Exhibit 99.1

Preliminary and Subject to Completion, dated July 11, 2017

INFORMATION STATEMENT

DGOC Series 28, L.P.

This information statement is being furnished in connection with the distribution by Atlas Resources Series 28-2010 L.P., or Atlas Series 28-2010, to its unitholders of 7,500 common units of DGOC Series 28, L.P., or DGOC, a subsidiary of Atlas Series 28-2010, that was formed to hold directly or indirectly the assets and liabilities associated with Atlas Series 28-2010’s natural gas wells in Pennsylvania. To implement the distribution, Atlas Series 28-2010 will distribute all of the common units of DGOC Series 28, L.P. held by Atlas Series 28-2010 on a pro rata basis to the Atlas Series 28-2010 unitholders.

For every common unit of Atlas Series 28-2010 held of record by you as of the close of business on                    , 2017, the record date for the distribution, you will receive one common unit of DGOC. We expect the DGOC common units to be distributed by Atlas Series 28-2010 to you on                    , 2017. We refer to the date of the distribution of the DGOC common units as the “distribution date.”

No vote of Atlas Series 28-2010’s unitholders is required. Therefore, you are not being asked for a proxy, and you are requested not to send us a proxy, in connection with the distribution. You do not need to pay any consideration, exchange or surrender your existing common units of Atlas Series 28-2010 or take any other action to receive your DGOC common units.

There is no current trading market for DGOC common units.

We intend that your receipt of common units be tax-free for U.S. federal income tax purposes. You should consult your own tax advisor as to the particular tax consequences of the distribution to you, including potential consequences under state, local and non-U.S. tax laws.

In reviewing this information statement, you should carefully consider the matters described under the caption “Risk Factors ” beginning on page 8.

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement does not constitute an offer to sell or the solicitation of an offer to buy any securities.

The date of this information statement is                         , 2017

This information statement was first mailed to Atlas Series 28-2010 unitholders on or about                 , 2017.

TABLE OF CONTENTS

	Page
Questions and Answers about the Separation and Distribution		1
Information Statement Summary		5
Risk Factors		8
Forward Looking Statements		18
Cash Distribution Policy		19
Capitalization		20
Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Business		29
Management		40
Executive Compensation		43
Certain Relationships and Related Transactions		44
Security Ownership of Certain Beneficial Owners and Management		45
The Separation and Distribution		46
Our Relationship with Atlas Series 28-2010 Following the Distribution		49
Description of our Common Units		52
Certain U.S. Federal Income Tax Matters		62
Where You Can Find More Information		75
Index to Financial Statements		F-1

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GLOSSARY OF TERMS

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

Bpd. Barrels per day.

Common units of DGOC. Limited Partner units of DGOC.

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 net 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.

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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:

(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.

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(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 and 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.

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.

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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.

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Trademarks, Trade Names and Service Marks

We own or have rights to use the trademarks, service marks and trade names that we use in conjunction with the operation of our business. Each trademark, trade name or service mark of any other company appearing in this information statement is, to our knowledge, owned by such other company.

Industry and Market Data

In this information statement, we rely on and refer to information and statistics regarding the natural gas and oil production and development industries. We obtained this data from independent publications or other publicly available information that we believe to be reliable.

Presentation of Information

Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement, including the financial statements of DGOC, assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Unless the context otherwise requires, references in this information statement to “DGOC,” “the Partnership,” “we,” “us,” “our” and “our company” refer to DGOC Series 28, L.P., a Delaware limited partnership. References in this information statement to “Atlas Series 28-2010” refers to Atlas Resources Series 28-2010 L.P., a Delaware limited partnership, unless the context otherwise requires.

Atlas Resources, LLC, or Atlas Resources or the MGP, currently serves as the Managing General Partner for Atlas Series 28-2010 and DGOC and DGOC Partnership Holdings II, LLC, an affiliate of Atlas Resources, or the DGOC MGP, will serve as our Managing General Partner following the separation and distribution. Atlas Resources and the DGOC MGP are each an indirect subsidiary of Titan Energy, LLC, or 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. Titan is the successor to the business and operations of Atlas Resource Partners, L.P., or ARP, a Delaware limited partnership organized in 2012. Atlas Energy Group, LLC, or Atlas Energy Group, is a publicly traded company and manages Titan, the MGP and the DGOC MGP through a 2% preferred member interest in Titan.

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QUESTIONS AND ANSWERS ABOUT THE SEPARATION AND DISTRIBUTION

What is DGOC and why is Atlas Series 28-2010 separating DGOC’s business and distributing its units?	DGOC currently is a subsidiary of Atlas Series 28-2010 that was formed to hold Atlas Series 28-2010’s natural gas wells in Pennsylvania. The separation of DGOC from Atlas Series 28-2010 and the distribution of DGOC common units are intended to provide you with equity investments in two separate companies that will collectively own the same assets currently owned by Atlas Series 28-2010. For more information, see the sections entitled “The Separation and Distribution—Background” and “The Separation and Distribution—Reasons for the Separation and Distribution.”
Is Atlas Series 28-2010 retaining any assets after completion of the distribution?	Atlas Series 28-2010 will retain its natural gas and oil wells in Indiana and Colorado.
Why am I receiving this document?	Atlas Series 28-2010 is delivering this document to you because you were a holder of common units of Atlas Series 28-2010 on                     , 2017, the record date for the distribution. Accordingly, you are entitled to receive one common unit of DGOC for each common unit of Atlas Series 28-2010 that you held at the close of business on the record date. This document will help you understand how the separation and distribution will affect your investment in Atlas Series 28-2010 and your investment in DGOC after the separation and distribution.
Will the number of common units of Atlas Series 28-2010 that I own change as a result of the distribution?	No. The number of common units of Atlas Series 28-2010 that you own will not change as a result of the distribution. After the distribution is completed, you will hold one common unit of Atlas Series 28-2010 and one common unit of DGOC for each common unit of Atlas Series 28-2010 that you currently hold.
How will the separation of DGOC be accomplished?	The separation will be accomplished through a transaction in which all of the natural gas and oil development and production assets of Atlas Series 28-2010 located in Pennsylvania will be transferred to DGOC. After such transfer, which we refer to as the “separation,” Atlas Series 28-2010 will distribute to its unitholders, on a pro rata basis, approximately 7,500 common units representing 100% of the limited partner interest in DGOC.
What is the record date for the distribution?	The record date for the distribution will be                     , 2017.
When will the distribution occur?	We expect that the distribution will occur on                     , 2017. The distribution will be made to holders of record of Atlas Series 28-2010 common units at the close of business on the record date.
What do unitholders need to do to participate in the distribution?	Holders of Atlas Series 28-2010 common units as of the record date will not be required to take any action to receive DGOC common units in the distribution, but you are urged to read this entire information statement carefully. No unitholder approval of the distribution is required or sought. You are not being asked for a proxy, and you are requested not to send us a proxy. You will not be required to make any payment, surrender or exchange of your Atlas Series 28-2010 common units or to take any other action to receive your DGOC common units.

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Will I receive physical certificates representing common units of DGOC following the distribution?	No. Following the separation and distribution, DGOC will not issue physical certificates representing common units of DGOC. If you own Atlas Series 28-2010 common units as of the close of business on the record date, Atlas Series 28-2010 will issue DGOC common units to you by way of notation in the unitholder register of DGOC. DGOC will not issue paper certificates.
How many common units of DGOC will I receive in the distribution?	Atlas Series 28-2010 will distribute to you one common unit of DGOC for each common unit of Atlas Series 28-2010 held at the close of business on the record date. Based on 7,500 common units of Atlas Series 28-2010 that are expected to be outstanding as of the record date, a total of 7,500 common units of DGOC will be distributed. For additional information on the distribution, see the section entitled “The Separation and Distribution.”
Will DGOC issue fractional units in the distribution?	Yes, DGOC will issue fractional common units in the distribution, if applicable.
What are the conditions to the distribution?	The distribution is subject to final approval by the MGP, as well as a number of additional conditions, including, among others, the SEC declaring effective the registration statement of which this information statement forms a part. We cannot assure you that any or all of these conditions will be met. For a complete discussion of all of the conditions to the distribution, see the section entitled “The Separation and Distribution—Conditions to the Distribution.”
Can Atlas Series 28-2010 decide to cancel the distribution even if all the conditions have been met?	Yes. The distribution is subject to the satisfaction or waiver of certain conditions. For more information, see the section entitled “The Separation and Distribution—Conditions to the Distribution.” Until the distribution has occurred, Atlas Series 28-2010 has the right to terminate the distribution, even if all of the conditions are satisfied, if at any time the board of directors of the MGP determines that the distribution is not in the best interests of Atlas Series 28-2010 and its unitholders.
What if I want to sell my common units of Atlas Series 28-2010 or DGOC?	There is no trading market for Atlas Series 28-2010 or DGOC common units. Transfers of Atlas Series 28-2010 or DGOC common units are also subject to the terms and conditions of the applicable partnership agreement. Neither Atlas Series 28-2010 nor DGOC makes any recommendations on the purchase, retention or sale of common units of Atlas Series 28-2010 or DGOC.
What are the material U.S. federal income tax consequences of the distribution of our common units by Atlas Series 28-2010?	In general, the distribution of common units of DGOC by Atlas Series 28-2010 to a U.S. holder (as defined in the section entitled “Certain U.S. Federal Income Tax Matters”) of common units of Atlas Series 28-2010 should not be taxable to the U.S. holder for U.S. federal income tax purposes, except to the extent that the aggregate amount of money you receive or are deemed to receive as a result of the distribution exceeds the tax basis in such holder’s interest in Atlas Series 28-2010 common units immediately before the distribution. The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S.

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	Federal Income Tax Matters.” and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.
How will I determine the initial basis that I will have in the DGOC common units I receive in the distribution?	A U.S. holder’s initial basis in the common units of DGOC received by such U.S. holder in the distribution generally will be equal to Atlas Series 28-2010’s adjusted basis in such common units immediately before the distribution for U.S. federal income tax purposes. However, such U.S. holder’s initial basis in such common units shall not exceed the adjusted basis of such U.S. holder’s interest in Atlas Series 28-2010, reduced by any money distributed in the same transaction. Atlas Series 28-2010 expects to provide unitholders with information regarding its adjusted basis for U.S. federal income tax purposes of our common units distributed in the distribution. The rules governing the determination of a unitholder’s initial basis of our common units distributed in the distribution and the other tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S. Federal Income Tax Matters” and to consult your own tax advisor regarding the determination of your initial basis in our common units distributed to you in the distribution and the other tax consequences of the distribution to you in your particular circumstances.
Does DGOC plan to pay distributions?	We will distribute those funds which our general partner determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions.
What will DGOC’s relationship be with Atlas Series 28-2010 following the separation?	DGOC will enter into a contribution agreement with Atlas Series 28-2010 to effect the separation. Separately, Atlas Series 28-2010 and the MGP will enter into a distribution agreement to effect the distribution. In connection with the completion of the separation and distribution, the MGP will transfer its limited partner and general partner interests in DGOC, or the DGOC equity interests, to the DGOC MGP. On May 4, 2017, Titan entered into a definitive purchase and sale agreement, or the purchase agreement, to sell certain of its Appalachia assets to Diversified Energy LLC, an affiliate of Diversified Gas & Oil, PLC (collectively, “Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close by September 2017 with respect to the wells owned by DGOC. The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the equity interests of the DGOC MGP, or the DGOC MGP equity interests, will be transferred to Diversified. Following the transfer of the DGOC MGP equity interests, Diversified will own the managing general partner of DGOC.

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	For more information, see the sections entitled “Management” and “Our Relationship with Atlas Series 28-2010 Following the Distribution.”
Who will manage DGOC after the separation?	The activities of DGOC are currently managed by the MGP. Following the transfer of the DGOC equity interests, the DGOC MGP will be the managing general partner of DGOC. For more information regarding management of DGOC’s general partner, see “Management.”
Are there risks to owning DGOC common units?	Yes. DGOC’s business is subject to both general and specific risks relating to its business and the separation. These risks are described in the section entitled “Risk Factors.” We encourage you to read that section carefully.
Where can I get more information about Atlas Series 28-2010 and DGOC?	If you have any questions relating to the separation, you should contact: Atlas Resources Series 28-2010 L.P. Investor Relations 425 Houston Street Suite 300 Fort Worth, TX 76102 (412) 489-0006 If you have any questions relating to DGOC common units or the distribution of our common units, you should contact: DGOC Series 28, L.P. Investor Relations 425 Houston Street Suite 300 Fort Worth, TX 76102 (412) 489-0006

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INFORMATION STATEMENT SUMMARY

The following is a summary of material information discussed in this information statement. This summary may not contain all the details concerning the separation or other information that may be important to you. To better understand the separation and DGOC’s business and financial position, you should carefully review this entire information statement. Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement, including the financial statements of DGOC, assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Unless the context otherwise requires, references in this information statement to “DGOC,” “the Partnership,” “we,” “us,” “our” and “our company” refer to DGOC Series 28, L.P., a Delaware limited partnership. References in this information statement to “Atlas Series 28-2010” refers to Atlas Resources Series 28-2010 L.P., a Delaware limited partnership, unless the context otherwise requires.

This information statement describes the assets to be transferred to us by Atlas Series 28-2010 in the separation as if the transferred assets were our business for all historical periods described. References in this information statement to our historical assets, liabilities, products, businesses or activities of our business are generally intended to refer to the historical assets, liabilities, products, businesses or activities of the transferred businesses as the businesses were conducted as part of Atlas Series 28-2010 prior to the separation.

We are a Delaware limited partnership formed on July 6, 2017 with Atlas Resources, LLC serving as our Managing General Partner. Atlas Resources, LLC is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). 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 herein, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012.

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

The Partnership currently operates wells located in Pennsylvania. We have no employees and rely on the 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. Produced natural gas 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.

Risks Associated with Our Business

An investment in our common units involves risks associated with our business. The following list of risk factors is not exhaustive. Please read carefully the risks relating to these and other matters described under “Risk Factors” and “Forward-Looking Statements.”

• Natural gas and oil prices are volatile and a substantial decrease in prices, particularly natural gas prices, would decrease our revenues, our cash distributions and the value of our properties;

• Estimates of our natural gas and oil reserves are based on many assumptions that may prove to be inaccurate;

• Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays;

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• An investment in DGOC must be for the long-term because the units are illiquid and not readily transferable;

• Our managing general partner’s management obligations to us are not exclusive;

• Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and will reduce our cash available for distribution to our unitholders;

• Current conditions may change and reduce our proved reserves, which could reduce our revenues;

• Government regulation of the oil and natural gas industry is stringent and could cause us to incur substantial unanticipated costs;

• Competition may reduce our revenues from the sale of our natural gas;

• We may have to replace our natural gas purchasers and receive a lower price for our natural gas;

• We intend to produce natural gas and/or oil from our wells until they are depleted, regardless of any changes in current conditions, which could result in lower returns to our participants;

• We could have to curtail operations or sell properties if we need additional funds and our managing general partner does not make a loan to us;

• Holders of our common units have limited voting rights and are not entitled to elect our general partner or its governing board;

• We have no operating history as a separate public reporting company;

• Changes in the law may reduce our participants’ tax benefits from an investment in us; and

• Our participants’ tax benefits from an investment in us are not contractually protected.

The Separation and Distribution

On May 15, 2017, Atlas Series 28-2010 announced that it intended to separate its Pennsylvania wells from the remainder of its businesses.

For more information, see the section entitled “The Separation and Distribution.”

Our Post-Separation Relationship with Atlas Series 28-2010

We intend to enter into a contribution agreement with Atlas Series 28-2010 to effect the separation. Separately, Atlas Series 28-2010 and the MGP will enter into a distribution agreement to effect the distribution. In connection with the completion of the separation and distribution, the MGP will transfer its limited partner and general partner interests in DGOC, or the DGOC equity interests, to the DGOC MGP.

On May 4, 2017, Titan entered into the purchase agreement to sell certain of its Appalachia assets to Diversified for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The transaction includes 12 wells owned by Atlas Series 28-2010, which will be transferred to DGOC. The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close by September 2017 with respect to the wells owned by DGOC.

The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the DGOC MGP equity interests will be transferred to Diversified. Following the transfer of the DGOC MGP equity interests, Diversified will own the managing general partner of DGOC.

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For additional information, see the sections entitled “Risk Factors—Risks Related to the Separation,” “The Separation and Distribution” and “Our Relationship with Atlas Series 28-2010 Following the Distribution.”

Reasons for the Separation

The board of directors of the MGP believes that separating Atlas Series 28-2010 into two public reporting companies is in the best interests of Atlas Series 28-2010 and its unitholders and has concluded that the separation and distribution will provide each company with certain opportunities and benefits, including facilitating the sale of the DGOC MGP equity interests to Diversified. For more information, see the section entitled “The Separation and Distribution.”

Corporate Information

DGOC was formed in Delaware on July 6, 2017 for the purpose of holding Atlas Series 28-2010’s Pennsylvania wells in connection with the separation and distribution described herein. Prior to the contribution of these assets, we had no operations. The address of DGOC’s principal executive offices is 425 Houston Street, Suite 300, Fort Worth, TX 76102. DGOC’s telephone number is (412) 489-0006.

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RISK FACTORS

You should carefully consider the following risks and other information in this information statement in evaluating us and our common units. Any of the following risks, as well as additional risks and uncertainties not currently known to us or that we currently deem immaterial, could materially and adversely affect our results of operations or financial condition.

Risks Relating to Our Business

Natural gas and oil prices are volatile and a substantial decrease in prices, particularly natural gas prices, would decrease our revenues, our cash distributions and the value of our properties and could reduce our managing general partner’s ability to loan us funds; meet its ongoing indemnification obligations and purchase units under our presentment feature.

A substantial decrease in natural gas and oil prices, particularly natural gas prices, would decrease our revenues and the value of our natural gas and oil properties. Our future financial condition and results of operations, and the value of our natural gas and oil properties, will depend on market prices for natural gas and, to a much lesser extent, oil. Also, our participants’ return level will decrease during our term, even if there are rising natural gas prices, because of reduced production volumes from our wells.

Prices for natural gas and oil are dictated by supply and demand factors and prices may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, and market uncertainty. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices. Other factors affecting the price and/or marketing of natural gas and oil production, which are beyond our control and cannot be accurately predicted, are the following:

• the cost, proximity, availability, and capacity of pipelines and other transportation facilities;

• the price and availability of other energy sources such as coal, nuclear energy, solar and wind;

• the price and availability of alternative fuels, including when large consumers of natural gas are able to convert to alternative fuel use systems;

• local, state, and federal regulations regarding production, conservation, water disposal, and transportation;

• overall domestic and global economic conditions;

• the impact of the U.S. dollar exchange rates on natural gas and oil prices;

• technological advances affecting energy consumption;

• domestic and foreign governmental relations, regulations and taxation;

• the impact of energy conservation efforts;

• the general level of supply and market demand for natural gas and oil on a regional, national and worldwide basis;

• weather conditions and fluctuating seasonal supply and demand for natural gas and oil because of various factors such as home heating requirements in the winter months;

• economic and political instability, including war or terrorist acts in natural gas and oil producing countries, including those of the Middle East, Africa and South America;

• the amount of domestic production of natural gas and oil; and

• the amount and price of imports of natural gas and oil from foreign sources, including the actions of the members of the Organization of Petroleum Exporting Countries (“OPEC”), which include production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels.

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These factors make it extremely difficult to predict natural gas and oil price movements with any certainty.

Estimates of our natural gas and oil reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate as discussed in “Business—Properties.” Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, will likely result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical prices and costs. However, the actual future net cash flows we derive from such properties also will be affected by factors such as:

• actual prices we receive for natural gas;

• the amount and timing of actual production;

• the amount and timing of our capital expenditures;

• supply of and demand for natural gas; and

• changes in governmental regulations or taxation.

The timing of both our production and incurrence of expenses in connection with the production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of our reserves, the amount of present value of future net revenues, or PV-10, and standardized measure, and our financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Bills have been introduced in Congress since 2009 that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information

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regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, Pennsylvania has adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring some degree of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations.

Risks Related to an Investment in DGOC

We may not have sufficient available cash to pay distributions and there is no guaranty that we will pay distributions to our unitholders in any quarter.

We may not have sufficient available cash to pay any distributions. Furthermore our Partnership Agreement does not require us to pay distributions. The amount of cash we have to distribute each quarter principally depends on the revenue we receive for our natural gas, oil and natural gas liquids. In addition, the actual amount of cash we will have available to distribute each quarter will be reduced by working capital and operating expenses that the governing board of our general partner may determine is appropriate. The governing board of our general partner may change our cash distribution policy at any time without the approval of the unitholders.

An investment in DGOC must be for the long-term because the units are illiquid and not readily transferable.

If you invest in us, then you must assume the risks of an illiquid investment. The transferability of the common units is limited by the securities laws, the tax laws, and the partnership agreement. The common units generally cannot be liquidated since there is no readily available market for the sale of the common units. Further, we do not intend to list our common units on any exchange.

Also, a sale of your common units could create adverse tax and economic consequences for you. The sale or exchange of all or part of your common units held for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your common units. Also, your pro rata share of our liabilities, if any, as of the date of the sale or exchange of your common units must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability greater than the cash proceeds, if any, received by you from the sale or other disposition of your common units, if permitted under the partnership agreement.

Our managing general partner’s management obligations to us are not exclusive, and if it does not devote the necessary time to our management there could be delays in providing timely reports and distributions to our participants, and our managing general partner, serving as operator of our wells, may not supervise the wells closely enough.

We do not have any officers, directors or employees. Instead, we rely totally on our managing general partner and its affiliates for our management. Our managing general partner is required to devote to us the time and attention that it considers necessary for the proper management of our activities. However, our managing general partner and its affiliates currently are, and will continue to be, engaged in other natural gas and oil activities, including other partnerships and unrelated business ventures for their own account or for the account of others,

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during our term. This creates a continuing conflict of interest in allocating management time, services, and other activities among us and its other activities. If our managing general partner does not devote the necessary time to our management, there could be delays in providing timely annual and semi-annual reports, tax information and cash distributions to our participants. Also, if our managing general partner, serving as the operator of our wells, does not supervise the wells closely enough, for example, there could be delays in undertaking remedial operations on a well, if necessary to increase the production of natural gas from the well.

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and will reduce our cash available for distribution to our unitholders.

Pursuant to our partnership agreement, our general partner will receive reimbursement for the provision of various general and administrative services for our benefit. Payments for these services will be substantial, are not subject to any aggregate limit, and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Current conditions may change and reduce our proved reserves, which could reduce our revenues.

Distributions to our partners are derived from the production of natural gas and oil from our productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. Our proved reserves will decline as they are produced from our wells and our distributions to our participants generally will decrease each year until our wells are depleted.

Our proved reserves at December 31, 2016 are set forth in “Business—Properties.” However, there is an element of uncertainty in all estimates of proved reserves, and current conditions, such as natural gas and oil prices and the costs of operating our wells and transporting our natural gas, will change in the future and could reduce the amount of our current proved reserves.

We base our estimates of proved natural gas and oil reserves and future net revenues from those reserves on various assumptions, including those required by the SEC, such as natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in the future in these assumptions based on actual production, natural gas and oil prices, taxes, development expenses, operating expenses, or availability of funds, would materially affect the estimated quantity of our reserves as discussed in “Business—Properties.”

Our properties also may be susceptible to hydrocarbon drainage from wells on adjacent properties in which we do not have an interest. In addition, our proved reserves may be revised downward in the future based on the following:

• the actual production history of our wells;

• results of future exploration and development in the area;

• decreases in natural gas and oil prices;

• governmental regulation; and

• other changes in current conditions, many of which are beyond our control.

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Government regulation of the oil and natural gas industry is stringent and could cause us to incur substantial unanticipated costs for regulatory compliance, environmental remediation of our well sites (which may not be fully insured) and penalties.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Production and sales of natural gas and oil are subject to extensive federal, state and local regulations. We discuss our regulatory environment in more detail in “Business—Environmental Matters and Regulation.” We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Also, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income.

In addition, our operations may cause us to incur substantial liabilities to comply with environmental laws and regulations. Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

• restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and

• impose substantial liabilities for pollution resulting from our operations.

These laws include, for example:

• the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

• the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including waste water produced from our wells; and

• the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances produced from our wells.

Failure to comply with these laws and regulations may result in the following:

• assessment of administrative, civil, and criminal penalties;

• incurrence of investigatory or remedial obligations; or

• imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transporting, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance or could restrict our methods or times of operation. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. Pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could reduce our revenues and the value of our assets.

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Our natural gas and oil activities are subject to operating hazards which could result in substantial losses to us.

Well blowouts, cratering, explosions, uncontrollable flows of natural gas, oil or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks are inherent operating hazards for us. The occurrence of any of those hazards could result in substantial losses to us, including liabilities to third-parties or governmental entities for damages resulting from the occurrence of any of those hazards and substantial investigation, litigation and remediation costs.

Our limited operating history creates greater uncertainty regarding our ability to operate profitably.

Our limited history of operating our wells may not indicate the results that we may achieve in the future. Our success depends on generating sufficient revenues by producing sufficient quantities of natural gas and oil from our wells and then marketing that natural gas and oil at sufficient prices to pay the operating costs of our wells and our administrative costs of conducting business as a partnership, and still provide a reasonable rate of return on our participants’ investment in us. If we are unable to pay our costs, then we may need to:

• borrow funds from our managing general partner, which is not contractually obligated to make any loans to us;

• shut-in or curtail production from some of our wells; or

• attempt to sell some of our wells, which we may not be able to do on terms that are acceptable to us.

Also, the events set forth below could decrease our revenues from our wells and/or increase our expenses of operating our wells:

• decreases in the price of natural gas and oil, which are volatile;

• changes in the oil and gas industry, including changes in environmental regulations, which could increase our costs of operating our wells in compliance with any new environmental regulations;

• an increase in third-party costs for equipment or services, or an increase in gathering and compression fees for transporting our natural gas production; and

• problems with one or more of our wells, which could require repairing or performing other remedial work on a well or providing additional equipment for the well.

Competition may reduce our revenues from the sale of our natural gas.

Competition arises from numerous domestic and foreign sources of natural gas and oil, including other natural gas producers and marketers in the Appalachian Basin as well as competition from other industries that supply alternative sources of energy. Competition will make it more difficult to market our natural gas. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial or other resources than we do, which may enable them to offer their natural gas to natural gas purchasers on terms, such as lower prices or a greater volume of natural gas that can be delivered to the purchaser that we cannot match. Also, other energy sources such as coal may be available to the purchasers at a lower price. As a result, we may have to seek other natural gas purchasers and we may receive lower prices for our natural gas and incur higher transportation and compression fees if we sell our natural gas to these other natural gas purchasers. In this event, our revenues from the sale of our natural gas would be reduced.

We may have to replace our natural gas purchasers and receive a lower price for our natural gas.

We will depend on a limited number of natural gas purchasers to purchase the majority of our natural gas production. Further, we will not be guaranteed a specific natural gas price, unless we engage in hedging in the future. Thus, if our current purchasers were to pay a lower price for our natural gas in the future, our revenues

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would decrease. Also, if our current purchasers began buying a reduced percentage of our natural gas, or stopped buying any of our natural gas, the sale of our natural gas would be delayed until we found other purchasers, and the substitute purchasers we found may pay lower prices for our natural gas, which would reduce our revenues.

We could incur delays in receiving payment, or substantial losses if payment is not made, for natural gas we previously delivered to a purchaser, which could delay or reduce our revenues and cash distributions.

There is a credit risk associated with a natural gas purchaser’s ability to pay. We may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In this event, our revenues and cash distributions to our participants also would be delayed or reduced. In accordance with industry practice, we typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before we receive payment. Thus, it is possible that we may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of our natural gas.

We intend to produce natural gas and/or oil from our wells until they are depleted, regardless of any changes in current conditions, which could result in lower returns to our participants as compared with other types of investments which can adapt to future changes affecting their portfolios.

Our natural gas and oil properties are relatively illiquid because there is no public market for working interests in natural gas and oil wells. In addition, one of our investment objectives is to continue to produce natural gas and oil from our wells until the wells are depleted. Thus, unlike mutual funds, for example, which can vary their portfolios in response to changes in future conditions, we do not intend, and in all likelihood we would be unable, to vary our portfolio of wells in response to future changes in economic and other conditions such as decreases or increases in natural gas or oil prices, or increased operating costs of our wells.

Since our managing general partner is not contractually obligated to loan funds to us, we could have to curtail operations or sell properties if we need additional funds and our managing general partner does not make a loan to us.

Our revenues from the sale of our natural gas and oil production may be insufficient to pay all of our ongoing expenses, such as our operating and maintenance costs for our productive wells or our costs associated with repairing or performing other remedial work on a well. If this were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, although they are not contractually committed to make a loan. Also, under our partnership agreement the amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings are permitted from third-parties. If, for any reason, our managing general partner did not loan us the funds needed to repair or perform other remedial work on a well, then we might have to curtail operations on the well or attempt to sell the well, although we may not be able to do so on terms that are acceptable to us.

A decrease in natural gas prices could subject our and our managing general partner’s oil and gas properties to an impairment loss under generally accepted accounting principles.

Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and our managing general partner will test our respective oil and gas properties on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated

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based on our or our managing general partner’s own economic interests and our respective plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and our managing general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, declines in the price of natural gas have caused the carrying values of properties in many of our managing general partner’s previous partnerships to exceed the expected future cash flow. Future declines in the price of natural gas may cause the carrying value of our, our managing general partner’s or its other partnerships’ oil and gas properties to exceed the expected future cash flows, and require an impairment loss to be recognized.

Unitholders may have limited liquidity for their common units, and a trading market may not develop for the common units.

There has been no public market for our common units prior to the distribution. After the distribution, there will be approximately 7,500 common units outstanding. It is unlikely that investor interest will lead to the development of a trading market, and any such market would likely be illiquid. You may not be able to resell your common units at a price you find attractive, or at all. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the units.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its governing board.

Unlike the holders of common stock in a corporation, our common unitholders will have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders will not elect our general partner or the members of its governing board, and will have no right to elect our general partner or its governing board on an annual or other continuing basis. Following the transfer of the DGOC MGP equity interests to Diversified, the governing board of our general partner will be chosen by Diversified Energy LLC. Furthermore, the vote of the holders of at least a majority of all outstanding common units is required to remove our general partner. As a result of these limitations on the ability of holders of our common units to influence the management of the company, the price at which the common units will trade could be diminished.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if, among other potential reasons:

• a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them, or other liabilities with respect to ownership of our units.

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Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17–607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

Atlas Energy Group is free to sell our general partner to a third party.

On May 4, 2017, Titan entered into the purchase agreement pursuant to which Diversified will acquire the DGOC MGP equity interests. For more information, see “The Separation and Distribution.”

Our partnership agreement does not restrict Atlas Energy from transferring all or a portion of its ownership interest in our general partner to a third party. As a result, Diversified will be in a position to replace the governing board and officers of our general partner with its own choices and thereby influence the decisions taken by the governing board and officers. The sale of the DGOC MGP equity interests to Diversified does not include a requirement for a concurrent offer to be made to acquire all of the common units, which will prevent you from realizing any change-of-control premium on your common units in connection with the proposed sale.

Risks Relating to the Separation

We have no operating history as a separate public reporting company.

The historical financial information included in this information statement does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate public reporting company or as the owner or operator of our assets during the periods presented or those that we will achieve in the future.

Estimates of the reserves we received from Atlas Series 28-2010 in connection with the separation are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our current estimates of our proved reserves were prepared by Atlas Series 28-2010’s independent petroleum engineers. Over time, Atlas Series 28-2010’s or our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of Atlas Series 28-2010’s reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, they make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

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Federal Income Tax Risks.

Changes in the law may reduce our participants’ tax benefits from an investment in us.

Our participants’ tax benefits from their investment in us may be affected by changes in the tax laws. For more information, see “Certain U.S. Federal Income Tax Matters.”

Our participants may owe taxes in excess of their cash distributions from us.

Our participants may become subject to income tax liability for their respective shares of our income in any taxable year in an amount that is greater than the cash they receive from us in that taxable year. For example:

• if we borrow money, our participants’ share of our revenues used to pay principal on the loan will be included in their share of our income and will not be deductible;

• income from sales of natural gas and oil may be included in our participants’ income from us in one tax year, even though payment is not actually received by us and, thus, cannot be distributed to our participants until the next tax year;

• if there is a deficit in a participant’s capital account, we may allocate income or gain to the participant even though the participant does not receive a corresponding distribution of our revenues;

• our revenues may be expended by our managing general partner for nondeductible costs or retained in us to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning our wells, which will reduce our participants’ cash distributions from us without a corresponding tax deduction; and

• the taxable disposition of our property or our participants’ Units may result in income tax liability to our participants in excess of the cash they receive from the transaction.

Our participants’ tax benefits from an investment in us are not contractually protected.

An investment in us does not give our participants any contractual protection against the possibility that part or all of the intended tax benefits of their investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of our participants’ investment in us. Our participants have no right to rescind their investment in us or to receive a refund of any of their investment in us if a portion or all of the intended tax consequences of their investment in us is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by us to our managing general partner, its affiliates or independent third-parties (including special counsel which issued the tax opinion letter) are refundable or contingent on whether the intended tax consequences of their investment in us are ultimately sustained if challenged by the IRS.

An IRS audit of us may result in an IRS audit of the personal federal income tax returns of our participants.

The IRS may audit our annual federal information income tax returns. If we are audited, the IRS also may audit the personal federal income tax returns of a portion or all of our participants, including prior years’ returns and items that are unrelated to us.

Our deductions may be challenged by the IRS.

If the IRS audits us, it may challenge the amount of our deductions and the taxable year in which the deductions were claimed, including the deductions for depreciation. Any adjustments made by the IRS to our federal information income tax returns could lead to adjustments on the personal federal income tax returns of our participants and could reduce the amount of their deductions from us.

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FORWARD LOOKING STATEMENTS

The matters discussed within this information statement include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this information statement are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates, and projections. While we believe these expectations, assumptions, estimates, and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. 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.

Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this information statement are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments, except as may be required by law.

Should one or more of the risks or uncertainties described in this information statement 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 information statement 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.

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CASH DISTRIBUTION POLICY

The MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which the MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions.

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CAPITALIZATION

The following table presents our capitalization as of March 31, 2017 (i) on an actual historical basis for Atlas Series 28-2010 and (ii) on an as adjusted basis to give effect to the separation. You should read the information below in connection with our financial statements and related notes and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this information statement.

	As of March 31, 2017
	Actual		As Adjusted
Cash and cash equivalents	$	395,700	$	313,600
Total debt, including current portion		—		—
Partners’ capital:
Managing general partner’s interest	$	3,854,800	$	2,949,600
Limited partners’ interest	$	18,125,000	$	16,177,600
Total partners’ capital	$	21,979,800	$	19,127,200
Total capitalization	$	21,979,800	$	19,127,200

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The historical financial statements included in this information statement reflect the assets, liabilities and operations of Atlas Series 28-2010 to be contributed to us pursuant to the separation. We refer to these assets, liabilities and operations as our predecessor. The discussion and analysis presented below refer to and should be read in conjunction with the audited financial statements and related notes and the unaudited interim condensed financial statements and related notes, each included elsewhere in this information statement. The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. The words “believe,” “expect,” “anticipate,” “project,” and similar expressions, among others, generally identify “forward-looking statements,” which speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this information statement, particularly in “Risk Factors” and “Forward-Looking Statements.” We believe the assumptions underlying the financial statements are reasonable. However, our predecessor’s financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what they would have been had our predecessor been a separate, stand-alone company during the periods presented.

As explained above, except as otherwise indicated or unless the context otherwise requires, the information included in this discussion and analysis assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Unless the context otherwise requires, references in this information statement to “DGOC,” “we,” “us,” “our,” “the Partnership” and “our company” refer to DGOC Series 28, L.P., a Delaware limited partnership. References in this information statement to “Atlas Series 28-2010” refers to Atlas Resources Series 28-2010 L.P., a Delaware limited partnership, unless the context otherwise requires.

Separation from Atlas Resources Series 28-2010 L.P.

On May 15, 2017, Atlas Series 28-2010 announced that it intended to separate its Pennsylvania wells from the remainder of its businesses. DGOC was formed in Delaware on July 6, 2017 for the purpose of holding such businesses and is currently a subsidiary of Atlas Series 28-2010.

For a complete discussion of all of the conditions to the distribution, see “The Separation and Distribution—Conditions to the Distribution.”

Business Overview

We are a Delaware limited partnership formed on July 6, 2017, with Atlas Resources, LLC serving as our Managing General Partner. Atlas Resources, LLC is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). 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.

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

On May 4, 2017, Titan entered into the purchase agreement to sell certain of its Appalachia assets to Diversified for $84.2 million (the “Asset Sale”). The Asset Sale includes approximately 8,400 oil and gas wells across

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Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The Asset Sale is subject to customary closing conditions, and has an effective date of April 1, 2017. On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the DGOC MGP equity interests will be transferred to Diversified. Following the transfer of the DGOC MGP equity interests, Diversified will own the managing general partner of DGOC.

The Partnership currently operates wells located in Pennsylvania. We currently have no employees and rely on the 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. Produced natural gas 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.

The prices at which the Partnership’s natural gas will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas that the Partnership can produce economically.

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

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. Historically, there has been no need to borrow funds from its general partner to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low through early 2017. 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 and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership intends. 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. 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.

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

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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 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.

General Trends and Outlook

We expect our business to be affected by key trends in natural gas 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 commodity price markets have suffered significant declines during the fourth quarter of 2014 and continued to remain low through early 2017. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas 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 reserves.

Our future gas 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 prices. As initial reservoir pressures are depleted natural gas production from particular wells decreases.

Results of Operations

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which primarily produce natural gas. Our produced natural gas 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 production. We paid the MGP, as operator, a monthly well supervision fee, which covered all normal and regularly recurring operating expenses for the production and sale of natural gas such as:

• Well tending, routine 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, did not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses were incurred, we were charged the costs for third-party services, materials, and a competitive charge for service performed directly by the MGP or its affiliates. Also, beginning one year after each of our wells was placed into production, the MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of March 31, 2017, the MGP withheld $27,200 of net production revenue for this purpose.

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Year Ended December 31, 2016 as compared to Year Ended December 31, 2015

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

	Years Ended December 31,
	2016			2015
Production revenues (in thousands):
Gas	$	2,644		$	3,471
Production volumes:
Gas (mcf/day)		5,156			6,538
Average sales price:
Gas (per Mcf)	$	1.40		$	1.45
Production costs:
As a percent of revenues		32	%		32	%
Per mcfe	$	0.44		$	0.46
Depletion per mcfe	$	0.70		$	0.68

Natural Gas Revenues. Our natural gas revenues were $2,643,700 and $3,471,400 for the years ended December 31, 2016 and 2015, respectively, a decrease of $827,700 (24%). The $827,700 decrease in natural gas revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $726,000 decrease in production volumes and a $101,700 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 5,156 mcf per day for the year ended December 31, 2016 from 6,538 mcf per day for the year ended December 31, 2015, a decrease of 1,382 (21%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements. 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 volume was mostly due to the normal decline inherent in the life of the wells.

Gain on Mark-to-Market Derivatives. We do not apply hedge accounting for our qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain on mark-to-market derivatives on our statements of operations.

We recognized a loss on mark-to-market derivatives of $20,100 for the year ended December 31, 2016. This loss was due primarily to mark-to-market losses in the current year primarily related to the change in natural gas prices during the year. We recognized a gain on mark-to-market derivatives of $357,900 for the year ended December 31, 2015.

Costs and Expenses. Production expenses were $837,700 and $1,100,000 for the years ended December 31, 2016 and 2015, respectively, a decrease of $262,300 (24%). This decrease was primarily due a decrease in transportation and compression costs due to the decline in production volumes.

Depletion of our gas properties as a percentage of gas revenues was 50% and 47% for the years ended December 31, 2016 and 2015, respectively. This change was primarily attributable to changes in gas reserve quantities and to a lesser extent, revenues, product prices and production volumes and changes in the depletable cost basis of gas.

General and administrative expenses were $42,800 and $54,100 for the years ended December 31, 2016 and 2015, respectively, a decrease of $11,300 (21%). These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP and vary from period to period due to the costs and services provided to us.

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Cash Flows Overview

Cash provided by operating activities decreased $1,294,700 for the year ended December 31, 2016 to $2,491,000 as compared to $3,785,700 for the year ended December 31, 2015. This decrease was due to a decrease in the change in accounts receivable trade-affiliate of $470,100 and a decrease in net earnings before depletion, impairment, and accretion of $932,100. This decrease was partially offset by an increase in the non-cash loss on derivative value of $99,700, an increase in the change in asset retirement receivable-affiliate of $800, and an increase in the change in accrued liabilities of $7,000 for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

There was no cash provided by investing activities during the years ended December 31, 2016 and 2015.

Cash used in financing activities decreased $1,103,500 to $2,510,200 for the year ended December 31, 2016 from $3,613,700 for the year ended December 31, 2015. This decrease was due to a decrease in cash distributions to partners.

The MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2016, the MGP withheld $24,800 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from the 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.

Three Months Ended March 31, 2017 as compared to Three Months Ended March 31, 2016

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

	Three Months Ended March 31,
	2017			2016
Production revenues (in thousands):
Gas	$	1,194		$	561
Production volumes:
Gas (mcf/day)		4,565			5,332
Average sales price:
Gas (per Mcf)	$	2.91		$	1.17
Production costs:
As a percent of revenues		24	%		36	%
Per mcfe	$	0.70		$	0.43
Depletion per mcfe	$	0.76		$	0.69

Natural Gas Revenues. Our natural gas revenues were $1,194,500 and $561,200 for the three months ended March 31, 2017 and 2016, respectively, an increase of $633,300 (113%). The $633,300 increase in natural gas revenues for the three months ended March 31, 2017 as compared to the prior year similar period was attributable to a $888,900 increase in our natural gas sales prices which were driven by market conditions, partially offset by a $255,600 decrease in production volumes. Our production volumes decreased to 4,565 mcf per day for the three months ended March 31, 2017 from 5,332 mcf per day for the three months ended March 31, 2016, a decrease of 767 mcf per day (14%). The overall decrease in natural gas production volumes for the three months ended March 31, 2017 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well.

Gain on Mark-to-Market Derivatives. We recognized changes in fair value of our derivatives immediately within gain on mark-to-market derivatives on our condensed statements of operations. As of March 31, 2017, all derivative contracts have matured and we have not entered into any new contracts.

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We recognized a gain on mark-to-market derivatives of $61,300 for the three months ended March 31, 2016. These gains were due to mark-to-market gains primarily related to the change in natural gas prices during the period.

Costs and Expenses. Production expenses were $288,300 and $204,400 for the three months ended March 31, 2017 and 2016, respectively, an increase of $83,900 (41%). The increase was mostly attributable to an increase in transportation expense as a result of higher natural gas revenue prices which led to an increase in natural gas revenues.

Depletion of gas and oil properties as a percentage of gas and oil revenues was 26% and 59% for the three months ended March 31, 2017 and 2016, 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.

General and administrative expenses for the three months ended March 31, 2017 and 2016 were $13,800 and $13,700, respectively, an increase of $100 (1%). These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP and vary from period to period due to the costs charged to us and services provided to us.

Cash Flows Overview

Cash flows from operating activities consists of $547,200 net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production, lease operating expenses, gathering, processing and transportation expenses, severance taxes, general and administrative expenses.

There was no cash provided by investing activities for the three months ended March 31, 2017 and 2016.

Cash used in financing activities decreased $153,100 during the three months ended March 31, 2017 to $386,400 from $539,500 for the three months ended March 31, 2016. This decrease was due to a decrease in cash distributions to partners.

The MGP may withhold funds for future plugging and abandonment costs. Through March 31, 2017, the MGP has withheld $27,200 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from the 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 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 included elsewhere in this information statement. The critical accounting policies and estimates we have identified are discussed below.

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Depletion and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of natural gas properties, less estimated salvage value, is generally depleted on the units-of-production method.

Natural gas 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 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 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 no impairment within natural gas properties.

Reserve Estimates

Our estimates of proved natural gas 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 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., an independent third-party reserve engineer, to prepare a report of our proved reserves. See “Business—Properties”.

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 reserves are inherently imprecise. Actual future production, natural gas, prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas 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 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 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 reserves volumes and values due to the 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 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. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas equivalent reserves due

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to anticipated future changes in gas 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 gas wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

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 the 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 properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.

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BUSINESS

General

We are a Delaware limited partnership formed on July 6, 2017 with Atlas Resources, LLC serving as our Managing General Partner. Atlas Resources, LLC is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). 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 herein, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012.

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

On May 4, 2017, Titan entered into the purchase agreement to sell certain of its Appalachia assets to Diversified for $84.2 million (the “Asset Sale”). The Asset Sale includes approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The Asset Sale is subject to customary closing conditions and has an effective date of April 1, 2017. On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the DGOC MGP equity interests will be transferred to Diversified. Following the transfer of the DGOC MGP equity interests, Diversified will own the managing general partner of DGOC. For more information, see “Our Relationship with Atlas Series 28-2010 Following the Distribution.”

The Partnership currently operates wells located in Pennsylvania. We currently have no employees and rely on the 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. Produced natural gas 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.

The prices at which the Partnership’s natural gas will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas that the Partnership can produce economically.

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The following description of our business reflects the operations of our business under the direction of the MGP prior to the separation and distribution. We expect the DGOC MGP to operate our business in substantially the same manner.

Gas Production

Production Volumes

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

	Years Ended December 31,
Production (1)	2016		2015
Natural gas (Mcf)		1,887,276		2,386,357

(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 marketed the majority of our natural gas production to gas marketers directly, or to third party plant operators who processed and marketed 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 NYMEX and TETCO-M2.

Our production revenues and estimated gas 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 production for the periods indicated along with our average production costs in each of the reported periods:

	Years Ended December 31,
Production revenues (in thousands)	2016		2015
Natural gas revenue	$	2,644	$	3,471
Average sales price:
Natural gas (per Mcf)	$	1.40	$	1.45
Production costs (per Mcfe)	$	0.44	$	0.46

Our ongoing operating and maintenance costs were fulfilled through revenues from the sale of our natural gas production. We were charged by the MGP a monthly well supervision fee of $975 per well per month for our Marcellus Shale wells as outlined in our drilling and operating agreement. This well supervision fee covered all normal and regularly recurring operating expenses for the production and sale of natural gas 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, did not include costs and expenses related to the purchase of certain equipment and materials and brine disposal. If these expenses were incurred, we were charged the costs for third-party services, materials and a competitive charge for services performed directly by the MGP or its affiliates. Also, beginning one year after each of our wells was placed into production, the 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, the MGP withheld $24,800 of net production revenue for this purpose.

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Drilling Activity

We received total cash subscriptions from investors of $77,203,000, which were paid to the MGP acting as operator and general drilling contractor under our drilling and operating agreement. The MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $20,618,800. We have drilled 12 development wells within the Marcellus Shale geological formations in Pennsylvania. We intend to produce these 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 we expect that no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by us:

	Gross		Net
Gas wells drilled		12.00		12.00
Dry hole		—		—
Total wells drilled		12.00		12.00

Natural Gas Leases

The MGP contributed all the undeveloped leases or lease interests necessary to drill each of our wells. The MGP 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 had reason to believe that cost was materially more than the fair market value.

Contractual Revenue Arrangements

The MGP marketed the majority of our natural gas production to gas purchasers directly or to third party midstream companies who gather, treat and process, as necessary, and market the gas. The sales price of natural gas produced is a function of the market in the area and typically linked to a regional index. The pricing indices for our production area are as follows:

• Appalachian Basin – NYMEX and TETCO-M2.

We attempt to 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.

For the year ended December 31, 2016, Hess Energy Marketing, LLC and Chevron Natural accounted for approximately 56% and 44%, respectively, of the total natural gas production revenues from our wells, with no other single customer accounting for more than 10% of revenues for this period.

Natural Gas Gathering Agreements

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

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 greater of $0.35 per mcf or 16% of the gross sales price of the natural gas is charged by Laurel Mountain for the majority of the gas. A lesser fee does apply to a small number of specific wells in the area.

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Competition

We operate in a highly competitive environment for contracting for drilling equipment and securing trained personnel. Competition also arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas. Many 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.

Markets

The availability of a ready market for natural gas and the price obtained depends upon numerous factors beyond our control. Product availability and price are the principal means of competition in selling natural gas. During the years ended December 31, 2016 and 2015, we did not experience problems in selling the natural gas produced by our wells although prices varied significantly during those periods.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas. 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 and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

• restricting the way waste disposal is handled;

• limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or public resources, such as areas inhabited by threatened or endangered species;

• requiring the acquisition of various permits before the commencement of site construction and drilling;

• requiring the installation of expensive pollution control equipment and water treatment facilities;

• restricting the types, quantities and concentration of various substances that can be released into the environment in connection with siting, drilling, completion, production, and plugging activities;

• requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

• enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;

• imposing substantial liabilities for pollution resulting from operations; and

• 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.

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Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury, nuisance, or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The legal burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

We believe that our operations 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 business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that 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 future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure future events, 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.

Environmental laws and regulations that could have a material impact on our operations include the following:

Hydraulic Fracturing. In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased. Regulation of the practice remains largely the province of state governments. Common elements of state regulations governing hydraulic fracturing may include, but not be limited to, the following: requirement that logs and pressure test results are included in disclosures to state authorities; disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations; specific disposal regimens for hydraulic fracturing fluids; replacement/remediation of contaminated water supplies; and minimum depth of hydraulic fracturing. In December 2016, EPA released the final report of its study of the impacts of hydraulic fracturing on drinking water in the U.S. finding that the hydraulic fracturing water cycle can impact drinking water resources under some circumstances, including but not limited to conditions where: there are water withdrawals for hydraulic fracturing in times or areas of low water availability; hydraulic fracturing fluids and chemicals or produced water are spilled; hydraulic fracturing fluids are injected into wells with inadequate mechanical integrity; or hydraulic fracturing wastewater is stored or disposed in unlined pits. If new federal regulations were adopted as a result of these findings, they could increase our cost to operate.

Oil Spills. 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 a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been, and continue to be, in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations impose a number of different types of requirements on our operations. First, these laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in

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accordance with the terms of a permit issued by the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. On June 28, 2016, EPA finalized Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Category (40 CFR 435), effectively prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and natural gas operations. Second, the Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The precise definition of “waters of the United States” subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to on-going litigation. A broader definition could result in more water and wetlands being subject to protection creating the possibility of additional permitting requirements for some of our existing or future facilities. Third, the Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean 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, recordkeeping and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs 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 costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations. While we will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to 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 companies.

Greenhouse Gas Regulation and Climate Change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. Under the past eight years during the Obama Administration several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple prominent Supreme Court decisions upheld those regulations. As President Trump pledged, during the election campaign, to suspend or reverse many if not all of the Obama Administration’s initiatives to reduce the nation’s emissions of greenhouse gases, it is difficult to predict how federal policy will unfold over the coming years. Some of the Obama Administration initiatives appear unyielding. It would be a significant departure from the principle of stare decisis for the Supreme Court to reverse its decision in Massachusetts v. EPA, 549 U.S. 497 (2007) holding that greenhouse gases are “air pollutants” covered by the Clean Air Act. Similarly, reversing EPA’s final determination that greenhouse gases “endangered” public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009), would seem to require development of new scientific evidence that runs counter to general discoveries since that determination. President Trump’s expressed disagreement with the Obama Administration’s climate change policy, however, casts a question over a whole series of other EPA rules, such as: (1) the New Source Performance Standards rulemaking from June 2016 that resulted in a new rule, NSPS Part 60, Subpart OOOOa, which broadly impacts oil and gas operations across the country, 81 Fed. Reg. 35824 (June 3, 2016); and (2) the Reporting of Greenhouse Gases rule specifically addressing the natural gas industry, 81 Fed. Reg. 86490 (November 30, 2016).

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Waste Handling. The Solid Waste Disposal Act, including RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. With authority granted by federal EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their 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 that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” EPA’s oversight of oil and natural gas wastes was recently challenged in federal court, and the court approved a consent decree in December 2016 where EPA agreed to evaluate and, if necessary, propose rulemaking to revise the current regulations by March 15, 2019. The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA or comparable state law requirements. We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations. More stringent regulation of natural gas and oil exploration and production wastes could increase the costs to manage and dispose of such wastes.

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, companies that disposed or arranged for the disposal of the hazardous substance at the site, and companies who transported hazardous substances to the selected 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 of 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.

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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. The various states regulate the exploration, development, 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 2016, 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, contingent on continued production of the well, the fee can 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.

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 legal 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.

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Properties

The following tables summarize information regarding our estimated proved natural gas reserves. Proved reserves are the estimated quantities of 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., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. All of the reserves are located in the United States. We base these estimated proved natural gas reserves and future net revenues of natural gas reserves upon reports prepared by Wright & Company, Inc., an independent third-party reserve engineer. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2016 and 2015 is included as Exhibit 99.2 and Exhibit 99.3, respectively, to our Form 10 registration statement, of which this information statement forms a part. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas 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

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas 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 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 reserve estimates was completed in accordance with the 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 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. The 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 the 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 the MGP’s senior engineering staff and management, with final approval by the 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 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 properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas 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-

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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. We base the estimates on operating methods and conditions prevailing as of the dates indicated:

	Proved Reserves at December 31,
	2016		2015
Proved developed reserves (3):
Natural gas reserves (Mcf)		25,989,540		30,206,100
Total proved developed reserves (Mcfe)		25,989,540		30,206,100
Standardized measure of discounted future cash flows (1)	$	7,504,638	$	11,257,943
Standardized measure of discounted future cash flows per Limited Partner Unit (2)	$	1,001	$	1,501
Undiscounted future cash flows per Limited Partner Unit	$	2,139	$	3,332

(1) Standardized measure 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 SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, no provision for federal or state income taxes was included in the December 31, 2016 and 2015 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

(2) This value per limited partner unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of the unit for purposes of presentment of the unit to the MGP for purchase is different, because it is calculated under a formula set forth in the partnership agreement.

(3) The Partnership did not have any proved undeveloped reserves as of December 31, 2016 and 2015.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries. 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 wells in which we have a working interest as of December 31, 2016:

	Number of productive wells
	Gross		Net
Gas wells		12.00		12.00

Developed Acreage

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

	Developed Acreage
	Gross		Net
Pennsylvania		261.58		261.58

The 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

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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 commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors 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 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.

Employees

We do not directly employ any of the persons responsible for our management or operation. Prior to the consummation of the sale of the DGOC MGP equity interests to Diversified, personnel employed by Atlas Energy Group will manage and operate our business. After the consummation of the sale of the DGOC MGP equity interests, personnel employed by Diversified Resources Inc., an affiliate of Diversified, will manage and operate our business. See “Management.”

Legal Proceedings

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management 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. See Note 9 (Commitments and Contingencies) to our audited financial statements included elsewhere herein.

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MANAGEMENT

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 the MGP and the DGOC MGP

The following table sets forth information with respect to those persons who prior to the consummation of the sale of the DGOC MGP equity interests to Diversified will serve as the officers of and on the governing board of, the MGP and the DGOC MGP:

Name	Age		Position(s)
Fredrick M. Stoleru		46	Chief Executive Officer, President and Director
Mark D. Schumacher		54	Chief Operating Officer
Daniel C. Herz		40	Executive Vice President and Director
Jeffrey M. Slotterback		35	Chief Financial Officer and Director
Gary Lichtenstein		69	Director
Christopher Shebby		51	Director

Fredrick M. Stoleru has served as the Chief Executive Officer and President of the MGP since February 2017. He has been Vice President of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Before that Mr. Stoleru was Managing Director of Resource Financial Institutions Group, Inc., responsible for 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.

Mark D. Schumacher has served as the Chief Operating Officer of the MGP since January 2014. He has served as ARP’s President since April 2015 and as a Senior Vice President of Atlas Energy Group since April 2015. Mr. Schumacher served as Chief Operating Officer of Atlas Energy Group from October 2013 to April 2015. Mr. Schumacher has been the Executive Vice President of Operations of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. He served as Executive Vice President of Atlas Energy from July 2012 to October 2013. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which ARP acquired in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher was an engineer with Union Pacific Resources from 1984 to 2000. Mr. Schumacher has over 33 years of experience in drilling, production and reservoir engineering management, operations and business development in East Texas, Austin Chalk, Barnett Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada.

Daniel C. 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 Partners, 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, LLC from August 2007 until February 2015.

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He also was Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy 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.

Jeffrey M. Slotterback has 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, 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.

Gary Lichtenstein has been one of our directors since September 2016. Mr. Lichtenstein has served as an independent director for Resource Real Estate Opportunity REIT, Inc. since September 2009 and Resource Real Estate Opportunity REIT II since November 2013. Mr. Lichtenstein served as a partner of Grant Thornton LLP, a registered public accounting firm, from 1987 until his retirement in 2009. He worked at Grant Thornton LLP from 1974 to 1977 and served as a manager at Grant Thornton LLP from 1977 to 1987. Prior to joining Grant Thornton LLP, Mr. Lichtenstein served as an accountant for Soloway & von Rosen CPA from 1970 to 1974 and for Touche Ross Bailey & Smart from 1969 to 1970. Mr. Lichtenstein is a past Chairman of the Board of the Diabetes Partnership of Cleveland. He received his Bachelor of Business Administration and his Juris Doctor degree from Cleveland State University.

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 governing board extensive knowledge and experience in the areas of corporate finance, investment banking, capital markets and the energy sector.

Officers and Key Operations Employees of our General Partner Controlled by Diversified

The following table sets forth information with respect to those persons who after the consummation of the sale of the DGOC MGP equity interests to Diversified will serve as the officers of our general partner and on the governing board of Diversified Gas & Oil Corporation, the parent of Diversified Energy LLC, the sole member of our general partner:

Name	Age		Position(s)
Robert R. Hutson, Jr.		48	Chief Executive Officer
Bradley G. Gray		48	Chief Operating Officer

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Robert R. Hutson, Jr. will serve as Chief Executive Officer of the general partner and has served as Chief Executive Officer of Diversified since its inception in 2001. Mr. Hutson Jr. is the fourth generation of his family to be involved in the oil and gas industry but the first to hold an executive role, with his Father, Grandfather and Great Grandfather all working in various field operational roles. Before founding Diversified Gas & Oil in 2001, Mr. Hutson Jr. held finance and accounting roles for 13 years at Bank One (Columbus, Ohio) and Compass Bank (Birmingham, Alabama). He finished his banking career as CFO of Compass Financial Services. Mr. Hutson has a B.S. degree in Accounting from Fairmont State College – West Virginia. He is a former certified public accountant (“CPA”) (Ohio).

Bradley G. Gray will serve as Chief Operating Officer of the general partner and has served as Chief Operating Officer of Diversified since October 2016. Prior to joining Diversified 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).

Code of Business Conduct and Ethics

We have not yet adopted a code of business conduct and ethics but intend to adopt one following the separation and distribution similar to the code currently in place at Atlas Series 28-2010.

Director Independence

We are not currently listed on any national securities exchange that has a requirement that the majority of our general partner’s governing board be independent.

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EXECUTIVE COMPENSATION

We have historically not directly employed any persons to manage or operate our businesses. Instead, prior to the consummation of the sale of the DGOC MGP equity interests to Diversified, all of the persons (including executive officers of the MGP and the DGOC MGP and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy Group. Pursuant to our partnership agreement, the MGP 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 the MGP receives any direct remuneration or other compensation from us. After the consummation of the sale of the DGOC MGP equity interests to Diversified, all management personnel will be employed and compensated by Diversified. For more information, see “Certain Relationships and Related Transactions.”

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For a discussion of certain agreements we will enter into in connection with the separation and distribution, see “Our Relationship with Atlas Series 28-2010 Following the Distribution.” For a discussion of certain transactions we have entered into with the MGP pursuant to the partnership agreement, see Note 8 to the audited financial statements and Note 3 to the unaudited interim condensed financial statements, each included elsewhere in this information statement.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of                , 2017, we had 7,500 units outstanding. No officer or director of the MGP currently owns any units. Although, subject to certain conditions, investor partners may present their units to us for purchase, the MGP is not obligated by our partnership agreement to purchase more than 5% of our total outstanding units in any calendar year.

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THE SEPARATION AND DISTRIBUTION

Background

On May 15, 2017, Atlas Series 28-2010 announced that it intended to separate its existing natural gas and oil development and production assets located in Pennsylvania from the remainder of its businesses. The separation will occur through Atlas Series 28-2010’s contribution of all of its existing natural gas and oil development and production assets located in Pennsylvania to DGOC Series 28, L.P., a newly formed subsidiary, and through the distribution of 7,500 common units representing all of the limited partner interest in DGOC to Atlas Series 28-2010 unitholders.

On May 4, 2017, Titan entered into the purchase agreement to sell certain of its Appalachia assets to Diversified for $84.2 million (the “Asset Sale”). The Asset Sale includes approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The Asset Sale is subject to customary closing conditions and has an effective date of April 1, 2017. On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the DGOC MGP equity interests will be transferred to Diversified. Following the transfer of the DGOC MGP equity interests to Diversified, Diversified will own the managing general partner of DGOC.

DGOC was formed as a limited partnership, which Atlas Series 28-2010 believed was the most appropriate structure due to the long-lived nature of the assets and their expected ability to generate steady cash flows over time. The number of common units to be distributed and the other financial terms of the distribution were determined by management and the board of directors of Atlas Series 28-2010’s general partner.

Immediately following completion of the separation and distribution, DGOC will hold Atlas Series 28-2010’s:

• proved reserves located in Pennsylvania; and

• producing natural gas and oil assets properties located in Pennsylvania, which assets and properties we will operate for development and production purposes.

Atlas Series 28-2010 will hold:

• producing natural gas and oil assets properties located in Indiana and Colorado.

The distribution of 7,500 common units in DGOC, as described in this information statement, is subject to the satisfaction or waiver of certain conditions. We cannot provide any assurances that the distribution will be completed or approved by the board of directors of Atlas Series 28-2010’s general partner. For a more detailed description of these conditions, see “—Conditions to the Distribution.”

Reasons for the Separation and Distribution

The board of directors of Atlas Series 28-2010’s general partner believes that separating Atlas Series 28-2010 into two public reporting companies is in the best interests of Atlas Series 28-2010 and its unitholders and has concluded that the separation and distribution will provide each company with certain opportunities and benefits, including facilitating the sale of the DGOC MGP equity interests to Diversified.

Neither we nor Atlas Series 28-2010 or any of their affiliates can assure you that, following the separation and distribution, any of the benefits described above or otherwise will be realized to the extent anticipated or at all.

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Formation Prior to Our Distribution

We were formed as a limited partnership in Delaware on July 6, 2017 for the purpose of holding all of Atlas Series 28-2010’s existing natural gas and oil development and production assets located in Pennsylvania.

When and How You Will Receive Common Units in the Distribution

We expect that Atlas Series 28-2010 will distribute 7,500 of our common units on                 , 2017, the distribution date. The distribution will be made to all holders of record of Atlas Series 28-2010 common units on                 , 2017, the record date for the distribution. DGOC will serve as its own transfer agent and registrar for the DGOC common units and as distribution agent in connection with the distribution of DGOC common units.

If you own Atlas Series 28-2010 common units of the close of business on the record date, the DGOC common units that you are entitled to receive in the distribution will be issued to you, as of the distribution date, by way of notation in the unitholder register of DGOC. No physical paper certificates will be issued to DGOC unitholders. If you have any questions concerning the mechanics of having your ownership of our common units registered in your name, we encourage you to contact us at the address set forth in this information statement.

Transferability of Our Common Units

Our common units that will be distributed in the distribution will be transferable without registration under the Securities Act except for common units received by persons who may be deemed to be our affiliates. Persons who may be deemed to be our affiliates after the distribution generally include individuals or entities that control, are controlled by or are under common control with us, which may include certain of our executive officers, directors or principal unitholders. Securities held by our affiliates will be subject to resale restrictions under the Securities Act. Our affiliates will be permitted to sell our common units only pursuant to an effective registration statement or an exemption from the registration requirements of the Securities Act, such as the exemption afforded by Rule 144 under the Securities Act. Transfers of DGOC common units are also subject to the terms and conditions of our partnership agreement.

Number of Our Common Units that You Will Receive

For each common unit of Atlas Series 28-2010 that you own at the close of business on                 , 2017, the record date, you will receive one of our common units on the distribution date. Fractional common units will be distributed, if applicable.

Results of the Separation and Distribution

After the separation and distribution, we will be a separate, public reporting company. Immediately after the distribution, Titan will indirectly own 100% of the equity of our general partner, the MGP. The MGP, in turn, will own 14.50 DGOC common units and 4,517.69 DGOC general partner units. Immediately following the distribution, we expect to have approximately                unitholders of record, based on the number of registered holders of Atlas Series 28-2010 common units as of                , 2017, and approximately 7,500 DGOC common units and 4,517.69 DGOC general partner units outstanding. The actual number of common units to be distributed will be determined on the record date.

Before the separation, we will enter into a contribution agreement with Atlas Series 28-2010 to effect the separation. This contribution agreement will provide for the allocation between Atlas Series 28-2010 and DGOC of certain of Atlas Series 28-2010’s assets, liabilities and obligations. Separately, Atlas Series 28-2010 and the MGP will enter into a distribution agreement to effect the distribution. In connection with the completion of the separation and distribution, the MGP will transfer the DGOC equity interests to the DGOC MGP. For a more detailed description of these agreements, see “Our Relationship with Atlas Series 28-2010 Following the Distribution.”

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The distribution will not affect the number of outstanding Atlas Series 28-2010 common units or any rights of Atlas Series 28-2010 unitholders.

Market for Our Common Units

There is no public market for our common units. See “Risk Factors—Risks Related to an Investment in DGOC.”

Conditions to the Distribution

We expect that the distribution will be effective on                , 2017, the distribution date, provided that, among other conditions described in this information statement, the following conditions shall have been satisfied or waived:

• the SEC shall have declared effective our registration statement on Form 10, of which this information statement forms a part, and no stop order relating to the registration statement is in effect;

• any required actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

• no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution or any of the other transactions contemplated by the purchase agreement, shall be in effect;

• the purchase agreement shall not have been terminated; and

• no other events or developments shall have occurred that, in the judgment of the board of directors of Atlas Series 28-2010’s general partner, would result in the distribution having a material adverse effect on Atlas Series 28-2010 or its unitholders.

The fulfillment of the foregoing conditions does not create any obligations on the part of Atlas Series 28-2010 to effect the distribution, and the board of directors of Atlas Series 28-2010’s general partner has reserved the right, in its sole discretion, to abandon, modify or change the terms of the distribution, including by accelerating or delaying the timing of the consummation of all or part of the distribution, at any time prior to the distribution date. Atlas Series 28-2010 does not intend to notify its unitholders of any modifications to the terms of the separation and distribution that, in the judgment of the board of directors of its general partner, are not material. For example, the board of directors of Atlas Series 28-2010’s general partner might not consider to be material such matters as significant changes to the distribution ratios, the assets to be contributed or the liabilities to be assumed in the separation. To the extent that the board of directors of Atlas Series 28-2010’s general partner determines that any modifications by Atlas Series 28-2010 changes the material terms of the distribution in any material respect, Atlas Series 28-2010 will notify its unitholders in a manner reasonably calculated to inform them about the modification as may be required by law, by, for example, publishing a press release, filing a current report on Form 8-K, or circulating a supplement to this information statement.

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OUR RELATIONSHIP WITH ATLAS SERIES 28-2010 FOLLOWING THE DISTRIBUTION

Following the separation, we and Atlas Series 28-2010 will operate separately, each as an independent public reporting company. Prior to the separation, we and Atlas Series 28-2010 and/or its affiliates will enter into certain agreements that will provide for the allocation between us and Atlas Series 28-2010 of Atlas Series 28-2010’s assets, liabilities and obligations (including its investments, property and employee benefits and tax-related assets and liabilities) attributable to periods prior to, at and after our separation from Atlas Series 28-2010. The following is a summary of the terms of the material agreements that we will enter into with Atlas Series 28-2010 and/or its affiliates prior to the separation. When used in this section, “distribution date” refers to the date on which Atlas Series 28-2010 distributes our common units to the holders of Atlas Series 28-2010 common units.

The material agreements described below will be filed as exhibits to the registration statement on Form 10 of which this information statement forms a part, and the summaries of each of these agreements set forth the terms of the agreements that we believe are material. These summaries are qualified in their entireties by reference to the full text of the applicable agreements, which are incorporated by reference into this information statement. The terms of the agreements described below that will be in effect following the distribution have not yet been finalized; changes to these agreements, some of which may be material, may be made prior to the distribution.

Our Relationship with Atlas Series 28-2010

Immediately following the separation and distribution, Titan will indirectly own all of the equity of our general partner, the MGP. The MGP will own 14.50 DGOC common units and 4,517.69 DGOC general partner units. In connection with the completion of the separation and distribution, the MGP will transfer the DGOC equity interests to the DGOC MGP.

We have historically not directly employed any persons to manage or operate our business. Instead, following the separation and distribution but prior to the consummation of the sale of the DGOC MGP equity interests to Diversified, these functions will be provided by employees of Atlas Energy Group and/or its affiliates. Neither the MGP nor the DGOC MGP receives a management fee in connection with its management of us. We reimburse the MGP and the DGOC MGP (as applicable) and its affiliates, including Atlas Energy Group, for expenses they incur in managing our operations and for an allocation of the compensation paid to the executive officers of the MGP or the DGOC MGP (as applicable), based upon an estimate of the time spent by such persons on activities for us. Other indirect costs, such as rent for offices, are currently allocated to us by Atlas Energy Group based on the number of its employees who devoted substantially all of their time to activities on our behalf. We reimburse Atlas Energy Group at cost for direct costs incurred by them on our behalf. Our partnership agreement provides that the general partner determines the costs and expenses allocable to us at its sole discretion, and does not set any aggregate limit on the amount of such reimbursements.

Following the consummation of the sale of the DGOC MGP equity interests to Diversified, Diversified will own the managing general partner of DGOC. We expect our arrangements with the DGOC MGP will be substantially similar to those currently in place with the MGP. However, we may continue to receive certain services from affiliates of Atlas Series 28-2010 following the transfer of the DGOC MGP equity interests. See “—Transition Services Agreement.”

Agreements with Atlas Series 28-2010

Prior to the separation and distribution, our assets and businesses are held by Atlas Series 28-2010. In connection with the separation and distribution, we will enter into a contribution agreement with Atlas Series 28-2010, pursuant to which Atlas Series 28-2010 will agree to transfer to us certain assets and liabilities comprising our businesses. Separately, Atlas Series 28-2010 and the MGP will enter into a distribution agreement pursuant to which Atlas Series 28-2010 will distribute 7,500 of our common units, representing all of the limited partner interest in us, to the Atlas Series 28-2010 unitholders (including the MGP) in a pro rata distribution.

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Transfer of Assets and Assumption of Liabilities

The contribution agreement will identify assets to be transferred, liabilities to be assumed and contracts to be assigned to us as part of our separation from Atlas Series 28-2010 and describe when and how these transfers, assumptions and assignments will occur. In particular, the agreement will generally provide that Atlas Series 28-2010 will transfer to us its proved reserves and its producing natural gas and oil assets properties located in Pennsylvania. We will also assume and be responsible for all liabilities and obligations related to these assets and businesses.

Atlas Series 28-2010 will retain the following assets, which will not be transferred to us in the separation:

• its proved reserves and its producing natural gas and oil assets properties located in Indiana and Colorado.

In general, neither we nor Atlas Series 28-2010 will make any representations or warranties regarding the assets, businesses or liabilities transferred or assumed, any consents or approvals that may be required in connection with such transfers or assumptions, the value or freedom from any lien or other security interest of any assets transferred, the absence of any defenses relating to any claim of either us or Atlas Series 28-2010, or the legal sufficiency of any conveyance documents. Except as expressly set forth in the contribution agreement, all assets will be transferred on an “as is,” “where is” basis.

The Distribution

The distribution agreement will govern the rights and obligations of the parties regarding the proposed distribution of our common units to the Atlas Series 28-2010 unitholders. Pursuant to the distribution agreement, Atlas Series 28-2010 will distribute one of our common units for each Atlas Series 28-2010 common unit held by such person as of the record date. Based on the number of outstanding Atlas Series 28-2010 common units outstanding on the record date, we expect that 7,500 of our common units, representing all of the limited partner interest in us, will be distributed in the distribution.

Atlas Series 28-2010 may, in its sole discretion, determine the distribution date and the terms of the distribution, and may at any time until completion of the distribution decide to abandon or modify the distribution.

Contribution of the DGOC Equity Interests to the DGOC MGP

Pursuant to the terms of a contribution agreement to be entered into prior to the separation by and between the MGP and the DGOC MGP, the MGP will transfer the DGOC equity interests to the DGOC MGP for no consideration in connection with the completion of the separation and distribution.

Purchase Agreement

On May 4, 2017, Titan entered into the purchase agreement to sell certain of its Appalachia assets to Diversified for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close by September 2017 with respect to the wells owned by DGOC.

The assets Titan has agreed to sell to Diversified include its indirect interests in the assets of Atlas Series 28-2010 being transferred to DGOC through the separation. As a result, the purchase agreement requires the MGP, on behalf of Atlas Series 28-2010, to take certain actions to facilitate the sale of those assets, including consummating the separation and distribution (and any related transactions) and drafting our partnership agreement to be substantially similar in all material respects to the partnership agreement for Atlas Series 28-2010 (subject to certain equitable adjustments to reflect a recalculation of the general partner’s subordination

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obligations for the wells to be contributed to DGOC by Atlas Series 28-2010). Following the completion of the separation and distribution (and any related transactions) and the satisfaction of the other applicable closing conditions set forth in the purchase agreement and the transfer of the DGOC equity interests to the DGOC MGP, the DGOC MGP equity interests will be transferred to Diversified pursuant to an equity interests assignment. Following the transfer of the DGOC MGP equity interests to Diversified, Diversified will own the managing general partner of DGOC. The MGP has until September 30, 2017 to complete the separation and distribution (and any related transactions). The purchase agreement requires the sale of the DGOC MGP equity interests to occur within 30 days after the completion of the separation and distribution (and any related transactions).

Transition Services Agreement

Under the terms of the purchase agreement, on the closing date, an affiliate of Titan, or the Service Provider, will enter into a transition services agreement with Diversified pursuant to which the Service Provider will provide Diversified with certain delineated services for a period of up to 120 days and certain other delineated services for a period of up to 180 days, in each case in substantially the same manner as those services were provided by the Service Provider for the 12 month period immediately prior to the closing date. The Service Provider will be entitled to certain fees in connection with the provision of such services as set forth in the transition services agreement. As a result, we may receive certain services from the Service Provider following the sale of the DGOC MGP equity interests to Diversified.

Drilling and Operating Agreement

Following the separation, Atlas Series 28-2010 and DGOC will enter into a Partial Assignment Agreement pursuant to which Atlas Series 28-2010 will assign to DGOC its rights, title and interest in and to that certain Drilling and Operating Agreement with Atlas Resources dated May 15, 2010, or the Drilling and Operating Agreement, as it relates to the Pennsylvania wells being transferred to DGOC as part of the separation. After the consummation of the sale of the DGOC MGP equity interests to Diversified, Atlas Resources and Diversified will enter into a Partial Assignment Agreement pursuant to which Atlas Resources will assign to an affiliate of Diversified its rights, title and interest in and to the Drilling and Operating Agreement as it relates to the Pennsylvania wells being transferred to DGOC as part of the separation.

Indemnification of Directors and Officers

Under our partnership agreement, in most circumstances, we will indemnify our general partner or any of its affiliates, to the fullest extent permitted by law, from and against all losses, claims or damages arising out of or incurred in connection with our business. See “Description of Our Common Units—Indemnification of Directors and Officers.”

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DESCRIPTION OF OUR COMMON UNITS

General. The rights and obligations of the holders of our Units (i.e., our participants) are governed by our partnership agreement. For purposes of this section, “Units” means limited partner Units and, if applicable, general partner Units. We were formed under the Delaware Revised Uniform Limited Partnership Act and are qualified to transact business in the jurisdictions where our wells are located. The following discussion is a summary of the material provisions of our partnership agreement that are not described elsewhere in this information statement. Capitalized terms not defined herein shall have the meaning ascribed to them in our partnership agreement.

General Powers of Our Managing General Partner. Subject to (i) rights granted under applicable law, (ii) the rights and obligations of the participants granted by our partnership agreement and (iii) any authority granted to the operator by the managing general partner, the managing general partner has exclusive management control over all aspects of our business, including generally the following power to:

• determine which Leases, wells and operations will be participated in by us, including which Leases are developed, abandoned, or sold or assigned to other parties;

• negotiate and execute any contracts, conveyances, or other instruments on our behalf, including, without limitation:

(a) the making of agreements for the conduct of operations, including agreements and financial instruments relating to hedging our natural gas and oil and the pledge of up to 100% of our assets and reserves in connection therewith;

(b) the exercise of any options, elections, or decisions under any such agreements; and

(c) the furnishing of equipment, facilities, supplies and material, services, and personnel;

• exercise, on our behalf or on behalf of the parties, as the managing general partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order;

• make all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments;

• select full or part-time employees and outside consultants and contractors and determine their compensation and other terms of employment or hiring;

• maintain insurance for our benefit and the benefit of the parties as it deems necessary, but in no event less in amount or type than those listed in Section 4.02(c)(1)(vi) of our partnership agreement;

• use our funds and revenues, borrow on behalf of, and loan money to us, on any terms it sees fit, for any purpose, including without limitation:

(a) the conduct or financing, in whole or in part, of our drilling and other activities;

(b) the conduct of additional operations; and

(c) the repayment of any borrowings or loans used initially to finance these operations or activities;

• dispose, hypothecate, sell, exchange, release, surrender, reassign or abandon any or all of our assets, including without limitation, the Leases, wells, equipment and production therefrom, provided that the sale of all or substantially all of the assets shall only be made with the consent of our participants who own a majority of our outstanding Units;

• form any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who the managing general partner selects in its sole discretion;

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• the control of any matters affecting our rights and obligations, including employing attorneys to advise and represent us, conduct litigation and incur other legal expenses, and settle claims and litigation;

• operate producing wells drilled on the Leases or on a Prospect which includes any part of the Leases;

• the exercise of the rights granted to the managing general partner under the power of attorney created under our partnership agreement; and

• the incurring of all costs and the making of all expenditures in any way related to any of the foregoing.

Indemnification of Our Managing General Partner. Subject to certain limitations contained in the partnership agreement, the partnership agreement provides for indemnification of our managing general partner, the operator, and their affiliates by us against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us provided that:

• they determined in good faith that the course of conduct was in our best interest;

• they were acting on behalf of, or performing services for us; and

• their course of conduct did not constitute negligence or misconduct.

Liability of Participants for Further Calls and Conversion. We are governed by the Delaware Revised Uniform Limited Partnership Act. If a participant invested in us as a limited partner, then generally the participant will not be liable beyond the subscription amount designated on the Subscription Agreement executed by the limited partner for our obligations unless the participant:

• also invested in us as an investor general partner; or

• in the case of the managing general partner, it purchases limited partner Units.

If the participant invested in us as an investor general partner for the tax benefits instead of as a limited partner, then his Units will be automatically converted by our managing general partner to limited partner Units after all of our wells have been drilled and completed.

After the investor general partner Units are converted to limited partner Units, which is a nontaxable event, the participant will have the lesser liability of a limited partner under Delaware law for our obligations and liabilities arising after the conversion, subject to the exceptions described above. However, an investor general partner will continue to have the responsibilities of a general partner for liabilities and obligations that we incurred before the effective date of the conversion. For example, an investor general partner might become liable for any liabilities we incurred in excess of his subscription amount during the time we engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. This could result in the former investor general partner being required to make payments, in addition to his original investment, in amounts that are impossible to predict because of their uncertain nature.

Distributions and Subordination. Our managing general partner will review our accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. Subject to our managing general partner’s subordination obligation as described below, our managing general partner and our participants share in all of our production revenues in the same percentage as their respective capital contribution bears to our total capital contributions, except that our managing general partner receives an additional 10% of our natural gas and oil revenues. As of March 31, 2017, our managing general partner received 33.75% of our production revenues and our participants received 66.25% of our production revenues. Subject to the foregoing, these sharing percentages will be adjusted based on the final amount of our managing general partner’s capital contributions to us after all of our wells have been drilled and completed. See our partnership agreement for special allocations between our managing general partner and our participants of equipment proceeds, lease proceeds and interest income.

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Our partnership agreement is structured to provide our participants with cumulative cash distributions equal to $1,243 per Unit (which is 12% of $10,356 per Unit) during the partnership’s first 12-month subordination period, $1,036 per Unit (which is 10% of $10,356 per Unit) in each of the partnership’s next three 12-month subordination periods and $829 per Unit (which is 8% of $10,356 per Unit) in the fifth 12-month subordination period, beginning when our managing general partner determines that natural gas or oil is being sold from at least 75% of our wells, excluding any wells drilled that were nonproductive. To help achieve this investment feature, under our partnership agreement our managing general partner will subordinate up to 50% of its share of our partnership net production revenues during this subordination period. The term “partnership net production revenues” means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related Operating Costs, Direct Costs, Administrative Costs, and all other costs not specifically allocated in our partnership agreement. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination, a participant may not receive the return of capital during the 60 month subordination period, or a return of all of his capital during our term, because the subordination is not a guarantee.

Subordination distributions will be determined by debiting or crediting our current period revenues to our managing general partner as may be necessary to provide the distributions to our participants. At any time during the 60 month aggregate subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous distributions to our participants including any subordination payments, to the extent cash distributions from us to our participants would exceed the return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership agreement.

Participant Allocations. Costs (other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the participants as a group, which includes all revenue credited to the participants under Section 5.01(b)(4) of our partnership agreement, including the managing general partner to the extent of any optional subscription for Units under Section 3.03(b)(1) of our partnership agreement, in the ratio of their respective number of Units, based on $20,000 per Unit regardless of the actual subscription price paid by any participant for a Unit. Intangible Drilling Costs and Tangible Costs charged to the participants as a group shall be allocated among the participants, including the managing general partner to the extent of any optional subscription for Units under Section 3.03(b)(1) of our partnership agreement, in the ratio of the subscription amount designated on their respective Subscription Agreements rather than the number of their respective Units. These allocations also take into account any investor general partner’s status as a defaulting investor general partner.

Certain participants, however, paid a reduced amount to acquire their Units. Thus, our intangible drilling costs and our participants’ share of our equipment costs to drill and complete our wells are charged among our participants in accordance with the respective subscription price they paid for their Units, rather than their respective number of Units.

Term, Dissolution and Distributions on Liquidation. We will continue in existence for 50 years unless we are terminated earlier by a final terminating event as described below, or by an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if an event which causes our dissolution under state law is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will we be liquidated. A final terminating event is any of the following:

• the election to terminate us by our managing general partner or the affirmative vote of our participants whose Units equal a majority of our total Units;

• our termination under Section 708(b)(1)(A) of the Internal Revenue Code because no part of our business is being carried on; or

• we cease to be a going concern.

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On our liquidation, a participant will receive his capital interest in us. Generally, this means an undivided interest in our assets, after payments to our creditors or a creation of a reasonable reserve therefor, in the ratio the participant’s capital account bears to all of the capital accounts in us until all capital accounts have been reduced to zero. Thereafter, the participant’s capital interest in our remaining assets will equal the participant’s interest in our related revenues.

Any in-kind property distributions to a participant from us must be made to a liquidating trust or similar entity, unless (i) the managing general partner offers the participants the election of receiving in-kind property distributions and the participant affirmatively consents to receive an in-kind property distribution after being told the risks associated with the direct ownership of our natural gas and oil properties or (ii) there are alternative arrangements in place which assure that the participant will not be responsible for the operation or disposition of our natural gas and oil properties at any time. If our managing general partner has not received a participant’s written consent to the in-kind distribution within 30 days after it is mailed, then it will be presumed that the participant did not consent. Our managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by our managing general partner. Also, if we are liquidated our managing general partner will be repaid for any debts owed it by us before there are any distributions to our participants.

Transferability. Our Units may not be sold, exchanged, gifted, assigned, pledged, mortgaged, hypothecated, redeemed or otherwise transferred unless certain conditions set forth in our partnership agreement are satisfied, including:

• there is either (i) an effective registration of the Unit under the Securities Act of 1933 and applicable state securities laws or (ii) an opinion of counsel acceptable to our managing general partner that the transfer of the Unit does not require registration and qualification under the Securities Act of 1933 and applicable state securities laws, unless this requirement is waived by our managing general partner; and

• a determination under the tax laws that a transfer of the Unit would not, in the opinion of our counsel, result in (i) our termination for tax purposes or (ii) our being treated as a “publicly-traded” partnership for tax purposes.

Also, under our partnership agreement, transfers are subject to limitations, including:

• except as provided by operation of law, we will not recognize the transfer of (i) less than whole Units, unless the participant making the transfer owns less than a whole Unit, in which case the entire fractional interest in the Unit must be transferred and (ii) Units to a person who is under the age of 18 or incompetent, unless the managing general partner consents;

• the costs and expenses associated with the transfer must be paid by the participant transferring the Unit;

• the form of transfer must be in a form satisfactory to our managing general partner; and

• the terms of the transfer must not contravene those of our partnership agreement.

A transfer of a participant’s Unit will not relieve the participant of responsibility for any obligations related to his Unit under our partnership agreement. Also, the transfer of a Unit does not grant rights under our partnership agreement, including the exercise of any elections, as among the transferring participant and us, our managing general partner, and the remaining participants to more than one Person unanimously designated by the transferee(s) of the Unit, and, if he has retained an interest in the transferred Unit, the transferor of the Unit. Further, the transfer of a Unit does not require an accounting by our managing general partner.

Under our partnership agreement, an assignee (transferee) of a Unit may become a substituted partner only on meeting certain further conditions. The conditions to become a substituted partner are as follows:

• the assignor (transferor) gives the assignee the right;

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• our managing general partner consents to the substitution;

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

• the assignee executes and delivers, in a form acceptable to our managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his or her agreement to be bound by all terms and provisions of our partnership agreement.

A substituted partner is entitled to all of the rights of full ownership of the assigned Units, including the right to vote. We will amend our records at least once each calendar quarter to effect the substitution of substituted partners.

Presentment Feature.

Subject to the terms of our partnership agreement, a participant may present his Units to our managing general partner for purchase. However, a participant is not required to offer his Units to our managing general partner.

Our managing general partner has no obligation to establish a reserve to satisfy the presentment obligation, and it does not intend to do so. Our managing general partner may immediately suspend its purchase obligation by notice to our participants if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange financing or other consideration for this purpose on terms it deems reasonable. Additionally, the presentment feature may be conditioned on our managing general partner receiving an opinion of counsel that the transfer will not cause us to be treated as a “publicly traded partnership” under the Internal Revenue Code.

Our managing general partner will not purchase less than one Unit unless the fractional Unit represents the participant’s entire interest in us (but this limitation may be waived by our managing general partner), nor more than 5% of our total Units in any calendar year. If fewer than all of the Units presented at any time are to be purchased, then the Units to be purchased will be selected by lot. Our managing general partner may not waive the limit on its purchasing more than 5% of our total Units in any calendar year.

Our managing general partner’s obligation to purchase the Units presented by our participants may be discharged for its benefit by a third-party or an affiliate of our managing general partner. The Unit will be transferred to the party who pays for it, along with the delivery of an executed assignment. The presentment must be within 120 days of our reserve report discussed below and, in accordance with Treas. Reg. Section 1.7704-1(f), the purchase may not be made by our managing general partner until at least 60 calendar days after written notice of the participant’s intent to present the Unit was made.

The amount of the presentment price will be the greater of the following amounts:

• three times the amount of our total distributions from the partnership’s natural gas and oil operations to a participant during the previous 12 months; or

• the amount that is generally attributable to the participant’s share of our natural gas and oil reserves, as discussed below.

The amount of the presentment price attributable to our natural gas and oil reserves will be determined based on our last reserve report. Our managing general partner prepares an annual reserve report of our natural gas and oil proved reserves based on engineering reports which are then reviewed by an independent expert. The presentment price to a participant will be based on his share of our net assets and liabilities as described below, based on the ratio that his number of Units bears to the total number of our Units. The presentment price will include the participant’s share of the sum of the following partnership items:

• an amount based on 70% of the present worth of future net revenues from our Proved Reserves as described in our most recent reserve report as described above;

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• cash on hand;

• prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and

• the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures.

There will be deducted from the foregoing sum the following items:

• an amount equal to the participant’s share of all debts, obligations, and other liabilities, including accrued expenses; and

• any distributions made to the participant between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, natural gas, or a producing property owned by the partnership after the date of the presentment request, for purposes of determining the reduction of the presentment price the distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of our Proved Reserves.

The amount may be further adjusted by our managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price because of various considerations described in Section 6.03(c) of our partnership agreement.

Voting Rights and Amendments. Other than as set forth below, a participant generally will not be entitled to vote on any of our partnership matters at any meeting. However, at any time participants whose Units equal 10% or more of our total Units for any matters on which participants may vote may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of our managing general partner. On the matters being voted on, a participant is entitled to one vote per Unit or, if the participant owns a fractional Unit, that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of our total Units may vote to:

• dissolve us;

• remove our managing general partner and elect a new managing general partner;

• elect a new managing general partner if our managing general partner elects to withdraw from the partnership;

• remove the operator and elect a new operator;

• approve or disapprove the sale of all or substantially all of our assets;

• cancel any contract for services with our managing general partner, the operator, or their affiliates, which is not otherwise described in the Private Placement Memorandum for the offering of our Units or our partnership agreement without penalty on 60 days’ notice; and

• amend our partnership agreement; provided however, any amendment may not:

• without the approval of our participants or our managing general partner, increase the duties or liabilities of the participants or our managing general partner, respectively, or increase or decrease the profits or losses or required Capital Contribution of our participants or our managing general partner; or

• without the unanimous approval of our participants, affect the classification of our income and loss for federal income tax purposes.

Our managing general partner and its officers, directors, and affiliates can vote on certain issues above as a participant if they have purchased Units. In addition to amendments by our participants as described above,

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amendments to our partnership agreement may be proposed in writing by our managing general partner and adopted with the consent of participants whose Units equal a majority of our total Units. Our partnership agreement may also be amended by our managing general partner without the consent of our participants for certain limited purposes set forth in Section 8.05(b) of our partnership agreement.

Books and Records. Our managing general partner is required to keep books and records of all of our financial activities in accordance with applicable law. A participant may inspect and copy any of the records, including a list of our participants subject to the conditions described below, at any reasonable time after giving adequate notice to our managing general partner. Access to the list of our participants is subject to the following conditions:

• an alphabetical list of the names, addresses, and business telephone numbers of our participants along with the number of Units held by each of them (the “Participant List”) must be maintained as a part of our books and records and be available for inspection by any participant or his designated agent at our home office on the participant’s request;

• the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List;

• a copy of the Participant List must be mailed to any participant requesting the Participant List within 10 days of the written request;

• the purposes for which a participant may request a copy of the Participant List include, without limitation, matters relating to the participant’s voting rights under our partnership agreement and the exercise of participant’s rights under the federal proxy laws; and

• our managing general partner may refuse to exhibit, produce, or mail a copy of the Participant List as requested if our managing general partner believes that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a participant relative to our affairs. Our managing general partner will require the participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the participant’s interest in us.

Also, our managing general partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time.

Restrictions on Roll-Up Transactions. In connection with a proposed Roll-up Transaction (defined below) involving us and the issuance of securities of an entity, or a Roll-Up Entity, that would be created or would survive after the successful completion of the Roll-up Transaction, an appraisal of all of our natural gas and oil properties must be obtained from a competent independent appraiser. Our properties must be appraised on a consistent basis, and the appraisal must be based on the evaluation of all relevant information and must indicate the value of our properties as of a date immediately before the announcement of the proposed Roll-up Transaction. The appraisal must assume an orderly liquidation of our properties over a 12-month period. The terms of the engagement of the independent appraiser must clearly state that the engagement is for the benefit of us and our participants. A summary of the appraisal, indicating all of the material assumptions underlying the appraisal, must be included in a report to our participants in connection with the proposed Roll-up Transaction. A “Roll-up Transaction” is a transaction involving our acquisition, merger, conversion or consolidation, directly or indirectly, and the issuance of securities of a Roll-Up Entity. This term does not include:

• a transaction involving our securities that have been listed on a national securities exchange or included for quotation on the National Association of Securities Dealers Automated Quotation National Market System for at least 12 months; or

• a transaction involving only our conversion to corporate, trust, or association form if, as a consequence of the transaction, there will be no significant adverse change in any of the following: voting rights; the term of our existence; our managing general partner’s compensation; or our investment objectives.

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In connection with a proposed Roll-up Transaction, the person sponsoring the Roll-up Transaction must offer to our participants who vote “no” on the proposal the choice of:

• accepting the securities of the Roll-Up Entity offered in the proposed Roll-up Transaction; or

• one of the following:

• remaining as participants in us and preserving their interests in us on the same terms and conditions as existed previously, or

• receiving cash in an amount equal to each participant’s pro rata share of the appraised value of our net assets.

We are prohibited from participating in any proposed Roll-Up Transaction:

• which would result in the diminishment of any participant’s voting rights under the Roll-Up Entity’s chartering agreement;

• in which the democracy rights of our participants in the Roll-Up Entity would be less than those provided for under Sections 4.03(c)(1) and 4.03(c)(2) of our partnership agreement or, if the Roll-Up Entity is a corporation, then the democracy rights of our participants must correspond to the democracy rights provided for our participants in our partnership agreement to the greatest extent possible;

• which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity;

• in which our participants’ rights of access to the records of the Roll-Up Entity would be less than those provided for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of our partnership agreement;

• in which any of the costs of the transaction would be borne by us if our participants whose Units equal a majority of our total Units do not vote to approve the proposed Roll-Up Transaction; and

• unless the Roll-up Transaction is approved by our participants whose Units equal a majority of our total Units.

We currently have no plans to enter into a Roll-up Transaction.

Withdrawal of Managing General Partner. Any time beginning 10 years after the Offering Termination Date and our primary drilling activities our managing general partner may voluntarily withdraw as our managing general partner for whatever reason by giving 120 days’ written notice to our participants. Although our withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of our participants whose Units equal a majority of our total Units.

Also, our managing general partner may assign its general partner interest in us to its affiliates and it may withdraw a property interest from us in the form of a Working Interest in our wells equal to or less than its respective interest in our revenues without the consent of our participants.

Drilling and Operating Agreement. Our managing general partner or its affiliate serves as the operator of all of our wells under the drilling and operating agreement. The following is a summary of the material provisions of the drilling and operating agreement that are not covered elsewhere in this information statement:

• The operator may be replaced at any time on 60 days’ advance written notice by our managing general partner acting on our behalf on the affirmative vote of investors whose Units equal a majority of our total Units.

• The operator may resign as operator upon 90 days’ advance written notice at any time after five years without our consent.

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• The operator has the right, beginning one year after each of our wells drilled and completed under our partnership agreement is placed into production, to retain up to $200 per well per month from the proceeds of the sale of the production from the well, in proportion to the share of the Working Interest owned by us in the well, to cover its estimate of our share of the costs of future plugging and abandonment costs of the well.

• The operator has a first and preferred lien on and security interest in our interest under the drilling and operating agreement in (i) the Leases, (ii) oil and gas produced and its share of the proceeds from the sale of the oil and gas and (iii) materials and equipment, in order to secure payment of amounts due to the operator by us.

• The operator must obtain and maintain workmens’ compensation insurance as required under applicable state law and comprehensive general public liability insurance of not less than $1 million per person per occurrence for personal injury or death and $1 million for property damage per occurrence, including coverage for blow-outs, and total liability coverage of not less than $10 million.

• Without our written consent, the operator is not permitted to incur extraordinary costs with respect to producing wells in excess of $5,000 per well, unless necessary to safeguard persons or property or to protect a well or related facilities if there is a sudden emergency.

• Without the prior written consent of the operator, we may not transfer our interest in fewer than all of our wells, production, equipment, and leasehold interests, unless the transfer is of an equal undivided interest in all such items.

• The operator will not have any liability for any loss suffered by us or our participants which arises out of any action or inaction of the operator if the operator determined in good faith that the course of conduct was in our best interest, the operator was performing services for us and the operator’s course of conduct did not constitute negligence or misconduct.

Also, nonperformance under the drilling and operating agreement by the operator due to force majeure, which generally means acts of God, catastrophes and other causes which preclude the operator’s performance and are not reasonably in the operator’s control, is suspended during the continuance of the force majeure.

Indemnification of Directors and Officers.

Under the terms of our partnership agreement, our managing general partner, the operator, and their affiliates have limited their liability to us and our participants for any loss suffered by us or the participants which arises out of any action or inaction on their part if:

• they determined in good faith that the course of conduct was in our best interest;

• they were acting on our behalf or performing services for us; and

• their course of conduct did not constitute negligence or misconduct.

In addition, our partnership agreement provides for our indemnification of our managing general partner, the operator, and their affiliates against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in our partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, in the SEC’s opinion this indemnification is contrary to public policy and therefore unenforceable.

Payments arising from the indemnification or agreement to hold harmless described above are recoverable only out of our tangible net assets, including our revenues, and any insurance proceeds received by us. Still, the use of our funds or assets for indemnification of our managing general partner, the operator or an affiliate would reduce amounts available for our operations or for distribution to our participants.

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Under our partnership agreement, we are not allowed to pay the cost of the portion of any insurance that insures our managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified as described above. However, our funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if we have adequate funds available and certain conditions in our partnership agreement are met, including pursuant to Section 4.05(a)(4) of our partnership agreement.

Units Outstanding

As of the completion of the distribution, there will be approximately 7,500 of our common units and 4,517.69 of our general partner units outstanding. DGOC does not have any other outstanding options, warrants or securities convertible into common units. None of the unitholders will have contractual rights for registration of the units under the Securities Act.

Transfer Agent and Registrar

After the distribution, DGOC will serve as its own transfer agent and registrar for the DGOC common units.

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CERTAIN U.S. FEDERAL INCOME TAX MATTERS

Overview

The following is a summary of certain U.S. federal income tax consequences to U.S. holders (as defined below) relating to the distribution of our units by Atlas Series 28-2010 and the ownership and disposition of our units. This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), the U.S. Treasury regulations promulgated thereunder, and interpretations of the Code and the U.S. Treasury regulations by the courts and the Internal Revenue Service (the “IRS”), in effect as of the date hereof, all of which are subject to change, possibly with retroactive effect. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “DGOC,” “us” or “we” are references to DGOC Series 28, L.P.

This summary addresses the material U.S. federal income tax consequences only to an individual citizen or resident of the United States who is a beneficial owner for U.S. federal income tax purposes of (i) our units and, (ii) solely with respect to the discussion under the heading “—Tax Consequences of the Distribution of Our Units by Atlas Series 28-2010” units of Atlas Series 28-2010 (a “U.S. holder”). In addition, this summary is limited to U.S. holders who receive our units in the distribution in their capacity as partners of Atlas Series 28-2010, and who hold such units and their units of Atlas Series 28-2010, as a capital asset for U.S. federal income tax purposes. In addition, this summary does not discuss all the tax considerations that may be relevant to unitholders in light of their particular circumstances, nor does it address the consequences to unitholders subject to special treatment under the U.S. federal income tax laws (including, for example, unitholders other than U.S. holders, insurance companies, dealers or brokers in securities or currencies, tax-exempt organizations, banks, financial institutions, mutual funds, real estate investment trusts, individual retirement accounts, pass-through entities and investors in such entities, unitholders who have a functional currency other than the U.S. dollar, unitholders who hold their units as a hedge or as part of a hedging, straddle, conversion, synthetic security, integrated investment or other risk-reduction transaction, unitholders who are subject to alternative minimum tax, or unitholders who acquired their units as compensation or otherwise in connection with compensation arrangements.

Furthermore, this summary does not address any U.S. federal taxes other than U.S. federal income tax, and does not discuss any state, local or foreign tax consequences. Each unitholder is urged to consult its tax advisor regarding the U.S. federal, state, local and foreign tax considerations of the distribution and the ownership and disposition of our units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or our unitholders. Accordingly, the U.S. federal income tax consequences described in this summary may be contested by the IRS and sustained by a court. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of the distribution, our operations, and an investment in us may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

This summary of U.S. federal income tax consequences is for general information purposes. This summary does not purport to address all U.S. federal income tax consequences that may be relevant to unitholders in light of their particular circumstances, nor does it address any state, local or foreign tax consequences. Unitholders are urged to consult their own advisors concerning the U.S. federal, state, local and foreign tax consequences to them of the distribution and of the ownership and disposition of our units.

Partnership Status

In general, a partnership is a pass-through entity and incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account such partner’s share of items of income, gain, loss and

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deduction of the partnership in computing such partner’s U.S. federal income tax liability, regardless of whether cash distributions are made to such partner by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in such partner’s partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations for U.S. federal income tax purposes. Since neither our units nor those of Atlas Series 28-2010 will be traded on an established securities market, we do not believe we will be considered a publicly traded partnership. Moreover, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

Based on estimates of our current gross income, we believe that at least 90% of such income constitutes qualifying income and, thus, we believe that we will be classified as a partnership for U.S. federal income tax purposes under the Qualifying Income Exception to Section 7704 of the Code even if our units were traded on an established securities market.

No ruling has been or will be sought from the IRS, nor has the IRS made any determination as to our or Atlas Series 28-2010’s status for U.S. federal income tax purposes. The IRS could assert that we or Atlas Series 28-2010 should be treated as a corporation for U.S. federal income tax purposes.

If Atlas Series 28-2010 were taxable as a corporation for U.S. federal income tax purposes on the date of the distribution, materially adverse consequences could result to Atlas Series 28-2010 and unitholders of Atlas Series 28-2010 who receive our units in the distribution. If Atlas Series 28-2010 was taxable as a corporation for U.S. federal income tax purposes on the date of the distribution, Atlas Series 28-2010 would be subject to tax on gain, if any, that it would have recognized if it had sold the units received by unitholders of Atlas Series 28-2010 in the distribution in a taxable sale for their fair market value. In addition, in such case, each unitholder of Atlas Series 28-2010 who receives our units in the distribution would be treated as if the unitholder had received a distribution equal to the fair market value of our units that were distributed to the unitholder, which generally would be treated as either taxable dividend income to the unitholder, to the extent of Atlas Series 28-2010’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in such unitholder’s units of Atlas Series 28-2010, or taxable capital gain, after the unitholder’s tax basis in such unitholder’s units of Atlas Series 28-2010 is reduced to zero. Accordingly, taxation of Atlas Series 28-2010 as a corporation on the date of the distribution could result in materially adverse tax consequences to Atlas Series 28-2010 and unitholders of Atlas Series 28-2010 who receive our units in the distribution.

If we were taxable as a corporation for U.S. federal income tax purposes in any taxable year, the unitholders will be subject to special tax rules and materially adverse consequences could result to unitholders and us. If we were a taxable corporation for U.S. federal income tax purposes, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates, currently at a maximum rate of 35%. In addition, in such case, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in such unitholders units in us, or taxable capital gain, after the unitholder’s tax basis in such unitholder’s units in us is reduced to zero. Accordingly, taxation of us as a corporation could result in materially adverse tax consequences, as well as a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our units.

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The discussion below assumes that we and Atlas Series 28-2010 will each be classified as a partnership for U.S. federal income tax purposes.

Tax Consequences of the Distribution of Our Units by Atlas Series 28-2010

Recognition of Gain

We believe that the distribution of our units by Atlas Series 28-2010 to a U.S. holder of units of Atlas Series 28-2010 should not be taxable to such U.S. holder for U.S. federal income tax purposes, except to the extent that the aggregate amount of money distributed or deemed distributed to such U.S. holder (as discussed below) exceeds such U.S. holder’s tax basis in such U.S. holder’s units of Atlas Series 28-2010 immediately before the distribution. In general, any money distributed or deemed distributed (as described below) to such U.S. holder in excess of such U.S. holder’s tax basis should be considered to be gain from the sale or exchange of such U.S. holder’s units of Atlas Series 28-2010, taxable in accordance with the rules described below under “—Tax Consequences of Disposition of Our Units.” No loss shall be recognized for U.S. federal income tax purposes by a U.S. holder on such distribution.

For purposes of determining whether gain is recognized by a U.S. holder on such distribution of our units, the distribution of a “marketable security” generally is treated as a distribution of money equal to the fair market value of such marketable security on the date of the distribution. In general, a “marketable security” includes a financial instrument (including stock or other equity interest) which is, as of the date of the distribution, “actively traded” for U.S. federal income tax purposes. We do not believe our units would be considered marketable securities.

To the extent the distribution causes the “at risk” amount of U.S. holder of units in Atlas Series 28-2010 to be less than zero at the end of any taxable year, such U.S. holder must recapture any losses deducted in previous years. Unitholders are urged to consult their own tax advisors with respect to the “at risk” rules in their particular circumstances and read the summary under the heading entitled “—Tax Consequences of Ownership of Our Units—Limitations on Deductibility of Losses.”

Basis and Holding Period

A U.S. holder’s initial basis in our units received by such U.S. holder in the distribution generally will be equal to Atlas Series 28-2010’s adjusted basis in such units immediately before the distribution, which will be equal to its basis in the assets contributed by Atlas Series 28-2010 to us. However, such U.S. holder’s initial basis in such units shall not exceed the adjusted basis of such U.S. holder’s interest in Atlas Series 28-2010 units, reduced by any money distributed in the same transaction. In addition, such U.S. holder’s initial basis in such units shall be increased by the amount of any gain such U.S. holder recognizes on the distribution of “marketable securities,” if any, as described above. Furthermore, if such U.S. holder acquired any part of such U.S. holder’s interest in Atlas Series 28-2010 in a transfer as to which an election under Section 754 of the Code was in effect, then Atlas Series 28-2010’s adjusted basis in our units distributed to such U.S. holder generally should take into account such U.S. holder’s special basis adjustment, if any, in such units.

A U.S. holder’s adjusted basis in such U.S. holder’s interest in Atlas Series 28-2010 generally will be reduced (but not below zero) by the amount of money distributed by Atlas Series 28-2010 to such U.S. holder and such U.S. holder’s initial basis in our units distributed by Atlas Series 28-2010 to such U.S. holder in the distribution, determined as if no gain were recognized by the U.S. holder as a result of our units being treated as “marketable securities” as described above.

A U.S. holder’s holding period for our units distributed by Atlas Series 28-2010 to such U.S. holder in the distribution generally will include Atlas Series 28-2010’s holding period for the assets that were contributed to us which is in excess of one year.

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Atlas Series 28-2010 expects to provide unitholders with information regarding its adjusted basis and holding period in our units distributed by Atlas Series 28-2010 to its unitholders in the distribution.

The rules governing the U.S. federal income tax consequences of the distribution of our units by Atlas Series 28-2010 in the distribution are complex. Unitholders are urged to consult their own tax advisors regarding the application of these rules and the U.S. federal income tax consequences of the distribution to them in their particular circumstances.

Tax Consequences of Ownership of Our Units

Limited Partner Status

Unitholders who have been admitted as limited partners of us will be treated as partners of us for U.S. federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of us for U.S. federal income tax purposes.

There is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some U.S. federal income tax information or reports furnished to record holders of units.

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for U.S. federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for U.S. federal income tax purposes would therefore appear to be fully taxable as ordinary income. Unitholders are urged to consult their own tax advisors with respect to their status as partners in us for U.S. federal income tax purposes.

This summary assumes that holders of our units are partners for U.S. federal income tax consequences. Further, the references to “unitholders” and “U.S. holder” in this summary are to persons who are treated as partners for U.S. federal income tax purposes.

Flow-Through of Taxable Income

In general, we are a pass-through entity and will incur no U.S. federal income tax liability. Instead, each unitholder will be required to take into account and report on such unitholder’s income tax return such unitholder’s share of our items of income, gain, loss and deduction in computing such unitholder’s U.S. federal income tax liability, regardless of whether we make corresponding cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if such unitholder has not received a cash distribution. Each unitholder will be required to include in income such unitholder’s allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes, except to the extent that any money (and certain “marketable securities”) distributed by us to such unitholder exceeds such unitholder’s adjusted basis in our units immediately before the distribution. Our distributions of money in excess of a unitholder’s adjusted basis generally will be considered to be gain from the sale or exchange of our units, taxable in accordance with the rules described under “—Tax Consequences of

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Disposition of Our Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Tax Consequences of Ownership of Our Units—Limitations on Deductibility of Losses.”

Basis of Our Units

A unitholder’s initial adjusted basis for our units received in the distribution by Atlas Series 28-2010 generally will be determined as described under the heading “—Tax Consequences of the Distribution of Our Units by Atlas Series 28-2010—Basis and Holding Period.” That basis will be (i) increased by such unitholder’s share of our income and by any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions from us, by such unitholder’s share of our losses, by any decreases in such unitholder’s share of our nonrecourse liabilities and by such unitholder’s share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on such unitholder’s share of profits, of our nonrecourse liabilities. Please read “—Tax Consequences of Disposition of Our Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of such unitholder’s share of our losses will be limited to such unitholder’s adjusted basis in our units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than such unitholder’s adjusted basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause such unitholder’s “at risk” amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that such unitholder’s adjusted basis or “at risk” amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit by such unitholder, any gain recognized by the unitholder can be offset by losses that were previously suspended by the “at risk” limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the “at risk” or basis limitations is no longer utilizable.

In general, a unitholder will be “at risk” to the extent of the unitholder’s adjusted basis in our units, excluding any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, reduced by any amount of money the unitholder borrows to acquire or hold the unitholder’s units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s “at risk” amount will increase or decrease as the unitholder’s adjusted basis of our units increases or decreases, other than basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and the “at risk” limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. Further, a unitholder’s share of our net income may be offset by any suspended passive losses from the unitholder’s investment in us, but may not be offset by our current or carryover losses from other passive activities. Passive losses that are not deductible because they exceed a unitholder’s share of income generate may be deducted in full when the unitholder’s disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the “at risk” rules and the basis limitation.

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Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. A unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any U.S. federal, state, or local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated to the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Section 754 Election

Atlas Series 28-2010 made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. Because our partners also owned 50% or more of Atlas Series 28-2010, we are a “continuing partnership” under Section 708(b)(2)(B). As such we also are deemed to have made a Section 754 election. The election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect such unitholder’s purchase price. This election does not apply to a person who purchases units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) the unitholder’s share of our tax basis in our assets (“basis”) and (2) the unitholder’s Section 743(b) adjustment to that basis.

U.S. Treasury regulations under Section 743 of the Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under U.S. Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168 of the Code, is generally required to be depreciated using either the straight-line method or the 150% declining balance method.

A Section 754 election is advantageous if the transferee’s tax basis in the transferee’s units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of

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the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and the transferee’s share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in the transferee’s units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built in loss immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally, a built in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than the purchaser would have been allocated had the election not been revoked.

Tax Consequences of Our Operations

Accounting Method and Taxable Year

Our initial taxable year will end on December 31, 2017. Each unitholder will be required to include in income such unitholder’s share of our income, gain, loss and deduction for our taxable year ending within or with such unitholder’s taxable year.

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Ownership of Our Units—Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Code requires each unitholder to compute the unitholder’s own depletion allowance and maintain records of the unitholder’s share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for U.S. federal income tax purposes. Each unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of the unitholder’s share of the adjusted tax basis of the underlying property for depletion and other purposes. Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative contracts or the operation of a major refinery.

Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder who qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

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In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders who do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of the unitholder’s units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and U.S. Treasury regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by us, no assurance can be given with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. We encourage each unitholder to consult the unitholder’s own tax advisor to determine whether percentage depletion would be available to the unitholder.

Deductions for Intangible Drilling and Development Costs

We will not be incurring any future intangible drilling and development cost.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above (please read “—Tax Consequences of Ownership of Our Units—Limitations on Deductibility of Losses”) and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the “Section 199 deduction,” equal to 6% of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine the unitholder’s Section 199 deduction, each unitholder will aggregate the unitholder’s share of the qualified production activities income allocated to the unitholder from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account the unitholder’s distributive share of the expenses allocated to the unitholder from our qualified production activities regardless of whether we otherwise have taxable

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income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Ownership of Our Units—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given as to the availability or extent of the Section 199 deduction to the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. Each prospective unitholder is encouraged to consult its own tax advisor to determine whether the Section 199 deduction would be available to the unitholder.

Lease Acquisition Costs

The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. We do not expect to make future lease acquisitions. Please read “—Tax Consequences of Our Operations—Depletion Deductions.”

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred. We do not anticipate incurring any such costs.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The tax initial basis of our assets will be equal to Atlas Series 28-2010’s basis in those assets. The U.S. federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to the distribution will be borne by our existing unitholders. Please read “—Tax Consequences of Ownership of Our Units—Allocation of Income, Gain, Loss and Deduction.”

We are required to use the depreciation and cost recovery methods that Atlas Series 28-2010 used.

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If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of such unitholder’s interest in us. Please read “—Tax Consequences of Ownership of Our Units—Allocation of Income, Gain, Loss and Deduction” and “—Tax Consequences of Disposition of Our Units—Recognition of Gain or Loss.”

Valuation and Tax Basis of Our Properties

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Tax Consequences of Disposition of Our Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of our units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by such unitholder plus such unitholder’s share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 20% plus the 3.8% Medicare tax. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income in the case of individuals.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in such partner’s entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. U.S. Treasury regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an

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ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the U.S. Treasury regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult such unitholder’s tax advisor as to the possible consequences of this ruling and application of the U.S. Treasury regulations.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this summary as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Constructive Termination

We will be considered to have been terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. Our partnership agreement forbids transfers that would result in our constructive termination.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including an IRS Schedule K-1, which describes the unitholder’s share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Code, the U.S. Treasury regulations or administrative interpretations of the IRS. Nor can we assure unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our U.S. federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to his returns.

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Partnerships generally are treated as separate entities for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement designates our general partner as our Tax Matters Partner.

For taxable years beginning after December 31, 2017, the Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action. The Balanced Budget Act of 2015 (the “BBA”) replaces the concept of Tax Matters Partner with that of Partnership Representative. The BBA significantly changes the way the IRS can assess deficiencies in the case of partnerships. In the absence of relevant regulatory guidance, we do not know how the BBA will affect us. It is likely that the IRS will treat our general partner as the Partnership Representative.

A unitholder must file a statement with the IRS identifying the treatment of any item on the unitholder’s U.S. federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

• for which there is, or was, “substantial authority”; or

• as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted tax basis, (b) the price for any property or services (or for the use of property) claimed on

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any such return with respect to any transaction between persons described in Section 482 of the Code is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net transfer price adjustment under Section 482 for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our U.S. federal income tax information return (and possibly our unitholders’ tax return) would be audited by the IRS. Please read “—Administrative Matters—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described in “—Administrative Matters—Accuracy-Related Penalties”;

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

74

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form 10 with the SEC with respect to our common units being distributed as contemplated by this information statement. This information statement is a part of, and does not contain all of the information set forth in, the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, please refer to the registration statement, including its exhibits and schedules. Statements made in this information statement relating to any contract or other document are not necessarily complete, and you should refer to the exhibits attached to the registration statement for copies of the actual contract or document. You may review a copy of the registration statement, including its exhibits and schedules, at the SEC’s public reference room, located at 100 F Street, N.E., Washington, D.C. 20549, by calling the SEC at 1-800-SEC-0330 as well as on the Internet website maintained by the SEC at www.sec.gov. Information contained on any website referenced in this information statement is not incorporated by reference in this information statement.

As a result of the distribution, we will become subject to the information and reporting requirements of the Exchange Act and, in accordance with the Exchange Act, we will file periodic reports, proxy statements and other information with the SEC.

We intend to furnish holders of our common units with annual reports containing consolidated financial statements prepared in accordance with U.S. generally accepted accounting principles and audited and reported on, with an opinion expressed, by an independent registered public accounting firm.

You should rely only on the information contained in this information statement or to which we have referred you. We have not authorized any person to provide you with different information or to make any representation not contained in this information statement.

75

INDEX TO FINANCIAL STATEMENTS

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

	PAGE
Audited Financial Statements for the Years Ended December 31, 2016 and 2015:
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheets		F-3
Statements of Operations		F-4
Statements of Changes in Partners’ Capital		F-5
Statements of Cash Flows		F-6
Notes to Financial Statements		F-7
Unaudited Condensed Financial Statements for the Three Months Ended March 31, 2017 and 2016:
Condensed Balance Sheets		F-21
Condensed Statements of Operations		F-22
Condensed Statement of Changes in Partners’ Capital		F-23
Condensed Statements of Cash Flows		F-24
Notes to Condensed Financial Statements		F-25

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

DGOC Series 28, L.P.

We have audited the accompanying balance sheets of DGOC Series 28, L.P. (a Delaware Limited Partnership) (the “Partnership”) as of December 31, 2016 and 2015, and the related statements of operations, changes in partners’ capital, 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 our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DGOC Series 28, L.P. 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 accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the financial statements, as of December 31, 2016, the Partnership’s Managing General Partner was in violation of certain debt covenants under its credit agreements and there are uncertainties regarding its liquidity and capital resources. The ability of the Managing General Partner to continue as a going concern also raises substantial doubt regarding the Partnership’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

July 11, 2017

F-2

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

BALANCE SHEETS

DECEMBER 31, 2016 AND 2015

	2016		2015
ASSETS
Current assets:
Cash	$	152,800	$	172,000
Accounts receivable trade-affiliate		656,300		990,200
Current portion of derivative assets		—		529,500
Total current assets		809,100		1,691,700
Gas and oil properties, net		19,836,500		21,164,400
Long-term asset retirement receivable-affiliate		24,800		15,200
Total assets	$	20,670,400	$	22,871,300
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	15,300	$	13,400
Current portion of put premiums payable-affiliate		—		107,800
Total current liabilities		15,300		121,200
Asset retirement obligations		1,698,100		1,602,400
Commitments and contingencies (Note 9)
Partners’ capital:
Managing general partner’s interest		2,787,500		2,984,900
Limited partners’ interest (7,500 units)		16,169,500		18,162,800
Total partners’ capital		18,957,000		21,147,700
Total liabilities and partners’ capital	$	20,670,400	$	22,871,300

See accompanying notes to financial statements.

F-3

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
REVENUES
Natural gas	$	2,643,700		$	3,471,400
Gain (loss) on mark-to-market derivatives		(20,100	)		357,900
Total revenues		2,623,600			3,829,300
COSTS AND EXPENSES
Production		837,700			1,100,000
Depletion		1,327,900			1,629,300
Accretion of asset retirement obligations		95,700			86,700
General and administrative		42,800			54,100
Total costs and expenses		2,304,100			2,870,100
Net income	$	319,500		$	959,200
Allocation of net income (loss):
Managing general partner	$	455,400		$	636,500
Limited partners	$	(135,900	)	$	322,700
Net loss (income) per limited partnership unit	$	(18	)	$	43

See accompanying notes to financial statements.

F-4

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2016 AND 2015

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2014	$	3,493,000		$	20,309,300		$	23,802,300
Participation in revenues and costs and expenses:
Net production revenues		918,400			1,453,000			2,371,400
Gain on mark-to-market derivatives		—			357,900			357,900
Depletion		(229,100	)		(1,400,200	)		(1,629,300	)
Accretion of asset retirement obligations		(32,600	)		(54,100	)		(86,700	)
General and administrative		(20,200	)		(33,900	)		(54,100	)
Net income		636,500			322,700			959,200
Subordination		(551,100	)		551,100			—
Distributions to partners		(593,500	)		(3,020,300	)		(3,613,800	)
Balance at December 31, 2015		2,984,900			18,162,800			21,147,700
Participation in revenues and costs and expenses:
Net production revenues		694,200			1,111,800			1,806,000
Gain on mark-to-market derivatives		—			(20,100	)		(20,100	)
Depletion		(186,700	)		(1,141,200	)		(1,327,900	)
Accretion of asset retirement obligations		(36,000	)		(59,700	)		(95,700	)
General and administrative		(16,100	)		(26,700	)		(42,800	)
Net income (loss)		455,400			(135,900	)		319,500
Subordination		(188,000	)		188,000			—
Distributions to partners		(464,800	)		(2,045,400	)		(2,510,200	)
Balance at December 31, 2016	$	2,787,500		$	16,169,500		$	18,957,000

See accompanying notes to financial statements.

F-5

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
Cash flows from operating activities:
Net income	$	319,500		$	959,200
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion		1,327,900			1,629,300
Non-cash loss on derivative value		421,700			322,000
Accretion of asset retirement obligations		95,700			86,700
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		333,900			804,000
Increase in asset retirement receivable-affiliate		(9,600	)		(10,400	)
Increase (decrease) in accrued liabilities		1,900			(5,100	)
Net cash provided by operating activities		2,491,000			3,785,700
Cash flows from investing activities:
Net cash provided by investing activities		—			—
Cash flows from financing activities:
Distributions to partners		(2,510,200	)		(3,613,700	)
Net cash used in financing activities		(2,510,200	)		(3,613,700	)
Net change in cash		(19,200	)		172,000
Cash at beginning of year		172,000			—
Cash at end of year	$	152,800		$	172,000

See accompanying notes to financial statements.

F-6

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2016 AND 2015

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Background and Organization

On May 4, 2017, Titan Energy, LLC (“Titan”) entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell certain of its Appalachia assets to an affiliate of Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million (the “Asset Sale”). The Asset Sale includes approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The Asset Sale is subject to customary closing conditions, and has an effective date of April 1, 2017. On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

Among other things, the Purchase Agreement includes the sale of Titan’s indirect interests in the assets and liabilities associated with Atlas Resources Series 28-2010 L.P.’s (“Atlas Series 28”) natural gas wells in Pennsylvania to be transferred to DGOC Series 28, L.P., a newly formed entity and currently a subsidiary of Atlas Series 28 (“DGOC,” the “Partnership,” “we,” “us,” and “our”), for which Atlas Resources, LLC serves as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). We refer to this transfer as the “separation.”

Following the satisfaction of a number of additional conditions, including, among others, the U.S. Securities and Exchange Commission (“SEC”) declaring the Partnership’s registration statement on Form 10 effective, the separation will be accomplished through a transaction in which all of the natural gas development and production assets of Atlas Series 28 located in Pennsylvania will be transferred to the Partnership. After the separation, Atlas Series 28 will distribute to its unit holders, on a pro rata basis, common units representing one hundred percent of the limited partner interest in the Partnership. In connection with the completion of the separation and the distribution, the MGP will transfer its limited partner and general partner interests in the Partnership (the “DGOC equity interests”) to an entity expected to be named DGOC Partnership Holdings II, LLC (“DGOC Holdings”) formed as a wholly owned subsidiary of Titan to serve as the Partnership’s new managing general partner (the “DGOC MGP”). Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the equity interests of the DGOC MGP will be transferred to Diversified and Diversified will own the managing general partner of the Partnership.

Atlas Series 28 is a Delaware limited partnership, formed on April 1, 2010 with Atlas Resources serving as its Managing General Partner and Operator. Atlas Resources is an indirect subsidiary of 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. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan.

The Partnership has drilled and currently operates wells located in Pennsylvania. We have no employees and rely on the 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. Produced natural gas 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.

F-7

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas that the Partnership can produce economically.

Basis of Presentation

The Partnership is currently a subsidiary of Atlas Series 28 and its assets and liabilities consist of those that the MGP considers to be related to the natural gas development and production assets located in Pennsylvania that comprise its operations. The accompanying financial statements have been derived from Atlas Series 28’s historical accounting records.

The statements of operations include all revenues and expenses directly attributable to the Partnership’s business. Certain of our general and administrative expenses include indirect costs, such as accounting, tax, and reservoir engineering fees, that were allocated to us based on the relative proportion of our production volumes to Atlas Series 28’s total production volumes. The statements of changes in partners’ capital include participation in revenues and costs and expenses directly attributable to the MGP’s and the Partnership’s limited partners’ respective interests, subordination, and distributions to partners. Subordination and distributions were allocated to the Partnership based on the relative proportion of its net production revenues to Atlas Series 28’s total net production revenues. See Note 8 for additional disclosure regarding the MGP’s subordination requirements in accordance with the partnership agreement. All of the allocations and estimates reflected in the financial statements are based on assumptions that the MGP believes are reasonable. However, these allocations and estimates are not necessarily indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity.

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

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. 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. 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 and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. 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.

F-8

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 also 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.

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 result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

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 a 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.

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility in an attempt to ameliorate some of its liquidity concerns. The amendment provides 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 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 180-day 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.

F-9

On April 21, 2017, the lenders under Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

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 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.

On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility in accordance with the first lien credit facility amendment. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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 expense, and the fair value of derivative instruments. The oil 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 its customers. At December 31, 2016 and 2015, 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

F-10

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 Partnership’s 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.

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

	December 31,
	2016		2015
Asset retirement receivable—affiliate, beginning of year	$	15,200	$	4,800
Asset retirement estimates withheld		9,600		10,400
Asset retirement receivable—affiliate, end of year	$	24,800	$	15,200

Gas Properties

Gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. 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 producing activities.

The Partnership’s depletion expense is determined at the field level 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 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.

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.

The review of the Partnership’s gas 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 expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. 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, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.

F-11

The determination of 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.

In addition, reserve estimates for 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.

Derivative Instruments

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. The Partnership does not apply hedge accounting for its commodity derivatives. As such, changes in fair value are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas wells and related facilities (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. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

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 federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements.

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 taken any tax positions 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 Pennsylvania. 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

F-12

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 and 2015.

Concentration of Credit Risk

The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the year ended December 31, 2016, the Partnership had two customers that individually accounted for approximately 56% and 44% of the Partnership’s natural gas revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, the Partnership had one customer that individually accounted for approximately 100% of the Partnership’s natural gas combined revenues, excluding the impact of all financial derivative activity.

Revenue Recognition

The Partnership generally sells natural gas 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 and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when 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 from the production of natural gas 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 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 $573,900 and $530,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance and provided enhanced disclosures, as applicable, within our financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number

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of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

NOTE 3—PARTICIPATION IN REVENUES AND COSTS

Working Interest

The partnership agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the partnership agreement.

The MGP and the limited partners generally participated in revenues and costs in the following manner:

	Managing General Partner			Limited Partners
Organization and offering cost		100	%		0	%
Lease costs		100	%		0	%
Intangible drilling costs		8	%		92	%
Tangible equipment costs		52	%		48	%
Revenues (1)		37	%		63	%
Operating costs, administrative costs, direct and all other costs (2)		37	%		63	%

(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 10% of the partnership revenues.

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

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2016			2015
Proved properties:
Leasehold interests	$	540,100		$	540,100
Wells and related equipment		90,300,700			90,300,700
Total natural gas and oil properties		90,840,800			90,840,800
Accumulated depletion and impairment		(71,004,300	)		(69,676,400	)
Gas and oil properties, net	$	19,836,500		$	21,164,400

The Partnership recorded depletion expense on natural gas properties of $1,327,900 and $1,629,300 for the years ended December 31, 2016 and 2015, respectively.

NOTE 5—ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of

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the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The estimated liability is based on the MGP’s 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 an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s gas 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 as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of December 31, 2016 and 2015, the MGP withheld $24,800 and $15,200, respectively, of net production revenues for future 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,
	2016		2015
Beginning of year	$	1,602,400	$	1,515,700
Accretion expense		95,700		86,700
End of year	$	1,698,100	$	1,602,400

NOTE 6—DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally swaps and 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. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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

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contracts allowed for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives were 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 $529,500 at December 31, 2016 and 2015, respectively.

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 $107,800, 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 assets and liabilities that the reporting entity has the ability to access at the measurement date.

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

Level 3 – Unobservable inputs that reflect the 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership used a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership managed and reported 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.

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2016
Derivative assets, gross
Commodity swaps	$	—	$	—	$	—	$	—
Commodity puts		—		—		—		—
Total derivative assets, gross	$	—	$	—	$	—	$	—
As of December 31, 2015
Derivative assets, gross
Commodity swaps	$	—	$	296,200	$	—	$	296,200
Commodity puts		—		233,300		—		233,300
Total derivative assets, gross	$	—	$	529,500	$	—	$	529,500

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments have 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.

NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its partnership agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable 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 $975 per well per month for Marcellus wells. 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 16% 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 when incurred.

	Years Ended December 31,
	2016		2015
Administrative fees	$	10,800	$	10,800
Supervision fees		140,400		140,400
Transportation fees		463,700		623,500
Direct costs		265,600		379,400
Total	$	880,500	$	1,154,100

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.

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In June 2016, the MGP transferred $464,800 of funds to the Partnership based on projected monthly distributions to its limited partners for a four to five month span to ensure accessible distribution funding coverage in accordance with the Partnership’s operations and partnership agreements in the event the MGP experienced a prolonged restructuring period as the MGP performs all administrative and management functions for the Partnership. As of December 31, 2016, the Partnership had used all of these funds for distributions.

Subordination by Managing General Partner

Under the terms of the partnership agreement, the MGP was required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (March 2011) and expiring 60 months from that date. The MGP subordinated $188,000 and $551,100 of its net production revenues to the limited partners for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, the MGP’s subordination period has expired.

NOTE 9—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2015 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2016 and 2015, the MGP withheld $24,800 and $15,200, respectively, of net production revenues for future plugging and abandonment costs.

Legal Proceedings

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

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

NOTE 10—SUPPLEMENTAL GAS INFORMATION (UNAUDITED)

Gas Reserve Information. The preparation of the Partnership’s natural gas reserve estimates was completed in accordance with the 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 reserves related to the Partnership. The reserve information for the Partnership includes natural gas 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. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management

F-18

review. The preparation of reserve estimates was overseen by the 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 industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s President.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas 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 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. 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 are 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, the standardized measures of discounted future net cash flows may not represent the fair market value of gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas 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 for the Partnership are as follows:

	Gas (Mcf)
Balance, December 31, 2014		32,889,000
Revisions (1)		(296,500	)
Production		(2,386,400	)
Balance, December 31, 2015		30,206,100
Revisions (1)		(2,329,300	)
Production		(1,887,300	)
Balance, December 31, 2016		25,989,500

(1) The downward revision in natural gas volumes is primarily due to a decrease in the unadjusted SEC base pricing, which resulted in forecast volume adjustments downward to reflect actual production and shorter economic life. Unadjusted SEC base prices were $2.48, $2.59, and $4.35 for the years ended December 31, 2016, 2015 and 2014, respectively.

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

	Years Ended December 31,
	2016			2015
Natural gas properties:
Leasehold interest	$	540,100		$	540,100
Wells and related equipment		90,300,700			90,300,700
Accumulated depletion, accretion and impairment		(71,004,300	)		(69,676,400	)
Net capitalized costs	$	19,836,500		$	21,164,400

F-19

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

	Years Ended December 31,
	2016			2015
Revenues	$	2,643,700		$	3,471,400
Production costs		(837,700	)		(1,100,000	)
Depletion		(1,327,900	)		(1,629,300	)
	$	478,100		$	742,100

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2016 and 2015 adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. 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:

	Years Ended December 31,
	2016			2015
Future cash inflows	$	30,315,600		$	40,332,900
Future production costs		(14,274,600	)		(15,340,800	)
Future net cash flows		16,041,000			24,992,100
Less 10% annual discount for estimated timing of cash flows		(8,536,400	)		(13,734,200	)
Standardized measure of discounted future net cash flows	$	7,504,600		$	11,257,900

F-20

NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	March 31, 2017		December 31, 2016
ASSETS
Current assets:
Cash	$	313,600	$	152,800
Accounts receivable trade-affiliate		998,400		656,300
Total current assets		1,312,000		809,100
Gas and oil properties, net		19,526,100		19,836,500
Long-term asset retirement receivable-affiliate		27,200		24,800
Total assets	$	20,865,300	$	20,670,400
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	14,600	$	15,300
Total current liabilities		14,600		15,300
Asset retirement obligations		1,723,500		1,698,100
Commitments and contingencies (Note 4)
Partners’ capital:
Managing general partner’s interest		2,949,600		2,787,500
Limited partners’ interest (7,500 units)		16,177,600		16,169,500
Total partners’ capital		19,127,200		18,957,000
Total liabilities and partners’ capital	$	20,865,300	$	20,670,400

See accompanying notes to condensed financial statements.

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NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2017		2016
REVENUES
Natural gas	$	1,194,500	$	561,200
Gain on mark-to-market derivatives		—		61,300
Total revenues		1,194,500		622,500
COSTS AND EXPENSES
Production		288,300		204,400
Depletion		310,400		330,000
Accretion of asset retirement obligations		25,400		23,900
General and administrative		13,800		13,700
Total costs and expenses		637,900		572,000
Net income	$	556,600	$	50,500
Allocation of net income (loss):
Managing general partner	$	288,700	$	87,700
Limited partners	$	267,900	$	(37,200	)
Net income (loss) per limited partnership unit	$	36	$	(5	)

See accompanying notes to condensed financial statements.

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NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED

March 31, 2017

(Unaudited)

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2016	$	2,787,500		$	16,169,500		$	18,957,000
Participation in revenues, costs and expenses:
Net production revenues		347,100			559,100			906,200
Depletion		(43,700	)		(266,700	)		(310,400	)
Accretion of asset retirement obligations		(9,500	)		(15,900	)		(25,400	)
General and administrative		(5,200	)		(8,600	)		(13,800	)
Net income		288,700			267,900			556,600
Distributions to partners		(126,600	)		(259,800	)		(386,400	)
Balance at March 31, 2017	$	2,949,600		$	16,177,600		$	19,127,200

See accompanying notes to condensed financial statements.

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NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities:
Net income	$	556,600		$	50,500
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion		310,400			330,000
Non-cash loss on derivative value		—			65,500
Accretion of asset retirement obligations		25,400			23,900
Changes in operating assets and liabilities:
Increase in accounts receivable trade-affiliate		(342,100	)		(105,500	)
Increase in asset retirement receivable-affiliate		(2,400	)		(2,400	)
(Decrease) increase in accrued liabilities		(700	)		5,500
Net cash provided by operating activities		547,200			367,500
Cash flows from investing activities:
Net cash provided by investing activities		—			—
Cash flows from financing activities:
Distributions to partners		(386,400	)		(539,500	)
Net cash used in financing activities		(386,400	)		(539,500	)
Net change in cash		160,800			(172,000	)
Cash beginning of period		152,800			172,000
Cash at end of period	$	313,600		$	—

See accompanying notes to condensed financial statements.

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NATURAL GAS ASSETS TO BE CONTRIBUTED TO DGOC SERIES 28, L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION

Background and Organization

On May 4, 2017, Titan Energy, LLC (“Titan”) entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell certain of its Appalachia assets to an affiliate of Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million (the “Asset Sale”). The Asset Sale includes approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure. The Asset Sale is subject to customary closing conditions, and has an effective date of April 1, 2017. On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

Among other things, the Purchase Agreement includes the sale of Titan’s indirect interests in the assets and liabilities associated with Atlas Resources Series 28-2010 L.P.’s (“Atlas Series 28”) natural gas wells in Pennsylvania to be transferred to DGOC Series 28, L.P., a newly formed entity and currently a subsidiary of Atlas Series 28 (“DGOC,” the “Partnership,” “we,” “us,” and “our”), for which Atlas Resources, LLC serves as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). We refer to this transfer as the “separation.”

Following the satisfaction of a number of additional conditions, including, among others, the U.S. Securities and Exchange Commission (“SEC”) declaring the Partnership’s registration statement on Form 10 effective, the separation will be accomplished through a transaction in which all of the natural gas development and production assets of Atlas Series 28 located in Pennsylvania will be transferred to the Partnership. After the separation, Atlas Series 28 will distribute to its unit holders, on a pro rata basis, common units representing one hundred percent of the limited partner interest in the Partnership. In connection with the completion of the separation and the distribution, the MGP will transfer its limited partner and general partner interests in the Partnership (the “DGOC equity interests”) to an entity expected to be named DGOC Partnership Holdings II, LLC (“DGOC Holdings”) formed as a wholly owned subsidiary of Titan to serve as the Partnership’s new managing general partner (the “DGOC MGP”). Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the equity interests of the DGOC MGP will be transferred to Diversified and Diversified will own the managing general partner of the Partnership.

Atlas Series 28 is a Delaware limited partnership, formed on April 1, 2010 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. 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. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan.

The Partnership has drilled and currently operates wells located in Pennsylvania. 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. Produced natural gas 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.

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The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas that the Partnership can produce economically.

Basis of Presentation

The Partnership is currently a subsidiary of Atlas Series 28 and our assets and liabilities consist of those that the MGP considers to be related to the natural gas development and production assets located in Pennsylvania that comprise our operations. The accompanying financial statements have been derived from Atlas Series 28’s historical accounting records.

The statements of operations include all revenues and expenses directly attributable to the Partnership’s business. Certain of our general and administrative expenses include indirect costs, such as accounting, tax, and reservoir engineering fees, that were allocated to us based on the relative proportion of our production volumes to Atlas Series 28’s total production volumes. All of the allocations and estimates reflected in the financial statements are based on assumptions that the MGP believes are reasonable. However, these allocations and estimates are not necessarily indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity.

The condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2016, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016. The results of operations for the three months ended March 31, 2017 may not necessarily be indicative of the results of operations for the year ended December 31, 2017.

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

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. 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. 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 and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and

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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.

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 also 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.

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 result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

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 2017. 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.

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On April 19, 2017, Titan entered into a third amendment to its first lien credit facility in an attempt to ameliorate some of its liquidity concerns. The amendment provides 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 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 180-day 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.

On April 21, 2017, the lenders under Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

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 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.

On June 30, 2017, Titan completed a majority of the Asset Sale for cash proceeds of approximately $66.6 million, which included customary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility in accordance with the first lien credit facility amendment. Titan expects to complete the remainder of the Asset Sale for additional cash proceeds of approximately $11.4 million by September 2017.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, and fair value of derivative instruments. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

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Derivative Instruments

The Partnership’s MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices. During the three months ended March 31, 2017, the Partnership did not have any derivative activity as all derivative contracts have matured. During the three months ended March 31, 2016, the Partnership recorded $0 as a gain reclassified from accumulated other comprehensive income into natural gas and oil revenues and $61,300 as a gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives.

Gas and Oil Properties

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

	March 31, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	540,000		$	540,000
Wells and related equipment		90,300,700			90,300,700
Total natural gas and oil properties		90,840,700			90,840,700
Accumulated depletion and impairment		(71,314,600	)		(71,004,200	)
Gas and oil properties, net	$	19,526,100		$	19,836,500

Recently Issued Accounting Standards

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

NOTE 3—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s condensed statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s condensed statements of operations, are payable at $975 per well per month for Marcellus wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s condensed statements of operations and are generally payable at 16% 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.

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The following table provides information with respect to these costs and the periods incurred.

	Three Months Ended March 31,
	2017		2016
Administrative fees	$	2,700	$	2,700
Supervision fees		35,100		35,100
Transportation fees		191,100		102,100
Direct costs		73,200		78,200
Total	$	302,100	$	218,100

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 condensed balance sheets includes the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (March 2011) and 60 months from that date. The subordination period expired September 2016.

NOTE 4—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2015 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of March 31, 2017, the MGP has withheld $27,200 of net production revenues for future plugging and abandonment costs.

Legal Proceedings

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

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