UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2016

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

For the transition period from ______ to ______

Commission file number: 000-54378

ATLAS RESOURCES SERIES 28-2010 L.P.

(Exact name of registrant as specified in its charter)

Delaware		27-2101952
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA		15275
(Address of principal executive offices)		Zip code

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

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

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

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

Common Units representing Limited Partnership Interests

(Title of Class)

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

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

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

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

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

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS RESOURCES SERIES 28-2010 L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

			Page
PART I	Item 1:	Business	7
	Item 2:	Properties	17
	Item 3:	Legal Proceedings	19
	Item 4:	Mine Safety Disclosures (Not Applicable)	19
PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	19
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
	Item 8:	Financial Statements and Supplementary Data	28
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
	Item 9A:	Controls and Procedures	47
PART III	Item 10:	Directors, Executive Officers and Corporate Governance	48
	Item 11:	Executive Compensation	50
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	50
	Item 13:	Certain Relationships and Related Transactions	50
	Item 14:	Principal Accountant Fees and Services	51
PART IV	Item 15:	Exhibits	52
SIGNATURES			53

GLOSSARY OF TERMS

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

Bpd. Barrels per day.

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

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

Development well. A well drilled within the proved area of an oil or 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.

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.

(v)

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

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

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

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

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

SEC. Securities Exchange Commission.

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

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

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

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

FORWARD-LOOKING STATEMENTS

The matters discussed within this report 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 report 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. The following and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

•

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

•

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

•

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

•

future financial and operating results;

•

resource potential;

•

economic conditions and instability in the financial markets;

•

the accuracy of estimated natural gas and oil reserves;

•

the financial and accounting impact of hedging transactions;

•

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

•

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

•

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

•

impact fees and severance taxes;

•

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

•

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

•

general market, labor and economic conditions and uncertainties;

•

the ability to retain certain key customers;

•

dependence on the gathering and transportation facilities of third parties;

•

the availability of drilling rigs, equipment and crews;

•

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

•

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

•

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

•

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

•

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

•

restrictions on hydraulic fracturing;

•

exposure to new and existing litigation;

•

development of alternative energy resources; and

•

the effects of a cyber-event or terrorist attack.

Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report 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 report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

PART I.

ITEM 1: BUSINESS

Overview

Atlas Resources Series 28-2010 L.P. (“we, “us” or the “Partnership”) is a Delaware limited partnership and was 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 Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series 28-2010 L.P.

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, Indiana and Colorado. 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.

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.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that reduced debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby were being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

ARP and the MGP operated the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired and were satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP and the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership was not a party to the Restructuring Support Agreement. The ARP Restructuring did not materially impact the MGP’s ability to perform as the managing general partner and operator of the Partnership’s operations. In June 2016, the MGP transferred $380,900 of funds to the Partnership based on projected monthly distributions to its limited partners over the next several months 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 has used these funds for distributions. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner would not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group was not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring did not have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

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

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

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.

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 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 downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

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

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

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

Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility.

Gas Production

Production Volumes

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

	Years Ended December 31,
	2016		2015
Production: ⁽¹⁾
Natural gas (Mcf)		2,969,292		3,618,091

(1)

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

Production Revenues, Prices and Costs

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

Our production revenues and estimated gas 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,
	2016		2015
Production revenues (in thousands):
Natural gas revenue	$	5,352	$	6,964
Average sales price:⁽¹⁾
Natural gas (per Mcf) ⁽²⁾	$	1.88	$	2.09

Production costs (per Mcfe)	$	1.19	$	1.19

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(2)

Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $243,000 and $600,800 for the years ended December 31, 2016 and 2015, respectively.

Our ongoing operating and maintenance costs have been or are expected to be fulfilled through revenues from the sale of our natural gas production. We are charged by our MGP a monthly well supervision fee of $975 per well per month for the Marcellus Shale wells, $1,500 per well per month for New Albany Shale wells and $400 per well per month for Niobrara Shale wells as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas such as:

•

Well tending, routing maintenance and adjustment;

•

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

•

Preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment and materials and brine disposal. If these expenses are incurred, we are charged the costs for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment cost of the well. As of December 31, 2016, our MGP withheld $110,000 of net production revenue for this purpose.

Drilling Activity

We received total cash subscriptions from investors of $149,724,600, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $57,055,000. We have drilled 127 development wells within the Marcellus Shale, Southern Appalachia Shale, Antrim Shale, New Albany Shale, and Niobrara Shale geological formations in Pennsylvania, Tennessee, Michigan, Indiana and Colorado. We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by the Partnership:

	Gross		Net
Gas wells drilled		112.00		104.68
Dry hole		15.00		14.02
Total wells drilled		127.00		118.70

Natural Gas Leases

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

Contractual Revenue Arrangements

Natural Gas. The MGP markets 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 the majority of our production areas are as follows:

•

Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5; and

•

Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

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, Atmos Energy Marketing, LLC and Hess Energy Marketing, LLC accounted for approximately 73% and 22%, respectively, of our total natural gas production revenues, 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 treatong are provided.

In Appalachia, we have gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”). Under these agreements, we dedicate our natural gas production in certain areas within southwest Pennsylvania to Laurel Mountain for transportation to interstate pipeline systems or local distribution companies, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas subject to certain conditions. The 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.

Competition

We operate in a highly competitive environment for acquiring properties and other energy companies, attracting capital, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for mineral property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. Our competitors may be able to pay more for hydrocarbon properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition 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 our natural gas although prices have 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 areas inhabited by threatened or endangered species;

•

requiring the acquisition of various permits before the commencement of 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.

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 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 regulatory 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:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

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, except for a Bureau of Land Management rule that would have imposed conditions on fracturing operations on federal lands, which was enjoined by a federal court holding BLM lacked the authority to adopt the rule. 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 assets; 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. Those circumstances included where (1) there are water withdrawals for hydraulic fracturing in times or areas of low water availability, (2) hydraulic fracturing fluids and chemicals or produced water are spilled, (3) hydraulic fracturing fluids are injected into wells with inadequate mechanical integrity, and (4) 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 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 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 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. 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 and wetland 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 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 carbon 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 carbon dioxide, it is difficult to predict, however, 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: (1) the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010), see also Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014); (2) the Reporting of Greenhouse Gases rule specifically addressing the natural gas industry, 80 Fed. Reg. 64262 (Oct. 22, 2015); (3) standards for venting, flaring, and equipment leaks from oil and gas production activities on onshore Federal and Indian leases.

Waste 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.” 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 and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. We are not presently aware the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition.

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

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

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

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

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

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

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

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

Employees

We do not directly employ any of the persons responsible for our management or operation. In general, personnel employed by Atlas Energy Group manage and operate our business. Some of the officers of our general partner may spend a substantial amount of time managing the business and affairs of our general partner and its affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Available Information

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

ITEM 2: PROPERTIES

Natural Gas Reserves

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 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas 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 our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our MGP’s internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s senior engineering staff and management, with final approval by our MGP’s President.

Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas 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-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)		33,811,600		45,094,000
Total proved developed reserves (Mcfe)		33,811,600		45,094,000
Standardized measure of discounted future cash flows ⁽¹⁾	$	13,143,400	$	23,941,400
Standardized measure of discounted future cash flows per Limited Partner Unit ⁽²⁾	$	1,094	$	1,992
Undiscounted future cash flows per Limited Partner Unit	$	2,089	$	4,132

(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 has been 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 our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.

(3)

The Partnership does 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		106.00		99.775

Developed Acreage

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

	Developed Acreage
	Gross		Net
Indiana		2,942.42		2,757.20
Colorado		1,805.61		1,805.61
Pennsylvania		261.58		261.58
Total		5,009.61		4,824.39

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 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.

ITEM 3: 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 Item 8: Note 9 Commitments and Contingencies).

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.

ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)

PART II

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

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

•

our MGP’s consent;

•

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

•

the transfer does not violate federal or state securities laws.

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

•

the assignor gives the assignee the right;

•

our MGP consents to the substitution;

•

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

•

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

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. As of December 31, 2016, we had 2,304 limited partners.

Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2016 and 2015, we distributed the following:

	Distributions
	2016		2015
Limited Partners	$	1,957,200	$	3,920,800
Managing General Partner		176,000		836,200
Total distributions	$	2,133,200	$	4,757,000

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

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with Item 8: Financial Statements and Supplementary Data, which contains our financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements 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. We believe the assumptions underlying the financial statements are reasonable. However, our financial statements included herein may not necessarily reflect our results of operations, financial position, and cash flows in the future.

BUSINESS OVERVIEW

Atlas Resources Series 28-2010 L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership and 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 Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series 28-2010 L.P.

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, Indiana, and Colorado. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group for administrative services.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

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

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

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 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 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.

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

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by key trends in natural gas 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 throughout 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas 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 pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas 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, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for service performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2016, our MGP withheld $110,000 of net production revenue for this purpose.

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

	Years Ended December 31,
	2016			2015
Production revenues (in thousands):
Gas	$	5,352		$	6,964
Production volumes:
Gas (mcf/day)		8,113			9,913
Average sales price:⁽¹⁾
Gas (per mcf) ⁽²⁾	$	1.88		$	2.09
Production costs:
As a percent of revenues		66	%		62	%
Per mcfe	$	1.19		$	1.19
Depletion per mcfe	$	0.64		$	0.65

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(2)

Natural Gas Revenues. Our natural gas revenues were $5,351,700 and $6,964,000 for the years ended December 31, 2016 and 2015, respectively, a decrease of $1,612,300 (23%). The $1,612,300 decrease in natural gas revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $1,248,800 decrease in production volumes and a $363,500 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 8,113 mcf per day for the year ended December 31, 2016 from 9,913 mcf per day for the year ended December 31, 2015, a decrease of 1,800 (18%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: “Business-Contractual Revenue Arrangements”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume is mostly due to the normal decline inherent in the life of the wells.

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

We recognized a gain on mark-to-market derivatives of $2,800 for the year ended December 31, 2016. This gain was due primarily to mark-to-market gains 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 $654,500 for the year ended December 31, 2015.

Costs and Expenses. Production expenses were $3,541,700 and $4,317,800 for the years ended December 31, 2016 and 2015, respectively, a decrease of $776,100 (18%). 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 35% and 34% 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 $132,000 and $137,800 for the years ended December 31, 2016 and 2015, respectively, a decrease of $5,800 (4%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs and services provided to us.

Impairment of gas properties for the years ended December 31, 2016 and 2015 was $212,400 and $6,320,500, respectively, net of offsetting gains from accumulated other comprehensive income of $0 and $100,000, respectively. At least annually, we compare the carrying value of our proved developed gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, impairment charges were recognized for the years ended December 31, 2016 and 2015. The estimate of fair value of these gas properties was impacted by, among other factors, the deterioration of natural gas prices.

Loss on Abandonment of Well. During the year ended December 31, 2015, the Partnership plugged and abandoned the remaining Michigan well. The remaining net asset value recorded in the Partnership’s gas properties prior to plugging and abandonment was $300. This net asset value was written off as part of the net loss on abandonment of well in the Partnership’s statement of operations for the year ended December 31, 2015 and also removed from gas properties on the Partnership’s balance sheet. Plugging and abandonment costs incurred through December 31, 2015 total $557,800, of which $269,600 had been previously recorded as an asset retirement obligation, resulting in a net loss on abandonment of well of $288,200.

Cash Flows Overview

Cash provided by operating activities decreased $2,484,600 for the year ended December 31, 2016 to $2,107,500 as compared to $4,592,100 for the year ended December 31, 2015. This decrease was due to a decrease in the change in accounts receivable trade-affiliate of $1,934,400, a decrease in net earnings before depletion, impairment, and accretion of $1,193,900, a decrease in the loss on abandonment of a well of $288,200, and a decrease in the change in asset retirement receivable-affiliate of $69,600. This decrease was partially offset by an increase in the change in asset retirement obligations settled of $551,600, an increase in the non-cash loss on derivative value of $422,300, and an increase in the change in accrued liabilities of $27,600 for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

Cash provided by investing activities decreased $329,800 during the year ended December 31, 2016 to $16,300 from $346,100 for the year ended December 31, 2015. This decrease was due to a decrease in proceeds from the sale of oil and gas properties of $196,000 and a decrease in the proceeds for the sale of tangible equipment of $133,700.

Cash used in financing activities decreased $2,623,800 to $2,133,200 for the year ended December 31, 2016 from $4,757,000 for the year ended December 31, 2015. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2016, our MGP withheld $110,000 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

SECURED HEDGE FACILITY

The MGP has a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2016, only the Partnership’s natural gas swaps are included in the secured hedge facility.

In addition, it will be an event of default under the MGP’s revolving credit facility if it, as our general partner, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

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 (See “Item 8: Financial Statements”), included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depletion and Impairment of Long-Lived Assets

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 a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

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

During the years ended December 31, 2016 and 2015, we recognized $212,400 and $6,320,500, respectively, of impairment within natural gas properties, net of offsetting gains from accumulated other comprehensive income of $0 and $100,000, respectively. The impairment related to the carrying amount of these gas properties being in excess of our estimate of their fair value at December 31, 2016 and 2015. The estimate of fair value of these gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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 “Item 2: 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 in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the year ended December 31, 2016, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas equivalent reserves due 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 our MGP’s assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas Resources Series 28-2010 L.P.

We have audited the accompanying balance sheets of Atlas Resources Series 28-2010 L.P. (a Delaware Limited Partnership) (the “Partnership”) as of December 31, 2016 and 2015, and the related statements of operations, comprehensive loss, 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 Atlas Resources Series 28-2010 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 disclosed 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

April 17, 2017

ATLAS RESOURCES SERIES 28-2010 L.P.

BALANCE SHEETS

DECEMBER 31, 2016 AND 2015

	2016		2015
ASSETS
Current assets:
Cash	$	171,800	$	181,200
Accounts receivable trade-affiliate		1,223,800		1,068,400
Current portion of derivative assets		-		799,500
Total current assets		1,395,600		2,049,100
Gas and oil properties, net		24,494,800		26,622,200
Long-term asset retirement receivable-affiliate		110,000		40,400
Total assets	$	26,000,400	$	28,711,700
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	206,300	$	181,600
Current portion of put premiums payable-affiliate		-		162,700
Total current liabilities		206,300		344,300
Asset retirement obligations		3,956,700		3,793,000
Commitments and contingencies (Note 9)
Partners’ capital:
Managing general partner’s interest		3,691,000		3,905,600
Limited partners’ interest (7,500 units)		18,146,400		20,665,000
Accumulated other comprehensive income		-		3,800
Total partners’ capital		21,837,400		24,574,400
Total liabilities and partners’ capital	$	26,000,400	$	28,711,700

See accompanying notes to financial statements.

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
REVENUES
Natural gas	$	5,351,700		$	6,964,000
Gain on mark-to-market derivatives		2,800			654,500
Total revenues		5,354,500			7,618,500
COSTS AND EXPENSES
Production		3,541,700			4,317,800
Depletion		1,898,700			2,361,600
Impairment		212,400			6,320,500
Accretion of asset retirement obligations		169,700			216,300
General and administrative		132,000			137,800
Total costs and expenses		5,954,500			13,354,000
Operating loss		(600,000	)		(5,735,500	)
Loss on abandonment of well		-			(288,200	)
Net loss	$	(600,000	)	$	(6,023,700	)

Allocation of net income (loss):
Managing general partner	$	88,000		$	(1,945,000	)
Limited partners	$	(688,000	)	$	(4,078,700	)
Net loss per limited partnership unit	$	(92	)	$	(544	)

See accompanying notes to financial statements.

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
Net loss	$	(600,000	)	$	(6,023,700	)
Other comprehensive loss:
Difference in estimated hedge gains receivable		-			(294,500	)
Reclassification adjustment to net loss of mark-to-market (gains) losses on cash flow hedges		(3,800	)		35,400
Total other comprehensive loss		(3,800	)		(259,100	)
Comprehensive loss	$	(603,800	)	$	(6,282,800	)

See accompanying notes to financial statements.

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2016 AND 2015

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2014	$	7,423,600		$	27,927,700		$	262,900		$	35,614,200

Participation in revenues and costs and expenses:
Net production revenues		975,500			1,670,700			-			2,646,200
Gain on mark-to-market derivatives		-			654,500			-			654,500
Loss on abandonment of well		(288,200	)		-			-			(288,200	)
Depletion		(455,600	)		(1,906,000	)		-			(2,361,600	)
Impairment		(2,043,600	)		(4,276,900	)		-			(6,320,500	)
Accretion of asset retirement obligations		(81,300	)		(135,000	)		-			(216,300	)
General and administrative		(51,800	)		(86,000	)		-			(137,800	)
Net loss		(1,945,000	)		(4,078,700	)		-			(6,023,700	)

Other comprehensive loss		-			-			(259,100	)		(259,100	)

Working interest adjustment		(5,600	)		5,600			-			-

Subordination		(731,200	)		731,200			-			-

Distributions to partners		(836,200	)		(3,920,800	)		-			(4,757,000	)
Balance at December 31, 2015		3,905,600			20,665,000			3,800			24,574,400
Participation in revenues and costs and expenses:
Net production revenues		703,400			1,106,600			-			1,810,000
Gain on mark-to-market derivatives		-			2,800			-			2,800
Depletion		(402,900	)		(1,495,800	)		-			(1,898,700	)
Impairment		(99,100	)		(113,300	)		-			(212,400	)
Accretion of asset retirement obligations		(63,800	)		(105,900	)		-			(169,700	)
General and administrative		(49,600	)		(82,400	)		-			(132,000	)
Net income (loss)		88,000			(688,000	)		-			(600,000	)
Other comprehensive loss		-			-			(3,800	)		(3,800	)
Subordination		(126,600	)		126,600			-			-
Distributions to partners		(176,000	)		(1,957,200	)		-			(2,133,200	)
Balance at December 31, 2016	$	3,691,000		$	18,146,400		$	-		$	21,837,400

See accompanying notes to financial statements.

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
Cash flows from operating activities:
Net loss	$	(600,000	)	$	(6,023,700	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		1,898,700			2,361,600
Impairment		212,400			6,320,500
Non-cash loss on derivative value		633,000			210,700
Accretion of asset retirement obligations		169,700			216,300
Loss on abandonment of well		-			288,200
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(155,400	)		1,779,000
Increase in asset retirement receivable-affiliate		(69,600	)		-
Increase (decrease) in accrued liabilities		24,700			(2,900	)
Asset retirement obligations settled		(6,000	)		(557,600	)
Net cash provided by operating activities		2,107,500			4,592,100
Cash flows from investing activities:
Proceeds from sale of tangible equipment		16,300			150,000
Proceeds from sale of gas and oil properties		-			196,100
Net cash provided by investing activities		16,300			346,100
Cash flows from financing activities:
Distributions to partners		(2,133,200	)		(4,757,000	)
Net cash used in financing activities		(2,133,200	)		(4,757,000	)
Net change in cash		(9,400	)		181,200
Cash at beginning of year		181,200			-
Cash at end of year	$	171,800		$	181,200

See accompanying notes to financial statements.

ATLAS RESOURCES SERIES 28-2010 L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2016 AND 2015

NOTE 1—BASIS OF PRESENTATION

Atlas Resources Series 28-2010 L.P. (the “Partnership”) 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 Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series 28-2010 L.P.

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.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

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

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

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.

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

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation 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, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. 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 their 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 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 Partnerships’ asset retirement receivable – affiliate for the years indicated:

	December 31,
	2016		2015
Asset retirement receivable – affiliate, beginning of year	$	40,400	$	40,400
Asset retirement estimates withheld		69,600		78,900
Plugging and abandonment costs incurred		-		(78,900	)
Asset retirement receivable –affiliate, end of year	$	110,000	$	40,400

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 on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The 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 (see Note 4).

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.

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. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.

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 any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2016 and 2015.

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

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2016 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 73% and 22% 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 two customers that individually accounted for approximately 53% and 43%, 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 $858,800 and $750,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Loss on Abandonment of Well

During the year ended December 31, 2015, the Partnership plugged and abandoned the remaining Michigan well. The remaining net asset value recorded in the Partnership’s gas properties prior to plugging and abandonment was $300. This net asset value was written off as part of the net loss on abandonment of well in the Partnership’s statement of operations for the year ended December 31, 2015 and also removed from gas properties on the Partnership’s balance sheet. Plugging and abandonment costs incurred through December 31, 2015 total $557,800, of which $269,600 had been previously recorded as an asset retirement obligation, resulting in a net loss on abandonment of well of $288,200.

Comprehensive Income (Loss)

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

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of December 15, 2016 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. 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. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. At December 31, 2016 and 2015, $0 and $5,600, respectively, of net earnings resulting from the working interest adjustment were reclassified from the MGP’s capital account to the limited partners’ capital account.

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	$	5,301,300		$	5,301,300
Wells and related equipment		159,420,100			159,436,400
Total natural gas and oil properties		164,721,400			164,737,700
Accumulated depletion and impairment		(140,226,600	)		(138,115,500	)
Gas and oil properties, net	$	24,494,800		$	26,622,200

The Partnership recorded depletion expense on natural gas properties of $1,898,700 and $2,361,600 for the years ended December 31, 2016 and 2015, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion.

During the years ended December 31, 2016 and 2015, the Partnership recognized $212,400 and $6,420,500, respectively, of impairment related to gas properties. These impairments relate to the carrying amount of these gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2016 and 2015. At December 31, 2016, the MGP redetermined estimated salvage values to be lower than previous estimates. This redetermination resulted in the impairment of gas and oil properties. At December 31, 2015, the estimate of fair value of these gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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 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 $110,000 and $40,400, respectively, of net production revenue 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	$	3,793,000		$	3,846,300
Accretion expense		169,700			216,300
Settlements		(6,000	)		(269,600	)
End of year	$	3,956,700		$	3,793,000

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 contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $0 and $799,500 at December 31, 2016 and 2015, respectively.

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

	Years Ended December 31,
	2016		2015
Gain (loss) reclassified from accumulated other comprehensive income into natural gas revenues	$	3,800	$	(35,400	)
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	2,800	$	654,500

Put Premiums Payable

During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2016 and 2015, the put premiums were recorded as short-term payables to affiliate of $0 and $162,700, respectively.

The MGP has a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2016, only the Partnership’s natural gas swaps are included in the secured hedge facility.

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

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

	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	$	-	$	447,200	$	-	$	447,200
Commodity puts		-		352,300		-		352,300
Total derivative assets, gross	$	-	$	799,500	$	-	$	799,500

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

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5).

The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the years ended December 31, 2016 and 2015, the Partnership recognized $212,400 and $6,420,500, respectively, of impairment of long-lived assets which were defined as Level 3 fair value measurements (See Note 4: Property, Plant and Equipment).

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, $1,500 per well per month for New Albany wells, $600 per well per month for horizontal Antrim Shale wells and for Colorado wells a fee of $400 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of 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 incurred.

	Years Ended December 31,
	2016		2015
Administrative fees	$	66,000	$	72,800
Supervision fees		705,300		838,800
Transportation fees		539,300		721,900
Direct costs		2,363,100		2,822,100
Total	$	3,673,700	$	4,455,600

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.

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 expiring 60 months from that date. The MGP subordinated $126,600 and $731,200 of its net production revenues to the limited partners for the years ended December 31, 2016 and 2015, respectively.

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 $110,000 and $40,400, respectively, of net production revenue 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.

NOTE 10—SUBSEQUENT EVENTS

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

NOTE 11—SUPPLEMENTAL GAS INFORMATION (UNAUDITED)

Gas Reserve Information. The preparation of the Partnership’s natural gas reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved 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 review. The preparation of reserve estimates was overseen by our MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas 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 included within the Partnership are as follows (unaudited):

	Gas (Mcf)
Balance, December 31, 2014		49,648,700
Revisions ⁽¹⁾		(936,600	)
Production		(3,618,100	)
Balance, December 31, 2015⁽²⁾		45,094,000
Revisions ⁽³⁾		(8,313,100	)
Production		(2,969,300	)
Balance, December 31, 2016		33,811,600

(1)

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

(2)

We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 and 2016 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 the Partnership’s gas equivalent reserves due 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.

(3)

The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to reflect actual production.

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	$	5,301,300		$	5,301,300
Wells and related equipment		159,420,100			159,436,400
Accumulated depletion, accretion and impairment		(140,226,600	)		(138,115,500	)
Net capitalized costs	$	24,494,800		$	26,622,200

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	$	5,351,700		$	6,964,000
Production costs		(3,541,700	)		(4,317,800	)
Depletion		(1,898,700	)		(2,361,600	)
Impairment		(212,400	)		(6,320,500	)
	$	(301,100	)	$	(6,035,900	)

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⁽¹⁾
Future cash inflows	$	50,652,900		$	79,780,100
Future production costs		(25,552,100	)		(30,111,800	)
Future net cash flows		25,100,800			49,668,300
Less 10% annual discount for estimated timing of cash flows		(11,957,400	)		(25,726,900	)
Standardized measure of discounted future net cash flows	$	13,143,400		$	23,941,400

(1)

We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the year ended December 31, 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 the Partnership’s gas equivalent reserves due 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.

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

None.

ITEM 9A:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

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

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

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

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

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

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

Officers and Key Operations Employees of Our General Partner

The following table sets forth information with respect to those persons who serve as the officers of and on the board of directors of, our general partner:

Name	Age		Position(s)
Fredrick M. Stoleru		45	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. 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 board of directors extensive knowledge and experience in the areas of corporate finance, investment banking, capital markets and the energy sector.

Code of Business Conduct and Ethics

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

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

ITEM 11: EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

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

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, 2016, we had 7,500 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us for purchase, the MGP is not obligated by the Partnership Agreement to purchase more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by Titan.

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

Our Relationship with Atlas Resources, LLC

Gas Revenues. Our MGP is allocated 37.59% of our gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 10.98% of our subscriptions, its payment of 52.93% of the tangible costs and 7.77% of intangible costs of drilling and completing our wells and its contributions to us of all of our gas leases for a total capital contribution of $57,055,000. During the years ended December 31, 2016 and 2015, our MGP received net production revenues of $703,400 and $975,500, respectively.

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, $1,500 per well per month for New Albany wells, $600 per well per month for horizontal Antrim Shale wells and for Colorado wells a fee of $400 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of 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 incurred:

	Years Ended December 31,
	2016		2015
Administrative fees	$	66,000	$	72,800
Supervision fees		705,300		838,800
Transportation fees		539,300		721,900
Direct costs		2,363,100		2,822,100
Total	$	3,673,700	$	4,455,600

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

ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2016 and 2015, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:

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

Audit Committee Pre-Approval Policies and Procedures

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

PART IV

ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT INDEX

		Description
4(a)		Certificate of Limited Partnership for Atlas Resources Series 28-2010 L.P. ⁽¹⁾
4(b)		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Series 28-2010 L.P. ⁽¹⁾
4(c)		Drilling and Operating Agreement for Atlas Resources Series 28-2010 L.P^.⁽¹⁾
23.1		Consent of Wright & Company, Inc.
31.1		Rule 13a-14(a)/15(d) – 14 (a) Certification
31.2		Rule 13a-14(a)/15(d) – 14 (a) Certification.
32.1		Section 1350 Certification.
32.2		Section 1350 Certification.
99.1		Summary Reserve Report
101		Interactive Data File

(1)	Filed on April 29, 2011 in our Form 10-12G Registration Statement dated April 29, 2011 as amended, File No. 000-54378

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS RESOURCES SERIES 28-2010 L.P.

	BY:	ATLAS RESOURCES, LLC, ITS GENERAL PARTNER

Date: April 17, 2017	By:	/s/ FREDRICK M. STOLERU
		Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)

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

Date: April 17, 2017

By:

/s/ FREDRICK M. STOLERU

Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)

Date: April 17, 2017

By:

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback, Chief Financial Officer (principal financial officer and principal accounting officer)

Date: April 17, 2017

By:

/s/ MATTHEW J. FINKBEINER

Matthew J. Finkbeiner, Chief Accounting Officer (principal accounting officer)

Date: April 17, 2017

By:

/s/ DANIEL C. HERZ

Daniel C. Herz, Executive Vice President and Director

Date: April 17, 2017

By:

/s/ GARY LICHTENSTEIN

Gary Lichtenstein, Director

Date: April 17, 2017

By:

/s/ CHRISTOPHER SHEBBY

Christopher Shebby, Director

Atlas Resources Series 28-2010 L.P. 10-K