset retirement obligations ~~was~~is based on the MGP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability ~~was~~is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. ~~Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.~~

The MGP’s historical practice and continued intention is to retain distributions from the limited partners asup ~~the~~to ~~wells within~~ the ~~Partnership~~fair ~~near~~value ~~the end~~ of ~~their useful life. On a partnership-by-partnership basis,~~ the ~~MGP~~future ~~assesses its right to withhold amounts related to~~ plugging and abandonment costs. ~~based~~As onof ~~several factors including commodity price trends~~December 31, ~~the~~2017 ~~natural decline in the production of the wells~~ and ~~current and future costs. Generally~~2016, the MGP’s ~~intention~~and ~~is to retain distributions from~~ the ~~limited~~Previous ~~partners~~MGP aswithheld ~~the~~$576,900 ~~fair~~and ~~value~~$382,500, ofrespectively, ~~the future cash flows~~ of ~~the~~net ~~limited~~production ~~partners’~~revenue ~~interest~~for ~~approaches the fair value of the~~ future plugging and abandonment ~~cost~~costs. ~~Upon~~The ~~the~~following ~~MGP’s~~table ~~decision~~reconciles ~~to retain all future distributions to~~ the ~~limited partners of the~~ Partnership,’s ~~the MGP will assume the related~~ asset retirement ~~obligations~~obligation ofliability ~~the limited partners. As of December 31, 2016 and 2015, the MGP withheld $382,500 and $188,100, respectively, of net production revenue~~ for ~~future~~well plugging and abandonment costs.:

A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows:



	Years Ended December 31,
	2017			2016
Asset retirement liability, beginning of year	$	1,948,300		$	1,879,800
Accretion expense	71,000			68,500
ARO liability relieved on wells sold during the year	$	(118,400	)	$	—
Asset retirement liability, end of year	$	1,900,900		$	1,948,300

	Years Ended December 31,
	2016		2015
Beginning of year	$	1,879,800	$	1,778,100
Accretion expense		68,500		101,700
End of year	$	1,948,300	$	1,879,800

39NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 6—DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally put options, in connection with the Partnership’s commodity price risk management activities. Management used financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged.

The Partnership entered into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $0 and $13,400 at December 31, 2016 and 2015, respectively.

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

	Years EndedDecember 31,
	2016			2015
Gain reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues	$	700		$	1,900
(Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	(100	)	$	8,500

Put Premiums Payable

During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2016 and 2015, the put premiums were recorded as short-term payables to affiliate of $0 and $6,200, respectively .

NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1–Unadjusted quoted prices ~~in active markets~~ for identical, ~~unrestricted~~instruments ~~assets~~in ~~and~~active ~~liabilities that the reporting entity has the ability to access at the measurement date~~markets.

Level 2–~~Inputs~~Quoted ~~other than quoted~~ prices ~~included within Level 1 that are observable~~ for ~~the~~similar ~~asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability~~instruments.

Level 3–~~Unobservable~~Valuations ~~inputs~~ that ~~reflect~~are ~~the~~significant ~~entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability~~ and ~~are consequently not based on market activity but rather through particular valuation techniques~~unobservable.

40Financial Instruments

~~Assets~~The Partnership determines its estimated fair value of the Partnership’s financial instruments, which include current assets and ~~Liabilities~~liabilities, ~~Measured~~based atupon ~~Fair~~its ~~Value~~assessment onof aavailable ~~Recurring~~market ~~Basis~~information and valuation methodologies. The Partnership has categorized the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature as Level 1.

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value was as follows:

As of December 31, 2016	Level 1		Level 2		Level 3		Total
Derivative assets, gross
Commodity puts	$	-	$	-	$	-	$	-
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	13,400	$	-	$	13,400

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale of such financial instruments. The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

~~The~~Asset ~~Partnership~~Retirement estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5). There were no adjustments to retirement obligations for the year ended December 31, 2016. There were no adjustments to retirement obligations for the year ended December 31, 2015. Obligations

The Partnership estimates the fair value of its ~~long-lived~~asset ~~assets~~retirement inobligations ~~conjunction~~based ~~with~~on ~~the~~discounted ~~review~~cash offlow ~~assets~~projections ~~for~~using ~~impairment~~numerous orestimates, ~~whenever~~assumptions ~~events~~and orjudgments ~~changes~~discussed in ~~circumstances~~Note ~~indicate~~5. ~~that~~The ~~the~~MGP ~~carrying~~made ~~amount~~no ofadjustments anto ~~asset~~retirement ~~may~~obligations ~~not~~for ~~be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For~~ the years ended December 31, ~~2016~~2017 and ~~2015,~~2016 ~~the~~and ~~Partnership~~would ~~recognized~~define ~~$162~~them,~~100~~ ~~and~~if ~~$457~~applicable,~~200,~~ ~~respectively, of impairment of long-lived assets which was defined~~ as a Level 3 fair value ~~measurement~~measurements. ~~(See~~For ~~Note~~additional 4:information ~~Property,~~see ~~Plant,~~Note ~~and Equipment)~~5.

~~NOTE~~Long-Lived ~~8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS~~ Assets:

The Partnership ~~has~~estimates ~~entered into~~ the ~~following~~fair ~~significant~~value ~~transactions~~of ~~with the MGP and~~ its ~~affiliates~~long-lived asassets ~~provided under its Partnership Agreement. Administrative costs, which are included~~ in ~~general~~conjunction ~~and~~with ~~administrative expenses in~~ the ~~Partnership’s~~review ~~statements~~ of ~~operations,~~assets ~~are~~for ~~payable~~impairment ator ~~$75~~whenever ~~per~~events ~~well~~or ~~per~~changes ~~month. Monthly well supervision fees which are included~~ in ~~production~~circumstances ~~expenses~~indicate inthat the ~~Partnership’s~~carrying ~~statements~~amount of ~~operations,~~an ~~are~~asset ~~payable~~may atnot ~~$337~~be ~~per~~recoverable, ~~well~~using ~~per~~estimates, ~~month~~assumptions, ~~for operating~~ and ~~maintaining~~judgments ~~the~~regarding ~~wells.~~such ~~Well~~events ~~supervision~~or ~~fees~~circumstances. ~~are~~For ~~proportionately reduced to~~ the ~~extent~~years ~~the~~ended ~~Partnership~~December 31, ~~does~~2017 ~~not~~and ~~acquire~~2016, ~~100% of working interest in a well. Transportation fees are included in production expenses in~~ the Partnership’s ~~statements~~recognized of$273,000 ~~operations~~ and ~~are~~$162,100, ~~generally~~respectively, ~~payable~~of atimpairment ~~13%~~ of ~~the~~its long-lived natural gas ~~sales~~and ~~price.~~oil ~~Direct costs~~properties, which ~~are~~we ~~included~~defined inas ~~production~~a ~~and~~Level ~~general~~3 ~~administrative~~fair ~~expenses~~value inmeasurement. ~~the~~For ~~Partnership’s~~additional ~~statements~~information ofsee ~~operations,~~Note ~~are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf~~4.

4131

~~The~~NOTE ~~following~~7—CERTAIN ~~table~~RELATIONSHIPS ~~provides~~AND ~~information~~RELATED ~~with~~PARTY ~~respect to these costs and the periods incurred:~~ TRANSACTIONS

	Years Ended December 31,
	2016		2015
Administrative fees	$	49,700	$	51,000
Supervision fees		223,300		229,400
Transportation fees		25,700		31,200
Direct Costs		134,700		141,300
Total	$	433,400	$	452,900

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 statements of operations, are payable at $75 per well per month. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Monthly well supervision fees of $337 per well per month for operating and maintaining the wells, are included in production expenses in the Partnership's statements of operations. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are payable at either 16% of the natural gas sales price or $0.35 per Mcf, whichever is greater. The MGP and its affiliates, with administrative support from the Previous MGP under the previously mentioned TSA, perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts Payable Trade-Affiliate on the Partnership’s balance sheet includes the net production expenses due to the MGP. The following table provides information with respect to these costs and the periods incurred:

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 balance sheet includes the net production expenses due to the MGP.



	Years Ended December 31,
	2017		2016		$ Change			% Change
Transportation fees	$	35,900	$	25,700	$	10,200		40	%
Supervision fees	240,600		223,300		17,300			8	%
Direct costs	52,600		79,500		(26,900		)	(34	)%
Total production costs	$	329,100	$	328,500	$	600		14	%

Administrative fees	$	53,300	$	49,700	$	3,600		7	%
Direct costs	75,800		55,200		20,600			37	%
Total general and administrative	$	129,100	$	104,900	$	24,200		23	%

NOTE 98—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, ~~limited~~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~~partnership ~~Agreement~~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~~exercised its right to retain $200 per month per well to cover estimated future plugging and abandonment costs. AsFor ofadditional ~~December~~information ~~31,~~refer ~~2016~~to ~~and~~Note ~~2015, the MGP withheld $382,500 and $188,100, respectively, of net production revenue for future plugging and abandonment costs~~5.

Environmental risk is inherent to oil and natural gas operations, and we and our affiliates may be, at times, subject to potential environmental remediation liability. At December 31, 2017, there were no unresolved environmental matters. For additional information refer to Note 1.

Legal Proceedings

~~The~~From time to time, the Partnership isand aaffiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising out of the ordinary course of its business. ~~Management~~The MGP 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. As of December 31, 2017, there were no outstanding legal proceedings.

~~Affiliates~~NOTE of9—SUPPLEMENTAL ~~the~~NATURAL ~~MGP~~GAS ~~and~~AND ~~their~~OIL ~~subsidiaries~~INFORMATION 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.(UNAUDITED)

~~NOTE~~Natural ~~10—SUBSEQUENT~~Gas ~~EVENTS~~and Oil Reserve Information. For the periods presented, the MGP retained Wright & Company, Inc., the MGP's independent third-party reserve engineer, to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 41 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures

~~Management has considered for disclosure any material subsequent events through the date the financial statements were issued.~~ 32

~~NOTE~~include ~~11—SUPPLEMENTAL~~verification ~~GAS~~of ~~AND~~input ~~OIL~~data ~~INFORMATION~~delivered ~~(UNAUDITED)~~to its third-party reserve specialist. Our MGP's Vice President of Gas Marketing, who has more than 18 years of natural gas and oil industry experience, oversaw the preparation, review and approval of reserve estimates with final approval by the MGP’s Chief Operating Officer.

~~Gas and Oil Reserve Information.~~ The ~~preparation~~reserve ofdisclosures ~~the~~that ~~Partnership’s~~follow ~~natural~~reflect ~~gas and oil reserve~~ estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved developed reserves ~~related~~of ~~to the Partnership. The reserve information for the Partnership includes~~ natural gas and oil ~~reserves~~owned ~~which~~at ~~are~~year ~~all~~end, ~~located~~net inof ~~the~~royalty ~~United States~~interests. ~~The~~Proved ~~independent~~developed reserves ~~engineer’s~~are ~~evaluation~~those ~~was~~reserves ~~based~~that oncan ~~more~~be ~~than~~expected 41to ~~years~~be ofrecovered ~~experience~~through inexisting ~~the~~wells ~~estimation~~with ofexisting equipment and ~~evaluation of petroleum reserves, specified economic parameters,~~ operating ~~conditions, and government regulations~~methods. The ~~MGP’s~~proved ~~internal~~reserves ~~control~~quantities ~~procedures~~and ~~include~~future ~~verification~~net ofcash ~~input~~flows ~~data~~were ~~delivered~~estimated tousing ~~its~~an ~~third-party~~unweighted ~~reserve specialist, as well as a multi~~12-~~functional~~month ~~management~~average ~~review.~~pricing ~~The~~based ~~preparation~~on ofthe ~~reserve~~prices ~~estimates~~on ~~was~~the ~~overseen~~first byday ~~our MGP’s Director~~ of ~~Reservoir~~each ~~Engineering,~~month ~~who~~during ~~is a member of~~ the ~~Society of Petroleum Engineers and has more than 18~~ years ofended ~~natural~~December 31, ~~gas~~2017 and ~~oil~~2016, ~~industry~~including ~~experience.~~adjustments ~~The~~related ~~reserve~~to ~~estimates~~regional ~~were~~price ~~reviewed~~differentials and ~~approved~~energy ~~by the MGP’s senior engineering staff and management, with final approval by the MGP’s President~~content.

42Numerous uncertainties are inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of natural gas and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in natural gas and oil prices and in production and development costs and other factors.

~~The~~ ~~reserve~~This ~~disclosures~~section ~~that~~is ~~follow~~not ~~reflect~~applicable ~~estimates~~as ofthere ~~proved~~have ~~developed~~been ~~reserves~~no ~~net~~economic ~~of royalty interests, of natural gas and crude oil owned at year end. Proved developed~~ reserves ~~are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or~~ in ~~which~~any ~~the cost~~ of the ~~required~~periods ~~equipment~~presented ~~is relatively minor compared to the cost of a new well;~~ and ~~through~~all ~~installed~~other ~~extraction~~required ~~equipment~~disclosures ~~and~~are ~~infrastructure~~covered ~~operational~~in atother ~~the~~areas ~~time~~ of the ~~reserves~~financial ~~estimate if the extraction is by means not involving a well~~statements. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content.

~~There~~In ~~are~~2017 ~~numerous uncertainties inherent in estimating quantities of proven reserves~~ and ~~in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition~~2016, ~~the~~we ~~standardized~~fully ~~measures~~impaired ~~of discounted future net cash flows may not represent~~ the ~~fair~~remaining ~~market~~ value of our natural gas and oil ~~reserves~~properties ~~included within the Partnership or the present value of future cash flows of equivalent reserves,~~ due to ~~anticipated~~prolonged ~~future~~reduced ~~changes~~commodity ~~in gas and oil~~ prices ~~and in production and development costs and other factors, for their effects have not been proved~~.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows:

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2014		772,500			5,500
Revisions(1)		(636,900	)		(4,700	)
Production		(135,600	)		(800	)
Balance, December 31, 2015(2)		-			-
Revisions		-			-
Production		-			-
Balance, December 31, 2016(2)		-			-

(1) The downward revision in natural gas forecasts is primarily due to a decrease in the SEC base pricing from the prior year, resulting in a shorter economic life.

(2) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2016 and 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the years presented, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows:

	Years Ended December 31,
	2016			2015
Natural gas and oil properties:
Leasehold interest	$	254,600		$	254,600
Wells and related equipment		18,721,700			18,721,700
Accumulated depletion, accretion and impairment		(18,637,800	)		(18,439,300	)
Net capitalized costs	$	338,500		$	537,000

Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows:

	Years Ended December 31,
	2016			2015
Revenues	$	216,400		$	264,800
Production costs		(328,500	)		(346,100	)
Depletion		(36,400	)		(27,600	)
Impairment		(162,100	)		(457,200	)
	$	(310,600	)	$	(566,100	)

ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A: CONTROLS AND PROCEDURES

~~Conclusion~~Evaluation ~~Regarding~~of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the ~~Effectiveness~~Exchange Act, we have evaluated, under the supervision and with the participation of ~~Disclosure~~our ~~Controls~~management, including our principal executive officer and ~~Procedures~~principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our MGP's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 at the reasonable assurance level.

WeChanges ~~maintain~~in ~~disclosure~~Internal ~~controls~~Controls ~~and~~over ~~procedures~~Financial ~~that~~Reporting. ~~are~~There ~~designed~~have tobeen ~~ensure~~no ~~that~~changes ~~information required to be disclosed~~ in our ~~Securities~~system ~~Exchange Act~~ of ~~1934~~internal ~~reports~~control isover ~~recorded,~~financial ~~processed,~~reporting ~~summarized~~(such ~~and~~as ~~reported~~term ~~within~~is ~~the~~defined ~~time periods specified~~ in ~~the~~Rules ~~SEC’s~~13a-15(f) ~~rules~~ and ~~forms,~~15d-15(f) ~~and~~under ~~that~~the ~~such~~Exchange ~~information~~Act) isduring 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~~quarter ~~controls~~ended ~~and~~December ~~procedures~~31, ~~our~~2017 ~~management recognized~~ that ~~any~~have ~~controls~~materially ~~and procedures~~affected, noor ~~matter~~are ~~how~~reasonably ~~well~~likely ~~designed~~to ~~and~~materially ~~operated~~affect, ~~can~~our ~~provide~~internal ~~only reasonable assurance of achieving the desired~~ control ~~objectives,~~over ~~and~~financial ~~our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures~~reporting.

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 December 31, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our ~~general partner~~MGP’s ~~Chief~~principal ~~Executive~~executive ~~Officer~~officer and ~~Chief~~principal ~~Financial~~financial ~~Officer~~officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 Internal Control –- Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

There have been no changes in our 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. 33

44certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, ~~2016~~2017. This annual report does not include an attestation report by our registered public accounting firm regarding internal control over financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.

This annual report does not include an attestation report by our registered public accounting firm regarding internal control over financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us.

Officers and Key Operations Employees of Our General Partner

The ~~following~~Partnership ~~table~~has ~~sets~~no ~~forth~~officers. ~~information~~Rather, ~~with~~our ~~respect~~Managing toGeneral ~~those~~Partner ~~persons~~has the following individuals who serve as ~~the~~its officers of and on ~~the~~its board of directors ~~of, our general partner~~:

Name	Age		Position(s)	~~Position(s)~~
Fredrick M. Stoleru		45		Chief Executive Officer, President and Director
Robert "Rusty" R. Hutson Jr.	48		Chief Executive Officer
Mark D. Schumacher		54		Chief Operating Officer
Bradley G. Gray	48		Finance Director and Chief Operating Officer
Daniel C. Herz		40		Executive Vice President and Director
Eric M. Williams	39		Chief Financial Officer
Jeffrey M. Slotterback		35		Chief Financial Officer and Director
John "Jack" W. Crook	59		Senior Vice President of Environmental, Health and Safety
Gary Lichtenstein		69		Director
William "Bill" Kurtz	52		Vice President, Gas Marketing
Christopher Shebby		51		Director

~~Fredrick~~Robert M.‘‘Rusty’’ ~~Stoleru has served as the Chief Executive Officer and President of the MGP since February 2017~~R. He ~~has~~Hutson ~~been Vice President of the general partner of Atlas Growth Partners, L~~Jr.~~P. since its inception in 2013. Before that Mr. Stoleru was Managing Director of Resource Financial Institutions Group~~, ~~Inc.~~(48), ~~responsible~~Chief ~~for~~Executive business development. From 2005 to 2008, Mr. Stoleru was a Principal at Direct Invest with responsibility for broker-dealer relationships and raising capital for real estate programs. From 2002 to 2005, Mr. Stoleru was an Associate in the Capital Transactions group of the Shorenstein Company, a national private equity real estate investor. From 2000 to 2002, Mr. Stoleru was an Investment Banking Associate with JP Morgan Chase and from 1993 to 1998 with JP Morgan Investment Management. Mr. Stoleru holds FINRA Series 7 and 63 licenses. Officer

~~Mark D~~Mr. ~~Schumacher has~~Hutson ~~served~~Jr. asis the Chief ~~Operating~~Executive Officer of the ~~MGP~~general ~~since~~partner ~~January~~and ~~2014. He~~ has served as ~~ARP’s~~Chief ~~President~~Executive ~~since~~Officer ~~April 2015 and as a Senior Vice President~~ of ~~Atlas~~Diversified ~~Energy~~since ~~Group~~its ~~since~~inception ~~April~~in ~~2015~~2001. Mr. ~~Schumacher~~Hutson ~~served~~Jr. asis ~~Chief~~the ~~Operating~~fourth ~~Officer~~generation of ~~Atlas~~his ~~Energy~~family ~~Group from October 2013~~ to ~~April~~be ~~2015.~~involved ~~Mr.~~in ~~Schumacher has been~~ the ~~Executive~~oil ~~Vice~~and ~~President~~natural ofgas ~~Operations~~industry ofbut the ~~general~~first ~~partner~~to ofhold ~~Atlas~~an ~~Growth~~executive ~~Partners~~role, ~~L.P.~~with ~~since~~his ~~its~~father, ~~inception~~grandfather inand ~~2013.~~great Hegrandfather ~~served~~all asworking ~~Executive~~in ~~Vice~~various ~~President~~field ofoperational ~~Atlas~~roles. ~~Energy~~Before ~~from~~founding ~~July~~Diversified ~~2012~~Gas to& ~~October~~Oil ~~2013.~~in ~~From August 2008 to July 2012~~2001, Mr. ~~Schumacher~~ ~~served~~Hutson asJr. ~~President~~held offinance ~~Titan~~and ~~Operating,~~accounting ~~LLC,~~roles ~~which~~for ~~ARP~~13 ~~acquired~~years inat ~~July~~Bank ~~2012. From~~One ~~November 2006 until August 2008~~(Columbus, ~~Mr. Schumacher~~Ohio) ~~served~~and asCompass ~~President~~Bank ~~of Titan Resources~~(Birmingham, ~~LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008~~Alabama). ~~From February~~ ~~2005~~He tofinished ~~November~~his ~~2006,~~banking ~~Mr. Schumacher~~career ~~served~~ as ~~the~~CFO ~~Team Lead~~ of ~~EnCana~~Compass ~~Oil &~~Financial ~~Gas (USA) Inc~~Services. ~~where he was responsible for Encana’s Barnett Shale development.~~ Mr. ~~Schumacher~~ ~~was~~Hutson anhas ~~engineer~~a ~~with Union Pacific Resources from 1984 to 2000~~B. MrS. ~~Schumacher~~ ~~has~~degree ~~over 33 years of experience~~ in ~~drilling,~~Accounting ~~production~~from ~~and~~Fairmont ~~reservoir~~State ~~engineering~~College ~~management,~~– ~~operations~~West ~~and~~Virginia. ~~business~~He ~~development~~is ina ~~East~~former ~~Texas,~~certified ~~Austin~~public ~~Chalk,~~accountant ~~Barnett~~(‘‘CPA’’) ~~Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada~~(Ohio).

~~Daniel~~Bradley CG. Herz has served as Executive Vice President of the MGP since May 2011. He has served as ARP’s Chief Executive Officer since August 2015 and as President of Atlas Energy Group since April 2015. Mr. Herz has served as President and a director of the general partner of Atlas Growth PartnersGray, L.P. since its inception in 2013. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Atlas Energy Group from March 2012 to April 2015. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Atlas Energy’s general partner from February 2011 until February 2015. Mr. Herz was Senior Vice President of Corporate Development of Atlas Pipeline Partners GP(48), ~~LLC~~Finance ~~from~~Director ~~August 2007 until February 2015. He also was Senior Vice President of Corporate Development of Atlas Energy, Inc.~~ and ~~Atlas~~Chief ~~Energy~~Operating Resources, LLC from August 2007 until February 2011. Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004 and of Atlas Energy’s general partner from January 2006.Officer

45Mr. Gray serves as the Chief Operating Officer of the general partner and has serviced as Chief Operating officer of Diversified since October 2016. Prior to joining the Company in October 2016, Mr. Gray held the position of Senior Vice President and Chief Financial Officer for Royal Cup, Inc., a United States based commercial coffee roaster and wholesale distributor of tea and other beverage related products. Prior to Royal Cup, Inc., from 2006 to 2014, Mr. Gray worked in the petroleum distribution industry for The McPherson Companies, Inc. and held the position of Executive Vice President and Chief Financial Officer. Additionally, from 1997 to 2006, Mr. Gray worked in various financial and operational roles with Saks Incorporated, a previously listed New York Stock Exchange retail group in the United States. Mr Gray began his career at Arthur Andersen. Mr. Gray has a B.S. degree in Accounting from the University of Alabama and he is a licensed CPA (Alabama).

~~Jeffrey~~Eric M. ~~Slotterback has~~Williams, served as Chief Financial Officer of each of the MGP and ARP since September 2015. Mr. Slotterback has served as Chief Financial Officer of Atlas Energy Group since September 2015 and served as its Chief Accounting Officer from March 2012 to October 2015. Mr. Slotterback has also served as the Chief Financial Officer of the general partner of Atlas Growth Partners(39), ~~L.P. since September 2015 and served as its~~ Chief Accounting Officer from its inception in 2013 to October 2015. Mr. Slotterback served as Chief Accounting Officer of Atlas Energy’s general partner from March 2011 until February 2015. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting for Atlas Energy GP, LLC from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both Atlas Energy GP, LLC and Atlas Pipeline Partners GP, LLC from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.Officer

~~Gary~~Mr. ~~Lichtenstein~~Williams ~~has~~joined ~~been~~Diversified ~~one~~in ofJuly ~~our~~2017 ~~directors~~from ~~since~~Callon ~~September 2016~~Petroleum. ~~Mr. Lichtenstein~~During ~~has~~Eric’s ~~served~~more asthan anseven-year ~~independent~~tenure ~~director~~with ~~for~~Callon, ~~Resource~~the ~~Real~~company ~~Estate~~grew ~~Opportunity~~significantly ~~REIT,~~from ~~Inc~~a market capitalization of $40 million to over $3.5 ~~since~~billion, ~~September~~successfully ~~2009~~transforming ~~and~~itself ~~Resource~~from ~~Real~~a ~~Estate~~deep-water ~~Opportunity~~asset ~~REIT~~focused IIcompany ~~since~~to ~~November~~an ~~2013~~onshore, pure-play horizontal drilling operator in the Permian Basin. Mr. ~~Lichtenstein~~ ~~served~~Williams aswas ainstrumental ~~partner~~in ofdeveloping ~~Grant~~and ~~Thornton~~enhancing ~~LLP,~~the acompany’s ~~registered~~external ~~public~~reporting ~~accounting firm~~streams, ~~from~~and ~~1987~~established ~~until~~a ~~his~~formal ~~retirement~~investor inrelations ~~2009.~~function Heserving ~~worked~~more atthan ~~Grant~~30 ~~Thornton~~sell-side ~~LLP~~analysts ~~from~~and ~~1974~~a togrowing ~~1977~~base ~~and~~of ~~served~~institutional asinvestors. aMr. ~~manager~~Williams atbegan ~~Grant~~his ~~Thornton~~career ~~LLP~~in ~~from~~PwC’s ~~1977~~Birmingham, toAlabama ~~1987.~~audit ~~Prior~~practice, and prior to ~~joining~~his ~~Grant~~time ~~Thornton~~at ~~LLP~~Callon, ~~Mr. Lichtenstein~~ served asin anvarious ~~accountant~~roles ~~for~~including ~~Soloway &~~internal ~~von~~audit ~~Rosen~~with ~~CPA~~a ~~from~~focus ~~1970~~on toSarbanes ~~1974~~Oxley implementation and ~~for~~compliance, ~~Touche~~controllership ~~Ross~~and ~~Bailey &~~financial ~~Smart~~reporting ~~from~~for ~~1969~~several toUS ~~1970~~publicly traded companies. Mr. ~~Lichtenstein~~ isWilliams has a ~~past~~B.S. ~~Chairman~~degree ofin ~~the~~Accounting ~~Board~~from ofSamford ~~the~~University, ~~Diabetes~~a ~~Partnership~~M.S. ofdegree ~~Cleveland.~~in HeAccounting ~~received~~from ~~his~~the ~~Bachelor~~University of ~~Business~~Alabama ~~Administration~~ and ~~his~~he ~~Juris~~is ~~Doctor~~a ~~degree~~licensed ~~from~~CPA ~~Cleveland State University~~(Alabama).

Christopher Shebby has been a Director of our general partner since September of 2016. From May 2008 through February 2016, Mr. Shebby was a Managing Director and Co-Group Head in the Energy Investment Banking Group at Stifel, Nicolaus & Company Incorporated. From July 2000 to May 2008, Mr. Shebby was a member of the Energy Investment Banking Group of FBR Capital Markets, holding positions that ranged from Vice President to Senior Managing Director and Co-Group Head. From March 1996 through August 1999, Mr. Shebby was a Director and CEO of Mountain Oil and Gas Company, a privately held oil and gas firm that owned, operated and developed assets in the U.S. Rocky Mountain region. From 1992 to 1996, Mr. Shebby was an Associate and Vice President of The Energy Recovery Fund, L.P.,a private equity firm that invested in energy related assets and companies in the U.S., Canada and Europe. Mr. Shebby is a Chartered Financial Analyst. Mr. Shebby possesses 25 years of experience in the field of energy investment and finance and brings to our general partner’s board of directors extensive knowledge and experience in the areas of corporate finance, investment banking, capital markets and the energy sector.35

John "Jack" W. Crook, (59), Senior Vice President of Environmental, Health and Safety

Jack Crook is a licensed geologist with 36 years of oil and natural gas experience in environmental, health, safety and regulatory compliance. Mr. Crook started his career with the Pennsylvania Department of Environmental Protection and gained extensive knowledge within this field by taking on roles in the Department’s hydrology, water supply and oil and natural gas divisions. In 2012, Mr. Crook joined Titan as Vice President of Environmental, Health, Safety, Regulatory, and Security compliance. At Titan he oversaw safety policies, procedures and training and served on the Executive Committee. Mr. Crook is an Executive Board Member and Secretary of the Board of Pennsylvania Independent Oil & Gas Association. Mr. Cayton and Mr. Crook will be appointed by the Group following Completion.

William M. Kurtz, (52), Vice President of Energy Marketing

Mr. Kurtz joined the Company in 2017, bringing extensive experience that spans a 35-year career in the Oil & Gas Industry. His talents focused on advising and executing mergers & acquisitions, divestitures, and joint ventures for multiple organizations. His ongoing focus includes energy marketing. Mr. Kurtz began his career in 1983 as a Cartographer. Early in his career, he held subsequent positions that included Appalachian Landman, Surveyor, Appalachian Land Manager, and Senior Production Manager. During this time, he worked with multiple organizations including Atwood Energy, Inc., Transfuel Resources (Mitsubishi), and Lomak Petroleum (aka Range Resources). Immediately prior to joining the Company, Mr. Kurtz was employed with Atlas Energy, Inc. for 21 years where he held diverse positions that included Director of Business Development, Director of Production, and Senior Manager - Project Development. Mr. Kurtz is an active member of American Association of Professional Landmen, Society of Petroleum Engineers, and the Ohio Oil & Gas association where he serves on the Producers Committee.

Code of Business Conduct and Ethics

Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a code of business conduct and ethics that applies to the principal executive officer, principal financial officer, and principal accounting officer of our general partner, as well as to persons performing services for us generally.

Following its emergence from bankruptcy, Titan, the indirect parent of the MGP, has not yet adopted a code of business conduct and ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, as well as to persons performing services for us generally or corporate governance guidelines. We expect Titan to do so in the near future as part of its ongoing corporate governance initiatives. Once adopted, we expect that the code of business conduct and ethics (as well as waivers therefrom) and corporate governance guidelines will be available to requesting shareholders and posted on Titan’s website.

ITEM 11: EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

~~Introduction~~We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our MGP and other personnel) necessary for the management of our business were employed and compensated by Atlas Energy Group, Titan's parent company, through a TSA effective through December 31, 2017. After expiration of the TSA, staffing is provided by an affiliate of Diversified Gas and Oil PLC. Pursuant to our partnership agreement, our general partner manages our operations and activities through its and its affiliates’ employees (including employees of Atlas Energy Group and its MGP through a TSA). No officer or director of our MGP receives any direct remuneration or other compensation from us. (See “Item 13: Certain Relationships and Related Transactions” for a discussion of compensation paid by us to our MGP).

We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our general partner and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy Group. Pursuant to our partnership agreement, our general partner manages our operations and activities through its and its affiliates’ employees (including employees of Atlas Energy Group and its general partner). No officer or director of our MGP receives any direct remuneration or other compensation from us. (See “Item 13: Certain Relationships and Related Transactions” for a discussion of compensation paid by us to our MGP).

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, ~~2016~~2017, we had 1,500 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us for purchase, though the MGP is not obligated by the ~~Partnership~~partnership ~~Agreement~~agreement to purchase more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by ~~Titan~~Diversified. The Partnership does not hae any equity compensation plans in place. The MGP is owned 100% by Diversified.

ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our Relationship with ~~Atlas~~DGOC ~~Resources~~Partnership Holdings, LLC

Natural Gas and Oil Revenues. Our MGP is allocated 35.5% of our natural gas and oil revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 15% of our subscriptions, its payment of 100% of the tangible costs of drilling and completing our wells and its contributions to us of all of our natural gas and oil leases for a total capital contribution of $6,256,300. During the ~~year~~years ended December 31, 2017 and 2016, our MGP ~~paid~~was allocated $3915,~~800~~300 ~~for~~and ~~our net production expenses. During the year ended December 31~~$39, ~~2015~~800, ~~our MGP received $29~~respectively,~~600~~ for our net production expenses.

~~Administrative~~For ~~costs,~~additional ~~which~~information ~~are~~see ~~included~~Part ~~in general and administrative expenses in the Partnership’s statements of operations~~II, ~~are~~Item ~~payable~~7 ~~at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $337 per well per month for operating~~ and ~~maintaining~~Item ~~the wells~~8. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s 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 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:~~ 36

	Years Ended December 31,
	2016		2015
Administrative fees	$	49,700	$	51,000
Supervision fees		223,300		229,400
Transportation fees		25,700		31,200
Direct Costs		134,700		141,300
Total	$	433,400	$	452,900

Other Compensation. For the years ended December 31, 2017 and 2016, our MGP did not advance any funds to us, nor did it provide us with any equipment, supplies or other services.

Other Compensation. For the years ended December 31, 2016 and 2015, our MGP did not advance any funds to us, nor did it provide us with any equipment, supplies or other services.

ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, ~~2016~~2017 and ~~2015~~2016, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as$50,600 ~~follows:~~and $41,200 respectively.

	Years Ended December 31,
	2016		2015
Audit fees	$	41,200	$	30,000

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our ~~general partner~~MGP, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during ~~2016~~2017 and ~~2015~~2016.

4737

PART IV

ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT INDEX

	Description	~~Description~~
4(a)		Certificate of Limited Partnership for Atlas America Public #9 LTD. (1)
4.1	Certificate of Limited Partnership for Atlas America Public #9 LTD. (filed as Exhibit 4(a) to the Partnership's Form SB-2 Registration Statement filed September 8, 2000, as amended, File No. 333-44130, and incorporated herein by reference)
4(b)		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #9 LTD. (1)
4.2	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #9 LTD. (filed as Exhibit 4(b) to the Partnership's Form SB-2 Registration Statement dated September 8, 2000, as amended, File No. 333-44130, and incorporated herein by reference)
4(c)		Drilling and Operating Agreement for Atlas America Public #9 LTD. (1)
4.3	Amendment to Amended and Restated Certificate and Agreement of Limited Partnership of Atlas America Public #9 LTD. dated June 30, 2017 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K dated June 30, 2017 and incorporated herein by reference)
23.1		Consent of Wright & Company, Inc.
4.4	Drilling and Operating Agreement for Atlas America Public #9 LTD. (filed as Exhibit to the Partnership's Form S-B Registration Statement dated September 8, 2000, as amended, File No. 333-44130, and incorporated herein by reference)
31.1		Rule 13a-14(a)/15(d) – 14 (a) Certification
23.1(a)	Consent of Wright & Company, Inc.
31.2		Rule 13a-14(a)/15(d) – 14 (a) Certification.
31.1(a)	Rule 13a-14(a)/15(d) – 14 (a) Certification
32.1		Section 1350 Certification.
31.2(a)	Rule 13a-14(a)/15(d) – 14 (a) Certification
32.2		Section 1350 Certification.
32.1(b)	Section 1350 Certification
99.1		Summary Reserve Report
32.2(b)	Section 1350 Certification
101		Interactive Data File
99.1(a)	Summary Reserve Report
101(c)	Interactive Data File
(a)	Filed herewith
(b)	Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as "accompanying" this report and not "filed" as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(c)	Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

~~(1) Filed on September 8, 2000 in our Form SB-2 Registration Statement dated September 8, 2000, as amended, File No. 333-44130~~38

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	ATLAS AMERICA PUBLIC #9 LTD.	~~ATLAS AMERICA PUBLIC #9 LTD.~~
		BY: ATLAS RESOURCES, LLC, ITS GENERAL PARTNER
	BY: DGOC PARTNERSHIP HOLDINGS, LLC, (MANAGING GENERAL PARTNER)
Date: April 17, 2017		By:	/s/ FREDRICK M. STOLERU
Date: March 28, 2018	By:	/s/ ROBERT R. HUTSON, JR.
			Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)
		Robert R. Hutson, Jr., Chief Executive Officer (principal executive officer) of the Managing General Partner

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person on behalf of the registrant and in the capacities and on the dates indicated.

Date: April 17, 2017		By:	/s/ FREDRICK M. STOLERU
Date: March 28, 2018	By:	/s/ ROBERT R. HUTSON, JR.
			Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)
		Robert R. Hutson, Jr., Chief Executive Officer (principal executive officer) of the Managing General Partner

Date: April 17, 2017		By:	/s/ JEFFREY M. SLOTTERBACK
Date: March 28, 2018	By:	/s/ BRADLEY G. GRAY
			Jeffrey M. Slotterback, Chief Financial Officer (principal financial officer and principal accounting officer)
		Bradley G. Gray, Chief Operating Officer (principal financial officer) of the Managing General Partner

Date: April 17, 2017	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner, Chief Accounting Officer (principal accounting officer)
Date: April 17, 2017	By:	/s/ DANIEL C. HERZ
		Daniel C. Herz, Executive Vice President and Director
Date: April 17, 2017	By:	/s/ GARY LICHTENSTEIN
		Gary Lichtenstein, Director
Date: April 17, 2017	By:	/s/ CHRISTOPHER SHEBBY
		Christopher Shebby, Director

Filing Compare · ATLAS AMERICA PUBLIC #9 LTD.