Atlas Resources Series 33-2013 10-12G Registration of securities

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10

GENERAL FORM FOR REGISTRATION OF SECURITIES

Pursuant to Section 12(b) or (g) of The Securities Exchange Act of 1934

Atlas Resources Series33-2013 L.P.

(Exact name of registrant as specified in its charter)

Delaware	61-1707524
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
425 Houston Street, Suite 300, Fort Worth, TX	76102
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class to be so registered	Name of each exchange on which each class is to be registered
None	None

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

Limited Partner Units

(Title of class)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-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 Rule12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐  (Do not check if a smaller reporting company)	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 7(a)(2)(B) of the Securities Act.  ☐

Table of Contents

Item 1 Business	2
Item 1A Risk Factors	12
Item 2 Financial Information	27
Item 3 Properties	41
Item 4 Security Ownership of Certain Beneficial Owners and Management	43
Item 5 Directors and Executive Officers	43
Item 6 Executive Compensation	45
Item 7 Certain Relationships and Related Transactions, and Director Independence	45
Item 8 Legal Proceedings	46
Item 9 Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters	46
Item 10 Recent Sales of Unregistered Securities	47
Item 11 Description of Registrant’s Securities to be Registered	47
Item 12 Indemnification of Directors and Officers	55
Item 13 Financial Statements and Supplementary Data	55
Item 14 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 15 Financial Statements and Exhibits	55

Forward Looking Statements

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

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

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

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

Presentation of Information

Unless the context otherwise requires, references in this registration statement to “the Partnership,” “we,” “us,” “our” and “our company” refer to Atlas Resources Series33-2013 L.P., a Delaware limited partnership.

Atlas Resources, LLC, or Atlas Resources or the MGP, serves as the Managing General Partner for our company. Atlas Resources is an indirect subsidiary of Titan Energy, LLC, or Titan. Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsored and currently managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P., or ARP, a Delaware limited partnership organized in 2012. Atlas Energy Group, LLC, or Atlas Energy Group, is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan.

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ITEM 1. BUSINESS.

General

We are a Delaware limited partnership formed on February 19, 2013 with Atlas Resources, LLC serving as our Managing General Partner (the “MGP”). Atlas Resources, LLC is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids (NGLs), with operations in basins across the United States. Titan also sponsored and currently managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012.

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

The Partnership has drilled and currently operates wells located in Oklahoma, Ohio and Texas.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

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

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

Employees. The Partnership has no employees and relies on the MGP for management, which in turn, relies on Atlas Energy Group for administrative services. See Item 5 “Directors and Executive Officers.”

Our Offering. Our offering was conducted in reliance on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act of 1933, as amended, or the Securities Act. All of the investors in the offering were reasonably believed by the MGP to be accredited investors at the time of sale. We broke escrow and had our first closing on May 29, 2013. When we had our final closing on December 31, 2013, we had 2,039 investors who purchased our Units. In accordance with the terms of our offering, 6,978.75 Units were sold at $20,000 per Unit, and 571.00 Units were sold at discounted prices to selling agents and their registered representatives and principals and clients of registered investment advisors, and investors who bought Units through the officers and directors of the MGP. As of December 31, 2013, the Units were held by more than 2,000 persons, and our assets exceeded $10 million.

Since inception, we have provided each investor with a monthly production and earnings statement, or the monthly statement, as supplemental information along with their monthly distribution check. The monthly statement includes pertinent details of an investor’s investment, such as invested amount, cash return, per unit distribution analysis, as well as a summary of the Partnership’s revenues and expenses, production volumes by product, average price received per product, producing well count, and management discussion and analysis commentary on the current month’s results compared to the prior month. We believe that the monthly statement, along with the other materials distributed to investors on a periodic basis, provides meaningful and timely information to our investors.

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We are filing this registration statement to register our limited partner units, or the Units, pursuant to Section 12(g) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We are subject to the registration requirements of Section 12(g) of the Exchange Act because the aggregate value of our assets exceeds the applicable threshold of $10 million and our units of record are held by more than 2,000 persons. Because of our obligation to register our Units with the Securities and Exchange Commission, or the SEC, under the Exchange Act, we will be subject to the requirements of the Exchange Act rules. We intend to comply with the disclosure obligations of the Exchange Act applicable to issuers filing registration statements pursuant to Section 12(g) of the Exchange Act.

Investment Objectives.

Our principal investment objectives are to:

• Provide monthly cash distributions to our partners until the wells are depleted, with a minimum subordinated cumulative return of capital of 96% over our 96-month (eight year) subordination period, which subordination begins with the managing general partner’s determination that proceeds of sales of natural gas or oil are being received by us from wells that represent at least 75% of our drilling and completion costs for all of our wells, and is based on $20,000 per unit for all units sold regardless of the actual subscription price paid. These subordination distributions are not guaranteed, but are subject to the MGP’s subordination obligation as described in Item 11 “Description of Registrant’s Securities to be Registered — Distributions and Subordination.”

• Offset a portion of any gross production income generated by us with tax deductions from percentage depletion.

• If you are self-employed and invest in the partnership as an investor general partner, then you may use your share of the partnership’s deductions to offset a portion of your net earnings fromself-employment.

The tax benefits of these depreciation deductions to our partners are subject to any objections by the Internal Revenue Service, or IRS, each partner’s individual tax circumstances, and the passive activity rules. Also, we do not guarantee the IRS’ treatment of our investors’ depreciation deductions for our equipment costs. If the IRS were to decrease the amount of the deductions, for example, our partners would not be entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits.

Oil and Natural Gas Properties.As of December 31, 2016, we had drilled 58.39 net productive development wells. We will not drill any additional wells. For further information concerning our natural gas and oil properties, including our leasing practices and our reserve and acreage information, see Item 3 “Properties.” We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 “Financial Information.” Thus, the subscription proceeds from the 2013 offering and our ongoing natural gas and oil production revenues from our wells will satisfy all of our cash requirements and we will not seek to raise additional funds from either our partners or new investors.

We pay the MGP a monthly well supervision fee of $1,000 per month for each vertical well in the Marble Falls primary area in north-central Texas, $2,000 per month for each horizontal well in the Mississippi Lime primary area in northern Oklahoma, and $2,000 per month for each horizontal well in the Utica Shale primary area in eastern Ohio. The well supervision fee will be proportionately reduced to the extent we acquire less than 100% of the working interest in the well. Also, the MGP’s well supervision fees are adjusted annually beginning in 2014 for inflation since January 1, 2013. If the MGP’s well supervision fee exceeds a competitive rate in the area where the well is situated, then the rate is adjusted to the competitive rate. Conversely, if in the future the MGP’s well supervision fee is less than a competitive rate in an area where a well is situated, then regardless of the inflation adjustment, the rate may be increased to the competitive rate by the MGP, as operator, as determined in its sole discretion.

The well supervision fee covers all normal and regularly recurring operating expenses for the production, delivery, and sale of natural gas, including natural gas liquids and oil, if applicable, such as:

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• well transportation, routine maintenance, and adjustment;

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

• preparing reports to the partnership and to government agencies.

The well supervision fees do not include costs and expenses related to:

• the purchase of equipment, materials, or third-party services;

• wastewater transportation, treatment or disposal; and

• rebuilding of access roads.

Production.All of our productive wells produce natural gas and/or oil, which are our only products. Our production revenues and estimated gas, oil and natural gas liquids reserves are substantially dependent on prevailing market prices for natural gas, oil and natural gas liquids We do not plan to sell any of our wells and we intend to continue to produce natural gas and/or oil until the wells are depleted, at which time they will be plugged and abandoned.

The following table shows the quantities of natural gas and oil produced (net to our interest), average sales price, and average production (lifting) cost per equivalent unit of production for the periods indicated.

	Years Ended December 31,						Period February 19, 2013 through December 31,
	2016		2015		2014		2013
Production volumes:
Gas (mcf/day)		5,535		9,673		13,767		1,365
Oil (bbls/day)		117		281		826		113
Liquids (bbls/day)		286		526		924		132
Total (mcfe/day)		7,953		14,515		24,267		2,835
Average sales price:(1)
Gas (per mcf)	$	2.00	$	2.14	$	3.75	$	3.53
Oil (per bbl)	$	38.52	$	48.25	$	94.84	$	99.69
Liquids (per bbl)	$	11.82	$	12.97	$	34.39	$	36.95
Production costs:
Per Mcfe	$	1.44	$	1.69	$	1.97	$	1.60

(1) Average gas, oil, and NGL pricing are calculated by dividing total revenue for each product by the respective volume for the period.

Drilling Activity.

We received total cash subscriptions from investors of $149,966,975, which were paid to the MGP acting as operator and general drilling contractor under our drilling and operating agreement. We used all of our subscription proceeds to drill and complete 97 development wells located in north-central Texas, eastern Ohio and northern Oklahoma. Under our partnership

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agreement, all of the subscription proceeds of our investors were used to pay the intangible drilling costs of our wells and a portion of the tangible costs. “Intangible drilling costs” generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. “Tangible costs” generally means the equipment costs of drilling and completing a well that are not currently deductible as intangible drilling costs and are not lease costs. The MGP contributed all of the leases on which our wells are situated, paid and/or contributed services towards our organization and offering costs up to an amount equal to 15% of our investors’ subscription proceeds and paid all of our equipment costs to drill and complete our wells that were not paid with our investors’ subscription proceeds. As of December 31, 2016, the aggregate amount of these contributions by the MGP was $56,644,554.

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 we expect that no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by us:

	Development Wells
	Productive(1)
	Gross (2)		Net (3)
February 19, 2013 through December 31, 2013		74.00		47.28
January 1, 2014 through December 31, 2014		97.00		58.40
January 1, 2015 through December 31, 2015		97.00		56.88
January 1, 2016 through December 31, 2016		97.00		56.88

(1) A “productive well” generally means a well that is not a dry hole.

(2) A “gross” well is a well in which we own a working interest.

(3) A “net” well equals the actual working interest we own in one gross well divided by one hundred. For example, a 50% working interest in a well is one gross well, but a .50 net well.

Natural Gas Leases.The MGP contributed all the undeveloped leases or lease interests necessary to drill each of our wells. The MGP received a credit to its capital account equal to the cost of each lease or the fair market value of each lease if the MGP had reason to believe that cost was materially more than the fair market value.

Gathering ofNaturalGas.Under our partnership agreement, the MGP is responsible for gathering and transporting the natural gas produced by us to interstate pipeline systems, local distribution companies, and/or end-users in the area. Our natural gas production is primarily transported through our flow lines from our wells, processed, if necessary, and then transported for sale as discussed in “– Natural Gas and Natural Gas Liquids Contracts,” below.

Natural Gas and Natural Gas Liquids Contracts.The natural gas and natural gas liquids purchaser or purchasers for each primary area where we operate our wells are set forth below:

• The liquids-rich natural gas produced from the Utica Shale primary area in eastern Ohio is transported by Blue Racer Midstream, LLC, a joint venture between Dominion Resources, Inc. and Caiman Energy II, LLC to one of several gas processing facilities accessible through Blue Racer and the liquids and residue gas will be marketed from those plants. Texas Eastern Transmission, Tennessee Gas Pipeline, or Dominion Transmission pipelines are the interstate gas pipelines used by the partnership to access natural gas markets. The natural gas liquids are marketed at the tailgate of the processing plant(s) under various marketing contracts.

• The natural gas and natural gas liquids produced from the Mississippi Lime primary area in northern Oklahoma is sold primarily at the tailgate of SemGas processing plants in the area under a contract with SemGas, LP. The natural gas liquids receive a price based on values at the Conway Kansas Group 140 Hub and the tailgate gas receives a price based on SemGas sales from the plants to various pipelines.

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• the majority of the Marble Falls production is gathered and processed by Enbridge G&P at its Weatherford Plant in Jack County, Texas. Enbridge G&P markets the liquid products based on Mt. Belvieu pricing, which represents the largest and most active natural gas liquids markets in the United States, and returns 92% of the proceeds from the sale of our natural gas and natural gas liquids production to us. The tailgate residue gas is transported by Enbridge G&P to Enterprise Products Operating where it is sold based on a WAHA index. The WAHA index is one of the most frequently referenced pricing indices for central and west Texas production.

All of the natural gas and natural gas liquids contracts, including those described above, are between the natural gas purchaser and Atlas Energy Group, Titan or the MGP or their affiliates. Also, the pricing and delivery arrangements with the vast majority of purchasers described above in the Utica Shale primary areas are tied to the settlement of the New York Mercantile Exchange Commission, or NYMEX, monthly futures contracts price, and production in the Mississippi Lime and Marbles Falls primary areas is priced based on the reported daily prices in Platts Gas Daily or other industry publications. Either the MGP or its affiliates receive the sales proceeds from the purchasers and then distribute the sales proceeds to us based on the volume of natural gas and natural gas liquids produced and sold. Until the sales proceeds are distributed to us, they will be subject to the claims of the MGP’s or its affiliates’ creditors.

Hedging Arrangements.To limit exposure to changes in natural gas and oil prices in the future, the MGP and its affiliates, including Atlas Energy Group and Titan, may use financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulatedover-the-counter futures contracts with qualified counterparties. They also may use physical hedges through their natural gas and oil purchasers as discussed below. The futures contracts employed by the MGP and its affiliates are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to 60 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the MGP has established a risk management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. The MGP does not contract for positions that it cannot offset with actual production. Any physical hedges require firm delivery of natural gas or oil and, therefore, are considered normal sales of natural gas and oil, rather than hedges, for accounting purposes. The percentages of natural gas and oil that are hedged through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of the MGP and its affiliates.

The MGP has entered into a secured hedge facility agreement with Wells Fargo Bank, National Association, as collateral agent, and certain hedge counterparties that permits certain partnerships sponsored by the MGP, including us, to engage in hedging arrangements. The secured hedge facility agreement is a pooled security agreement under which partnerships that join it, “participating partnerships,” provide credit support to the counterparties of their hedge transactions. Before executing any hedge transaction, a participating partnership will be required to: (i) enter into an ISDA Master Agreement with a hedge provider under the secured hedge facility agreement; and (ii) provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the hedge providers. The collateral provided by each participating partnership will secure only that partnership’s hedge obligations, and will not secure the hedge obligations of any other participating partnership. In addition, all obligations under the secured hedge facility agreement will be guaranteed by the MGP. Also, we may enter into our own agreements and financial instruments relating to hedging our natural gas and oil and the pledging of up to 100% of our assets and reserves in connection therewith. Although entering into hedging arrangements may provide us some protection against changing prices, these activities could reduce the potential benefits of price increases and we could incur liability on the financial hedges.

Crude Oil.Crude oil produced from our wells flows directly into storage tanks where it is picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. The MGP sells oil produced by our wells to regional oil refining companies at the prevailing spot market price. The MGP received an average selling price for oil of approximately $38.52 per barrel in 2016, $48.25 per barrel in 2015, $94.84 per barrel in 2014 and $99.69 per barrel in 2013.

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Major Customers.Our natural gas and oil is sold to various purchasers. For the year ended December 31, 2016, sales to SemGas LP, Phillips 66 Company, Castleton Com Merchant Trading, Midcoast Energy Partners, and South Jersey Resource Group accounted for approximately 27%, 16%, 16%, 14%, and 11% of our total revenues, respectively. For the year ended December 31, 2015, SemGas, LLC, Phillips 66 Company, Hess Energy Marketing, LLC, Midcoast Energy Partners, and Enterprise Crude Oil, LLC accounted for approximately 28%, 20%, 13%, 13% and 13%, respectively, of our total natural gas, oil, and NGL production revenues. For the year ended December 31, 2014, Phillips 66 Company, SemGas, LP and Enterprise Crude Oil, LLC accounted for approximately 29%, 29% and 21%, respectively of our total natural gas, oil, and NGL production revenues. For the period February 19, 2013 through December 31, 2013, Enterprise Crude Oil LLC, SemGas, L.P., Phillips 66 Company and Enbridge Texas Energy accounted for approximately 41%, 24%, 18%, and 13% of our total natural gas, oil, and NGL production revenues. No other customer accounted for more than 10% of our total revenues for the years ended December 31, 2016, 2015, 2014 and 2013, respectively.

Competition.We operate in a highly competitive environment for contracting for drilling equipment and securing trained personnel. Competition also arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, crude oil and natural gas liquids. 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 natural gas and oil produced by our wells must be marketed in order for us to receive revenues. The availability of a ready market for natural gas, oil and natural gas liquids and the price obtained, depends on numerous factors beyond our control. During the years ended 2016, 2015, 2014 and 2013, we did not experience any problems in selling the natural gas, oil and natural gas liquids produced from our wells, although prices varied significantly during those periods.

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

Environmental Matters and Regulation.

Our operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

• restricting the way waste disposal is handled;

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

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

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

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

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

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

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• 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, nuisance, or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The legal burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal andclean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

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

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

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

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

Water Discharges.The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations impose a number of different types of requirements on our operations. First, these laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. On June 28, 2016, EPA finalized Effluent Limitations Guidelines and Standards for the Oil

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and Gas Extraction Category (40 CFR Part 435), effectively prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and natural gas operations. Second, the Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The precise definition of “waters of the United States” subject to thedredge-and-fill permit requirement has been enormously complicated and is subject toon-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 ornon-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.

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

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

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 ofnon-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 oil and natural gas constitute “solid wastes,” which are regulated under the less stringentnon-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling ofnon-hazardous wastes or categorize somenon-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” EPA’s oversight of oil and natural gas wastes was

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recently challenged in federal court, and the court approved a consent decree in December 2016 where EPA agreed to evaluate and, if necessary, propose rulemaking to revise the current regulations by March 15, 2019. The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA or comparable state law requirements. We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations. More stringent regulation of natural gas and oil exploration and production wastes could increase the costs to manage and dispose of such wastes.

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

OSHA and Chemical Reporting Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. On March 25, 2016, OSHA published its final Occupational Exposure to Respirable Crystalline Silica final rule, which imposes specific requirements to protect workers engaged in hydraulic fracturing. 81 Fed. Reg. 16,285. The requirements of that final rule as it applies to hydraulic fracturing become effective June 23, 2018, except for the engineering controls component of the final rule, which has a compliance date of June 23, 2021. We expect implementation of the rule to result in significant costs. The OSHA hazard communication standard, the EPA communityright-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 whichcommunity-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. The various states regulate the exploration, development, production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the

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NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2016, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and, contingent on continued production of the well, the fee can continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.

States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill.

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

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

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

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Item 1A. Risk Factors

Statements made by us that are not strictly historical facts are “forward looking” statements that are based on current expectations about our business and assumptions made by the MGP. These statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than those predicted.

Risks Related To Our Business

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

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

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

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

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

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

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

• overall domestic and global economic conditions;

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

• technological advances affecting energy consumption;

• domestic and foreign governmental relations, regulations and taxation;

• the impact of energy conservation efforts;

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

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

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

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

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

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

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

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate as discussed in Item 3 “Properties.” Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, will likely result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

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

• actual prices we receive for natural gas;

• the amount and timing of actual production;

• the amount and timing of our capital expenditures;

• supply of and demand for natural gas; and

• changes in governmental regulations or taxation.

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

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

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

Bills have been introduced in Congress since 2009 that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of

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nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, Pennsylvania has adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring some degree of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations.

Risks Related to an Investment in the Partnership

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

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

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

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

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

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

We do not have any officers, directors or employees. Instead, we rely totally on our managing general partner and its affiliates for our management. Our managing general partner is required to devote to us the time and attention that it considers necessary for the proper management of our activities. However, our managing general partner and its affiliates currently are, and will continue to be, engaged in other natural gas and oil activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during our term. This creates a continuing conflict of interest in allocating management time, services, and other activities among us and its other activities. If our managing general partner does not devote the necessary time to our management, there could be delays in providing timely annual and semi-annual reports, tax information and cash distributions to our participants. Also, if our managing general partner, serving as the operator of our wells, does not supervise the wells closely enough, for example, there could be delays in undertaking remedial operations on a well, if necessary to increase the production of natural gas or oil from the well.

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

Pursuant to our partnership agreement, our general partner will receive reimbursement for the provision of various general and administrative services for our benefit. Payments for these services will be substantial, are not subject to any aggregate limit, and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership

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law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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

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

Our proved reserves at December 31, 2016 are set forth in Item 3 “Properties.” However, there is an element of uncertainty in all estimates of proved reserves, and current conditions, such as natural gas and oil prices and the costs of operating our wells and transporting our natural gas, will change in the future and could reduce the amount of our current proved reserves.

We base our estimates of proved natural gas and oil reserves and future net revenues from those reserves on various assumptions, including those required by the SEC, such as natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in the future in these assumptions based on actual production, natural gas and oil prices, taxes, development expenses, operating expenses, or availability of funds, would materially affect the estimated quantity of our reserves as discussed in Item 3 “Properties.”

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

• the actual production history of our wells;

• results of future exploration and development in the area;

• decreases in natural gas and oil prices;

• governmental regulation; and

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

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

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Production and sales of natural gas and oil are subject to extensive federal, state and local regulations. We discuss our regulatory environment in more detail in Item 1 “Business—Environmental Matters and Regulation.” We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Also, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income.

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

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

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

• impose substantial liabilities for pollution resulting from our operations.

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These laws include, for example:

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

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

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

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

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

• assessment of administrative, civil, and criminal penalties;

• incurrence of investigatory or remedial obligations; or

• imposition of injunctive relief.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We will depend on a limited number of natural gas purchasers to purchase the majority of our natural gas production. Further, we will not be guaranteed a specific natural gas price, unless we engage in hedging in the future. Thus, if our current purchasers were to pay a lower price for our natural gas in the future, our revenues would decrease. Also, if our current purchasers began buying a reduced percentage of our natural gas, or stopped buying any of our natural gas, the sale of our natural gas would be delayed until we found other purchasers, and the substitute purchasers we found may pay lower prices for our natural gas, which would reduce our revenues.

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

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

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

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

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We have identified a deficiency in our disclosure controls and procedures and we may identify other significant control deficiencies in the future.

We did not maintain effective disclosure controls and procedures to ensure that we registered our limited partner units pursuant to Section 12(g) of the Exchange Act in a timely manner. Our offering was conducted in reliance on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act. Upon our final closing on December 31, 2013, we had 2,039 investors who purchased our Units and our assets exceeded $10 million, which required us to file a registration statement to register our Units with the SEC under the Exchange Act. As a result, our registration statement has been delinquently filed.

We have taken steps to remediate our ineffective disclosure controls and procedures, but there can be no assurance that we will be successful in pursuing these measures or that these measures will significantly improve or remediate our ineffective disclosure controls and procedures in the future. We also cannot assure you that we have identified all of our existing disclosure controls and procedures deficiencies.

Because of our obligation to register our Units with the SEC, we will be subject to the requirements of the Exchange Act. We intend to comply with our disclosure obligations under the Exchange Act applicable to issuers filing registration statements pursuant to Section 12(g) of the Exchange Act. We have designed our disclosure controls and procedures to ensure information required to be disclosed in our Exchange Act 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. Even with this filing, there can be no assurance that we have remediated our ineffective disclosure controls and procedures or that we will be successful in our ability to accurately and timely report our financial information in the future, which could result in late filings of our annual and quarterly reports under the Exchange Act or restatements of our financial statements.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report financial results or prevent fraud, which could have an adverse effect on our business and financial condition.

Effective internal controls are necessary to provide reliable financial reports and to assist in the effective prevention of fraud. Any inability to provide reliable financial reports or prevent fraud could harm our business. The Sarbanes-Oxley Act of 2002 requires, among other things, that we perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting. If we are not able to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our independent registered public accounting firm identifies deficiencies in our internal control over financial reporting that are deemed to be material weaknesses, investors could lose confidence in the accuracy and completeness of our financial reports and we could be subject to sanctions, investigations by the SEC or other regulatory authorities, or unitholder litigation.

In connection with the preparation of our financial statements for the year ended December 31, 2016, our management identified several control deficiencies that constituted an overall material weakness in our internal control over financial reporting. Specifically, the material weakness resulted from an insufficient review of financial information and support for accrual estimates,non-standard transactions, and the prices used to determine our estimated future cash flows for evaluating our gas and oil properties for impairment. As such, our controls over financial reporting were not operating effectively as the control deficiencies resulted in a reasonably possible likelihood that a material misstatement of our annual financial statements would not be prevented or detected.

We reperformed our impairment analysis with the correct prices and concluded that the estimated future cash flows exceeded the carrying values of our gas and oil properties, resulting in no impairments for the year ended December 31, 2016. We also reperformed our review of various accrual estimates and recorded corresponding adjustments in the financial statements for each of the periods presented. Management is in the process of implementing a remediation plan to address the material weakness but there can be no assurance that we will be successful in pursuing these measures or that these measures will significantly improve or remediate the control deficiencies and overall material weakness described above. Management’s remediation plan to address the deficiency consists of a more formal review of key inputs and assumptions associated with significant estimates and a more thorough review of the financial statements and related supporting information. There is no assurance that we have identified all of our material weaknesses or that we will not in the future have additional material weaknesses. There is no assurance that in the future, additional material weaknesses will not exist or otherwise be discovered. If our efforts to remediate the material weakness described above are not successful, or if other material weaknesses or other deficiencies occur, our ability to accurately and timely report our financial position could be impaired, which could result in late filings of our annual and quarterly reports under the Exchange Act or restatements of our financial statements.

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

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

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

Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and our managing general partner will test our respective oil and gas properties on afield-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our or our managing general partner’s own economic interests and our respective plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and our managing general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, declines in the price of natural gas and oil have caused the carrying values of properties in many of our managing general partner’s previous partnerships to exceed the expected future cash flow. Future declines in the price of natural gas or oil may cause the carrying value of our, our managing general partner’s or its other partnerships’ oil and gas properties to exceed the expected future cash flows, and require an impairment loss to be recognized.

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

There is currently no public market for our units. As of the date of this registration statement, there are approximately 7,550 units outstanding. It is unlikely that investor interest will lead to the development of a trading market, and any such market would likely be illiquid. You may not be able to resell your units at a price you find attractive, or at all. Additionally, the lack of liquidity may result in widebid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

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

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

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

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

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

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

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

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

The managing general partner’s interest in us may be transferred to an affiliate, and the control of the managing general partner may be transferred to a third-party, without the investors’ consent.

The managing general partner may transfer its managing general partner interest in us to an affiliate without the consent of you and the other investors. Furthermore, our partnership agreement does not restrict the ability of the owners of the managing general partner to transfer all or a portion of their ownership interest in the managing general partner to a third-party. The new owner of the managing general partner would then be in a position to replace the governing board and officers of the managing general partner with their own choices and thereby influence the decisions made by the managing general partner.

Our Total Annual Cash Distributions During Our First Five Years May be Less Than $20,000 Per Unit, Even With Subordination.

Our partnership agreement is structured to provide our participants with cumulative cash distributions equal to at least 12% of capital ($2,400 per $20,000 unit) in each of eight12-month subordination periods beginning when the managing general partner determines that proceeds of sales of natural gas or oil are being received by us from at least 75% of our wells, excluding any wells drilled that were nonproductive. To help achieve this investment feature, under our partnership agreement the managing general partner will subordinate up to 50% of its share of our partnership net production revenues during this subordination period. The term “partnership net production revenues” means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related Operating Costs, Direct Costs, Administrative Costs, and all other costs not specifically allocated in the partnership agreement. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination, a participant may not receive the return of capital during the96-month subordination period, or a return of all of his capital during our term,

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because the subordination is not a guarantee. Also, at any time during the96-month aggregate subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent our participants’ cash distributions from us would exceed the return of capital described above. A more detailed discussion of the managing general partner’s subordination obligation is set forth in Item 11 “Description of Registrant’s Securities to be Registered — Distributions and Subordination.”

The proceeds from the sale of our natural gas and oil will be subject to claims of the managing general partner’s and our affiliates’ creditors until the sales proceeds are paid to us.

All of the contracts for the sale and purchase of our natural gas and oil production may be between the purchaser and either Atlas Energy Group or Titan. In that event, either Atlas Energy Group, Titan or an affiliate, including our managing general partner as operator under our drilling and operating agreement, will receive the sales proceeds from the purchasers and then distribute the sales proceeds to us based on the volume of natural gas and oil produced and sold by us. Until the sales proceeds are distributed to us, they will be subject to the claims of Atlas Energy Group’s, Titan’s, our managing general partner’s or their affiliates’ creditors.

The managing general partner may not meet its capital contributions, indemnification and purchase obligations if its liquid net worth is not sufficient.

The managing general partner has made commitments to you and the other investors in us regarding the following:

• the payment of all of our organization and offering costs and 5% of our equipment costs;

• indemnification of the investor general partners for liabilities in excess of their pro rata share of our assets and insurance proceeds, which commitment the managing general partner has made in virtually all of the previous partnerships it has sponsored; and

• purchasing units presented by an investor, although this feature may be suspended by the managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds or arrange other consideration for this purpose on reasonable terms.

However, a significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations as discussed below.

The managing general partner’s net worth is based primarily on the estimated value of its producing natural gas properties and is not available in cash without borrowings or a sale of the properties. If natural gas prices decrease further, then the estimated value of the properties and the managing general partner’s net worth will be reduced since the majority of the managing general partner’s proved reserves are currently natural gas reserves, and the managing general partner’s net worth is more susceptible to movements in natural gas prices than in oil prices. Also, natural gas price decreases will reduce the managing general partner’s revenues, and may make some oil and gas reserves uneconomic to produce. This would reduce the managing general partner’s reserves and cash flow, and could cause the lenders of the managing general partner and its affiliates to reduce the borrowing base for the managing general partner and its affiliates.

The managing general partner’s net worth may not be sufficient, either currently or in the future, to meet its financial commitments under our agreement. These risks are increased because the managing general partner has made similar financial commitments in most of its other partnerships and it expects to make the same financial commitments in future partnerships. In addition, because of the current tight credit market in the United States, there is a risk that Titan’s credit facility could be adversely affected.

Compensation and fees to the managing general partner regardless of success of our activities will reduce cash distributions.

The managing general partner and its affiliates will profit from their services in operating our wells, and will receive the other fees and reimbursement of direct costs, regardless of the success of our wells. These fees and direct costs will reduce the amount of cash distributions to you and the other investors. The amount of the fees is subject to the complete discretion of

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the managing general partner, other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and there must be compliance with any other restrictions. With respect to direct costs, the managing general partner has sole discretion on behalf of us to select the provider of the services or goods and the provider’s compensation.

Conflicts of interest between the managing general partner and the investors may not necessarily be resolved in favor of the investors.

There are conflicts of interest between you and the other investors and the managing general partner and its affiliates. These conflicts of interest, which are not otherwise discussed in this “Risk Factors” section, include the following:

• the managing general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with us without any unaffiliated third-party dealing at arms’ length on behalf of you and the other investors;

• the managing general partner must monitor and enforce, on behalf of us, its own compliance with the drilling and operating agreement and our agreement;

• the determination of the amount and timing of cash distributions from us and the amount of cash reserved by us for future contingencies, including the eventual plugging and abandonment of our wells;

• because the managing general partner will receive a greater percentage of revenues beginning when you and the other investors have received cash distributions from us equal to 100% (excluding tax benefits) of our total offering proceeds (based on $20,000 per unit for all units sold regardless of the actual subscription price you paid for your units), which is not guaranteed, there may be a conflict of interest concerning which wells will be drilled based on each well’s risk and profit potential;

• the allocation of all intangible drilling costs and 95% of the equipment costs to you and the other investors, and the allocation of all organization and offering costs and lease acquisition costs and 5% of the equipment costs to the managing general partner, may create a conflict of interest concerning the managing general partner’s selection, in its sole discretion, of our prospects or whether to drill or complete a well;

• if the managing general partner, as tax matters partner, represents us before the IRS, potential conflicts include, for example, whether or not to expend our funds to contest a proposed adjustment by the IRS, if any, to the amount of your deduction for intangible drilling costs, or the credit to the managing general partner’s capital account for paying our organization and offering costs;

• the managing general partner’s policies and procedures for allocating hedging production volumes and hedging settlements between it and the managing general partner’s partnerships, including this partnership, includes many subjective determinations, which are in the managing general partner’s discretion;

• the managing general partner and its officers, directors, and affiliates may purchase units at a reduced price, which would dilute the voting rights of you and the other investors on certain matters; and

• the same legal counsel represents the managing general partner and us.

Other than certain guidelines, the managing general partner has no established procedures to resolve a conflict of interest. Also, we do not have an independent investment committee. Thus, certain matters, including conflicts of interest between us and the managing general partner and its affiliates may not be resolved as favorably to you and the other investors as they would be if there was an independent investment committee.

We may incur costs in connection with exchange act compliance and become subject to liability for any failure to comply.

Compliance with the reporting requirements under the Exchange Act would require us to timely file quarterly reports on Form10-Q, annual reports on Form10-K and current reports on Form8-K, among other actions, and comply with corporate governance and disclosure requirements under the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). This would increase our costs to you and the other investors.

In addition, compliance with the Exchange Act, the Sarbanes-Oxley Act and their related rules and regulations, would be new legal grounds for administrative enforcement and civil and criminal proceedings against us in case ofnon-compliance, which increases our risks of liability and potential sanctions.

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Future hedging activities may adversely affect our financial situation and results of operations.

The managing general partner anticipates that we will engage in hedging activities in the future to help reduce, but not eliminate, the potential adverse effects of changing natural gas and oil prices on a portion, which may be substantial, of our cash flow from the sale of our natural gas and oil production for the periods covered by the hedges.

In this regard, the managing general partner has entered into a secured hedge facility agreement with a syndicate of banks that permits certain partnerships sponsored by the managing general partner, including us, to engage in hedging arrangements. The secured hedge facility agreement is a pooled security agreement under which partnerships that join it (“participating partnerships”) will provide credit support to the counterparties of their hedge transactions. Before executing any hedge transaction, a participating partnership will be required to: (i) enter into an ISDA Master Agreement with a hedge provider under the secured hedge facility agreement; and (ii) provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the hedge providers. The managing general partner anticipates that we will join the secured hedge facility agreement as a participating partnership.

The secured hedge facility agreement contains covenants that limit each participating 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. The events which constitute an event of default under the secured hedge facility agreement are customary for security agreements of this nature, including breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. In addition, it will be an event of default if: (i) an event of default, termination event or additional termination event occurs with respect to any participating partnership ISDA Master Agreement; and (ii) if a payment default, insolvency event or financial covenant default occurs under ARP’s credit facility or its credit facility indebtedness is otherwise accelerated. Upon an event of default, a hedge counterparty would be entitled to foreclose its lien on our assets, and we could be forced to liquidate our wells and other assets at a time and at prices that would otherwise be unacceptable to us, which could reduce, or even eliminate, future distributions from us to you and the other investors in us.

Also, our future hedging activities, depending on the hedging instrument used, could reduce the potential benefits of price increases if natural gas or oil prices were to rise substantially over the price established by the hedge, and we could incur liability on financial hedges. For example, we would be exposed to the risk of a financial loss if any of the following occurred:

• our production is less than expected;

• a counterparty is unable to satisfy its obligations; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and oil and are considered normal sales of natural gas. We will generally limit these arrangements to smaller quantities than those projected to be available at any delivery point. In addition, the managing general partner anticipates that we will enter into financial hedges, which may include, for example, purchases of regulated NYMEX futures and options contracts andnon-regulatedover-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas and oil at future dates and generally coverone-month periods for up to six years in the future. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Also, our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

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The failure by counterparties to our derivative risk management activities to perform their obligations could have a material adverse effect on our results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under our derivative arrangements, such a default could have a material adverse effect on our results of operations, and could result in a larger percentage of our future production being subject to commodity price changes.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production will sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we receive could significantly reduce our cash available for distribution to you and the other investors and adversely affect our financial condition. Also, the managing general partner anticipates that the relevant benchmark price will be used to calculate our hedge positions, and we do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we may experience in respect of our oil and natural gas production, if any. Accordingly, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.

Severance taxes and other taxes/fees could materially increase our liabilities.

In an effort to offset budget deficits and fund state programs, many states have imposed severance taxes on the natural gas and oil industry. In addition, certain states have imposed other taxes/fees. For example, in February 2012 the Commonwealth of Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. The impact fee is based upon the year a well is spudded and varies, like most severance taxes, based upon natural gas prices.

Currently the states in which we operate are only affected by severance taxes, although any new or additional taxes or fees in the future will reduce our cash flow and may reduce distributions to you and the other investors.

A cyber incident or a terrorist attack could result in information theft, data corruption, operational disruption and/or financial loss.

The managing general partner has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate its businesses, to process and record financial and operating data, communicate with its employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves, and engage in other activities related to its businesses. Strategic targets, such as energy-related assets, may be at greater risk of future cyber or terrorist attacks than other targets in the United States. Deliberate attacks on, or security breaches in the managing general partner’s systems or infrastructure, or the systems or infrastructure of third parties or the cloud, could lead to corruption or loss of proprietary data and potentially sensitive data, delays in production or delivery, challenges in maintaining our books and records and other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerability to cyber incidents.

Federal Income Tax Risks

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. We were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

Although the anticipated tax benefits of an investment in us depend largely on us being treated as a partnership for federal income tax purposes, we have not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter that affects us. In this regard, current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. Also, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income tax, franchise tax or other forms of taxation.

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If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%. Distributions to you and the other investors in us would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you or the other investors in us. Accordingly, if an income tax or other entity-level tax is imposed on us, our cash available for distribution to you and the other investors could be reduced.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal and state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal and state income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the increase of the amortization period of geological and geophysical expenses, (iii) the elimination of current deductions for intangible drilling and development costs; and (iv) the elimination of the deduction for certain U.S. production activities. Moreover, other generally applicable features of proposed tax reform legislation, such as changes to the deductibility of interest expense, the cost recovery rules and the types of income subject to federal income taxes could impact our income taxes and resulting operating cash flow. The passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us or otherwise affect our U.S. federal income tax liability and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for petroleum products and thereby affect the prices we receive for our commodity products. In December 2017, Congress enacted, and the President signed, significant changes to the federal income tax code as part of the Tax Cuts and Jobs Act. These changes will be effective for taxable years beginning after December 31, 2017. We are currently evaluating the impact of these changes on our business and operations. You are urged to consult with your tax advisors with respect to these changes and their potential effect on your investment in us.

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

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

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

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

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

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

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

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Investment interest deductions of investor general partners may be limited.

If you invest in us as an investor general partner, your share of our deduction for intangible drilling costs in 2017 will reduce your investment income for purposes of calculating whether the amount of your deductible investment interest expense, if any, is limited under the Internal Revenue Code.

Investors in us may be subject to state and local taxes and tax return filing requirements as a result of investing in us.

In addition to U.S. federal income taxes, investors will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes and tax return filing requirements that are imposed by the various jurisdictions in which we drill wells or otherwise do business now or in the future, even if investors do not reside in any of those jurisdictions. We presently anticipate that all or substantially all of our wells will be drilled in Texas (Texas currently does not impose a state income tax), although we may drill wells in other states as well. It is each investor’s responsibility to file all federal, foreign, state and local tax returns that may be required of such individual investor.

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

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

Our deductions may be challenged by the IRS.

The IRS may audit our annual federal information income tax returns, particularly since our investors were eligible to claim deductions for intangible drilling costs in 2013. If we are audited, the IRS may audit investors’ personal federal income tax returns, including prior years’ returns and items that are unrelated to us. Any adjustments made by the IRS to the federal information income tax returns of us could lead to adjustments on an investor’s personal federal income tax returns and could reduce the amount of your deductions from us.

It may be many years before you receive any marginal well production credits, if ever.

There is a federal income tax credit if qualified marginal natural gas and oil production is sold at relatively low prices as determined each year under the Internal Revenue Code. Currently, natural gas and oil prices are above the applicable reference prices under the Internal Revenue Code at which the marginal well production credit is reduced to zero. Thus, you may not receive any marginal well production credits from us for many years, if ever.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders could be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders could be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

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Item 2. Financial Information

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

As explained above, except as otherwise indicated or unless the context otherwise requires, the information included in this discussion and analysis assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Unless the context otherwise requires, references in this information statement to “we,” “us,” “our,” “the Partnership” and “our company” refer to Atlas Resources Series33-2013 L.P., a Delaware limited partnership.

Business Overview

We are a Delaware limited partnership formed on February 19, 2013 with Atlas Resources, LLC serving as our Managing General Partner. Atlas Resources, LLC is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids (NGLs), with operations in basins across the United States. Titan also sponsors and managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012.

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

The Partnership has drilled and currently operates wells located in Oklahoma, Ohio and Texas.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

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

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

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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 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 continue to remained low in 2017. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership 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 remained low in 2017. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of a downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

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

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility (which has been superseded by subsequent amendments as described further below). The amendment provides for, among other things, waivers ofnon-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales ofnon-core assets, which include the sale of its Appalachian and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien credit facility. Titan’s strategy is to continue to sellnon-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

On April 21, 2017, the lenders under the Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

On May 4, 2017, Titan entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell its conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). On June 30, 2017, Titan completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirements to reduce its first lien credit facility borrowings below $360 million as required by August 31, 2017.

On September 27, 2017, the lenders under Titan’s second lien credit facility entered into a letter agreement with Titan and its lenders under the first lien credit facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the second lien credit facility lenders agreed to extend the180-day standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the first lien credit facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide Titan with additional time to negotiate proposed amendments to each of the first lien credit facility and the second lien credit facility.

On September 29, 2017, Titan completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under its first lien credit facility.

On November 6, 2017, Titan entered into a fourth amendment to its first lien credit facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming andnon-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires Titan to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of thenon-conforming tranche of the borrowing base was confirmed as May 1, 2018. Titan is required to use proceeds from asset sales to make prepayments.

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In addition to the requirements above, the first lien credit facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the first lien credit facility and (iii) the exercise of remedies under its second lien credit facility. Pursuant to the fourth amendment, Titan is required to hedge at least 50% and 80% of its 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively.

In connection with, and as a condition to, the effectiveness of the fourth amendment to the first lien credit facility, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until December 29, 2017.

On December 19, 2017, Titan entered into a limited waiver agreement with respect to its first lien credit facility (the “Limited Waiver”). The Limited Waiver has an effective date of December 8, 2017. Pursuant to the Limited Waiver, the lenders agreed to a further limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) January 31, 2018, (ii) the occurrence of additional events of default under the first lien facility and (iii) the exercise of remedies under Titan’s second lien credit facility.

In connection with, and as a condition to, the effectiveness of the Limited Waiver, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until February 22, 2018.

On February 2, 2018, Titan entered into the first amendment (the “Amendment”) to the Limited Waiver. The Amendment has an effective date of January 31, 2018. Pursuant to the Amendment, the lenders agreed to extend the length of the waiver from January 31, 2018 to February 15, 2018.

In connection with, and as a condition to, the effectiveness of the Amendment, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until March 8, 2018.

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.

General Trends and Outlook

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

The natural gas and oil commodity price markets have suffered significant declines during the fourth quarter of 2014 and remained low in 2017. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas and oil production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas and oil reserves.

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

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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, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We paid the MGP, as operator, a monthly well supervision fee, which covered all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

• Well tending, routine maintenance and adjustment;

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

• Preparation of reports for us and government agencies.

The well supervision fees, however, did not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses were incurred, we were charged the costs for third-party services, materials, and a competitive charge for service performed directly by the MGP or its affiliates. Also, beginning one year after each of our wells was placed into production, the MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2017, the MGP withheld $119,100 of net production revenue for this purpose.

Nine Months Ended September 30, 2017 as compared to Nine Months Ended September 30, 2016

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

	Nine Months Ended September 30,
	2017			2016
Production revenues (in thousands):
Gas	$	3,067		$	3,005
Oil		1,044			1,267
Liquids		955			911
Total	$	5,066		$	5,183
Production volumes:
Gas (mcf/day)		4,065			5,893
Oil (bbls/day)		82			126
Liquids (bbls/day)		197			307
Total (mcfe/day)		5,739			8,491
Average sales price: (1)
Gas (per mcf)	$	2.76			1.86
Oil (per bbl)	$	46.85			36.65
Liquids (per bbl)	$	17.78			10.83
Production costs:
As a percent of revenues		49	%		66	%
Per mcfe	$	1.60		$	1.46
Depletion per mcfe	$	0.65		$	0.54

(1) Average gas, oil, and NGL pricing are calculated by dividing total revenue for each product by the respective volume for the period.

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Natural Gas Revenues. Our natural gas revenues were $3,066,400 and $3,005,100 for the nine months ended September 30, 2017 and 2016, respectively, an increase of $61,300 (2%). The increase in natural gas revenues was attributable to a $1,001,400 increase in natural gas prices after the effects of financial hedges, which were driven by market conditions, partially offset by a $940,100 decrease in production volumes. Our production volumes decreased to 4,065 mcf per day for the nine months ended September 30, 2017 from 5,893 mcf per day for the nine months ended September 30, 2016, a decrease of 1,828 (31%) mcf per day. The price we receive for our natural gas is primarily a result of index driven agreements (See Item 1 “Business—Natural Gas and Natural Gas Liquids Contracts”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Oil Revenues. Our oil revenues were $1,044,200 and $1,267,200 for the nine months ended September 30, 2017 and 2016, respectively, a decrease of $223,000 (18%). The decrease in oil revenues was attributable to a $450,200 decrease in production volumes and a $227,200 increase in oil prices. Our production volumes decreased to 82 bbls per day for the nine months ended September 30, 2017 from 126 bbls per day for the nine months ended September 30, 2016, a decrease of 44 (35%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Natural Gas Liquids Revenues. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $955,400 and $911,200 for the nine months ended September 30, 2017 and 2016, respectively, an increase of $44,200 (5%). The increase in liquid revenues was attributable to a $373,600 increase in natural gas liquid prices partially offset by a $329,400 decrease in production volumes. Our production volumes decreased to 197 bbls per day for the nine months ended September 30, 2017 from 307 bbls per day for the nine months ended September 30, 2016, a decrease of 110 (36%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Gain onMark-to-Market Derivatives.Changes in fair value of derivative instruments are recognized immediately within gain onmark-to-market derivatives on our statements of operations.

We did not recognize a gain or loss onmark-to-market derivatives for the nine months ended September 30, 2017. We recognized a loss onmark-to-market derivatives of $26,500 for the nine months ended September 30, 2016.

Costs and Expenses.Production expenses were $2,507,100 and $3,408,200 for the nine months ended September 30, 2017 and 2016, respectively, a decrease of $901,100 (26%). This decrease was primarily due to decreases in water hauling and disposal charges and transportation expense.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 20% and 23% for the nine months ended September 30, 2017 and 2016, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $76,600 and $82,200 for the nine months ended September 30, 2017 and 2016, respectively, a decrease of $5,600 (7%). These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP, and vary from period to period due to the costs and services provided to us.

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Cash Flows Overview.

Cash provided by operating activities increased $283,900 for the nine months ended September 30, 2017 to $2,642,800 as compared to $2,358,900 for the nine months ended September 30, 2016. This increase was due to an increase in net earnings before depletion and accretion of $815,800 partially offset by a decrease in change in accounts receivable trade-affiliate of $4,000 and a decrease in the change in accrued liabilities of $14,600.

Cash used in investing activities was $6,100 for the nine months ended September 30, 2017 due to the purchase of tangible equipment of $13,800 partially offset by the sale of tangible equipment of $7,700. Cash provided by investing activities was $92,400 for the nine months ended September 30, 2016 due to the sale of tangible equipment of $157,700, partially offset by the purchase of tangible equipment of $65,300.

Cash used in financing activities increased $98,200 for the nine months ended September 30, 2017 to $2,720,400 as compared to $2,622,200 for the nine months ended September 30, 2016. This increase was due to an increase in cash distributions to partners.

The MGP may withhold funds for future plugging and abandonment costs. Through September 30, 2017, the MGP has withheld $119,100 of net production revenue for future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from the MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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

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

	Years Ended December 31,
	2016			2015
Production revenues (in thousands):
Gas	$	4,060		$	7,560
Oil		1,656			4,941
Liquids		1,238			2,490
Total	$	6,954		$	14,991
Production volumes:
Gas (mcf/day)		5,535			9,673
Oil (bbls/day)		117			281
Liquids (bbls/day)		286			526
Total (mcfe/day)		7,953			14,515
Average sales price: (1)
Gas (per mcf)	$	2.00			2.14
Oil (per bbl)	$	38.52			48.25
Liquids (per bbl)	$	11.82			12.97
Production costs:
As a percent of revenues		60	%		60	%
Per mcfe	$	1.44		$	1.69
Depletion per mcfe	$	0.59		$	1.32

(2) Average gas, oil, and NGL pricing are calculated by dividing total revenue for each product by the respective volume for the period.

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Natural Gas Revenues. Our natural gas revenues were $4,059,900 and $7,559,800 for the years ended December 31, 2016 and 2015, respectively, a decrease of $3,499,900 (46%). The $3,499,900 decrease in natural gas revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $3,222,600 decrease in production volumes and a $277,300 decrease in natural gas prices after the effects of financial hedges, which were driven by market conditions. Our production volumes decreased to 5,535 mcf per day for the year ended December 31, 2016 from 9,673 mcf per day for the year ended December 31, 2015, a decrease of 4,138 (43%) mcf per day. The price we receive for our natural gas is primarily a result of index driven agreements (See Item 1 “Business—Natural Gas and Natural Gas Liquids Contracts”). 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.

Oil Revenues. Our oil revenues were $1,655,900 and $4,941,200 for the years ended December 31, 2016 and 2015, respectively, a decrease of $3,285,300 (66%). The $3,285,300 decrease in oil revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $2,866,800 decrease in production volumes and a $418,500 decrease in oil prices. Our production volumes decreased to 117 bbls per day for the year ended December 31, 2016 from 281 bbls per day for the year ended December 31, 2015, a decrease of 164 (58%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Natural Gas Liquids Revenues. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $1,237,600 and $2,489,500 for the years ended December 31, 2016 and 2015, respectively, a decrease of $1,251,900 (50%). The $1,251,900 decrease in liquid revenues for the year ended December 31, 2016 as compared to the prior year was attributable to a $1,130,700 decrease in production volumes and a $121,200 decrease in natural gas liquid prices. Our production volumes decreased to 286 bbls per day for the year ended December 31, 2016 from 526 bbls per day for the year ended December 31, 2015, a decrease of 240 (46%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Gain onMark-to-Market Derivatives.Changes in fair value of derivative instruments are recognized immediately within gain onmark-to-market derivatives on our statements of operations.

We recognized a loss onmark-to-market derivatives of $27,400 for the year ended December 31, 2016. This loss was due primarily tomark-to-market losses in the current year related to the change in natural gas prices during the year. We recognized a gain onmark-to-market derivatives of $383,500 for the year ended December 31, 2015.

Costs and Expenses.Production expenses were $4,102,000 and $8,947,600 for the years ended December 31, 2016 and 2015, respectively, a decrease of $4,845,600 (54%). This decrease was primarily due to decreases in water hauling and disposal charges and transportation expense.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 25% and 46% for the years ended December 31, 2016 and 2015, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $75,300 and $180,200 for the years ended December 31, 2016 and 2015, respectively, a decrease of $104,900 (58%), primarily due to lower Texas franchise taxes. These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP, and vary from period to period due to the costs and services provided to us.

Impairment of gas and oil properties for the years ended December 31, 2016 and 2015 was $0 and $15,251,700, respectively. At least annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the year ended December 31, 2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices.

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Cash Flows Overview. Cash provided by operating activities decreased $12,533,300 for the year ended December 31, 2016 to $3,030,300 as compared to $15,563,300 for the year ended December 31, 2015. This decrease was due to a decrease in change in accounts receivable trade-affiliate of $9,501,400, a decrease in net earnings before depletion, accretion, and impairment of $3,713,000, and a decrease in the change in accrued liabilities of $85,900. The decrease was partially offset by an increase in the change innon-cash gain on derivative value of $767,000 for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

Cash provided by investing activities was $79,700 for the year ended December 31, 2016 due to the sale of tangible equipment of $157,700 and the purchase of tangible equipment of $78,000. Cash used in investing activities was $2,039,600 for the year ended December 31, 2015 due to the purchase of tangible equipment.

Cash used in financing activities decreased $9,858,400 for the year ended December 31, 2016 to $3,262,700 as compared to $13,121,100 for the year ended December 31, 2015. This decrease was due a decrease in cash distributions to partners.

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

Year Ended December 31, 2015 as compared to Year Ended December 31, 2014

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

	Years Ended December 31,
	2015			2014
Production revenues (in thousands):
Gas	$	7,560		$	18,866
Oil		4,941			28,590
Liquids		2,490			11,603
Total	$	14,991		$	59,059
Production volumes:
Gas (mcf/day)		9,673			13,767
Oil (bbls/day)		281			826
Liquids (bbls/day)		526			924
Total (mcfe/day)		14,515			24,267
Average sales price: (1)
Gas (per mcf)		2.14			3.75
Oil (per bbl)		48.25			94.84
Liquids (per bbl)		12.97			34.39
Production costs:
As a percent of revenues		60	%		30	%
Per mcfe	$	1.69		$	1.97
Depletion per mcfe	$	1.32		$	3.63

(1) Average gas, oil, and NGL pricing are calculated by dividing total revenue for each product by the respective volume for the period.

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Natural Gas Revenues. Our natural gas revenues were $7,559,800 and $18,866,200 for the years ended December 31, 2015 and 2014, respectively, a decrease of $11,306,400 (60%). The $11,306,400 decrease in natural gas revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $5,697,100 decrease in natural gas prices after the effects of financial hedges, which were driven by market conditions, and a $5,609,300 decrease in production volumes. Our production volumes decreased to 9,673 mcf per day for the year ended December 31, 2015 from 13,767 mcf per day for the year ended December 31, 2014, a decrease of 4,094 (30%) mcf per day. The price we receive for our natural gas is primarily a result of index driven agreements (See Item 1: “Business- Natural Gas and Natural Gas Liquids Contracts”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells and a decrease in the number of producing wells due to wellsshut-in due to it being uneconomical to continue production in the current pricing environment.

Oil Revenues. Our oil revenues were $4,941,200 and $28,590,000 for the years ended December 31, 2015 and 2014, respectively, a decrease of $23,648,800 (83%). The $23,648,800 decrease in oil revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $18,877,700 decrease in production volumes and a $4,771,100 decrease in oil prices. Our production volumes decreased to 281 bbls per day for the year ended December 31, 2015 from 826 bbls per day for the year ended December 31, 2014, a decrease of 545 (66%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Natural Gas Liquids Revenues. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $2,489,500 and $11,603,100 for the years ended December 31, 2015 and 2014, respectively, a decrease of $9,113,600 (79%). The $9,113,600 decrease in liquid revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $5,004,700 decrease in production volumes and a $4,108,900 decrease in natural gas liquid prices. Our production volumes decreased to 526 bbls per day for the year ended December 31, 2015 from 924 bbls per day for the year ended December 31, 2015, a decrease of 398 (43%) bbls per day. The decrease in production volume was mostly due to the normal decline inherent in the life of the wells.

Gain onMark-to-Market Derivatives. Changes in fair value of derivative instruments are recognized immediately within gain onmark-to-market derivatives on our statements of operations.

We recognized a gain onmark-to-market derivatives of $383,500 for the year ended December 31, 2015. This gain was due primarily tomark-to-market gains in the current year primarily related to the change in natural gas prices during the year. There were no gains or losses onmark-to-market derivatives during the year ended December 31, 2014.

Costs and Expenses. Production expenses were $8,947,600 and $17,471,000 for the years ended December 31, 2015 and 2014, respectively, a decrease of $8,523,400 (49%). This decrease was primarily due to decreases in water hauling and disposal charges and transportation expense.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 46% and 54% for the years ended December 31, 2015 and 2014, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $180,200 and $92,300 for the years ended December 31, 2015 and 2014, respectively, an increase of $87,900 (95%), primarily due to higher Texas franchise taxes. These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP, and vary from period to period due to the costs and services provided to us.

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Impairment of gas and oil properties for the years ended December 31, 2015 and 2014 was $15,251,700 and $148,419,900, respectively. At least annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2015 and 2014. This charge is based on reserve quantities, future market prices and our carrying value.

Cash Flows Overview. Cash provided by operating activities decreased $18,503,100 for the year ended December 31, 2015 to $15,563,300 as compared to $34,066,400 for the year ended December 31, 2014. This decrease was due to a decrease in net earnings before depletion, accretion, and impairment of $35,249,800, a decrease in the change in accrued liabilities of $486,900, and a decrease in the change innon-cash gain on derivative value of $383,500. The decrease was partially offset by an increase in change in accounts receivable trade-affiliate of $17,545,100 for the year ended December 31, 2015 as compared to the year ended December 31, 2014.

Cash used in investing activities decreased $1,873,500 for the year ended December 31, 2015 to $2,039,600 as compared to $3,913,100 for the year ended December 31, 2014. This decrease was due to a decrease in the purchase of tangible equipment.

Cash used in financing activities decreased $18,262,400 for the year ended December 31, 2015 to $13,121,100 as compared to $31,383,500 for the year ended December 31, 2014. This decrease was due a decrease in cash distributions to partners.

The MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2015, the MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from the MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

Year Ended December 31, 2014 as compared to Period Ended December 31, 2013

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

	Year Ended December 31,		For the Period February 19, 2013 Through December 31,
	2014		2013
Production revenues (in thousands):
Gas	$	18,866	$	1,518
Oil		28,590		3,542
Liquids		11,603		1,535
Total	$	59,059	$	6,595
Production volumes:
Gas (mcf/day)		13,767		1,365
Oil (bbls/day)		826		113
Liquids (bbls/day)		924		132
Total (mcfe/day)		24,267		2,835
Average sales price: (1)

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Gas (per mcf)		3.75			3.53
Oil (per bbl)		94.84			99.69
Liquids (per bbl)		34.39			36.95
Production costs:
As a percent of revenues		30	%		22	%
Per mcfe	$	1.97		$	1.60
Depletion per mcfe	$	3.63		$	3.40

(1) Average gas, oil, and NGL pricing are calculated by dividing total revenue for each product by the respective volume for the period.

Natural Gas Revenues. Our natural gas revenues were $18,866,200 and $1,517,800 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively, an increase of $17,348,400. The $17,348,400 increase in natural gas revenues for the year ended December 31, 2014 as compared to the prior period was attributable to a $16,221,100 increase in production volumes and a $1,127,300 increase in natural gas prices. Our production volumes increased to 13,767 mcf per day for the year ended December 31, 2014 from 1,365 mcf per day for the period ended December 31, 2013, an increase of 12,402 mcf per day due to more wells being online for a greater period of time. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: “Business- Natural Gas and Natural Gas Liquids Contracts”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions.

Oil Revenues. Our oil revenues were $28,590,000 and $3,542,300 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively, an increase of $25,047,700. The $25,047,700 increase in oil revenues for the year ended December 31, 2014 as compared to the prior period was attributable to a $26,508,100 increase in production volumes, partially offset by a $1,460,400 decrease in oil prices. Our production volumes increased to 826 bbls per day for the year ended December 31, 2014 from 113 bbls per day for the period ended December 31, 2013, an increase of 713 bbls per day.

Natural Gas Liquids Revenues. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $11,603,100 and $1,535,400 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively, an increase of $10,067,700. The $10,067,700 increase in liquid revenues for the year ended December 31, 2014 as compared to the prior period was attributable to a $10,933,100 increase in production volumes, partially offset by a $865,400 decrease in natural gas liquid prices. Our production volumes increased to 924 bbls per day for the year ended December 31, 2014 from 132 bbls per day for the period ended December 31, 2013, an increase of 792 bbls per day.

Costs and Expenses.Production expenses were $17,471,000 and $1,426,200 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively, an increase of $16,044,800. This increase was primarily due to an increase in the number of wells online.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 54% and 46% for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $92,300 and $26,100 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, respectively, an increase of $66,200. These expenses include third-party costs for services as well as the monthly administrative fees charged by the MGP, and vary from period to period due to the costs and services provided to us.

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Impairment of gas and oil properties for the year ended December 31, 2014 was $148,419,900. There was no impairment recognized for the period ended December 31, 2013. Annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the year ended December 31, 2014. This charge is based on reserve quantities, future market prices and our carrying value.

Cash Flows Overview.Cash provided by operating activities increased $32,765,100 for the year ended December 31, 2014 to $34,066,400 as compared to $1,301,300 for the period February 19, 2013 through December 31, 2013. This increase was due to an increase in net earnings before depletion, accretion, and impairment of $36,352,800, and an increase in the change in accrued liabilities of $193,100. The increase was partially offset by a decrease in change in accounts receivable trade-affiliate of $3,780,800 for the year ended December 31, 2014 compared to the period February 19, 2013 through December 31, 2013.

Cash used in investing activities was $3,913,100 for the year ended December 31, 2014 for the purchase of tangible equipment. Cash used in investing activities was $150,036,500 for the period February 19, 2013 through December 31, 2013. This was due to well drilling funds paid to the MGP and the purchase of tangible equipment.

Cash used in financing activities was $31,383,500 for cash distributions paid to the partners for the year ended December 31, 2014. Cash provided by financing activities was $149,967,000 for the period February 19, 2013 through December 31, 2013. This was due to funds contributed by the investor partners.

The MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2014, the MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from the MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

We are generally limited to the amount of funds generated by the cash flow from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from the MGP to fund operations.

Critical Accounting Policies and Estimates

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

Depletion and Impairment of Long-Lived Assets

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

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Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put 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 year ended December 31, 2015, we recognized $15,251,700 of impairment related to gas and oil properties on our balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2015. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil futures prices at the date of measurement. During the year ended December 31, 2014, we recognized $148,419,900 of impairment related to gas and oil properties on our balance sheet.

Reserve Estimates

Our estimates of proved natural gas, oil and NGL 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, oil and NGL 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 3 “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 and oil reserves are inherently imprecise. Actual future production, natural gas, oil and NGL prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL 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, oil and NGL prices, mechanical difficulties, governmental regulation, and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of natural gas and oil properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values 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 unweighted12-month average pricing based on the gas and oil prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

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Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

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

Item 3. Properties.

Natural Gas, Oil and NGL Reserve Information.The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves as of December 31, 2016, 2015, 2014 and 2013. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids 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, oil and NGL reserves and future net revenues of natural gas, oil and NGL 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, oil and NGL properties. We make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL 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 thefirst-day-of-the-month price for each month during the year ended December 31, 2016, 2015, 2014 and 2013 and are adjusted for basis differentials:

	December 31,
	2016		2015		2014		2013
Natural gas (per Mcf)	$	2.48	$	2.59	$	4.35	$	3.67
Oil (per Bbl)	$	42.75	$	50.28	$	94.99	$	96.78
Natural gas liquids (per Bbl)	$	19.57	$	11.02	$	30.21	$	30.10

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

Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGLs 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

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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, oil and NGL properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL 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		2014		2013
Proved developed reserves:(3)
Natural gas reserves (Mcf)		12,682,800		15,734,800		22,999,600		22,552,100
Oil reserves (Bbl)		93,400		180,400		897,400		1,285,700
Natural gas liquids (Bbl)		305,700		445,200		1,440,900		1,548,200
Total proved developed reserves (Mcfe)		15,077,400		19,488,400		37,029,400		39,555,500
Standardized measure of discounted future cash flows(1)	$	9,543,300	$	12,690,900	$	71,476,800	$	67,225,200
Standardized measure of discounted future cash flows per Limited Partner Unit(2)	$	848	$	1,126	$	6,351	$	5,966
Undiscounted future cash flows per Limited Partner Unit	$	1,502	$	1,870	$	9,485	$	9,798

(1) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined without giving effect tonon-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%. Because we are a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2016, 2015, 2014 and 2013 calculations of standardized measure, which is, therefore, the same as thePV-10 value.

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

(3) The Partnership did not have any proved undeveloped reserves as of December 31, 2016, 2015, 2014 and 2013.

Productive Wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells. The table below shows the location by state and the number of productive gross and net wells in which we owned a working interest at December 31, 2016. Our wells are classified as natural gas and oil wells.

Location (by state)	Gross		Net
Ohio		3.00		2.93
Oklahoma		20.00		19.20
Texas		74.00		36.26
Total		97.00		58.39

Developed Acreage.The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2016.

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	Developed Acreage
Location (by state)	Gross(1)		Net(2)
Ohio		93.92		91.42
Oklahoma		497.55		478.10
Texas		3,120.00		1,530.42
Total		3,711.47		2,099.94

(1) A “gross” acre is an acre in which we own a working interest.

(2) A “net” acre equals the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre.

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 and oil 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 and oil 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 perform curative work on any 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 and oil leases,farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Item 4. Security Ownership of Certain Beneficial Owners and Management.

As of September 30, 2017, we had 7,550 units outstanding. Of those units, three units, or .04%, were sold to the MGP’s Chief Operating Officer, Mark Schumacher. Mark Schumacher began serving as the MGP’s Chief Operating Officer in January 2014 and was not an officer or director of the MGP at the time of the sale. Although, subject to certain conditions, investor partners may present their units to us for purchase, the MGP is not obligated by our partnership agreement to purchase more than 5% of our total outstanding units in any calendar year.

We are not aware of any arrangements which may, at a subsequent date, result in a change in our control.

Item 5. Directors and Executive Officers.

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

Officers and Key Operations Employees of the MGP

The following table sets forth information with respect to those persons who serve as the officers of and on the governing board of, the MGP:

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

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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.

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.

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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 andCo-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 andCo-Group Head. From March 1996 through August 1999, Mr. Shebby was a Director and CEO of Mountain Oil and Gas Company, a privately held oil and gas firm that owned, operated and developed assets in the U.S. Rocky Mountain region. From 1992 to 1996, Mr. Shebby was an Associate and Vice President of The Energy Recovery Fund, L.P.,a private equity firm that invested in energy related assets and companies in the U.S., Canada and Europe. Mr. Shebby is a Chartered Financial Analyst. Mr. Shebby possesses 25 years of experience in the field of energy investment and finance and brings to our general partner’s governing board extensive knowledge and experience in the areas of corporate finance, investment banking, capital markets and the energy sector.

Item 6. Executive Compensation.

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

Item 7. Certain Relationships and Related Transactions, and Director Independence.

The MGP is allocated 32.92% of our gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 15% of our subscriptions and its payment of 78.44% of the tangible costs for a total capital contribution of $56,644,554. During the years ended December 31, 2016, 2015, 2014 and 2013, the MGP received net production revenues of $938,600, $1,888,200, $13,690,900 and $1,701,700, 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 general and administrative expenses in the Partnership’s statements of operations, are payable at $1,000 per well per month for the Marble Falls wells and $2,000 per well per month for Mississippi Lime and Utica Shale wells. The well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. The MGP utilizes a combination of affiliate and third-party gas gathering systems to transport the natural gas, oil and liquid production. Transportation costs are included in production expenses in the Partnership’s statements of operations. The MGP owns and operates waste water disposal wells and charges the Partnership a competitive rate for the hauling and disposal of waste water. Third-party vendors are used in areas where the MGP’s disposal wells are unavailable. 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 years incurred:

	Years Ended December 31,
	2016		2015		2014		2013
Administrative fees	$	33,700	$	44,500	$	46,000	$	5,300
Supervision fees		610,100		817,200		821,500		89,200
Transportation fees		291,200		560,900		1,166,200		114,400
Water hauling and disposal fees		1,117,200		3,193,600		7,883,300		788,500
Direct Costs		2,125,100		4,511,600		7,646,300		454,900
Total	$	4,177,300	$	9,127,800	$	17,563,300	$	1,452,300

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Assets contributed (returned to) from the MGP, which are disclosed on the Partnership’s statements of cash flows as anon-cash investing and financing activities, for the years ended December 31, 2016, 2015, 2014 and 2013 were $2,600 of assets returned, $882,800 of assets returned, $26,183,300 of assets contributed and $48,624,400 of assets contributed, respectively. 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.

Director Independence

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

Item 8. Legal Proceedings.

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

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

Item 9. Market Price of and Distributions on the Registrant’s Equity and Related Partner Matters.

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:

• the 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;

• the 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 the 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 September 30, 2017, we had 7,550 limited partners.

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The MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which the MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2016, 2015 and 2014, we made the following distributions to our unitholders:

	Distributions
	2016		2015		2014		2013
Limited partners	$	2,369,500	$	9,969,900	$	22,566,700	$	—
Managing general partner	$	893,200		3,151,200		8,816,800		—
Total distributions	$	3,262,700	$	13,121,100	$	31,383,500	$	—

Equity Compensation Plan Information

We have no equity compensation plans as of the date of this registration statement.

Item 10. Recent Sales of Unregistered Securities.

None.

Item 11. Description of Registrant’s Securities to be Registered.

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

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

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

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

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

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

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

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

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

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

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

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

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

(b) the conduct of additional operations; and

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Distributions and Subordination.Our managing general partner will review our accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. Subject to our managing general partner’s subordination obligation as described below, our managing general partner and our participants share in all of our production revenues in the same percentage as their respective capital contribution bears to our total capital contributions, except that our managing general partner receives an additional 10% of our natural gas and oil revenues. As of September 30, 2017, our managing general partner received 32.92% of our production revenues and our participants received 67.08% of our production revenues. Subject to the foregoing, these sharing percentages will be adjusted based on the final amount of our managing general partner’s capital contributions to us after all of our wells have been drilled and completed. See our partnership agreement for special allocations between our managing general partner and our participants of equipment proceeds, lease proceeds and interest income.

Our partnership agreement is structured to provide our participants with cumulative cash distributions equal to at least 12% of capital ($2,400 per $20,000 unit) in each of eight12-month subordination periods beginning when our managing general partner determines that proceeds of sales of natural gas or oil are being received by us from at least 75% of our wells, excluding any wells drilled that were nonproductive. To help achieve this investment feature, under our partnership agreement our managing general partner will subordinate up to 50% of its share of our partnership net production revenues during this subordination period. The term “partnership net production revenues” means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related Operating Costs, Direct Costs, Administrative Costs, and all other costs not specifically allocated in the partnership agreement. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination, a participant may not receive the return of capital during the96-month subordination period, or a return of all of his capital during our term, because the subordination is not a guarantee.

Subordination distributions will be determined by debiting or crediting our current period revenues to our managing general partner as may be necessary to provide the distributions to our participants. At any time during the96- month aggregate subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent cash distributions from us to our participants would exceed the return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership agreement.

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

Intangible Drilling Costs and Tangible Costs charged to the participants as a group shall be allocated among the participants, including the managing general partner to the extent of any optional subscription for Units under Section 3.03(b)(1) of our partnership agreement, in the ratio the subscription amount designated on their respective Subscription Agreements bears to the total subscription amount of all of the participants rather than the number of their respective Units. These allocations also take into account any investor general partner’s status as a defaulting investor general partner.

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

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

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

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

• we cease to be a going concern.

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

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

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

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

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

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

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

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

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

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

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

Finally, a sale of a participant’s Units could create adverse tax and economic consequences for the participant. The sale or exchange of Units held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions by the participant for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain, regardless of how long the participant owned the Units. If the Units are held for 12 months or less, then the gain or loss generally will be short-term gain or loss. The participant’s pro rata share of our

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liabilities, if any, as of the date of the sale or exchange must be included in the amount realized by the participant. Thus, the gain recognized by the participant may result in a tax liability greater than the cash proceeds, if any, received by the participant from the sale or other taxable disposition of his Units.

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

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

• our managing general partner consents to the substitution;

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

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

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

Presentment Feature.Beginning in 2018, a participant may present his Units to our managing general partner for purchase. However, a participant is not required to offer his Units to our managing general partner.

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

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

Our managing general partner’s obligation to purchase the Units presented by our participants may be discharged for its benefit by a third-party or an affiliate of our managing general partner. The Unit will be transferred to the party who pays for it, along with the delivery of an executed assignment.

A presentment must be within 120 days of our reserve report discussed below and, in accordance with Treas. Reg.§1.7704-1(f), the purchase may not be made by our managing general partner until at least 60 calendar days after written notice of the participant’s intent to present the Unit was made.

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

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

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

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

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

• cash on hand;

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

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

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

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

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

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

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

• dissolve us;

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

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

• remove the operator and elect a new operator;

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

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

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

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

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

Our managing general partner and its officers, directors, and affiliates can vote on certain issues as a participant if they have purchased Units (see Item 4 “Security Ownership of Certain Beneficial Owners and Management”). In addition to amendments by our participants as described above, amendments to our partnership agreement may be proposed in writing by our managing general partner and adopted with the consent of participants whose Units equal a majority of our total Units. Our partnership agreement may also be amended by our managing general partner without the consent of our participants for certain limited purposes set forth in Section 8.05(b) of our partnership agreement.

Books and Records.Our managing general partner is required to keep books and records of all of our financial activities in accordance with applicable law. A participant may inspect and copy any of the records, including a list of our participants

subject to the conditions described below, at any reasonable time after giving adequate notice to our managing general partner. Access to the list of our participants is subject to the following conditions:

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

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

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

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

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

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

Restrictions onRoll-Up Transactions.In connection with a proposed“Roll-up Transaction” (defined below) involving us and the issuance of securities of an entity, or aRoll-Up Entity, that would be created or would survive after the successful completion of theRoll-up Transaction, an appraisal of all of our natural gas and oil properties must be obtained from a competent independent appraiser. Our properties must be appraised on a consistent basis, and the appraisal must be based on the evaluation of all relevant information and must indicate the value of our properties as of a date immediately before the announcement of the proposedRoll-up Transaction. The appraisal must assume an orderly liquidation of our properties over a12-month period. The terms of the engagement of the independent appraiser must clearly state that the engagement is for the benefit of us and our participants. A summary of the appraisal, indicating all of the material assumptions underlying the appraisal, must be included in a report to our participants in connection with the proposedRoll-up Transaction. A“Roll-up Transaction” is a transaction involving our acquisition, merger, conversion or consolidation, directly or indirectly, and the issuance of securities of aRoll-Up Entity. This term does not include:

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

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

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

• accepting the securities of theRoll-Up Entity offered in the proposedRoll-up Transaction; or

• one of the following:

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

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

53

We are prohibited from participating in any proposedRoll-up Transaction:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Without our written consent, the operator is not permitted to incur extraordinary costs with respect to producing wells in excess of $50,000 per well, unless necessary to safeguard persons or property or to protect a well or related facilities if there is a sudden emergency.

54

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

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

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

Item 12. Indemnification of Directors and Officers.

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

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

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

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

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

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

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

Item 13. Financial Statements and Supplementary Data.

Our financial statements are included in this registration statement beginning on pageF-1 (see Item 15).

Item 14. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

There have been no changes in or disagreements with accountants on accounting or financial disclosure matters.

Item 15. Financial Statements and Exhibits.

(a) The Financial Statements of Atlas Resources Series33-2013 L.P. required to be filed as part of this registration statement are included in Item 13 hereof.

55

INDEX TO FINANCIAL STATEMENTS

ATLAS RESOURCES SERIES33-2013 L.P.

	PAGE
Audited Financial Statements for the Years Ended December 31, 2016 and 2015:
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheets		F-3
Statements of Operations		F-4
Statements of Changes in Partners’ Capital		F-5
Statements of Cash Flows		F-6
Notes to Financial Statements		F-7
Audited Financial Statements for the Year Ended December 31, 2014 and the Period February 19, 2013 (Inception of Operations) through December 31, 2013:
Report of Independent Registered Public Accounting Firm		F-20
Balance Sheets		F-21
Statements of Operations		F-22
Statements of Changes in Partners’ Capital		F-23
Statements of Cash Flows		F-24
Notes to Financial Statements		F-25
Unaudited Condensed Financial Statements for the Nine Months Ended September 30, 2017 and 2016:
Condensed Balance Sheets		F-38
Condensed Statement of Operations		F-39
Condensed Statement of Changes in Partners’ Capital		F-40
Condensed Statement of Cash Flows		F-41
Notes to Condensed Financial Statements		F-42

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas Resources Series33-2013 L.P.

We have audited the accompanying balance sheets of Atlas Resources Series33-2013 L.P. (a Delaware limited partnership) (the “Partnership”) as of December 31, 2016 and 2015, and the related statements of operations, changes in partners’ capital, and cash flows for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Series33-2013 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.

Cleveland, Ohio

February 12, 2018

F-2

ATLAS RESOURCES SERIES33-2013 L.P.

BALANCE SHEETS

DECEMBER 31, 2016 AND 2015

	2016		2015
ASSETS
Current assets:
Cash	$	251,200	$	404,200
Accounts receivable trade-affiliate		2,102,400		2,178,500
Current portion of derivative asset		—		383,500
Total current assets		2,353,600		2,966,200
Gas and oil properties, net		9,628,800		11,347,900
Total assets	$	11,982,400	$	14,314,100
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	235,000	$	535,600
Distribution payable		277,000		72,000
Total current liabilities		512,000		607,600
Asset retirement obligations		5,203,200		4,986,500
Commitments and contingencies (Note 9)
Partners’ capital:
Managing general partner’s interest		5,165,400		5,723,300
Limited partners’ interest (7,550 units)		1,101,800		2,996,700
Total partners’ capital		6,267,200		8,720,000
Total liabilities and partners’ capital	$	11,982,400	$	14,314,100

See accompanying notes to financial statements.

F-3

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF OPERATIONS

YEARS ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
REVENUES
Natural gas, oil and liquids	$	6,953,400		$	14,990,500
(Loss) gain onmark-to-market derivatives		(27,400	)		383,500
Total revenues		6,926,000			15,374,000
COSTS AND EXPENSES
Production		4,102,000			8,947,600
Depletion		1,719,500			6,970,300
Impairment		—			15,251,700
Accretion of asset retirement obligations		216,700			269,800
General and administrative		75,300			180,200
Total costs and expenses		6,113,500			31,619,600
Net income (loss)	$	812,500		$	(16,245,600	)
Allocation of net income (loss):
Managing general partner	$	337,900		$	(5,297,600	)
Limited partners	$	474,600		$	(10,948,000	)
Net income (loss) per limited partnership unit	$	63		$	(1,450	)

See accompanying notes to financial statements.

F-4

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2016 AND 2015

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2014	$	15,058,900		$	23,914,600		$	38,973,500
Partners’ capital contributions:
Tangible equipment and leasehold costs		(886,800	)		—			(886,800	)
Syndication and offering costs		4,000			—			4,000
Total contributions		(882,800	)		—			(882,800	)
Syndication and offering costs, immediately charged to capital		(4,000	)		—			(4,000	)
Participation in revenue and costs and expenses:
Net production revenues		1,888,200			4,154,700			6,042,900
Gain onmark-to-market derivatives		—			383,500			383,500
Depletion		(2,072,700	)		(4,897,600	)		(6,970,300	)
Impairment		(4,965,000	)		(10,286,700	)		(15,251,700	)
Accretion of asset retirement obligations		(88,800	)		(181,000	)		(269,800	)
General and administrative		(59,300	)		(120,900	)		(180,200	)
Net loss		(5,297,600	)		(10,948,000	)		(16,245,600	)
Distributions to partners		(3,151,200	)		(9,969,900	)		(13,121,100	)
Balance at December 31, 2015		5,723,300			2,996,700			8,720,000
Partners’ capital contributions:
Tangible equipment and leasehold costs		(2,600	)		—			(2,600	)
Total contributions		(2,600	)		—			(2,600	)
Participation in revenue and costs and expenses:
Net production revenues		938,600			1,912,800			2,851,400
Loss onmark-to-market derivatives		—			(27,400	)		(27,400	)
Depletion		(504,600	)		(1,214,900	)		(1,719,500	)
Accretion of asset retirement obligations		(71,300	)		(145,400	)		(216,700	)
General and administrative		(24,800	)		(50,500	)		(75,300	)
Net income		337,900			474,600			812,500
Distributions to partners		(893,200	)		(2,369,500	)		(3,262,700	)
Balance at December 31, 2016	$	5,165,400		$	1,101,800		$	6,267,200

See accompanying notes to financial statements.

F-5

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2016 AND 2015

	2016			2015
Cash flows from operating activities:
Net income (loss)	$	812,500		$	(16,245,600	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion		1,719,500			6,970,300
Non-cash gain on derivative value		—			(383,500	)
Impairment		—			15,251,700
Accretion of asset retirement obligations		216,700			269,800
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate and other		376,900			9,710,300
Decrease in accrued liabilities		(300,600	)		(81,700	)
Increase in distribution payable		205,000			72,000
Net cash provided by operating activities		3,030,000			15,563,300
Cash flows from investing activities:
Sale of tangible equipment		157,700			—
Purchase of tangible equipment		(78,000	)		(2,039,600	)
Net cash used in investing activities		79,700			(2,039,600	)
Cash flows from financing activities:
Distributions to partners		(3,262,700	)		(13,121,100	)
Net cash used in financing activities		(3,262,700	)		(13,121,100	)
Net change in cash		(153,000	)		402,600
Cash beginning of year		404,200			1,600
Cash end of year	$	251,200		$	404,200
Supplemental Schedule ofnon-cash investing and financing activities:
Assets contributed by (returned to) the managing general partner:
Tangible drilling costs	$	1,500		$	(587,300	)
Lease costs		3,300			(2,800	)
Intangible drilling costs		(7,400	)		(296,700	)
Syndication and offering costs		—			4,000
	$	(2,600	)	$	(882,800	)

See accompanying notes to financial statements.

F-6

ATLAS RESOURCES SERIES33-2013 L.P.

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2016 AND 2015

NOTE 1 — BASIS OF PRESENTATION

Atlas Resources Series33-2013 L.P. is a Delaware limited partnership and was formed on February 19, 2013 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”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsored and currently managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series33-2013 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 Oklahoma, Ohio and Texas. We have no employees and rely on the MGP for management, which in turn, relies on Atlas Energy Group for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

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

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

Liquidity, 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 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 remained low in 2017. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the liquidation of the Partnership’s operations.

F-7

ATLAS RESOURCES SERIES 33-2013 L.P.

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 remained low in 2017. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

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

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility (which has been superseded by subsequent amendments as described further below). The amendment provided for, among other things, waivers ofnon-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales ofnon-core assets, which include the sale of its Appalachian and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien credit facility. Titan’s strategy is to continue to sellnon-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

On April 21, 2017, the lenders under the Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

On May 4, 2017, Titan entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell its conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). On June 30, 2017, Titan completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility.

F-8

ATLAS RESOURCES SERIES 33-2013 L.P.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirements to reduce its first lien credit facility borrowings below $360 million as required by August 31, 2017.

On September 27, 2017, the lenders under Titan’s second lien credit facility entered into a letter agreement with Titan and its lenders under the first lien credit facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the second lien credit facility lenders agreed to extend the180-day standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the first lien credit facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide Titan with additional time to negotiate proposed amendments to each of the first lien credit facility and the second lien credit facility.

On September 29, 2017, Titan completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under its first lien credit facility.

On November 6, 2017, Titan entered into a fourth amendment to its first lien credit facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming andnon-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires Titan to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of thenon-conforming tranche of the borrowing base was confirmed as May 1, 2018. Titan is required to use proceeds from asset sales to make prepayments.

In addition to the requirements above, the first lien credit facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the first lien credit facility and (iii) the exercise of remedies under its second lien credit facility. Pursuant to the fourth amendment, Titan is required to hedge at least 50% and 80% of its 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively.

In connection with, and as a condition to, the effectiveness of the fourth amendment to the first lien credit facility, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until December 29, 2017.

On December 19, 2017, Titan entered into a limited waiver agreement with respect to its first lien credit facility (the “Limited Waiver”). The Limited Waiver has an effective date of December 8, 2017. Pursuant to the Limited Waiver, the lenders agreed to a further limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) January 31, 2018, (ii) the occurrence of additional events of default under the first lien facility and (iii) the exercise of remedies under Titan’s second lien credit facility.

In connection with, and as a condition to, the effectiveness of the Limited Waiver, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until February 22, 2018.

On February 2, 2018, Titan entered into the first amendment (the “Amendment”) to the Limited Waiver. The Amendment has an effective date of January 31, 2018. Pursuant to the Amendment, the lenders agreed to extend the length of the waiver from January 31, 2018 to February 15, 2018.

In connection with, and as a condition to, the effectiveness of the Amendment, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until March 8, 2018.

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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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Gas and Oil Properties

Gas and oil 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 and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.

The Partnership’s depletion expense is calculated on afield-by-field basis using theunits-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 of an individual well, the Partnership reclassifies the cost 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).

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The review of the Partnership’s gas and oil properties is done on afield-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 oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

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.

Distribution Payable and Correction of Immaterial Errors

In the current year the Partnership became aware of an immaterial error whereby amounts were withheld from the MGP and Limited Partners for estimated franchise taxes and reduced the Partnership’s cash distributions during the year ended December 31, 2015. The Partnership assessed the impact of this error on its previously issued financial statements for the year ended December 31, 2015, provided to investors, and pursuant to the guidance in ASC250“Accounting Changes and Error Corrections” (“ASC 250”) and SEC Staff Accounting Bulletin (“SAB”) No. 99 Materiality. The Assessment concluded that the error was not material, individually or in the aggregate, to any prior period financial statements. As such, in accordance with ASC 250 (SAB No. 108, Considering Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements), the prior period financial statements have been revised in the applicable financial statements. The Partnership concluded a revision of prior period financial statements was appropriate the next time they were reported, since the correction of the error would have been material if recorded in fiscal year 2016.

Distribution payable represents amounts payable to the MGP and Limited Partners resulting from the reduction of direct costs of $205,000 and $72,000, which was recognized in general and administrative expenses on the statement of operations for the years ended December 31, 2016 and 2015, respectively. The $205,000 and $72,000 was previously withheld from the MGP and Limited Partners for estimated franchise taxes and reduced the Partnership’s cash distributions during the years ended December 31, 2016 and 2015, respectively. As a result of this adjustment, the Partnership recorded a corresponding receivable from the MGP of $277,000 and $72,000, which was included in accounts receivable trade – affiliate on the balance sheet at December 31, 2016 and 2015, respectively. The $72,000 recognized as of and for the year ended December 31, 2015, represents the correction of an error, which also required a reduction to accrued liabilities of $72,000 on the balance sheet at December 31, 2015. Corresponding changes were also made to the Statement of Changes in Partners’ Capital and Statement of Cash Flows for the year ended December 31, 2015.

Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

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

Income Taxes

The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.

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. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations.

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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/orclean-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 year ended December 31, 2016 and 2015.

Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2016, the Partnership had five customers that individually accounted for approximately 27%, 16%, 16%, 14% and 11% of the Partnership’s natural gas, oil, and NGL combined revenues. For the year ended December 31, 2015, the Partnership had five customers that individually accounted for approximately 28%, 20%, 13%, 13% and 13% of the Partnership’s natural gas, oil, and NGL combined revenues.

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2015, there were no deposits over the limit of the Federal Deposit Insurance Corporation. At December 31, 2016, the Partnership had $2,758,938 in deposits at one bank of which $25,938 was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Revenue Recognition

The Partnership generally sells natural gas, crude oil, and NGLs 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 inception 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, crude oil, and NGLs, 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, NGLs, crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $1,129,200 and $1,583,500, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Recently Issued Accounting Standards

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

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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. We have made progress on our contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at apoint-in-time. We are currently unable to reasonably estimate the expected financial statement impact; however, we do not believe the new accounting guidance will have a material impact on our financial position, results of operations or cash flows. We intend to adopt the new accounting guidance using the modified retrospective method. The new 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.

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

Working Interest

The Management General Partner and the Limited Partners shall share in Partnership revenues in the same percentage as their respective Capital Contributions bears to the Partnership’s total Capital Contributions, except that the Managing General Partner shall receive an additional 10% of Partnership revenues as a Carried Interest, when the Limited Partners have received cash distributions from the Partnership equal to at least 70% of their subscription proceeds. 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 turnedon-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

The MGP 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		0	%		100	%
Tangible equipment costs		78	%		22	%
Revenues(1)		33	%		67	%
Operating costs, administrative costs, direct and all other costs(2)		33	%		67	%

(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 as a Carried Interest, when the Limited Partners have received cash distributions from the Partnership equal to at least 70% of their subscription proceeds.

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

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NOTE 4 — PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2016			2015
Proved properties:
Leasehold interests	$	20,647,000		$	20,643,700
Wells and related equipment		194,142,200			194,227,800
Total natural gas and oil properties		214,789,200			214,871,500
Accumulated depletion and impairment		(205,160,400	)		(203,523,600	)
Gas and oil properties, net	$	9,628,800		$	11,347,900

The Partnership recorded depletion expense on natural gas and oil properties of $1,719,500 and $6,970,300 for the year 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.

There was no impairment related to gas and oil properties on its balance sheet during the year ended December 31, 2016. During the year ended December 31, 2015, the Partnership recognized $15,251,700 of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2016. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil futures 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 and oil 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 and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On apartnership-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.

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

	Years Ended December 31,
	2016		2015
Beginning of year	$	4,986,500	$	4,716,700
Accretion expense		216,700		269,800
End of year	$	5,203,200	$	4,986,500

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NOTE 6 — DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally swaps, 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.

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. The Partnership reflected net derivative assets on its balance sheet of $0 and $383,500 at December 31, 2016 and 2015, respectively. The Partnership reflected a $27,400 loss and a $383,500 gain onmark-to-market derivatives at December 31, 2016 and 2015, respectively.

NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership 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 value of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2016
Derivative assets, gross
Commodity swaps	$	—		—		—		—
Total derivative assets, gross	$	—		—		—		—
As of December 31, 2015
Derivative assets, gross
Commodity swaps	$	—		383,500		—		383,500
Total derivative assets, gross	$	—		383,500		—		383,500

Assets and Liabilities Measured at Fair Value on aNon-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). There were no adjustments to retirement obligations for the year ended December 31, 2016 or 2015.

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 $0 and $15,251,700 of impairment of long-lived assets which was defined as a Level 3 fair value measurement (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 its 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 general and administrative expenses in the Partnership’s statements of operations are payable at $1,000 per well per month for the Marble Falls wells and $2,000 per well per month for Mississippi Lime and Utica Shale wells. The well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. The MGP utilizes a combination of affiliate and third-party gas gathering systems to transport the natural gas, oil and liquid production. Transportation costs are included in production expenses in the Partnership’s statements of operations. The MGP owns and operates waste water disposal wells and charges the Partnership a competitive rate for the hauling and disposal of waste water. Third-party vendors are used in areas where the MGP’s disposal wells are unavailable. 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 years incurred:

	Years Ended December 31,
	2016		2015
Administrative fees	$	33,700	$	44,500
Supervision fees		610,100		817,200
Transportation fees		291,200		560,900
Water hauling and disposal fees		1,117,200		3,193,600
Direct Costs		2,125,100		4,511,600
Total	$	4,177,300	$	9,127,800

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Assets returned to the MGP, which are disclosed on the Partnership’s statements of cash flows asnon-cash investing and financing activities, for the years ended December 31, 2016 and December 31, 2015 were $2,600 and $882,800 of assets contributed, respectively. 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 partnership net production revenues that is based on the amount of its capital contributions to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in each of the eight12-month subordination periods, determined on a cumulative basis, commencing with the Partnership’s receipt of proceeds from the sale of natural gas and oil that represent at least 75% of the Partnership’s drilling and completion costs for all Partnership wells. The subordination period began with the October 2014 distribution month. As of December 31, 2016, the MGP had not subordinated any of its net production revenues based on the subordination terms in the partnership agreement.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2018 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, the MGP has not withheld any such funds.

Legal Proceedings

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

NOTE 10 — SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)

Gas and Oil Reserve Information.The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with the MGP’s prescribed internal control procedures by its reserve engineers. For the period 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 and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. 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 the MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s President.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids 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 unweighted12-month average pricing based on the prices on the first day of each month during the year ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content.

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ATLAS RESOURCES SERIES 33-2013 L.P.

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 and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil prices and in production and development costs and other factors, for their effects have not been proved.

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

	Gas (Mcf)			Oil (Bbls)			Liquid (Bbls)
Balance, December 31, 2014		22,999,600			897,400			1,440,900
Revisions(1)		(3,734,000	)		(614,600	)		(803,800	)
Production		(3,530,800	)		(102,400	)		(191,900	)
Balance, December 31, 2015		15,734,800			180,400			445,200
Revisions(1)		(1,026,300	)		(44,000	)		(34,800	)
Production		(2,025,700	)		(43,000	)		(104,700	)
Balance, December 31, 2016(1)		12,682,800			93,400			305,700

(1) The downward revision in natural gas, oil, and NGL forecasts is primarily due to forecast adjustments in order to reflect actual production.

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

	Years Ended December 31,
	2016			2015
Natural gas and oil properties:
Leasehold interest	$	20,647,000		$	20,643,700
Wells and related equipment		194,142,200			194,227,800
Accumulated depletion and impairment		(205,160,400	)		(203,523,600	)
Net capitalized costs	$	9,628,800		$	11,347,900

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

	Years Ended December 31,
	2016			2015
Revenues	$	6,953,400		$	14,990,500
Production costs		(4,102,000	)		(8,947,600	)
Depletion and amortization		(1,719,500	)		(6,970,300	)
Impairment		—			(15,251,700	)
	$	1,131,900		$	(16,179,100	)

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas and oil 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 onyear-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil 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:

F-18

ATLAS RESOURCES SERIES 33-2013 L.P.

	Years Ended December 31,
	2016			2015(1)
Future cash inflows	$	32,894,600		$	44,248,600
Future production costs		(15,616,400	)		(22,736,700	)
Future development costs		(374,000	)		(442,800	)
Future net cash flows		16,904,200			21,069,100
Less 10% annual discount for estimated timing of cash flows		(7,360,900	)		(8,378,200	)
Standardized measure of discounted future net cash flows	$	9,543,300		$	12,690,900

(1) The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted12-month average pricing based on the gas and oil 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 and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas Resources Series33-2013 L.P.

We have audited the accompanying balance sheets of Atlas Resources Series33-2013 L.P. (a Delaware limited partnership) (the “Partnership”) as of December 31, 2014 and 2013, and the related statements of operations, changes in partners’ capital, and cash flows for the year ended December 31, 2014 and for the period February 19, 2013 (inception of operations) through December 31, 2013. 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). 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 Series33-2013 L.P. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the year ended December 31, 2014 and for the period February 19, 2013 (inception of operations) through December 31, 2013 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.

Cleveland, Ohio

February 12, 2018

F-20

ATLAS RESOURCES SERIES33-2013 L.P.

BALANCE SHEETS

DECEMBER 31, 2014 AND 2013

	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	1,600	$	1,231,800
Accounts receivable trade affiliate		11,888,800		4,054,000
Total current assets		11,890,400		5,285,800
Gas and oil properties, net		32,417,100		132,350,300
Construction in progress		—		49,377,300
	$	44,307,500	$	187,013,400
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	617,300	$	212,100
Total current liabilities		617,300		212,100
Asset retirement obligations		4,716,700		1,951,900
Commitments and contingencies (Note 8)
Partners’ capital:
Managing general partner’s interest		15,058,900		33,539,800
Limited partners’ interest (7,550 units)		23,914,600		151,309,600
Total partners’ capital		38,973,500		184,849,400
	$	44,307,500	$	187,013,400

See accompanying notes to financial statements.

F-21

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014 AND THE

PERIOD FEBRUARY 19, 2013 (Inception of Operations)

THROUGH DECEMBER 31, 2013

	2014			2013
REVENUES
Natural gas, oil and liquids	$	59,059,300		$	6,595,500
Total revenues		59,059,300			6,595,500
COST AND EXPENSES
Production		17,471,000			1,426,200
Depletion		32,187,000			3,033,900
Impairment		148,419,900			—
Accretion of asset retirement obligation		135,300			—
General and administrative		92,300			26,100
Total costs and expenses		198,305,500			4,486,200
Net (loss) income	$	(139,246,200	)	$	2,109,300
Allocation of net (loss) income:
Managing general partner	$	(34,417,900	)	$	766,700
Limited partners	$	(104,828,300	)	$	1,342,600
Net (loss) income per limited partnership unit	$	(13,885	)	$	178

See accompanying notes to financial statements.

F-22

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

YEAR ENDED DECEMBER 31, 2014 AND THE

PERIOD FEBRUARY 19, 2013 (Inception of Operations)

THROUGH DECEMBER 31, 2013

	Managing
	General			Limited
	Partner			Partners			Total
Balance at February 19, 2013	$	100		$	—		$	100
Partners’ capital contributions:
Capital (return) contribution		(100	)		149,967,000			149,966,900
Tangible equipment and leasehold costs		32,773,100			—			32,773,100
Syndication and offering costs		15,851,300			—			15,851,300
Total contributions		48,624,400			149,967,000			198,591,400
Syndication and offering costs, immediately charged to capital		(15,851,300	)		—			(15,851,300	)
Participation in revenue and costs and expenses:
Net production revenues		1,701,700			3,467,600			5,169,300
Depletion		(926,400	)		(2,107,500	)		(3,033,900	)
General and administrative		(8,600	)		(17,500	)		(26,100	)
Net income		766,700			1,342,600			2,109,300
Balance at December 31, 2013		33,539,800			151,309,600			184,849,400
Partners’ capital contributions:
Tangible equipment and leasehold costs		24,753,800			—			24,753,800
Syndication and offering costs		1,429,500			—			1,429,500
Total contributions		26,183,300			—			26,183,300
Syndication and offering costs, immediately charged to capital		(1,429,500	)		—			(1,429,500	)
Participation in revenue and costs and expenses:
Net production revenues		13,690,900			27,897,400			41,588,300
Depletion		(8,566,200	)		(23,620,800	)		(32,187,000	)
Impairment		(39,467,700	)		(108,952,200	)		(148,419,900	)
Accretion of asset retirement obligation		(44,500	)		(90,800	)		(135,300	)
General and administrative		(30,400	)		(61,900	)		(92,300	)
Net loss		(34,417,900	)		(104,828,300	)		(139,246,200	)
Distributions to partners		(8,816,800	)		(22,566,700	)		(31,383,500	)
Balance at December 31, 2014	$	15,058,900		$	23,914,600		$	38,973,500

See accompanying notes to financial statements.

F-23

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014 AND THE

PERIOD FEBRUARY 19, 2013 (Inception of Operations)

THROUGH DECEMBER 31, 2013

	2014			2013
Cash flows from operating activities:
Net (loss) income	$	(139,246,200	)	$	2,109,300
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion		32,187,000			3,033,900
Impairment		148,419,900			—
Accretion of asset retirement obligation		135,300			—
Changes in operating assets and liabilities:
Increase in accounts receivable-affiliate		(7,834,800	)		(4,054,000	)
Increase in accrued liabilities		405,200			212,100
Net cash provided by operating activities		34,066,400			1,301,300
Cash flows from investing activities:
Gas and oil well drilling costs paid to MGP		—			(149,967,000	)
Purchase of tangible equipment		(3,913,100	)		(69,500	)
Net cash used in investing activities		(3,913,100	)		(150,036,500	)
Cash flows from financing activities:
Initial capital contribution by MGP		—			100
Partners’ capital contributions		—			149,967,000
Return of initial capital contribution		—			(100	)
Distributions to partners		(31,383,500	)		—
Net cash (used in) provided by financing activities		(31,383,500	)		149,967,000
Net change in cash and cash equivalents		(1,230,200	)		1,231,800
Cash and cash equivalents at beginning of period		1,231,800			—
Cash and cash equivalents at end of period	$	1,600		$	1,231,800
Supplemental Schedule ofnon-cash investing and financing activities:
Assets contributed by the managing general partner:
Tangible drilling costs	$	17,846,100		$	14,072,300
Lease costs		2,261,600			18,700,800
Intangible drilling costs		4,646,100			—
Syndication and offering costs		1,429,500			15,851,300
	$	26,183,300		$	48,624,400
Asset retirement obligation revision and additions	$	2,629,500		$	1,951,900

See accompanying notes to financial statements.

F-24

ATLAS RESOURCES SERIES33-2013 L.P.

NOTES TO FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2014 AND THE

PERIOD FEBRUARY 19, 2013 (Inception of Operations)

THROUGH DECEMBER 31, 2013

NOTE 1 — BASIS OF PRESENTATION

Atlas Resources Series33-2013 L.P. is a Delaware limited partnership and was formed on February 19, 2013 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”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsored and currently managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series33-2013 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 Oklahoma, Ohio and Texas. We have no employees and rely on the MGP for management, which in turn, relies on Atlas Energy Group for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

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

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

Liquidity, 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 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 remained low in 2017. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position and may make it uneconomical for the Partnership to produce its wells

F-25

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 remained low in 2017. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

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

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility (which has been superseded by subsequent amendments as described further below). The amendment provided for, among other things, waivers ofnon-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales ofnon-core assets, which include the sale of its Appalachian and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien credit facility. Titan’s strategy is to continue to sellnon-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

F-26

On April 21, 2017, the lenders under the Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

On May 4, 2017, Titan entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell its conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). On June 30, 2017, Titan completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirements to reduce its first lien credit facility borrowings below $360 million as required by August 31, 2017.

On September 27, 2017, the lenders under Titan’s second lien credit facility entered into a letter agreement with Titan and its lenders under the first lien credit facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the second lien credit facility lenders agreed to extend the180-day standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the first lien credit facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide Titan with additional time to negotiate proposed amendments to each of the first lien credit facility and the second lien credit facility.

On September 29, 2017, Titan completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under its first lien credit facility.

On November 6, 2017, Titan entered into a fourth amendment to its first lien credit facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming andnon-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires Titan to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of thenon-conforming tranche of the borrowing base was confirmed as May 1, 2018. Titan is required to use proceeds from asset sales to make prepayments.

In addition to the requirements above, the first lien credit facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the first lien credit facility and (iii) the exercise of remedies under its second lien credit facility. Pursuant to the fourth amendment, Titan is required to hedge at least 50% and 80% of its 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively.

F-27

In connection with, and as a condition to, the effectiveness of the fourth amendment to the first lien credit facility, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until December 29, 2017.

On December 19, 2017, Titan entered into a limited waiver agreement with respect to its first lien credit facility (the “Limited Waiver”). The Limited Waiver has an effective date of December 8, 2017. Pursuant to the Limited Waiver, the lenders agreed to a further limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) January 31, 2018, (ii) the occurrence of additional events of default under the first lien facility and (iii) the exercise of remedies under Titan’s second lien credit facility.

In connection with, and as a condition to, the effectiveness of the Limited Waiver, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until February 22, 2018.

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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments and the probability of forecasted transactions. Actual results could differ from those estimates.

Cash Equivalents

The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Receivables

Accounts receivable 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, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

F-28

Gas and Oil Properties

Gas and oil 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 and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.

The Partnership’s depletion expense is calculated on afield-by-field basis using theunits-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.

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 of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.

Impairment of Long-Lived Assets

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

The review of the Partnership’s gas and oil properties is done on afield-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 oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

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.

During the year ended December 31, 2014, we recognized $148,419,900 of impairment within natural gas and oil properties. The impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2014. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil futures prices at the date of measurement. There was no impairment recognized for the period February 19, 2013 through December 31, 2013.

F-29

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil 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 treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.

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, 2014 and 2013.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations.

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/orclean-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 year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013.

Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, the Partnership had three customers that individually accounted for approximately 29%, 29% and 21% of the Partnership’s natural gas, oil, and NGL combined revenues. For the period February 19, 2013 through December 31, 2013, the Partnership had four customers that individually accounted for approximately 41%, 24%, 18%, and 13% of the Partnership’s natural gas, oil, and NGLs combined revenues.

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. There were no deposits over the insurance limit as of December 31, 2014. At December 31, 2013, the Partnership had $1,231,800, in deposits at one bank of which $981,800 was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

F-30

Revenue Recognition

The Partnership generally sells natural gas, crude oil, and NGLs 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 inception 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, crude oil, and NGLs, 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, NGLs, crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See Note 2: “Use of Estimates” for further description). The Partnership had unbilled revenues at December 31, 2014 and 2013 of $5,940,400 and $3,066,600, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Recently Issued Accounting Standards

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

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We have made progress on our contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at apoint-in-time. We are currently unable to reasonably estimate the expected financial statement impact; however, we do not believe the new accounting guidance will have a material impact on our financial position, results of operations or cash flows. We intend to adopt the new accounting guidance using the modified retrospective method. The new 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.

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

Working Interest

The Management General Partner and the Limited Partners shall share in Partnership revenues in the same percentage as their respective Capital Contributions bears to the Partnership’s total Capital Contributions, except that the Managing General Partner shall receive an additional 10% of Partnership revenues as a Carried Interest, when the Limited Partners have received cash distributions from the Partnership equal to at least 70% of their subscription proceeds.

F-31

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 turnedon-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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

	Managing General Partner			Limited Partners
Organization and offering cost		100	%		0	%
Lease costs		100	%		0	%
Revenues(1)		33	%		67	%
Operating costs, administrative costs, direct and all other costs(2)		33	%		67	%
Intangible drilling costs		0	%		100	%
Tangible equipment costs		78	%		22	%

(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 as a Carried Interest, when the Limited Partners have received cash distributions from the Partnership equal to at least 70% of their subscription proceeds.

(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 and oil properties at the dates indicated:

	December 31,
	2014			2013
Proved properties:
Leasehold interests	$	20,962,300		$	18,700,800
Wells and related equipment		195,095,600			116,683,400
Total natural gas and oil properties		216,057,900			135,384,200
Accumulated depletion and impairment		(183,640,800	)		(3,033,900	)
Gas and oil properties, net	$	32,417,100		$	132,350,300

The Partnership recorded depletion expense on natural gas and oil properties of $32,187,000 and $3,033,900 for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, 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 year ended December 31, 2014, the Partnership recognized $148,419,900 of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil futures prices at the date of measurement. There was no impairment of gas and oil properties for the period February 19, 2013 through December 31, 2013.

F-32

NOTE 5 — ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil 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 and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On apartnership-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.

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

	Year Ended December 31, 2014		For the Period February 19, 2013 Through December 31, 2013
Asset retirement obligations, beginning of period	$	1,951,900	$	—
Liabilities incurred from drilling wells		326,800		1,951,900
Accretion of asset retirement obligations		135,300		—
Asset retirement obligation revision		2,302,700		—
Asset retirement obligations, end of period	$	4,716,700	$	1,951,900

NOTE 6 — 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.

F-33

Assets and Liabilities Measured at Fair Value on aNon-Recurring Basis

The Partnership’s current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

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). Adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis were $2,302,700 for the year ended December 31, 2014. There were no adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis for the period February 19, 2013 through December 31, 2013.

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 year ended December 31, 2014, the Partnership recognized a $148,419,900 impairment of long-lived assets which was defined as a Level 3 fair value measurement (See Note 2: Impairment of Long-Lived Assets). No impairment was recognized for the period February 19, 2013 through December 31, 2013.

NOTE 7 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with its 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 general and administrative expenses in the Partnership’s statements of operations are payable at $1,000 per well per month for the Marble Falls wells and $2,000 per well per month for Mississippi Lime and Utica Shale wells. The well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. The MGP utilizes a combination of affiliate and third-party gas gathering systems to transport the natural gas, oil and liquid production. Transportation costs are included in production expenses in the Partnership’s statements of operations. The MGP owns and operates waste water disposal wells and charges the Partnership a competitive rate for the hauling and disposal of waste water. Third-party vendors are used in areas where the MGP’s disposal wells are unavailable. 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:

			For the Period
			February 19, 2013
	Year Ended		Through
	December 31,		December 31,
	2014		2013
Administrative fees	$	46,000	$	5,300
Supervision fees		821,500		89,200
Transportation fees		1,166,200		114,400
Water hauling and disposal fees		7,883,300		788,500
Direct Costs		7,646,300		454,900
Total	$	17,563,300	$	1,452,300

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 partnership net production revenues that is based on the amount of its capital contributions to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in each of the eight12-month subordination periods, determined on a cumulative basis, commencing with the Partnership’s receipt of proceeds from the sale of natural gas and oil that represent at least 75% of the Partnership’s drilling and completion costs for all Partnership wells. The subordination period began with the October 2014 distribution month. As of December 31, 2014, the MGP had not subordinated any of its net production revenues based on the subordination terms in the partnership agreement.

F-34

NOTE 8 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2018 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, 2014, the MGP has not withheld any such funds.

Legal Proceedings

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

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

NOTE 9 — SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)

Gas and Oil Reserve Information.The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas Resources Series33-2013 L.P. Annual Report for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013 (See Note 2). For the period 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 and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 38 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 Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s Senior Engineering Staff and management, with final approval by the MGP’s Chief Operating Officer.

F-35

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids 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. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2014 and 2013 were estimated using an unweighted12-month average pricing based on the prices on the first day of each month during the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, 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 and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil prices and in production and development costs and other factors, for their effects have not been proved.

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

	Gas (Mcf)			Oil (Bbls)			Liquid (Bbls)
Balance, February 19, 2013		—			—			—
Extensions, discoveries and other additions		22,982,000			1,321,200			1,589,700
Production		(429,900	)		(35,500	)		(41,500	)
Balance, December 31, 2013		22,552,100			1,285,700			1,548,200
Extensions, discoveries and other additions		5,258,900			410,100			635,100
Revisions(1)		213,400			(496,900	)		(405,000	)
Production		(5,024,800	)		(301,500	)		(337,400	)
Balance, December 31, 2014		22,999,600			897,400			1,440,900

(2) The upward revision in natural gas forecasts is primarily due to forecast adjustments in order to better reflect actual production. The downward revision in oil and NGL forecasts are primarily due to forecast adjustments in order to better reflect actual production.

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

				For the Period
				February 19, 2013 Through December 31,
	Year Ended
	December 31,
	2014			2013
Natural gas and oil properties:
Leasehold interest	$	20,962,300		$	18,700,800
Wells and related equipment		195,095,600			116,683,400
Accumulated depletion and impairment		(183,640,800	)		(3,033,900	)
Net capitalized costs	$	32,417,100		$	132,350,300

F-36

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

	Year Ended December 31,			For the Period February 19, 2013 Through December 31,
	2014			2013
Revenues	$	59,059,300		$	6,595,500
Production costs		(17,471,000	)		(1,426,200	)
Depletion and amortization		(32,187,000	)		(3,033,900	)
Impairment		(148,419,900	)		—
	$	(139,018,600	)	$	2,135,400

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 and oil reserves. The estimated future production was priced at a twelve-month average for the year ended December 31, 2014 and the period February 19, 2013 through December 31, 2013, 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 onyear-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil 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:

	Year Ended			For the Period February 19, 2013 Through December 31,
	December 31,
	2014			2013
Future cash inflows	$	220,542,800		$	248,725,625
Future production costs		(113,057,800	)		(110,452,925	)
Future development costs		(731,800	)		(27,861,700	)
Future net cash flows		106,753,200			110,411,000
Less 10% annual discount for estimated timing of cash flows		(35,276,400	)		(43,185,800	)
Standardized measure of discounted future net cash flows	$	71,476,800		$	67,225,200

F-37

ATLAS RESOURCES SERIES33-2013 L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash	$	167,500	$	251,200
Accounts receivable trade-affiliate		1,826,700		2,102,400
Total current assets		1,994,200		2,353,600
Gas and oil properties, net		8,612,600		9,628,800
Long-term asset retirement receivable – affiliate		119,100		—
Total assets	$	10,725,900	$	11,982,400
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	238,800	$	235,000
Distribution payable		277,000		277,000
Total current liabilities		515,800		512,000
Asset retirement obligations		5,373,600		5,203,200
Commitments and contingencies (Note 4)
Partners’ capital:
Managing general partner’s interest		4,722,700		5,165,400
Limited partners’ interest (7,550 units)		113,800		1,101,800
Total partners’ capital		4,836,500		6,267,200
Total liabilities and partners’ capital	$	10,725,900	$	11,982,400

See accompanying notes to condensed financial statements.

F-38

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF OPERATIONS

(Unaudited)

	Nine Months Ended
	September 30,
	2017		2016
REVENUES
Natural gas, oil and liquids	$	5,066,100	$	5,183,500
Loss onmark-to-market derivatives		—		(26,500	)
Total revenues		5,066,100		5,157,000
COSTS AND EXPENSES
Production		2,507,100		3,408,200
Depletion		1,022,300		1,263,700
Accretion of asset retirement obligations		170,400		162,500
General and administrative		76,600		82,200
Total costs and expenses		3,776,400		4,916,600
Net income	$	1,289,700	$	240,400
Allocation of net income:
Managing general partner	$	462,400	$	179,400
Limited partners	$	827,300	$	61,000
Net income per limited partnership unit	$	110	$	8

See accompanying notes to condensed financial statements.

F-39

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2016	$	5,165,400		$	1,101,800		$	6,267,200
Participation in revenue and costs and expenses:
Net production revenues		842,400			1,716,600			2,559,000
Depletion		(298,700	)		(723,600	)		(1,022,300	)
Accretion of asset retirement obligations		(56,100	)		(114,300	)		(170,400	)
General and administrative		(25,200	)		(51,400	)		(76,600	)
Net income		462,400			827,300			1,289,700
Subordination		(400,800	)		400,800			—
Distributions to partners		(504,300	)		(2,216,100	)		(2,720,400	)
Balance at September 30, 2017		4,722,700			113,800			4,836,500

See accompanying notes to condensed financial statements.

F-40

ATLAS RESOURCES SERIES33-2013 L.P.

STATEMENT OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	1,289,700		$	240,400
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion		1,022,300			1,263,700
Non-cash loss on derivative value		—			320,400
Accretion of asset retirement obligations		170,400			162,500
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		275,700			271,700
Increase in asset retirement receivable-affiliate		(119,100	)		—
Increase in accrued liabilities		3,800			18,400
Increase in distribution payable		—			81,800
Net cash provided by operating activities		2,642,800			2,358,800
Cash flows from investing activities:
Sale of Tangible equipment		7,700			157,700
Purchase of tangible equipment		(13,800	)		(65,300	)
Net cash (used in) provided by investing activities		(6,100	)		92,400
Cash flows from financing activities:
Distributions to partners		(2,720,400	)		(2,622,200	)
Net cash used in financing activities		(2,720,400	)		(2,622,200	)
Net change in cash		(83,700	)		(171,000	)
Cash beginning of period		251,200			404,200
Cash end of period	$	167,500		$	233,200
Supplemental Schedule ofnon-cash investing and financing activities:
Assets contributed by the managing general partner:
Tangible drilling costs	$	—		$	1,600
Lease costs		—			1,500
Intangible drilling costs		—			1,300
Syndication and offering costs		—			—
	$	—		$	4,400

See accompanying notes to condensed financial statements.

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ATLAS RESOURCES SERIES33-2013 L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas Resources Series33-2013 L.P. is a Delaware limited partnership and was formed on February 19, 2013 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”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsored and currently managestax-advantaged investment partnerships, in which itco-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series33-2013 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 Oklahoma, Ohio and Texas. We have no employees and rely on the MGP for management, which in turn, relies on Atlas Energy Group for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

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

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

Liquidity, 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 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 remained low in 2017. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. In addition, the Partnership has experienced significant

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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 remained low in 2017. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

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

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility (which has been superseded by subsequent amendments as described further below). The amendment provides for, among other things, waivers ofnon-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales ofnon-core assets, which include the sale of its Appalachian and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien credit facility. Titan’s strategy is to continue to sellnon-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

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On April 21, 2017, the lenders under the Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

On May 4, 2017, Titan entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell its conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). On June 30, 2017, Titan completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirements to reduce its first lien credit facility borrowings below $360 million as required by August 31, 2017.

On September 27, 2017, the lenders under Titan’s second lien credit facility entered into a letter agreement with Titan and its lenders under the first lien credit facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the second lien credit facility lenders agreed to extend the180-day standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the first lien credit facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide Titan with additional time to negotiate proposed amendments to each of the first lien credit facility and the second lien credit facility.

On September 29, 2017, Titan completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under its first lien credit facility.

On November 6, 2017, Titan entered into a fourth amendment to its first lien credit facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming andnon-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires Titan to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of thenon-conforming tranche of the borrowing base was confirmed as May 1, 2018. Titan is required to use proceeds from asset sales to make prepayments.

In addition to the requirements above, the first lien credit facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the first lien credit facility and (iii) the exercise of remedies under its second lien credit facility. Pursuant to the fourth amendment, Titan is required to hedge at least 50% and 80% of its 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively.

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In connection with, and as a condition to, the effectiveness of the fourth amendment to the first lien credit facility, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until December 29, 2017.

On December 19, 2017, Titan entered into a limited waiver agreement with respect to its first lien credit facility (the “Limited Waiver”). The Limited Waiver has an effective date of December 8, 2017. Pursuant to the Limited Waiver, the lenders agreed to a further limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) January 31, 2018, (ii) the occurrence of additional events of default under the first lien facility and (iii) the exercise of remedies under Titan’s second lien credit facility.

In connection with, and as a condition to, the effectiveness of the Limited Waiver, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until February 22, 2018.

On February 2, 2018, Titan entered into the first amendment (the “Amendment”) to the Limited Waiver. The Amendment has an effective date of January 31, 2018. Pursuant to the Amendment, the lenders agreed to extend the length of the waiver from January 31, 2018 to February 15, 2018.

In connection with, and as a condition to, the effectiveness of the Amendment, the lenders under Titan’s second lien credit facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) until March 8, 2018.

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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The results of operations for the interim periods presented are not necessarily indicative of results for the full year. Theyear-end condensed balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our financial statements for the fiscal year ended December 31, 2016.

Use of Estimates

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

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Gas and Oil Properties

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

	September 30, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	20,647,000		$	20,647,000
Wells and related equipment		194,148,300			194,142,200
Total natural gas and oil properties		214,795,300			214,789,200
Accumulated depletion and impairment		(206,182,700	)		(205,160,400	)
Gas and oil properties, net	$	8,612,600		$	9,628,800

Derivative Instruments

The MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices. Changes in fair value after December 31, 2014 of these derivatives were recognized immediately within gain (loss) onmark-to-market derivatives in the Partnership’s statements of operations. During the nine months ended September 30, 2017, the Partnership did not have any derivative activity as all derivative contracts have matured. During the nine months ended September 30, 2016, the Partnership recorded a loss of $26,500 recognized in loss onmark-to-market derivatives.

Recently Issued Accounting Standards

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

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We have made progress on our contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at apoint-in-time. We are currently unable to reasonably estimate the expected financial statement impact; however, we do not believe the new accounting guidance will have a material impact on our financial position, results of operations or cash flows. We intend to adopt the new accounting guidance using the modified retrospective method. The new 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.

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NOTE 3 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with its 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 general and administrative expenses in the Partnership’s statements of operations are payable at $1,000 per well per month for the Marble Falls wells and $2,000 per well per month for Mississippi Lime and Utica Shale wells. The well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. The MGP utilizes a combination of affiliate and third-party gas gathering systems to transport the natural gas, oil and liquid production. Transportation costs are included in production expenses in the Partnership’s statements of operations. The MGP owns and operates waste water disposal wells and charges the Partnership a competitive rate for the hauling and disposal of waste water. Third-party vendors are used in areas where the MGP’s disposal wells are unavailable. 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 years incurred:

	Nine Months Ended September 30,
	2017		2016
Administrative fees	$	20,800	$	25,500
Supervision fees		384,400		462,100
Transportation fees		164,300		234,000
Water hauling and disposal fees		595,100		903,200
Direct Costs		1,419,100		1,865,600
Total	$	2,583,700	$	3,490,400

Assets contributed by the MGP, which are disclosed on the Partnership’s statements of cash flows asnon-cash investing and financing activities, were $4,400 for the nine months ended September 30, 2016. 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 partnership net production revenues that is based on the amount of its capital contributions to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in each of the eight12-month subordination periods, determined on a cumulative basis, commencing with the Partnership’s receipt of proceeds from the sale of natural gas and oil that represent at least 75% of the Partnerships drilling and completion costs for all Partnership wells. The subordination period began with the October 2014 distribution month. The MGP subordinated $400,900 of its net production revenues to the limited partners for the nine months ended September 30, 2017.

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NOTE 4 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2018 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2017 the MGP has withheld $119,100 of net production revenues for future plugging and abandonment costs.

Legal Proceedings

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

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(b) Exhibits:

Exhibit No.	Description
3.1	Certificate of Limited Partnership for Atlas Resources Series33-2013 L.P.
3.2	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Series33-2013 L.P.
10.1	Drilling and Operating Agreement for Atlas Resources Series33-2013 L.P.
10.2	Amended and Restated Gas Purchase, Gathering and Processing Agreement by and between ARP Oklahoma, LLC and SemGas, L.P. effective as of August 1, 2013.
10.3	Lease Crude Oil Purchase Agreement by and between Phillips 66 Company and ARP Oklahoma, LLC effective as of June 1, 2017.
21.1	Subsidiaries of Atlas Resources Series33-2013 L.P.
99.1	Summary Reserve Report of Wright & Company, Inc.

Signatures

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.

	Atlas Resources Series33-2013 L.P.
	By: Atlas Resources, LLC, its Managing General Partner
Date: February 12, 2018	By:	/s/ Jeffrey M. Slotterback
	Name: Jeffrey M. Slotterback
	Title: Chief Financial Officer