SEC Info - Atlas Growth Partners, L.P. - ‘10-K’ for 12/31/20

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		Alternative Formats (Word, et al.) Business Certain Relationships and Related Transactions, and Director Independence Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Changes in Partners' Capital Consolidated Statements of Operations Controls and Procedures Directors, Executive Officers and Corporate Governance Executive Compensation Exhibits and Financial Statement Schedules Financial Statements and Supplementary Data Legal Proceedings Management's Discussion and Analysis of Financial Condition and Results of Operations Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Mine Safety Disclosures Notes to Consolidated Financial Statements Other Information Principal Accountant Fees and Services Properties Quantitative and Qualitative Disclosures about Market Risk Report of Independent Registered Public Accounting Firms Risk Factors Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Selected Financial Data Signatures Unresolved Staff Comments
1	1st Page – Filing Submission
"	Business
"	Risk Factors
"	Unresolved Staff Comments
"	Properties
"	Legal Proceedings
"	Mine Safety Disclosures
"	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
"	Selected Financial Data
"	Management's Discussion and Analysis of Financial Condition and Results of Operations
"	Quantitative and Qualitative Disclosures about Market Risk
"	Financial Statements and Supplementary Data
"	Report of Independent Registered Public Accounting Firms
"	Consolidated Balance Sheets
"	Consolidated Statements of Operations
"	Consolidated Statements of Changes in Partners' Capital
"	Consolidated Statements of Cash Flows
"	Notes to Consolidated Financial Statements
"	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
"	Controls and Procedures
"	Other Information
"	Directors, Executive Officers and Corporate Governance
"	Executive Compensation
"	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
"	Certain Relationships and Related Transactions, and Director Independence
"	Principal Accountant Fees and Services
"	Exhibits and Financial Statement Schedules
"	Signatures

Common units representing limited partner interests; warrants to purchase common units at an exercise price of $10.00 per common unit

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal controls over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

As of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s commons units were not publicly traded. Accordingly, there was no market value for the registrant’s common units on such date.

Unless the context otherwise requires, references below to “Atlas Growth Partners, L.P.,” “Atlas Growth Partners,” “the Company,” “we,” “us,” “our” and “our company”, refer to Atlas Growth Partners, L.P. and our consolidated subsidiaries.

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

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

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

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

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

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

Exchange Act. The Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well (as such terms are defined in the federal securities laws).

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

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

gross acres or gross wells. A gross well or gross acre in which we own a working interest.

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

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

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

MMBbl. One million barrels of crude oil, condensate or other liquid hydrocarbons.

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

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

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

Partnership Agreement. Our First Amended and Restated Limited Partnership Agreement.

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

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

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

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

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

recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

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

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

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

Titan. Titan Energy, LLC, a Delaware limited liability company (OTHER OTC: TTEN).

undeveloped acreage or undeveloped acres. Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

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

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

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A: Risk Factors. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

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

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

Our business is subject to numerous risks and uncertainties, including those highlighted in the section title “Risk Factors,” that represent challenges that we face in connection with the successful implementation of our strategy. The occurrence of one or more of the events or circumstances described in the section titled “Risk Factors,” alone or in combination with other events or circumstances, may adversely affect our ability to effect a business combination, and may have an adverse effect on our business, cash flows, financial condition and results of operations. Such risks include, but are not limited to:

Atlas Growth Partners, L.P. (the “Company”) is a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC, owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us.

Through May 1, 2020, Atlas Energy Group, LLC (“ATLS”), a Delaware limited liability company, managed and controlled us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management owned the remaining 20% member interest in our general partner.

On May 1, 2020, pursuant to an Exchange Agreement by and among Riverstone Credit Partners – Direct, L.P. (“Riverstone”) and other lenders (collectively, the “Lenders”), ATLS and New Atlas Holdings, LLC (the “Borrower”, and together with ATLS and the other guarantors, the “Loan Parties”), ATLS transferred (the “Debt Exchange”) assets to the Lenders that included (i) its 80.01% membership interest in the general partner of the Company, and (ii) 500,010 common units representing limited partner interests in the Company. As of the date of the Debt Exchange, approximately $108,431,309 in principal amount of loans remained outstanding, which obligation was terminated in the Debt Exchange.

As a result of the Debt Exchange and related transactions, Riverstone, in its capacity as a Lender, received an approximate 61% membership interest in our general partner, and, as a result, now has the ability to control the Company’s management and operations and appoint all of the members of the Board of Directors (the “Board”) of our general partner.

The interests of our Limited Partners were not affected, altered or otherwise modified by the Debt Exchange.

At December 31, 2020, we had 23,300,410 common limited partner units issued and outstanding.

See Item 7: Management Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Ability to Continue as a Going Concern section for further disclosures.

Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in south Texas generating stable cash flows, despite a significant decline in oil and natural gas prices. While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses. As of December 31, 2020, we had $1.4 million of cash on our balance sheet and no debt. Our general and administrative expenses decreased $0.2 million to $4.3 million for the year ended December 31, 2020 from $4.5 million for the year ended December 31, 2019.

In 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well, which turned in-line during the second quarter of 2018.

While we manage the company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations. Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital, but we have limited avenues to do so at this time. We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders. We will continue to vigorously pursue all options to maximize returns to our investors.

Through December 31, 2020, our production positions were in the following areas:

Eagle Ford. The Eagle Ford Shale is an Upper Cretaceous-age formation that is prospective for horizontal drilling in approximately 26 counties across south Texas. Target vertical depths range from 4,000 to some 11,000+ feet with thickness from 40 to over 400 feet. The Eagle Ford formation is considered to be the primary source rock for many conventional oil and gas fields including the prolific East Texas Oil Field, one of the largest oil fields in the contiguous United States. We acquired our Eagle Ford position through a series of acquisitions in 2014 and 2015 for approximately $100 million. We estimate 4 Bcfe of total proved reserves for our Eagle Ford position, of which 88% are oil. All of our production volumes and revenues are derived from our Eagle Ford operations.

Marble Falls. The Marble Falls play is Pennsylvanian-age formation located above the Barnett Shale and beneath the Atoka at depths of approximately 5,500 feet and ranges in thickness from 50 and 500 feet. In January 2019, we sold our Marble Falls position, which resulted in a gain of $15 thousand after customary purchase price adjustments.

Mississippi Lime. The Mississippi Lime formation is an expansive carbonate hydrocarbon system and is located at depths between 4,000 and 7,000 feet between the Pennsylvanian-aged Morrow formation and the Devonian-age world-class source rock Woodford Shale formation. The Mississippi Lime formation can reach 600 feet in gross thickness, with a targeted porosity zone between 50 and 100 feet thickness. In July 2019, we sold our Mississippi Lime position, which resulted in a loss of $48 thousand after customary purchase price adjustments.

See Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations for a summary of our total net natural gas, oil and NGL production volumes, production per day, production revenue and average sales prices for our direct interest natural gas, oil and NGL production.

The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves. See Item 1A: Risk Factors—Risks Relating to Our Business and Item 8: Financial Statements and Supplementary Data—Note 12 for additional information and considerations regarding the preparation and estimates used in our reserves.

In accordance with SEC guidelines, 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 the first-day-of-the-month prices for the preceding twelve months from the periods indicated, which are listed below along with our average realized prices over the same twelve month period.

	December 31,
	2020		2019
Proved reserves:
Natural gas reserves (MMcf):
Proved developed reserves		359		283
Proved undeveloped reserves		—		---
Total proved reserves of natural gas		359		283
Oil reserves (MBbl):
Proved developed reserves		433		493
Proved undeveloped reserves		—		--
Total proved reserves of oil		433		493
NGL reserves (MBbl):
Proved developed reserves		67		53
Proved undeveloped reserves		—		--
Total proved reserves of NGL		67		53
Total proved reserves (MMcfe)		3,359		3,558
Standardized measure of discounted future cash flows (in thousands)	$	3,896	$	7,827

Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.

PUD Locations. As of January 1, 2020 and December 31, 2020, we had no PUD locations primarily due to the uncertainty of availability of capital for future development. These PUDs are based on the definition of PUDs in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. There were no development costs incurred during the year ended December 31, 2020.

The following table sets forth information regarding productive natural gas and oil wells in which we had a working interest as of December 31, 2020. Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have an interest directly and net wells are the sum of our fractional working interests in gross wells:

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2020:

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have primary terms that vary from less than one year to two years with options to extend. There were no concessions for undeveloped acreage as of December 31, 2020. As of December 31, 2020, there were no leases set to expire on or before December 31, 2021 and 2022.

We believe that we hold good and indefeasible title related to our producing properties, in accordance with standards generally accepted in the 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 industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas 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.

Our drilling activities are conducted mostly on undeveloped acreage. There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on each of our operated wells.

In 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well, which turned in-line during the second quarter of 2018.

The typical oil and gas lease agreement provides for the payment of a percentage of the proceeds, known as a royalty, to the mineral owner(s) for all natural gas, oil and other hydrocarbons produced from any well(s) drilled on the leased premises. In Texas (Eagle Ford Shale play), where we have acquired acreage positions, royalties are commonly in the 15-25% range, resulting in net revenue interests to us in the 75-85% range.

In the Texas Eagle Ford Shale play, where horizontal wells are generally drilled on much larger drilling units (sometimes approaching 1,000 acres), the mineral and/or surface rights are generally acquired from multiple parties.

Because the acquisition of hydrocarbon leases in highly desirable basins is an extremely competitive process, and involves certain geological and business risks to identify prospective areas, leases are frequently held by other oil and gas operators. In order to access the rights to drill on those leases held by others, we may elect to farm-in lease rights and/or purchase assignments of leases from competitor operators. Typically, the assignor of such leases will reserve an overriding royalty interest (over and above the existing mineral owner royalty), that can range from 2-3% up to as high as 7% or 8%, and sometimes contain options to convert the overriding royalty interests to working interests at payout of a well. Areas where farm-ins are utilized can result in additional reductions in our net revenue interests, depending upon their terms and how much of a particular drilling unit the farm-in acreage encompasses.

There will be occasions where competitors owning leasehold interests in areas where we want to drill will not farm-out or sell their leases, but will instead join us as working interest partners, paying their proportionate share of all drilling and operating costs in a well. However, it is generally our goal to obtain 100% of the working interest in any and all new wells that we operate.

Natural Gas. We market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing for our Eagle Ford production is primarily Houston Ship Channel daily prices. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of natural gas in any future periods under existing contracts or agreements.

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

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our NGLs are generally priced and sold using the Mont Belvieu (TX) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2020, Shell Trading Co individually accounted for approximately 94% of our total natural gas, crude oil and NGLs production revenue with no other single customer accounting for more than 10% for this period, excluding the impact of all financial derivative activity.

We may seek to provide greater stability in our cash flows through the use of financial hedges for our oil production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk, and cash is settled to

the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with our secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of December 31, 2020, we do not hold any derivative contract positions.

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

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. Over the past year, we and other oil and natural gas companies have experienced a significant reduction in drilling and operating costs. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the supply and demand for natural gas and oil.

The oil and natural gas industry is highly competitive. We encounter strong competition from independent oil and gas companies, MLPs and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.

Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.

We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Our oil and natural gas operations are subject to stringent and complex laws and regulations pertaining to drilling and production, 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:

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

While we believe that compliance with existing federal, state and local environmental laws and regulations has not had a material adverse effect on our operations, there can be no assurance that compliance with future federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. 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 be sure that future events, such as changes in existing laws, the more stringent interpretation or enforcement of existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

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

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

Hydraulic Fracturing. In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased. Regulation of the practice remains largely the province of state governments. Under the Obama Administration, however, steps were taken towards some federal regulation of hydraulic fracturing. On March 26, 2015, the Bureau of Land Management (“BLM”) issued a final rule requiring disclosure of hydraulic fracturing chemicals, establishing effluent limitations produced water must meet before being discharged to a publicly owned treatment plant, and imposing conditions for hydraulic fracturing operations on federal and tribal lands. Moreover, in December 2016 the prior Administration 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. At the time, this study was expected to provide more impetus to federal regulation of the management of hydraulic fracturing fluids and wastewater. With the change of Administration, however, interest in federal regulation waned, and in September 2018, the BLM rescinded the final rule that had been issued under the prior Administration. Court challenges to the rescinding of the rule remain pending before the U.S. District Court for the Northern District of California, and there remains uncertainty regarding the final outcome of this litigation. While we do not currently expect new federal regulations to be adopted, if they were, they could increase our cost to operate.

Although hydraulic fracturing is not currently the subject of substantial environmental regulation at the federal level, a number of states, and local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements. Common elements of state regulations governing hydraulic fracturing may include, but not be limited to, the following: requirement that logs and pressure test results are included in disclosures to state authorities; disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations; specific disposal regimens for hydraulic fracturing fluids; replacement/remediation of contaminated water assets; minimum depth of hydraulic fracturing; and measures aimed at reducing or preventing induced seismicity, including putting certain areas off limits for hydraulic fracturing. Some states and localities have banned or are considering banning hydraulic fracturing altogether.

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, vessels and pipelines 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 that compliance with OPA has not had a material adverse effect on our operations, future inadvertent noncompliance, including accidental spills or releases, 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. Second, the Clean Water Act prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The precise definition of waters and wetland subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to recurrent litigation and rulemaking. 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 requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. While we believe that compliance with the Clean Water Act has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Clean Air Act rules impose additional emissions control requirements and practices on some of our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

States are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations. States in which air emissions from oil and natural gas operations, including well sites, compressor stations, and pipelines are a substantial contributor to air pollution have adopted comprehensive air emissions permitting regimes.

While we believe that compliance with the existing requirements of the Clean Air Act and comparable state laws and regulations has not had a material adverse effect on our operations, 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 do not expect future requirements 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. During and before the prior Administration, several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple foundational findings were upheld by the courts. In April 2007, the Supreme Court held in Massachusetts v. EPA that greenhouse gases are “air pollutants” covered by the Clean Air Act. In December 2009, the EPA issued a final determination that greenhouse gases “endanger” public health and welfare, which was upheld in court in Coalition for Responsible Regulation, Inc. v. EPA. In light of these findings and rulings, the EPA attempted to require the permitting of greenhouse gas emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control greenhouse gas emissions when a permit is required due to emissions of other pollutants. The EPA has adopted a mandatory greenhouse gas emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities. On March 28, 2017, President Trump issued an Executive Order on Promoting Energy Independence and Economic Growth explaining how his Administration would withdraw, rescind, revisit, or revise virtually every element of the Obama Administration’s program for reducing greenhouse gas emissions. Under the Executive Order, some actions had immediate effect. Other actions, including those most directly affecting our operations and the overall consumption of fossil fuels, will be the subject of potentially lengthy notice-and-comment rule-making. With respect to rules more directly applicable to the types of operations we conduct, federal agencies have begun the rule-making as directed by the Executive Order. Initial efforts to revise or rescind 2015 methane emissions standards for new or modified wells were invalidated by the courts but corrective rule-making initiated, with the EPA proposing additional amendments to the rule in the fall of 2018. With respect to rules of greater applicability affecting overall consumption of fossil fuels, federal agencies have also initiated rule-making to give effect to the Executive Order. The most sweeping action was the replacement of the 2015 Clean Power Plan – the rule aimed at reducing greenhouse gas emissions from existing power

plants by one-third (compared to 2005 levels). In August 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule to replace the Clean Power Plan, which was finalized on June 19, 2019.

While we generally foresee a less stringent approach to the regulation of greenhouse gases, efforts at undoing the prior Administration’s greenhouse gas emissions regulations necessarily involve lengthy notice-and-comment rulemaking, and the resulting decisions may then be subject to litigation by those opposed to rescinding the prior Administration’s regulations. It could be several years before the precise regulatory framework is known. Opponents of the rescissions, including states and environmental groups, may then decide to sue large sources of greenhouse gas emissions for the alleged nuisance created by such emissions. In 2011, the Supreme Court held that federal common law nuisance claims were displaced by the EPA’s authority to regulate greenhouse gas emissions from large sources of emissions. If the Administration fails to pursue regulation of emissions from such sources or takes the position that it has no authority to regulate their emissions, then it is possible that a court would find common law nuisance claims are no longer displaced. In light of EPA’s ACE rule, the revival of public nuisance litigation may be less likely.

Although further regulation of greenhouse gas emissions from our operations may stall at the federal level, it is possible that, in the absence of federal regulation, states may pursue additional regulation of our operations, including restrictions on new and existing wells and fracturing operations, as many states already have done.

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. With authority granted by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. Following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016, the EPA and environmental groups entered into an agreement that required the EPA to either propose revisions to RCRA’s regulations governing oil and gas wastes, including the regulations that defined such wastes as “solid wastes” and not “hazardous wastes,” or to determine that such revisions were unnecessary. The EPA determined in 2019 that such revisions were unnecessary. Nonetheless, there is no guarantee that individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA’s or comparable states’ more stringent requirements. While we believe that compliance with the requirements of RCRA and related state and local laws and regulations has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities. 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 so-called potentially responsible parties (“PRP”) include the owner or operator of the site where the release occurred, regardless of whether a third party such as a prior owner or operator actually released the hazardous substances; former owners and operators of a site if the release occurred during the period of their ownership or operation; and companies that disposed or arranged for the disposal of the hazardous substance at the site, notwithstanding that the original disposal activity may have accorded with applicable regulations. Under CERCLA, PRPs may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. Moreover, although CERCLA generally exempts “petroleum” from the definition of “hazardous substance,” in the course of our operations we generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. While 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, there can be no assurance that no such incidents will occur in the future.

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. Portions of OSHA’s Respirable Crystalline Silica rule that apply to hydraulic fracturing became effective in June 2018, with additional engineering controls becoming effective in 2021. While we believe we comply with the portions of the rule that became effective, we believe on-going compliance obligations could impose significant additional costs. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase. While we believe that compliance with these applicable requirements and with other OSHA and comparable requirements has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities.

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 believe we are in substantial compliance with all such requirements.

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing taxes and requirements for obtaining drilling permits. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced and an oil field clean-up fee of $0.00625 per barrel of oil.

Endangered Species Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that we own or lease.

In August 2019, the Fish and Wildlife Service finalized revisions to ESA regulations that somewhat loosened procedures for listing species, recovery, reclassifications and critical habitat designations. The rules removed the requirement that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” The rules also further relaxed the protection afforded to species listed as “threatened” from those that are endangered, with the protection for “threatened” species being made on more of a case-by-case basis.

Exports of US Oil Production and Natural Gas Production. In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,” which include all of our sales of our own production.

Under the Energy Policy Act of 2005 (“EPAct”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas

wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.

FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions require compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain.

Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate common carrier oil pipelines must provide service on a non-duly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various parties. Due to the pending rehearing of the order and its recency, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018.

Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act. The U.S. Commodities and Futures Exchange Commission (“CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affecting derivatives contracts that the Company uses to hedge its exposure to price volatility.

While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending, including a proposal to set position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents. The CFTC also has proposed, but not yet finalized, a rule regarding the capital posting requirements for swap dealers and major swap market participants. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to either rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases

our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

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

We do not directly employ any of the persons responsible for our management or operation. As of December 31, 2020, the Company has engagement letters with PhiCap Advisors, LLC (“PCA”) and Westbrook Energy Partners, LLC (“Westbrook”) who manage and support our operations. PCA provides financial, advisory and consultation services and employs Mr. Jeffrey Slotterback who serves as the Chief Executive Officer and Chief Financial Officer of the Company. Westbrook provides technical and advisory services and employs Mr. Christopher Walker who serves as the Chief Operating Officer of the Company.

We do not currently maintain a publicly-available website. However, you may receive, without charge, a paper copy of our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports by request to us at 2400 Market Street, Suite 230, Philadelphia, Pennsylvania 19103, telephone number (800) 251-0171. The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us. Copies of our filings can also be obtained on the SEC website at www.sec.gov.

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our business, while others relate principally to the securities markets and ownership of our limited partnership interests. Partnership interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The risks and uncertainties we face are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. In addition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Our independent registered public accounting firm has issued an opinion on our consolidated financial statements included in this Annual Report on Form 10-K that states that the consolidated financial statements were prepared assuming we will continue as a going concern. Our consolidated financial statements have been prepared using accounting principles generally accepted in the United States of America applicable for a going concern, which assume that we will realize our assets and discharge our liabilities in the ordinary course of business. We have incurred substantial operating losses and have used cash in our operating activities for the past few years. As of and for the year ended December 31, 2020, we had a net loss of $7.6 million, negative working capital of $0.8 million and net cash used in operating activities of $0.9 million. Our consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that may be necessary should we be unable to continue as a going concern. We also cannot be certain that additional financing, if needed, will be available on acceptable terms, or at all, and our failure to raise capital when needed could limit our ability to continue our operations. There remains substantial doubt about the Company's ability to continue as a going concern for the next twelve months from the date the consolidated financial statements were issued.

We may not have sufficient available cash to pay the full target distribution, or any distribution at all, on our common units and there is no guarantee that we will pay distributions to our unitholders in any quarter.

We may not have sufficient available cash each quarter to pay the full target distribution, or any distribution at all, to our unitholders. Furthermore, our Partnership Agreement does not require us to pay distributions on a quarterly basis or otherwise. 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 under the cash distribution policy that the board of directors of our general partner has adopted will be reduced by working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions that the board of directors may determine is appropriate. The board of directors of our general partner may change our cash distribution policy at any time without the approval of the unitholders or the conflicts committee of the board of directors of our general partner.

On November 2, 2016, the board of directors of our general partner determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. At this time, we can provide no certainty as to when or if distributions will be reinstituted.

We rely exclusively on our general partner and its appointed officers to provide us with facilities and personnel and to conduct operations.

We have no employees and no separate facilities. Consequently, we rely exclusively on our general partner and, because our general partner has no direct employees, ultimately upon its appointed officers, to provide facilities and personnel and to conduct operations. Our general partner has significant discretion as to the implementation of our operating policies and investment strategies. Moreover, we believe that our success depends to a significant extent upon the experience of the appointed officers. The departure of any of the members of these management teams could harm our investment performance.

There is no guarantee of return of investment or rate of return on investment because of the speculative nature of drilling natural gas and oil wells.

Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well, our general partner cannot predict with absolute certainty:

You may not recover any or all of your investment in us or, if you do recover your investment in us, you may not receive a rate of return on your investment that is competitive with other types of investments that may be available to you. Except in the case of a liquidity event, you will be able to recover your investment only through distributions of our net proceeds from the sale of our natural gas and oil from productive wells. However, there is no requirement that a liquidity event will occur within a specified timeframe or at all.

Our ability to convert our locations into cash flowing wells may be improved by raising additional capital. We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders. We will continue to vigorously pursue all options to maximize returns to our investors.

Our quarterly distributions may not be sourced from our cash generated from operations but from offering proceeds, and borrowings, among other sources, and this will decrease our cash available for distributions in the future.

There is no limitation on the amount of our distributions that can be funded from offering proceeds or financing proceeds. Our target distribution may be sourced from offering proceeds and borrowings, among other sources, rather than cash from operations. The payment of distributions from sources other than operating cash flow may decrease the cash available to invest in oil and gas properties, which may decrease our cash available for distributions in the future.

On November 2, 2016, our board of directors of our general partner determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. At this time, we can provide no certainty as to when or if distributions will be reinstituted.

Distributions from us may be a return of capital rather than a return on your investment.

The amount of cash that we have available for distribution will depend on our cash flow, including cash reserves, working capital and borrowings, if any, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

If a listing event occurs, our Partnership Agreement will automatically be amended and restated, becoming the Post-Listing Partnership Agreement, which will alter some of your rights as a limited partner.

If we undertake a listing event, our Partnership Agreement will automatically be amended and restated to become the Second Amended and Restated Agreement of Limited Partnership (the “Post-Listing Partnership Agreement”) and the common units will automatically convert into a new series of common units (the “Post-Listing common units”). Some of your rights as a limited partner will be altered as a result of that amendment and restatement, particularly voting rights. There is no requirement that a listing event will occur within a specified timeframe or at all. On November 2, 2016, our management decided to suspend our primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues.

Our general partner has received its general partner interest and its IDRs for only nominal consideration. In addition, our general partner receives an annual management fee equal to 1.00% of total capital contributions to us (other than those of our general partner and its affiliates), payable quarterly, as well as reimbursement of direct costs regardless of the success of our wells. The amount of reimbursements paid to our general partner are subject to only narrow limits in certain circumstances such as the reimbursement of administrative costs to our general partner are limited to those supportable as to the necessity of such reimbursement and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and other considerations. Otherwise, our Partnership Agreement and the other agreements we have with our general partner do not place meaningful limits on the magnitude of potential reimbursements; specifically, our general partner will determine which costs incurred are reimbursable and there are no limits on the amount of reimbursements on administrative costs to be paid to our general partner. These fees and reimbursements will reduce the amount of cash otherwise available for distribution to our limited partners.

Quarterly cash distributions have not been paid since 2016 and may not be paid in the future. Distributions may continue to be withheld or if reinstituted, may be reduced or deferred at any time, in the discretion of our general partner, due to local, state and federal regulations regarding permitting, fracturing, production, conservation, water disposal and treatment and pipeline construction and transportation of natural gas and oil, or to the extent our revenues are used for any of the following:

Changes in laws or regulations that require an amendment to our Partnership Agreement could limit the rights of our limited partners.

Our general partner may, without the consent of our limited partners, amend our Partnership Agreement to reflect any changes as a result of a change in law or regulation that causes any term or condition set forth in our Partnership Agreement to be no longer viable, as determined by our general partner in its sole discretion. Our general partner expects that any such changes will be made as narrowly as possible in order to effectuate the original intent of our Partnership Agreement. Nevertheless, any such change could limit our rights and obligations or those of our limited partners.

Our Post-Listing Partnership Agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Our Post-Listing Partnership Agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our Post-Listing Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or

restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

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

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 board of directors on an annual or other continuing basis. The board of directors of our general partner is elected by its unitholders. Furthermore, the vote of the holders of at least a majority of all outstanding common units is required to remove our general partner.

We may issue an unlimited number of common units and other equity securities, including interests that are senior to the common units, without approval of our limited partners, which would dilute your ownership interests in us.

Our Partnership Agreement does not limit the number of common units or other equity securities that we may issue at any time without the approval of our limited partners. In addition, we may issue an unlimited amount of interests that are senior to your interests in right of distribution, liquidation and voting. The issuance by us of equity interests of equal or senior rank will have the following effects:

In addition, the payment of distributions on any additional interests may increase the risk that we will not be able to make distributions at prior levels or at all. To the extent new interests are senior to the interests offered hereby, their issuance will increase the uncertainty of the payment of distributions.

Common units may also be issued in lieu of unpaid management fees. At December 31, 2020 there were unpaid management fees of $1.7 million.

The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

The common units are generally not liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Furthermore, although our Partnership Agreement contains provisions designed to permit the listing of the common units on a national securities exchange, the common units are currently not listed on any exchange or over-the-counter market and we may not be able to effect such listing. Your inability to sell or transfer your common units increases the risk that you could lose some or all of your investment because, if we are unable to meet our performance goals, you may not have the ability to transfer your common units prior to our winding up and liquidation.

We may be unable to sell our properties or list the common units on a national securities exchange within our planned timeline or at all.

We continue to evaluate and work towards either selling our properties and distributing the proceeds of the sale, after payment of liabilities and expenses, to our partners, with the approval of our general partner, or listing the common units on a national securities exchange. The decision to sell our properties will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of our assets, the projected amount of our oil and gas reserves, general economic conditions and other factors that are out of our control. In addition, the ability to list our common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, our ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If we are unable to either sell our properties or list the common units on a national

securities exchange in accordance with our current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. There is no requirement that a liquidity event occur within a specified timeframe or at all.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, volatile prices of oil, natural gas and NGLs, declining business and consumer confidence, energy costs, geopolitical issues, inflation and the availability and cost of credit have contributed to increased economic uncertainty and may diminish expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids produced from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our unitholders have agreed to be bound by our Partnership Agreement, which contains provisions that reduce the fiduciary standards to which our general partner is held. For example, our Partnership Agreement permits our general partner to:

Our general partner and the oil and gas and other professionals assembled by our general partner, face competing demands relating to their time, and this may cause our operations and our unitholders’ investments to suffer.

We rely on our general partner for the day-to-day operation of our business and the selection of our oil and gas properties. The Company does not directly employ any of the persons responsible for our management or operation, and the directors are employed by another company. As a result, the directors of our general partner and officers of the Company have other demands on their time as key executives of other entities. As a result of their interests in other entities, their obligations to other investors and the fact that they engage in and they will continue to engage in other business activities, these individuals will continue to face conflicts of interest in allocating their time among us and other business activities in which they are involved. As a result, the returns on our investments, and the value of our unitholders’ investments, may decline.

The fiduciary duties of our general partner’s officers and directors may conflict with those they may have to affiliates of our general partner.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, on the one hand, and our limited partners and us, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our unitholders. The directors and officers of our general partner have duties to manage our general partner in a manner beneficial to its owners. In addition, the directors of our general partner may serve in similar capacities with other companies, which may lead to additional conflicts of interest. At the same time, our general partner has certain fiduciary or contractual duties to us and our limited partners under our Partnership Agreement, the Post-Listing Partnership Agreement and applicable law.

Conflicts of interest between our general partner and our limited partners may not necessarily be resolved in favor of our limited partners.

There are potential conflicts of interest between our limited partners and our general partner and its affiliates. These conflicts of interest include the following:

These conflicts of interest may not be resolved in a way satisfactory to some or all of our limited partners.

We may choose not to retain separate counsel or other service providers for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other hand, depending on the nature of the conflict, although we may choose not to do so.

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2020, the NYMEX Henry Hub natural gas index price ranged from a high of $3.35 per MMBtu to a low of $1.48 per MMBtu, and West Texas Intermediate (“WTI”) oil prices ranged from a high of $63.27 per bbl to a low of ($37.63) per bbl.

Any prolonged substantial decline in the price of oil and natural gas such as that experienced from 2015 until 2017 will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil and natural gas sales to reduce the impact of commodity price fluctuations. However, the entire exposure of our operations from commodity price volatility is not currently hedged, and we may not be able to hedge such exposure going forward. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be further diminished.

In addition, low oil and natural gas prices can reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices.

The ongoing COVID-19 outbreak and the related impact on oil and natural gas prices have adversely affected, and could continue to adversely affect, our business, financial condition and results of operations.

The ongoing COVID-19 outbreak, which the WHO declared a pandemic and the United States Government declared a national emergency in March 2020, has reached more than 200 countries and has continued to be a rapidly evolving situation. The pandemic has resulted in widespread adverse impacts on the global economy and financial markets and we and our operators and other parties with whom we have business relations have experienced some resulting disruptions to our and their business operations. For example, since mid-March, we have had to limit access to our administrative offices and have taken certain other precautionary measures intended to help minimize the risk to our employees, our business and our community. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. In addition, our employees are now working remotely, which could increase the risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions.

The impact of the pandemic, including the resulting significant reduction in global demand for oil and, to a lesser extent natural gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, is expected to lead to significant global economic contraction generally and in our industry in particular. Oil and natural gas prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil and natural gas inventories, industry demand and economic performance are reported. The current price environment has caused some of our operators’ wells to become uneconomic, which has resulted, and may result in the future, in suspension of production from those wells or a significant reduction in, existing production. Some operators may also attempt to shut in producing wells and avoid lease termination or payment of shut-in royalties by claiming force majeure, if provided for in the applicable lease. The curtailment of production or the shut-in of wells as a result of the ongoing COVID-19 outbreak and the drop in oil prices are both outside of our control, and the materialization of either circumstance could have a significant impact on our result of operations. We may receive notices regarding well shut-ins and curtailments of production from our operators as reductions in global demand for oil and natural gas resulting from the COVID-19 outbreak and depressed oil prices resulting from the OPEC decisions each continue and as oil storage facilities reach capacity and/or purchasers of crude products cancel previous orders as a result.

Due to the recent significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and other supply factors, we have recorded an impairment on our oil and natural gas properties for the three months ended March 31, 2020. If the expected significant decline in the price of oil, natural gas and NGLs continues through future periods or if prices decrease further in future periods, we may be required to record additional impairments.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments beyond our control, which are highly uncertain and cannot be predicted, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, future actions taken by members of OPEC and other foreign oil-exporting countries, actions taken by governmental authorities, our operators and other third parties and the timing and extent to which normal economic and operating conditions resume.

The ability or willingness of the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

The Organization of Petroleum Exporting Countries (“OPEC”) is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. There can be no assurance that OPEC members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition and results of operations.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire natural gas and oil properties and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas, natural gas liquids and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we do. Any of these factors could make it more difficult for us to execute our business strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective revenues or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy, such as wind or solar power. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many oil and gas companies possess greater financial and other resources than we do, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Previous drilling by others may reduce our ability to find economically recoverable quantities of natural gas or oil.

Our primary drilling areas are located in areas where other oil and gas companies have previously drilled wells. As a result, many of the areas to be drilled by us are in locations that have already been partially depleted or drained by earlier drilling. This may reduce our ability to find economically recoverable quantities of natural gas and oil in those areas.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

We depend on certain key customers for sales of our natural gas, crude oil and NGLs. To the extent these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us, or cease to purchase or process natural gas, crude oil and NGLs from us, our revenues and cash available for distribution could decline.

We sell natural gas, crude oil and NGLs under contracts to purchasers in the normal course of business. For the year ended December 31, 2020, Shell Trading Co individually accounted for approximately 94% of our total natural gas, crude oil and NGLs production revenue, excluding the impact of all financial derivative activity. If one or more of our customers ceased purchasing our natural gas, crude oil and NGLs altogether, the loss of such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes, which could in turn reduce our revenue and cash available for distribution.

An increase in the differential between the NYMEX or other benchmark prices of natural gas and oil and the wellhead price that we receive for our production could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

The prices that we receive for our natural gas and oil production sometimes reflect a discount to relevant benchmark prices, such as those on the New York Mercantile Exchange, or 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 natural gas and oil and the wellhead price that we receive could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only because dry holes may be drilled, but also because productive wells may not produce sufficient revenues to be commercially viable. This risk is exacerbated by the current decline in oil and gas prices. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

Any one or more of these factors could reduce or delay our receipt of drilling and production revenues and increase our costs, thereby reducing our ability to make distributions to our limited partners. In addition, any of these events can cause substantial losses, which may not fully be covered by insurance, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties, which could reduce our cash flow and our ability to make distributions to our limited partners.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks are not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

Our operations require substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our asset base will decline, which could cause our revenues to decline.

The natural gas and oil industry is capital intensive. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our revenues to decline and diminish our ability to service any debt that we may have at such time. If we do not make sufficient or effective capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would reduce our cash flows from operations and income.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas and oil reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and sources of capital, all of which are subject to the risks discussed elsewhere in this section. The value of our common units and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production or replace our declining production with new production. We may not be able to develop, exploit, find or acquire sufficient additional reserves or replace our current and future production.

A decrease in commodity prices could subject our oil and gas properties to impairment losses under U.S. generally accepted accounting principles.

U.S. 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 general partner will test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and estimated abandonment costs is less than the estimated expected undiscounted future cash flows. Expected future cash flows are estimated based on our or our general partner’s own economic interests and our 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 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. Natural gas and oil prices remain volatile and have recently declined substantially and could continue to decrease in the future. Prolonged depressed prices of natural gas or oil may cause the carrying value of our or our general partner’s oil and gas properties to exceed the expected future cash flows, and require that an impairment loss be recognized.

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

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our estimates of our proved reserves are prepared by our internal engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our standardized measure is calculated using natural gas prices that do not include

financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the 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 the estimated natural gas and oil reserves. We base the estimated discounted future net cash flows from proved reserves on historical prices and costs, but actual future net cash flows from our natural gas and oil properties will also be affected by factors such as:

The timing of both the production and incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10.00% discount factor that 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 the company or the natural gas and oil industry in general.

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

Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we may use financial hedges and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes, but rather forward contracts because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil.

In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The futures contracts are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

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. 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.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

We account for our derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in us recognizing a non-cash loss in our statements of operations and a consequent non-cash decrease in our equity between reporting periods. Any such decrease could be substantial. In addition, we may be required to make cash payments upon the termination of any of these derivative contracts.

Regulations adopted by the Commodities Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The ongoing implementation of derivatives legislation adopted by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The Dodd-Frank Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission (the “CFTC”), and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized many of the regulations associated with the reform legislation, and is in the process of implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits, subject to reporting and record keeping requirements and internal authorizations. The CFTC adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants and financial end users (though non-financial end users are excluded from margin requirements). While, as a non-financial end user, we are not subject to margin requirements, application of these requirements to our counterparties could affect the cost and availability of swaps we use for hedging. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation or regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and/or cash flows.

Our investment strategy depends on our ability to acquire projects. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including difficulty in assessing recoverable reserves, future production rates, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control. As a result, we may not recover our investment in a project from the sale of production from the project, or may not recognize an acceptable return from investments we make. A downturn in the credit markets and a potential lack of available debt could result in a further reduction of suitable investment opportunities and create a competitive advantage to other entities that have greater financial resources than we do. During such times, our ability to borrow monies to finance the purchase of, or other activities related to, oil and gas assets will be negatively impacted. In addition, if we pay fees to lock in a favorable interest rate, falling interest rates or other factors could require us to forfeit these fees. If we acquire properties and other investments at higher prices or by using less-than-ideal capital structures, our returns will be lower and the value of our assets may decrease significantly below the amount we paid for the assets.

We can give no assurance that we will be successful in identifying or, even if identified, acquiring suitable properties on financially attractive terms or that our objectives will be achieved. Any of these factors could adversely affect our ability to achieve our anticipated levels of cash flow from our projects, pay distributions and meet our investment objectives.

Acquired properties may prove to be worth less than we paid, or provide less than anticipated proved reserves or production, because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our or our general partner’s internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain; our proved reserves estimates may thus exceed actual acquired proved reserves. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not inspect every well. Even when we do inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and natural gas properties may exceed the value we realize.

Also, our reviews of the properties included in the acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify all liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our investment strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable or may be limited by floors and caps, and the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on our ability to recover the costs related to any potential problem could materially impact our financial condition and results of operations.

Ownership of our oil, gas and natural gas liquids production depends on good title to our property.

Good and clear title to our oil and gas properties is important. Although we will generally conduct title reviews before the purchase of most oil, gas, natural gas liquids and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction or elimination of the revenue received by us from such properties.

Local and municipal laws could also result in increased costs and additional operating restrictions or delays.

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing and related operations in particular. In some jurisdictions, the authority of localities to regulate hydraulic fracturing has become contentious. Courts have been asked to determine whether state regulatory schemes “pre-empt” local regulation. The outcome of legal challenges to local efforts to regulate hydraulic fracturing depends in large part on the intent of the State legislature and the comprehensiveness of its statutory scheme. If the right of municipalities to impose additional requirements is upheld, and municipalities elect to do so, local rules could impose additional constraints – such as siting and setback restrictions – and costs on our operations.

We must operate in accordance with comprehensive environmental laws that affect the manner, feasibility and cost of our operations.

Our operations are regulated extensively at the federal, state and local levels. Our operations, wells and other facilities are subject to stringent and complex federal, state and local environmental laws governing air emissions, water use and wastewater discharge, hazardous waste management and hazardous substance response. In some cases, we may be required to obtain environmental assessments, environmental impact studies, and/or plans of development before commencing drilling and production activities. Our activities may be subject to regulations regarding conservation practices. These regulations affect our operations and may limit the quantity of natural gas and oil we may produce and sell. Compliance with environmental laws will add to the costs of planning, designing, drilling, installing, operating and abandoning natural gas and oil wells.

Our ability to obtain, remove, treat, recycle or otherwise dispose of water will affect our production, and the cost of water treatment and disposal may affect our ability to make distributions.

Hydraulic fracturing requires large amounts of water and results in water discharges that must be treated, recycled or otherwise disposed. Environmental regulations governing the injection, withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our operations and financial performance. Although not anticipated by our general partner, we may need to drill our own water disposal wells. We currently use trucks to transport the water to water disposal wells or water treatment or recycling facilities, in certain areas, and pipe the water to disposal wells in other areas. If, however, we needed to drill our own disposal wells, there is a risk that we could not operate a gas production well at its full capacity until the required permit for the water disposal well was issued. Finally, if the environmental laws governing the management of produced waters become more stringent, they could restrict our ability to conduct hydraulic fracturing or increase our cost.

Rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

In 2012, USEPA established the NSPS rule for oil and natural gas production, transmission, and distribution, and also made significant revisions to the existing National Emission Standards for Hazardous Air Pollutants (“NESHAP”) rules for oil and natural gas production, transmission, and storage facilities. These rules require oil and natural gas production facilities to conduct “green completions” for hydraulic fracturing, which is recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. Both the NSPS and NESHAP rules continue to evolve based on new information and changing environmental concerns. President Trump’s March 28, 2017, Executive Order on Promoting Energy Independence and Economic Growth ordered federal agencies to revisit federal rules aimed at limiting methane emissions from oil and gas wells. Initial efforts to revise or rescind standards for new or modified wells were invalidated by the courts but corrective rule-making initiated. We believe it will be several years before those new rules are fully implemented.

Some states in which we operate are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations.

Compliance with new rules regulating air emissions from our operations could result in significant costs, including increased capital expenditures and operating costs, and could affect the results of our business.

Environmental laws may become more stringent, increasing the financial and managerial costs of compliance and, consequently, reducing our profitability.

The possibility exists that stricter environmental laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs. Failure to comply with environmental laws may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. States outside the geographic area in which we conduct our activities have imposed a variety of restrictions on hydraulic fracturing that could be adopted in jurisdictions in which we operate. State restrictions have included permitting, chemical disclosure, siting, seismicity, water withdrawal and disposal, and tank secondary containment requirements. If new restrictions such as these or others are imposed on our operations, we may (i) incur significant additional costs to comply, (ii) experience delays or curtailment in the pursuit of exploration, development or production activities, and (iii) perhaps even be precluded from drilling wells.

The federal government could take a more active role in regulating hydraulic fracturing, which could result in increased costs, operating restrictions or delays.

Presently, the hydraulic fracturing process, unless conducted on federal land, has not generally been subject to comprehensive regulation at the federal level. Presently, federal interests are primarily in the disclosure of fracturing fluid ingredients where fracturing occurs on federal lands and in air emissions from fracturing wells. If hydraulic fracturing were to become comprehensively regulated at the federal level, our fracturing activities could be significantly affected. Federal restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are able to produce. New environmental initiatives and regulations could include restrictions on the ability to conduct hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas. Also, the threat of climate change has resulted in increasing political risks in the United States, including climate-related pledges to ban hydraulic fracturing of oil and gas wells. Any of these environmental initiatives and regulations could have a material adverse effect on our financial condition and results of operations.

We may not be able to secure all the authorizations required under environmental law to conduct drilling operations.

A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our leases. Under some laws, environmental organizations have the right to challenge production operations on grounds of environmental protection. In recent years, organized opposition has succeeded in curtailing certain drilling projects.

We may incur liability as the result of an accidental release of hazardous substances into the environment.

Our operations create the risk of inadvertent releases of hazardous substances into the environment, despite the exercise of reasonable caution. If such a release were to occur, we will be liable for the costs of responding to any such release, investigating the extent of its impacts and the cost of any remediation that may become necessary. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. We may not be able to recover remediation costs under our insurance policies.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, oil and NGLs we produce.

Future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.

With the issuance, on March 28, 2017, of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth, we believe it may take many years for new comprehensive federal policy aimed at greenhouse gas emissions to gel (see Item 1: Business—Environmental Matters and Regulation—Greenhouse Gas Regulation and Climate Change). Given the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are “air pollutants” covered by the Clean Air Act) and scientific hurdles to overturning EPA’s endangerment finding, we believe some form of regulation will have to remain. Regulations with the most direct impact on our operations concern controlling methane emissions from wells. Rules that affect overall consumption of fossil fuels, and the mix of fossil fuels consumed, could also affect the demand for our products. We believe, however, that federal agency implementation of the President’s Executive Order is some years away. While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. Greater Congressional activity with respect to greenhouse gas emissions may be expected however as a result of Democrats regaining control of the House of Representatives.

In the absence of comprehensive federal climate change policy, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. States may also pursue additional regulation of our operations, including restrictions on methane emissions from new and existing wells and fracturing operations. State and regional initiatives could result in significant costs, including increased capital expenditures and operating costs, affect the demand for our products, and could affect the results of our business.

If the current Administration’s initiatives to lessen the burden of environmental regulation on fossil fuel production and consumption become effective, they could result in greater overall supply of fossil fuels, reducing the price we receive for our output.

Pursuant to the President’s Executive Order on Promoting Energy Independence and Economic Growth, federal agencies have initiated several rule-makings to rescind and reconsider rules issued by the prior Administration that increased the overall stringency of environmental regulation of fossil fuel production and consumption. The Administration has taken several steps to reverse the prior Administration’s policies that disadvantaged coal as a fuel for energy production, including withdrawing from the Paris Climate

Agreement, a replacement of the 2015 Clean Power Plan, withdrawal of mercury limits on coal plants’ air emissions, lifting the prior Administration’s ban on new coal leases on federal lands and ending the review of the program’s greenhouse gas impacts, and withdrawing the “Waters of the United States” stream protection rule. The Administration has opened more federal lands for oil and gas production, approved the construction of the Keystone Pipeline to facilitate refining of Alberta oil shale in the United States, licensed the Dakota Access Pipeline, and opened areas in the Arctic and Atlantic Ocean to drilling. The Administration has initiated several rule-makings aimed at lessening the stringency of environmental regulation of oil and gas production. Most of these actions are susceptible to, and can be expected to be the target of, court challenges. If they are fully implemented, and if they have the effect of increasing the overall fuel supply, they could have the effect of diminishing demand for our natural gas and oil output. Diminished demand could put additional downward pressure on the price of the natural gas and oil we produce.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third- party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we will pay for their services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could subject us to liability and, if such failures are material, would require us to make alternative arrangements, which may not be available or which may involve increased costs.

Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our credit facility, our ability to make distributions to our unitholders will be inhibited. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

As of December 31, 2020 the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but it allows us to have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and a first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. If such borrowing base were to be established, it would be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders. In addition, any limitations on our ability to borrow under our credit facility could inhibit our ability to make acquisitions, which could prevent us from being able to pay the target distribution.

If we are unable to obtain funding for future capital needs, cash distributions to our unitholders and the value of our properties could decline.

If we need additional capital in the future to improve or maintain our properties or for any other reason, we may have to obtain financing from sources beyond our funds from operations, such as borrowings. These sources of funding may not be available on attractive terms or at all. If we cannot procure additional funding for capital improvements, our properties may generate lower cash flows or decline in value, or both, which would limit our ability to make distributions to our unitholders and could reduce the value of your investment.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from our operators than we or they currently anticipate.

As of December 31, 2018, a portion of our total estimated proved reserves were proved undeveloped or proved developed non-producing reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. Our reserve report assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for our operators. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Because some wells may not return their drilling and completion costs, it may take many years to return your investment in cash, if ever.

Even if a well is completed by us and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. Thus, it may take many years to return your investment in cash, if ever.

Horizontal wells are more expensive and difficult to drill and complete than vertical wells.

Our general partner anticipates that some of the wells we will drill will be horizontal wells. Horizontal wells are more expensive to drill and complete than vertical wells because of increased costs associated with the drilling rigs needed to drill a horizontal well, including hydraulically fracturing the wells multiple times and using more casing in the wells. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process of hydraulically fracturing wells results in higher costs, which may not result in greater recoverable reserves. In addition, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment, than vertical wells. Further, fracturing the formation in a horizontal well is more complicated than fracturing the same geological formation in a vertical well.

Our business depends on third-party natural gas and oil transportation and processing facilities and our ability to contract with those parties.

Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could require us to curtail or shut-in one or more producing wells or delay or discontinue drilling wells in an area where we have acquired projects. A curtailment or shut-in of production could materially reduce our cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow. Also, we may be unable to, or elect not to, purchase firm transportation on third party facilities and, in that event, our production transportation could be interrupted by other developers having firm arrangements. If any third-party pipelines and other facilities become partially or fully unavailable to transport or process our natural gas and oil production, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as to restrict our ability to transport natural gas on those pipelines or facilities, we could be required to curtail or shut-in one or more of our wells and our revenues could decrease. Also, the disruption of third-party facilities due to maintenance and/or weather could limit our ability to market and deliver our natural gas, NGLs and oil production.

Participation with third parties in drilling wells may require us to pay additional costs and could subject our revenues to the claims of the third-party creditors.

Our general partner anticipates that we may participate with third parties in drilling some of our wells. In this regard, additional financial risks exist when the costs of drilling, equipping, completing, and operating wells are shared by more than one person. If we pay our share of the costs, but another interest owner does not pay its share of the costs, then we would have to pay the costs of the

defaulting party. In this event, we would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, cover all of the additional costs paid by us.

If we are not the actual operator of the well for all of the working interest owners of the well, then there is a risk that our general partner will not be able to supervise the third-party operator closely enough, and that decisions related to the following would be made by the third-party operator, which may not be in our best interests or the best interests of our limited partners:

Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause us to incur extra costs in discharging materialmen’s and workmen’s liens. In this regard, we may not be the operator of a well for all of the working interest owners of the well if we own less than a 50.00% working interest in the well, or if we acquired the working interest in the well from a third party under arrangements that required the third party to be named operator.

A terrorist attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.

Terrorist activities, anti-terrorist efforts, and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Costs for insurance, recovery, remediation and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and increase compliance challenges.

We rely extensively on information technology systems, including Internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions.

Although we have implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations which may include drilling, completion, production and corporate functions. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:

All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

Outbreaks of communicable diseases could adversely affect our business, financial condition and results of operations.

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“COVID-19”). The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition and results of operations.

We are an “emerging growth company” under the federal securities laws and are subject to reduced public company reporting requirements.

We are an “emerging growth company,” as defined in the JOBS Act, and are eligible to take advantage of certain exemptions from, or reduced disclosure obligations relating to, various reporting requirements that are normally applicable to public companies.

We could remain an “emerging growth company” until the earliest of (i) December 31 following the fifth anniversary of the date of the first sale of our common units pursuant to an effective registration statement filed under the Securities Act of 1933, as amended; (ii) December 31 of the first fiscal year in which we have total annual gross revenue of $1.07 billion or more; (iii) December 31 of the fiscal year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act (which would occur if the market value of our common units held by non-affiliates exceeds $700 million, measured as of the last business day of our most recently completed second fiscal quarter, and we have been publicly reporting for at least 12 months); or (iv) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period. Under the JOBS Act, emerging growth companies are not required to (a) provide an auditor’s attestation report on management’s assessment of the effectiveness of internal control over financial reporting, pursuant to Section 404 of the Sarbanes-Oxley Act, (b) comply with new audit rules adopted by the PCAOB, (c) provide certain disclosures relating to executive compensation generally required for larger public companies or (d) hold shareholder advisory votes on executive compensation.

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If 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 do 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, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

Following a listing event, 90% or more of our gross income for every taxable year must be qualifying income, as defined in Section 7704 of the Code, in order to avoid being treated as a corporation for federal income tax purposes. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof) or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise be subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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 rate, which is 21% for taxable years beginning after December 31, 2018, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and none of our income, gain, loss, deduction and credit would flow through to you. If a tax were imposed on us as a corporation, our cash available for distribution could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to you, and therefore result in a substantial reduction in the value of our securities.

Your tax benefits from an investment in us may be affected by changes in the tax laws. For example, from time to time members of Congress have proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including your option to amortize intangible drilling costs over a 60 month period) and the passive activity exception for working interests. These proposals may or may not be enacted into law.

Limited partners need passive income to use their partnership deductions that exceed the income from us.

A limited partner’s share of our net losses will be passive losses that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, you may not have enough passive income from us or net passive income from your other passive activities, if any, to be offset by a portion or all of your passive deductions from us. However, any unused passive loss from us may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Also, except as described below, the passive activity limitations on your share of our losses do not apply to you if you invest in us and you are a corporation taxable under Subchapter C of the Code, which:

You may become subject to income tax liability for your share of our income in any taxable year in an amount that is greater than the cash you receive from us in that taxable year. For example:

In addition, under the recently enacted tax reform law known as the Tax Cuts and Jobs Act, if we borrow money and pay interest, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a limited partner’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

You and the other 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, you and the other 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 you do not reside in any of those jurisdictions. Substantially all of our income is currently generated in Texas, although we may drill wells in other states as well. It is your responsibility to file all federal, foreign, state and local tax returns that may be required of you. In this regard, our tax counsel has not rendered an opinion on any foreign, state or local tax consequences of an investment in us.

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

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and IRAs, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. If you are a tax-exempt entity, you should consult your tax advisor before investing in our common units.

We may be required to deduct and withhold certain amounts upon transfers of common units by non-U.S. persons.

Under the recently enacted tax reform law, if a limited partner sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld.

If the IRS makes audit adjustments to our income tax returns for taxable years beginning after 2017, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our limited partners may be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, the IRS may collect any resulting taxes (including any applicable penalties and interest) directly from us (rather than our general partner and our limited partners). Certain states in which we own assets and conduct business may adopt the IRS approach or apply similar rules.

We will generally have the ability to shift any such tax liability (including penalties and interest) to our general partner and our limited partners in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our limited partners might be substantially reduced.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our limited partners in accordance with their interests in us during the taxable year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment owed by us by reducing the suspended passive loss carryovers of our limited partners (without any compensation from us to such limited partners), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected limited partners.

An IRS audit of us may result in an IRS audit of your personal federal income tax returns.

The IRS may audit our annual federal information income tax returns, particularly since our investors will be eligible to claim deductions for intangible drilling costs and, with respect to wells drilled, completed and placed in service by us, depreciation of qualified equipment costs. If we are audited, the IRS also may audit your personal federal income tax returns, including prior years’ returns and items that are unrelated to us. Any adjustments made by the IRS to our federal information income tax returns could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from us.

Upon a listing event, we will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our limited partners. The IRS may challenge this treatment, which could adversely affect the value of your common units.

When we issue additional equity interests or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our limited partners and general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we may make many of the fair market value estimates ourselves using a methodology based on the market value of our equity interests as a means to measure the fair market value of our assets. The methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain holders of common units and our general partner, which may be unfavorable to you. Moreover, under current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge the valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of the holders of common units.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our limited partners. It also could affect the amount of gain on the sale of equity interests by you and could have a negative impact on the value of our equity interests or result in audit adjustments to the tax returns of our limited partners without the benefit of additional deductions.

We are a party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See Part II, Item 8: Financial Statements and Supplementary Data - Note 8.

The common units are currently not listed on any exchange or over-the-counter market. The common units have not been approved for quotation or trading on a national securities exchange. Subject to the approval of the board of directors of our general partner, our Partnership Agreement gives our general partner the right to cause the common units to be listed on a national securities exchange if our general partner determines that the common units meet the listing requirements of a national securities exchange. No assurances can be made that the common units will be listed on a national securities exchange, and even if listed an active market for the common units may not develop.

The following table presents our selected historical consolidated financial data as of and for the periods indicated and should be read in conjunction with Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8: Financial Statements and Supplementary Data.

		Years Ended December 31,
		2020		2019			2018			2017			2016
				(in thousands, except per unit data)
Statement of operations data:
Revenues:
Natural gas revenue	$	56		$	82		$	225		$	322		$	358
Oil revenue		2,672			5,791			9,708			7,117			11,121
NGLs revenue		125			188			508			402			372
Gain (loss) on mark-to-market derivatives		—			—			(381	)		310			(780	)
Total revenues		2,853			6,061			10,060			8,151			11,071
Costs and expenses:
Gas and oil production		1,289			2,512			3,486			2,528			2,660
General and administrative		1,572			1,261			655			813			571
General and administrative – affiliate		2,710			3,206			3,291			4,131			9,347
Depreciation, depletion and amortization		899			3,607			5,874			3,576			14,868
Asset impairment		4,020			10,982			41,762			—			41,879
Total costs and expenses		10,490			21,568			55,068			11,048			69,325
Operating loss	$	(7,637	)	$	(15,507	)	$	(45,008	)	$	(2,897	)	$	(58,254	)
Loss on asset sales		—			(33	)		—			—			—
Other loss		—			—			—			—			(5,383	)
Net loss	$	(7,637	)	$	(15,540	)	$	(45,008	)	$	(2,897	)		(63,637	)
Balance sheet data (at period end):
Property, plant and equipment, net	$	4,782		$	9,682		$	24,686		$	65,293		$	68,899
Total assets		6,914			12,955			28,920			74,219			78,500
Total partners’ capital		3,727			11,364			26,904			71,912			74,809
Cash flow data:
Net cash provided by (used in) operating activities	$	(859	)	$	(1,284	)	$	2,180		$	(350	)	$	8,105
Net cash used in investing activities		—			(20	)		(6,873	)		—			(6,602	)
Net cash provided by (used in) financing activities		—			—			—			—			(16,238	)
Capital expenditures		—			—			6,873			—			6,602

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6: Selected Financial Data” and “Item 8: Financial Statements and Supplemental Data”, which contains our consolidated financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and in “Item 1A: Risk Factors”. We believe the assumptions underlying the consolidated financial statements are reasonable. However, our consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.

Atlas Growth Partners, L.P. (the “Company”) is a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.

The interests of Limited Partners of the Company were not affected, altered or otherwise modified by the Debt Exchange.

In connection with and following the Debt Exchange, our general partner appointed Christopher Abbate, Daniel Flannery and Jack Maleh to serve as directors on the Board (collectively, the “New Directors”) replacing each of the previous directors of our general partner. The New Directors terms as directors began on May 1, 2020 and the former directors resignations were effective on May 1, 2020.

In connection with and following the Debt Exchange, our general partner appointed Jeffrey Slotterback, its previous Chief Financial Officer, to serve as Chief Executive Officer in addition to serving as Chief Financial Officer, and Christopher Walker, its previous Chief Operating Officer, will serve in that capacity (collectively, the “New Officers”) going forward. The respective terms of the New Officers as officers began on May 1, 2020 and the previous officers resignations were effective on May 1, 2020.

We anticipate further reductions in general and administrative expenses following the Debt Exchange and the appointment of the New Officers.

On June 19, 2020, affiliates of Titan closed on the sale of their Eagle Ford Shale assets with Texas American Resources Corporation II (“TARC”) for $13.2 million based on a May 1, 2020 effective date. In connection with the transaction, we entered into a contract operator agreement with TARC, whereby TARC will operate certain oil and gas properties and will provide other services to the Company related to our properties. We anticipate the TARC contract operator agreement will further reduce our general and administrative expenses.

The significant risks and uncertainties related to our inability to satisfy our current liabilities raise substantial doubt about our ability to continue as a going concern. If these liabilities are called, we will not have sufficient liquidity to repay all of our outstanding liabilities, and as a result, there would be substantial doubt regarding our ability to continue as a going concern.

We continually monitor capital markets and may make changes from time to time to our capital structures, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our liabilities or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our 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 our stakeholders. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets.

Our combined consolidated 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. Our combined consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in south Texas. While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses. At December 31, 2020, we had $1.4 million of cash on our balance sheet and no debt. Our general and administrative expenses decreased $0.2 million to $4.3 million for the year ended December 31, 2020 from $4.5 million for the year ended December 31, 2019.

During the year ended December 31, 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line during May 2018.

While we manage the Company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the Company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the Company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations. Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital, but we have limited avenues to do so at this time. We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders. We will continue to vigorously pursue all options to maximize returns to our investors.

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 or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Since 2017, the natural gas, oil and natural gas liquids commodity price markets have been marked by volatility. While we anticipate high levels of exploration and production activities over the long-term in the area in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves. The economics of drilling new oil wells across our acreage position in the Eagle Ford Shale in south Texas have improved over the past few years, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.

Beginning in March 2020, significant price decline and price volatility for oil and gas products emerged in the market. We have been and could continue to be directly impacted by these price changes if demand and prices remain depressed for an extended period of time. Given the volatility and uncertainty, we may be at risk of being able to identify and secure a party to gather and purchase our products. A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses. To date, we have been able to sell our production and we continue to identify multiple

purchasers. However, should these parties become unwilling to purchase our production, we will need to work to identify other purchasers in the area to gather and purchase our oil and gas products. Failure to identify other purchasers and storage facilities, may result in the potential shut-in of the field. The financial statement impact, change in price and expected time for these changes is not estimable but could result in significant decreases in oil and gas operations.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our obligations and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we would not have access to sufficient capital, our ability to drill and acquire more reserves would be negatively impacted. As of December 31, 2020, the Company does not have any immediate plans to drill new wells.

For additional information, please see “Liquidity and Ability to Continue as a Going Concern.”

Production Profile. We have established production positions in the following areas:

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production volumes per day for the periods indicated:

	Years Ended December 31,
	2020	2019		2018
Total production volumes per day:
Natural gas (Boed)	25		31		51
Oil (Bpd)	208		274		396
NGLs (Bpd)	31		38		57
Total (Boed)	264		343		504
Total production volumes:
Natural gas (MBoe)	9		11		19
Oil (MBbls)	76		100		145
NGLs (MBbls)	12		14		20
Total (MBoe)	97		125		184

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and NGL production, along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, for the periods indicated:

	Years Ended December 31,
	2020		2019		2018
Production revenues (in thousands):⁽¹⁾
Natural gas revenue	$	56	$	82	$	225
Oil revenue		2,672		5,791		9,708
NGLs revenue		125		188		508
Total production revenues	$	2,853	$	6,061	$	10,441
Average sales price, unhedged:
Natural gas (per Mcf)	$	1.01	$	1.21	$	2.03
Oil (per Bbl)	$	35.20	$	57.99	$	67.13
NGLs (per Bbl)	$	10.91	$	13.50	$	24.26

Total Oil and Gas Costs (in thousands)		1,289		2,512		3,486

Oil and Gas Production Costs (per Boe):
Lease operating expenses	$	10.29	$	15.24	$	15.37
Production taxes		2.31		3.70		3.36
Transportation and compression		0.75		1.14		0.21
Total production costs per Boe	$	13.35	$	20.08	$	18.94

Our gas and oil production revenues were lower in the current year as compared to the prior year due to a $1.4 million decrease resulting from decreased production volumes and a $1.8 million decrease due to lower realized prices. The decrease in our gas and oil production revenues for the year ended December 31, 2019 as compared to the prior year was due to a $3.3 million decrease resulting from decreased production volumes and a $1.1 million decrease due to lower realized prices.

Our gas and oil production costs were lower in the current year as compared to the prior year due to $1.2 million of lower lease operating expenses primarily resulting from reduced repairs, maintenance and workover costs. Our gas and oil production costs were lower in the year ended December 31, 2019 as compared to the prior year due to $1.0 million of lower lease operating expenses primarily resulting from reduced repairs, maintenance and workover costs.

Gain (loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our consolidated statements of operations. The recognized gains/(losses) during the year ended December 31, 2018 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior period end. As of December 31, 2020 and 2019, we did not have any commodity derivatives outstanding.

General and Administrative Expenses. The decrease in general and administrative expenses for the current year as compared to the prior year was due to a decrease in salaries, wages and other corporate costs as a result of management’s plan to reduce general and administrative expenses, offset by an increase due to certain one-time charges associated with our separation from ATLS. The increase in general and administrative expenses for the year ended December 31, 2019 as compared to the prior year was due to an increase of $0.6 million in corporate activity costs related to due diligence costs for acquisition evaluations.

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization for the current year as compared to the prior year period of $2.7 million was due to the asset impairments recorded in the first quarter of 2020 and previous periods, which lowered our depletable base, as well as, lower production volumes. The decrease in depreciation, depletion and amortization for the year ended December 31, 2019 as compared to the prior year was $2.3 million due to the asset impairments recorded in the 4^th quarter of 2019 and 2018, which lowered our depletable base, as well as, lower production volumes.

Asset Impairment. For the years ended December 31, 2020 and 2019, we recognized $4.0 million and $11.0 million, respectively, of impairment related to our proved oil and gas properties in the Eagle Ford operating area, which were impaired due to lower forecasted commodity prices.

Loss on Asset Sales. In January 2019, we sold our Marble Falls position, which resulted in a gain of $15 thousand after customary purchase price adjustments. In July 2019, we sold our Mississippi Lime position, which resulted in a loss of $48 thousand after customary purchase price adjustments.

See “Liquidity and Ability to Continue as a Going Concern” section above for additional disclosures regarding our liquidity and financial condition.

We currently fund our operations through cash on hand and cash generated from operations. Our future cash flows are subject to a number of variables, including oil and natural gas prices.

As of December 31, 2020, we had $1.4 million of cash on our balance sheet and no debt.

For the years ended December 31, 2020 and 2019, we had net losses of $7.6 million and $15.5 million, respectively, and cash used in operating activities of $0.9 million and $1.3 million, respectively. With the Company’s negative working capital, the Company may not have sufficient resources to fund operations into 2022.

The change in cash flows (used in) provided by operating activities compared with the prior period was due to a $0.4 million increase in net cash provided by operating activities from cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production revenues, and collections net of payments for royalties, lease operating expenses, severance taxes and general and administrative expenses coupled with certain one-time charges associated with our separation from ATLS.

The change in cash flows used in investing activities compared with the prior year period was due to asset sales in 2019 for which there was no comparable activity in 2020.

The change in cash flows provided by (used in) operating activities compared with the prior period was due to a $3.5 million decrease in net cash provided by operating activities from cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production revenues, and collections net of payments for royalties, lease operating expenses, severance taxes and general and administrative expenses.

The change in cash flows used in investing activities compared with the prior year period was due to a decrease of $6.9 million in capital expenditures related to our development activities as we drilled and brought in line a well in the Eagle Ford Shale during May 2018.

During the years ended December 31, 2020 and 2019, we did not have any material accrued well drilling and completion and capital expenditures.

As of December 31, 2020, we did not have any off-balance sheet commitment arrangements for our drilling and completion and capital expenditures.

As of December 31, 2020, we did not have any contractual obligations or commercial commitments.

On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks, which matured on May 1, 2020. As of December 31, 2019, the lenders under the credit facility had no commitment to lend to us under the credit facility and we have a zero dollar borrowing base, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interests in substantially all of our assets. The credit facility may be amended in the future if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit our and our subsidiaries’ ability to incur indebtedness, grant liens, make loans or investments, make distributions, 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 our assets. We were in compliance with these covenants as of December 31, 2019 and as of maturity of the contract on May 1, 2020. In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

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 impairment of gas and oil properties, and fair value of derivative instruments. We summarize our significant accounting policies within our consolidated financial statements included in Item 8: Financial Statements and Supplementary Data – Notes 2, 6 and 12 included in this report. The critical accounting policies and estimates we have identified are discussed below.

We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed.

Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for wells 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 costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in joint venture wells, wells drilled solely by us for our interests, properties purchased and working interests with other outside operators.

We review our gas and oil properties for impairment whenever events or changes in circumstances indicate that the net carrying amount of an asset may not be recoverable. 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. Additional factors impacting the economic viability of long-lived assets are discussed under Item 1A: Risk Factors in this report. 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 for that asset to its estimated fair value if such carrying amount exceeds the fair value.

Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area. As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs for the unsuccessful work on these properties are charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.

The review of our proved oil and gas properties is done on a field-by-field basis by determining if the net carrying value of proved properties is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on management’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. We estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published future 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 undiscounted future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) 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. Our reserve estimates are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. 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. We cannot predict what reserve revisions may be required in future periods. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset.

Our estimates of proved natural gas, oil and natural gas liquids 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 natural gas liquids 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 independent third-party reserve engineers to prepare annual reports of our proved reserves (See Item 1A: Risk Factors—Risks Relating to Our Business and Item 8: Financial Statements and Supplementary Data—Note 12 for additional information and considerations regarding the preparation and estimates used in our reserves).

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, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids 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 oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

See Item 8: Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements for additional information related to recently issued accounting standards. Although we qualify for emerging growth company status, we have not elected to adopt the exemption in relation to accounting standards.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We may manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. As of December 31, 2020, we did not have any commodity derivatives outstanding. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2020. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Commodity Price Risk. Our market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our financial results. To limit the exposure to changing commodity prices, we may use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period. As of December 31, 2020, we did not have any commodity derivatives outstanding.

Holding all other variables constant, a 10% change in average commodity prices would result in a change to our net loss for the twelve-month period ended December 31, 2020 of $0.2 million.

Realized pricing of natural gas, oil, and NGL production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and NGL production. Pricing for natural gas, oil and NGL production has been volatile and unpredictable for many years.

We have audited the accompanying consolidated balance sheets of Atlas Growth Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, the Partnership has suffered recurring losses from operations and has a net working capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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

We have audited the accompanying consolidated balance sheet of Atlas Growth Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018 (not presented herein), and the related consolidated statement of operations, changes in partners’ capital, and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 (not presented herein), and the results of its operations and its cash flows for the year ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

	December 31,
	2020			2019
ASSETS
Current assets:
Cash and cash equivalents	$	1,380		$	2,239
Advances to affiliates		—			486
Accounts receivable		669			548
Prepaid expenses and other		83			—
Total current assets		2,132			3,273
Property, plant and equipment, net		4,782			9,682
Other assets, net		—			—
Total assets	$	6,914		$	12,955
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	623		$	536
Accrued liabilities		2,329			839
Total current liabilities		2,952			1,375
Asset retirement obligations		235			216
Commitments and contingencies (Note 8)
Partners’ Capital:
General partner’s interest		(3,973	)		(3,821	)
Common limited partners’ interests		4,564			12,049
Common limited partners’ warrants		3,136			3,136
Total partners’ capital		3,727			11,364
Total liabilities and partners’ capital	$	6,914		$	12,955

	Years Ended December 31,
	2020			2019			2018
Revenues:
Natural gas revenue	$	56		$	82		$	225
Oil revenue		2,672			5,791			9,708
NGLs revenue		125			188			508
Loss on mark-to-market derivatives		—			—			(381	)
Total revenues		2,853			6,061			10,060
Costs and expenses:
Gas and oil production		1,289			2,512			3,486
General and administrative		1,572			1,261			655
General and administrative – affiliate		2,710			3,206			3,291
Depreciation, depletion and amortization		899			3,607			5,874
Asset impairment		4,020			10,982			41,762
Total costs and expenses		10,490			21,568			55,068
Operating loss		(7,637	)		(15,507	)		(45,008	)
Loss on asset sales		—			(33	)		—
Net loss	$	(7,637	)	$	(15,540	)	$	(45,008	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(7,485	)	$	(15,230	)	$	(44,108	)
General partner’s interest		(152	)		(310	)		(900	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.32	)	$	(0.65	)	$	(1.89	)
Weighted average common limited partner units outstanding:
Basic and Diluted		23,300			23,300			23,300

	General Partner’s Interest					Common Limited Partners’ Interests					Common Limited Partners’ Warrants				Total
	Class A Units		Amount			Units		Amount			Warrants		Amount			Partners’ Capital
Balance at January 1, 2018		100	$	(2,611	)		23,300,410	$	71,387			2,330,041	$	3,136	$	71,912
Net loss		—		(900	)		—		(44,108	)		—		—		(45,008	)
Balance at December 31, 2018		100	$	(3,511	)		23,300,410	$	27,279			2,330,041	$	3,136	$	26,904
Net loss		—		(310	)		—		(15,230	)		—		—		(15,540	)
Balance at December 31, 2019		100	$	(3,821	)		23,300,410	$	12,049			2,330,041	$	3,136	$	11,364
Net loss		—		(152	)		—		(7,485	)		—		—		(7,637	)
Balance at December 31, 2020		100	$	(3,973	)		23,300,410	$	4,564			2,330,041	$	3,136	$	3,727

	Years Ended December 31,
	2020				2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(7,637	)	$	(15,540	)	$	(45,008	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		899			3,607			5,874
Asset impairment		4,020			10,982			41,762
Gains on derivatives		—			—			(535	)
Loss on asset sales		—			33			—
Amortization of deferred financing costs		—			67			51
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(204	)		76			(14	)
Advances to/from affiliates		486			(636	)		(456	)
Accounts payable and accrued liabilities		1,577			127			506
Net cash provided by (used in) operating activities		(859	)		(1,284	)		2,180
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		—			—			(6,873	)
Net disposed assets		—			(37	)		—
Proceeds from sale of assets		—			17			—
Net cash used in investing activities		—			(20	)		(6,873	)
Net change in cash and cash equivalents		(859	)		(1,304	)		(4,693	)
Cash and cash equivalents, beginning of year		2,239			3,543			8,236
Cash and cash equivalents, end of year	$	1,380		$	2,239		$	3,543

Supplemental Disclosure of Non-Cash Activities:
Revisions to asset retirement obligation	$	—		$	78		$	—

Through May 1, 2020, Atlas Energy Group, LLC (“ATLS”), a Delaware limited liability company, managed and controlled us through its 2.1% limited partner interest in us and its 80% member interest in our general partner. Current and former members of ATLS management owned the remaining 20% member interest in our general partner.

The interests of our Limited Partners were not affected, altered or otherwise modified by the Debt Exchange.

At December 31, 2020, we had 23,300,410 common limited partner units issued and outstanding.

Our consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.

Beginning May 1, 2020, we have no continuing common ownership or corporate affiliation with ATLS and its affiliates. We will continue to identify any transaction between us and other ATLS managed operations as transactions between affiliates for all historical periods.

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

products. A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses. To date, we have been able to sell our production and we continue to identify multiple purchasers. However, should these parties become unwilling to purchase our production, we will need to work to identify other purchasers in the area to gather and purchase our oil and gas products. Failure to identify other purchasers and storage facilities, may result in the potential shut-in of the field. The financial statement impact, change in price and expected time for these changes is not estimable but could result in significant decreases in oil and gas operations.

Our primary sources of liquidity are cash generated by gas and oil production and their subsequent sale. Our primary cash requirements, in addition to normal operating expenses, are for management fees and capital expenditures, which we expect to fund through operating cash flow. Accordingly, our sources of liquidity are currently not sufficient to satisfy our current obligations.

We consider all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Accounts receivable consists solely of the trade accounts receivable associated with our operations. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness as determined by our review of customers’ credit information. We extend credit on sales on an unsecured basis to many of our customers. At December 31, 2020 and 2019, we had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets.

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which 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 which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for 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 costs of undeveloped and developed producing properties. We also consider the estimated salvage value in our calculation of depletion. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated joint venture wells, wells drilled solely by us for our interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to our consolidated statements of operations. Upon the sale of an individual well, we credit the proceeds to accumulated depreciation and depletion within our consolidated balance sheet. Upon our sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Support equipment and other are carried at cost and consist primarily of pipelines, processing and compression facilities, and gathering systems and related support equipment. We compute depreciation of support equipment and other using the straight-line balance method over the estimated useful life of each asset type, which is 15-20 years.

We review our property, plant and equipment 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 for that asset to its estimated fair value if such carrying amount exceeds the fair value.

Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area. As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.

The review of our proved oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. We estimate 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 (as determined by discounted future cash flows) and the carrying value of the assets.

See Note 3 for additional disclosures regarding impairment of property, plant and equipment.

We entered into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair

value of derivative instruments were recognized currently within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. See Note 4 for additional disclosures regarding derivative instruments.

We recognize an estimated liability for the plugging and abandonment of our gas and oil wells and related facilities. We recognize a liability for our 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.

The estimated liability for asset retirement obligations was based on our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we determined that there were no other material retirement obligations associated with tangible long-lived assets. As of December 31, 2020 and 2019, our asset retirement obligation was $0.2 million and $0.2 million, respectively. For the years ended December 31, 2020, 2019 and 2018, we recorded $19,000, $17,000, and $36,000, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our consolidated statements of operations. See Note 5 for additional disclosures regarding asset retirement obligations.

We have two lease agreements in our Eagle Ford operating area that required us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the lease. We determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law. As of December 31, 2020 and 2019, we presented $0.3 million and $0.3 million, respectively, included in current accrued liabilities on our consolidated balance sheets.

Current accrued liabilities include $1.7 million related to unpaid management fees to our General Partner.

We are not subject to U.S. federal and most state income taxes. Our partners are liable for income tax in regard to their distributive share of our taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the consolidated financial statements.

We evaluate tax positions taken or expected to be taken in the course of preparing our tax returns and disallow the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe it has taken any tax positions within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. We have not recognized any potential interest or penalties in our consolidated financial statements for the years ended December 31, 2020 and 2019.

We file Partnership Returns of Income in the U.S. and various state jurisdictions. We are not subject to income tax examinations by major tax authorities for years prior to 2013, our year of formation. We are not currently being examined by any jurisdiction and are not aware of any potential examinations.

On December 22, 2017, the President Trump signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since our operations are not subject to federal income tax, the Tax Act did not have a material impact on us.

We derive revenue from our gas and oil production. The production facilities associated with our oil and gas production have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

On January 1, 2018, we adopted ASU No. 2014–09, Revenue from Contracts with Customers (the “new revenue standard”), using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The adoption of the new revenue standard did not have a material impact on our consolidated financial statements and no cumulative effect adjustment was recorded to beginning partners’ capital. As a result of adopting the new revenue standard, we disaggregated our revenues by product type on our consolidated statements of operations for all periods presented.

Our revenues are derived from the sale of oil, natural gas, and NGLs, which is recognized in the period that the performance obligations are satisfied. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and the delivery of each unit represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser and title has transferred. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by us from a customer, are excluded from revenue. Payment is generally received one month after the sale has occurred.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, we generally record sales based on the net amount received.

Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For natural gas contracts, we generally record wet gas sales (which consist of natural gas and NGLs based on end products after processing) at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to us at the tailgate of the plant. Conversely, we generally record residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to us at the tailgate of the plant. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.

A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses pursuant to which these contracts typically automatically renew under the same terms and conditions. For those contracts, we have utilized the practical expedient allowed in the new revenue standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, we have utilized the practical expedient that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration.

Under our sales contracts, customers are invoiced once performance obligations have been satisfied, at which point our right to payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $0.5 million, at December 31, 2020 and December 31, 2019.

Basic net loss attributable to common limited partners per unit is computed by dividing net loss attributable to common limited partners (which is determined after the deduction of the general partner’s interest) by the weighted average number of common limited partner units outstanding during the period.

The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands):

Diluted net loss attributable to common limited partners per unit is calculated by dividing net loss attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.

The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common limited partners per unit with those used to compute diluted net loss attributable to common limited partners per unit (in thousands):

Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. We place our temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2020 and 2019, we had $1.4 million and $2.2 million, respectively, in deposits at various banks, of which $0.9 million and $2.0 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.

We sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2020, Shell Trading Co individually accounted for approximately 94% of our natural gas, oil and NGL consolidated revenues. For the year ended December 31, 2019, Shell Trading Co individually accounted for approximately 95% of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2018, Shell Trading Co individually accounted for approximately 91% of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Update 2016-02, “Leases (Topic 842)”. 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. We have evaluated our existing arrangements and service contracts and determined that none of the agreements meet the definition of a lease as defined in Topic 842. As such, there was no impact to our consolidated statements of operations, financial position and financial disclosures upon adoption of the new accounting standard on January 1, 2019.

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

For the year ended December 31, 2020, 2019, and 2018, we recognized $4.0 million, $11.0 million, and $42.0 million, respectively, of impairment related to our proved oil and gas properties in the Eagle Ford operating area, which were impaired due to lower forecasted production performance and commodity prices.

During the years ended December 31, 2020 and 2019, we did not have any material non-cash investing activity capital expenditures.

We used swaps in connection with our commodity price risk management activities. We did not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments were recognized as gains on mark-to-market derivatives on our consolidated statements of operations.

We entered into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may have included regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index.

As of December 31, 2020 and 2019, we did not have any commodity derivatives outstanding.

On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks, which matured on May 1, 2020. As of December 31, 2019, the lenders under the credit facility had no commitment to lend to us under the credit facility and we have a zero dollar borrowing base, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and a first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit our and our subsidiaries’ ability to incur indebtedness, grant liens, make loans or investments, make distributions, 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 our assets. We were in compliance with these covenants as of December 31, 2019 and as of maturity of the contract on May 1, 2020. In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

We recognize the fair value of our asset retirement obligations related to plugging, abandonment, and remediation of our gas and oil producing properties at the end of their productive lives. We determined the asset retirement obligation by calculating the present value of estimated future cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the obligation’s inception, with an offsetting increase to proved reserves. Changes in the liability for the asset retirement obligations are recognized for the passage of time and revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimate settlement value.

The following table summarizes the changes to our asset retirement obligations for the period indicated (in thousands):

Management has established a hierarchy to measure our financial instruments at fair value, which requires us 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 our 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.

We used a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments (see Note 4). We managed and reported derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments 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. These derivative values were 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 pricing formula utilized in the derivative instrument. As of December 31, 2020 and 2019, we did not have any commodity derivatives outstanding.

The asset retirement obligation is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgements. The estimated liability for asset retirement obligations was based on our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. See Note 5 for disclosure of asset retirement obligations and changes to the liability for the year.

Our other current assets and liabilities on our consolidated 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.

Asset Impairments. We estimate the fair value of our gas and oil properties in connection with reviewing these assets for impairment 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 based on a discounted cash flow model, which considers the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. See Note 3 for disclosure of impairments of our gas and oil properties. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

On June 19, 2020, affiliates of Titan (as defined below) closed on the sale of their Eagle Ford Shale assets with Texas American Resources Corporation II (“TARC”) for $13.2 million based on a May 1, 2020 effective date. In connection with the transaction, we entered into a contract operator agreement with TARC, whereby TARC will operate certain oil and gas properties and will provide other services to the Company related to our properties.

On May 1, 2020, pursuant to an Exchange Agreement by and among the Lenders and the Loan Parties, ATLS transferred assets to the Lenders that included (i) its 80.01% membership interest in the general partner of the Company, and (ii) 500,010 common units representing limited partner interests in the Company. As of the date of the Debt Exchange, approximately $108,431,309 in principal amount of loans remained outstanding, which obligation was terminated in the Debt Exchange.

The interests of Limited Partners of the Company were not affected, altered or otherwise modified by the Debt Exchange.

In connection with the Debt Exchange, the Company entered into that certain engagement letter (the “Slotterback Engagement Letter”), dated as of April 29, 2020 by and between the Company and PCA, pursuant to which the Company will pay to PCA $25,000 per month and PCA will provide financial, advisory and consultation services to the Company. The Slotterback Engagement Letter may be terminated at any time by either party upon seven days written notice. The Slotterback Engagement Letter also provides for a transaction fee equal to 2.0% of the gross purchase price of the sale of the Company’s Eagle Ford Assets provided PCA is still engaged at the time of the closing of such transaction.

In connection with the Debt Exchange, the Company entered into that certain engagement letter (the “Walker Engagement Letter”), dated as of April 30, 2020, by and between the Company and Westbrook, pursuant to which the Company will pay to Westbrook $8,000 per month and Westbrook will provide technical and advisory services to the Company. The Walker Engagement Letter may be terminated by either party upon seven days written notice.

Relationship with general partner. Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During both of the years ended December 31, 2020 and 2019 we paid a management fee of $2.3 million to our general partner. As of December 31, 2020, we had payables of $1.7 million related to the management fee, which were recorded in accrued liabilities in the condensed consolidated balance sheets.

Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions were historically provided by employees of ATLS and/or its affiliates, including Titan Energy, LLC (“Titan”). Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. Other indirect costs, such as rent for offices, are allocated by Titan at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. Historically, we reimbursed ATLS at cost for direct costs incurred on our behalf and all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and our general partner discussed above were included in general and administrative expenses – affiliate in the consolidated statements of operations. As of December 31, 2020 and December 31, 2019, we had no payables to ATLS related to the management fee, direct costs or allocated indirect costs, which were recorded in advances from affiliates in the consolidated balance sheets. Beginning May 1, 2020, we have no continuing common ownership or corporate affiliation with ATLS and its affiliates.

Relationship with Titan. Prior to May 1, 2020, at the direction of ATLS, we reimbursed Titan for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. As of December 31, 2020 and December 31, 2019, we had receivables from Titan of zero and $0.5 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for reimbursement of operating activities and capital expenditures, which were recorded in advances to/from affiliates in the consolidated balance sheets. Beginning May 1, 2020, we have no continuing common ownership or corporate affiliation with ATLS and its affiliates.

Rental expense for equipment was $0.2 million, $0.2 million, and $0.2 million for the years ended December 31, 2020, 2019, and 2018, respectively. We do not have any future minimum rental commitments as of December 31, 2020.

As of December 31, 2020, the Company has engagement letters to receive financial, advisory and consultation services and technical and advisory services. Each of these engagement letters can be terminated by either party upon seven days written notice.

As of December 31, 2020, we did not have any commitments related to our drilling and completion and capital expenditures. We have two lease agreements in our Eagle Ford operating area that required us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the lease. Refer to Note 2 for further discussion. We determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law. As of December 31, 2020 and 2019, we presented $0.3 million and $0.3 million, respectively, included in current accrued liabilities on our consolidated balance sheet.

We and our subsidiaries are parties to various routine legal proceedings arising in the ordinary course of business. Our management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

We and our subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of December 31, 2020 or December 31, 2019.

On November 2, 2016, our management decided to suspend our primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues.

Historically we had a cash distribution policy under which we distributed to holders of our common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we had sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions were generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders were entitled to receive distributions from us beginning with the quarter following the quarter in which we first admit them as limited partners. On November 2, 2016, the Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. No distributions have been made since that time.

In connection with the preparation of our Quarterly Report on Form 10-Q for the period ended September 30, 2019, we identified an error in the amounts settled from our purchaser for the production periods June 2018 to July 2019. The purchaser issued revised settlement statements for this period, which resulted in a reduction of revenues of $0.8 million and depletion expense of $0.3 million for a net increase in our net loss of $0.5 million. The adjustment decreased our advances to (from) affiliates from a receivable of $1.3 million to a receivable of $0.5 million for the period ended December 31, 2019. In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, we evaluated the errors and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to our consolidated financial statements for any prior annual or interim period. Therefore, amendments of previously filed reports are not required. If the settlement statement correction had been recognized in the respective production months of 2018, the revenue reported for 2018 would have been decreased $0.4 million from $10.4 million to $10.0 million, net loss would have increased $0.4 million from $45.0 million to $45.4 million and total assets would have decreased $0.4 million from $28.9 million to $28.5 million. If the settlement statement correction had been recognized in the respective production months of 2019, revenue would have increased by $0.4 million from $6.1 million to $6.5 million, and net loss would have decreased $0.4 million from $15.5 million to $15.1 million. The total assets as of December 31, 2019 would have decreased $0.2 million from $13.0 million to $12.8 million.

Oil and Gas Reserve Information. The preparation of our natural gas, oil and NGL reserve estimates was completed in accordance with the prescribed guidelines established by the SEC. In accordance with our internal policies and procedures related to reserve estimates, annually we engage an independent petroleum engineering firm to audit our reserves. For the years ended December 31, 2020, 2019 and 2018, we engaged VSO Petroleum Consultants, Inc.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last year. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2020, 2019 and 2018, 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 our oil, gas and NGL reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil, gas and NGL 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 were as follows:

	Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			Total (MMcfe)
Balance, January 1, 2018		1,866			4,475			416			31,213
Extensions, discoveries and other additions		89			355			21			2,343
Sales of reserves in-place		—			—			—			—
Purchase of reserves in-place		—			—			—			—
Revisions of previous estimates ⁽¹⁾		(739	)		(818	)		(157	)		(6,589	)
Production		(114	)		(145	)		(21	)		(1,110	)
Balance, December 31, 2018		1,102			3,867			259			25,587
Extensions, discoveries and other additions⁽¹⁾	—			—			—			—
Sales of reserves in-place	—			—			—			—
Purchase of reserves in-place	—			—			—			—
Revisions of previous estimates ⁽¹⁾	(751		)	(3,274		)	(192		)	(21,548		)
Production	(68		)	(100		)	(14		)	(751		)
Balance, December 31, 2019	283			493			53			3,558
Extensions, discoveries and other addition		—			—			—			—
Sales of reserves in-place		—			—			—			—
Purchase of reserves in-place		—			—			—			—
Revisions of previous estimates ⁽¹⁾		131			16			25			378
Production		(55	)		(76	)		(11	)		(577	)
Balance, December 31, 2020		359			433			67			3,359
Proved developed reserves at:
January 1, 2018		613			788			121			6,069
December 31, 2018		292			676			69			4,762
December 31, 2019	283			493			53			3,558
December 31, 2020	359			433			67			3,359
Proved undeveloped reserves at:
January 1, 2018		1,253			3,687			295			25,144
December 31, 2018		810			3,191			190			21,095
December 31, 2019	—			—			—			—
December 31, 2020	—			—			—			—

The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above:

For the year ended December 31, 2020, we had positive revisions of 381 MMcfe primarily due to updates in economic assumptions of 1,350 MMcfe and 190 MMcfe due to updated forecast of production offset by negative revisions of 1,162 MMcfe due to decreases in pricing.

For the year ended December 31, 2019, we had negative revisions of 21,548 MMcfe primarily due to the removal of proved undeveloped properties as a result of uncertainty regarding our ability to access capital to develop the proved undeveloped reserves of 21,095 MMcfe and 437 MMcfe due to decreases in pricing.

For the year ended December 31, 2018, we had extensions, discoveries and other additions of 2,343 MMcfe due to the addition of two proved undeveloped wells resulting from our well that was drilled and completed in May 2018. For the year ended December 31, 2018, we had negative revisions of 6,5895 MMcfe due to updated type curves based on well results located closer to our Eagle Ford positions of 6,062 MMcfe, actual production underperforming previous year’s forecast by 339 MMcfe and operating expense revisions of 848 MMcfe offset by increases in pricing of 720 MMcfe.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of our capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands):

Results of Operations from Oil and Gas Producing Activities. The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands):

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by our oil and gas activities during the periods indicated are as follows (in thousands):

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the periods presented, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas 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 (in thousands):

Change in Standardized Discounted Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since we allocate taxable income to our unitholders, no recognition has been given to income taxes:

		Years Ended December 31,
	2020			2019			2018
Balance, beginning of year	$	7,827		$	51,715		$	40,449
Increase (decrease) in discounted future net cash flows⁽¹⁾:
Sales of oil and gas produced, net of related costs		(1,564	)		(3,549	)		(6,955	)
Net changes in estimated future prices and production costs		(3,069	)		(6,555	)		32,438
Revisions of previous quantity estimates		(81	)		(35,387	)		(26,896	)
Development costs incurred		—			—			6,873
Changes in future development costs		—			—			—
Extensions, discoveries, and improved recovery less related costs		—			—			1,761
Sales of reserves in-place		—			—			—
Accretion of discount		783			1,603			4,045
Estimated settlement of asset retirement obligations		—			—			—
Estimated proceeds on disposals of well equipment		—			—			—
Balance, end of year	$	3,896		$	7,827		$	51,715

	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
	(in thousands, except unit data)
Year ended December 31, 2020:
Revenues	$	761		$	756		$	335		$	1,001
Net loss attributable to common limited partners and the general partner’s interests⁽¹⁾	$	(456	)	$	(808	)	$	(1,542	)	$	(4,831	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(447	)	$	(792	)	$	(1,511	)	$	(4,735	)
General partner’s interest		(9	)		(16	)		(31	)		(96	)
Net loss attributable to common unitholders per unit:
Basic	$	(0.02	)	$	(0.03	)	$	(0.06	)	$	(0.20	)
Diluted	$	(0.02	)	$	(0.03	)	$	(0.06	)	$	(0.20	)

	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
	(in thousands, except unit data)
Year ended December 31, 2019:
Revenues	$	1,495		$	764		$	1,903		$	1,899
Net loss attributable to common limited partners and the general partner’s interests⁽¹⁾	$	(12,286	)	$	(1,547	)	$	(839	)	$	(868	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(12,040	)	$	(1516	)	$	(823	)	$	(851	)
General partner’s interest		(246	)		(31	)		(16	)		(17	)
Net loss attributable to common unitholders per unit:
Basic	$	(0.50	)	$	(0.07	)	$	(0.04	)	$	(0.04	)
Diluted	$	(0.50	)	$	(0.07	)	$	(0.04	)	$	(0.04	)

We maintain disclosure controls and procedures that are designed to ensure that 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 Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2020, our disclosure controls and procedures were effective at the reasonable assurance level.

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

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

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2020.

This report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting due to a transition period established by rules of the SEC for newly public companies.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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. Our general partner will be liable, as general partner, for all of our debts to the extent not paid, except to the extent that indebtedness or other obligations incurred by us are specifically with recourse only to our assets. Whenever possible, our general partner intends to make any of our indebtedness or other obligations with recourse only to our assets.

The non-management members of our general partner’s board of directors have the ability to meet in executive session without management, when necessary. The purpose of these executive sessions is to promote open and candid discussion among the non-management board members. Interested parties wishing to communicate directly with the non-management members may contact the chair of our audit committee, Daniel Flannery. Correspondence to Mr. Flannery should be marked “Confidential” and sent to Mr. Flannery’s attention, c/o Atlas Growth Partners, L.P., 2400 Market Street, Suite 230, Philadelphia, Pennsylvania 19103.

The independent board members comprise all of the members of the board’s committees: audit committee and conflicts committee.

We do not directly employ any of the persons responsible for our management or operation. Rather, personnel employed by PCA and Westbrook manage and operate our business. Some of our general partner’s officers may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Our general partner receives an annual management fee in connection with its management of us equal to 1% of capital contributions per annum. We reimburse our general partner and its affiliates for all expenses incurred on our behalf. These expenses include the costs of employee, officer and board member compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner as determined by our general partner in its sole discretion, and does not set any aggregate limit on such reimbursements. Prior to the transaction described below, our general partner allocated the costs of employee and officer compensation and benefits based upon the amount of business time spent by those employees and officers on our business.

Through May 1, 2020, ATLS managed and controlled us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management owned the remaining 20% member interest in our general partner. On May 1, 2020, pursuant to an Exchange Agreement by and among Riverstone Credit Partners – Direct, L.P. (“Riverstone”) and other lenders (collectively, the “Lenders”), ATLS and New Atlas Holdings, LLC (the “Borrower”, and together with ATLS and the other guarantors, the “Loan Parties”), ATLS transferred (the “Debt Exchange”) assets to the Lenders that included (i) its 80.01% membership interest in the general partner of the Company, and (ii) 500,010 common units representing limited partner interests in the Company. As of the date of the Debt Exchange, approximately $108,431,309 in principal amount of loans remained outstanding, which obligation was terminated in the Debt Exchange.

The interests of our Limited Partners were not affected, altered or otherwise modified by the Debt Exchange.

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

Daniel P. Flannery has been the Chairman of the board of directors of our general partner since 2020. Mr. Flannery, is a Managing Director of Riverstone, which he joined in June 2014 and is responsible for sourcing and managing energy investments with a focus on credit and debt capital markets. He is based in New York. Since joining Riverstone, Mr. Flannery has helped oversee over $4 billion in debt investments in the energy sector made by both Riverstone’s dedicated credit fund and its traditional private equity funds. In addition, he is actively involved in an advisory capacity with all of Riverstone’s portfolio companies with respect to capital structure and access to the capital markets. Prior to joining Riverstone, Mr. Flannery worked at Nomura Securities International as a Vice President in the Leveraged Finance Group, and prior to that as an Associate at First Reserve from 2009 to 2011 and UBS from 2007 to 2009. Over his career, Mr. Flannery has worked predominantly on energy-focused principal investing and leveraged finance transactions. Mr. Flannery graduated with an A.B. from Duke University. These diverse experiences have enabled Mr. Flannery to bring unique perspectives to the Board, particularly with respect to business management, financial markets and financing transactions and corporate governance issues.

Jack S. Maleh has been a director of our general partner since 2020. Mr. Maleh is a Vice President of Riverstone, and is focused on the Firm’s credit and capital markets activities. He is based in New York. Prior to joining Riverstone in 2017, Mr. Maleh was an Analyst in the Global Energy Investment Banking Group at Citigroup. While at Citigroup, Mr. Maleh evaluated and executed M&A transactions and capital markets financings across the oil and gas sector. Mr. Maleh graduated cum laude with a combined B.S. and M.S. in Finance from The University of Florida. Our board of directors benefits from his diverse energy experience.

Christopher A. Abbate has been a director of our general partner since 2020. Mr. Abbate is a Partner of Riverstone and Co-Head of Riverstone Credit Partners, focused on the firm’s credit and capital markets activities. He is based in New York. Prior to joining Riverstone in 2014, Mr. Abbate was a Managing Director and Head of Energy Leveraged Finance at Citigroup. Prior to Citigroup, Mr. Abbate was the Head of US Leveraged Finance Origination at UBS Investment Bank. Mr. Abbate joined UBS in 2000 as an Associate Director in the Energy Group where he worked covering upstream and midstream oil and gas companies. He started his investment banking career in 1997 at PaineWebber as an Associate in the Energy Group. Prior to his career on Wall Street, Mr. Abbate served as an Intelligence Applications Officer in the US Air Force for 5 years. Mr. Abbate graduated with an A.B. from Duke University and has an M.B.A. from the University of Maryland. Our board of directors benefits from his diverse energy experience.

Jeffrey M. Slotterback has served as the Chief Executive Officer and Chief Financial Officer of our general partner since May 2020, in his capacity as a Principal at PhiCap Advisors, LLC (“PCA”). Prior to this, Mr. Slotterback served as the Chief Financial Officer of our general partner since September 2015 and as a director since March 2018. Mr. Slotterback served as the Chief Accounting Officer of our general partner from its inception in February 2013 to October 2015. In addition, Mr. Slotterback has served as the Chief Financial Officer and a Class A Director of Titan Energy, LLC since September 2016. Before then, he served as Titan Energy, LLC’s predecessor’s Chief Financial Officer since September 2015. Mr. Slotterback has served as Chief Financial Officer of Atlas Energy Group, Titan Energy, LLC’s predecessor’s general partner, since September 2015 and served as its Chief Accounting Officer from March 2012 to October 2015. Mr. Slotterback served as Chief Accounting Officer of Atlas Energy’s general partner from March 2011 until February 2015. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting for Atlas Energy GP, LLC from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both Atlas Energy GP, LLC and Atlas Pipeline Partners GP, LLC from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant. Mr. Slotterback’s significant accounting and financial experience, as well as his familiarity with the company and its operations, enable him to provide the board with important insight into the company.

Christopher K. Walker has served as our Chief Operating Officer since May 2020, in his capacity as a Partner at Westbrook Energy Partners, LLC (“Westbrook”). He served as the Chief Operating Officer of Titan Energy, LLC from March 2018 to July 2020. Prior to that he served as Vice President of Operations from January 2016 through February 2018. From July 2012 through January 2016, Mr. Walker served as an Operations Engineer and Operations Manager at Titan Energy, LLC. Mr. Walker’s significant energy experience as well as his familiarity with the company and its operations, enable him to provide the board with important insight into the company.

Because we did not have any securities registered pursuant to Section 12 of the Exchange Act during the fiscal year ended December 31, 2020, no persons were required to file forms or reports required by Section 16(a) of the Exchange Act during that period.

The standing committees of the board of directors of our general partner are the Audit Committee and Conflicts Committee.

Audit Committee. The Audit Committee’s duties include establishing the scope of, and overseeing, the annual audit. The Audit Committee provides assistance to the board of directors of our general partner in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements and our compliance with legal and regulatory requirements. The Audit Committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that our management and the board of directors of our general partner have established. In doing so, it is the responsibility of the Audit Committee to maintain free and open communication between the committee and the independent auditors, internal accounting function and our management. The members of the Audit Committee are Messrs. Flannery, Maleh and Abbate. Mr. Flannery serves as the chairman and has been determined by the board of directors of our general partner to be an “audit committee financial expert,” as defined by SEC rules.

Conflicts Committee. The Conflicts Committee reviews specific matters that the board of directors of our general partner believes may involve conflicts of interest. The Conflicts Committee determines if the conflict of interest has been resolved in accordance with our partnership agreement. If we seek approval of a conflict of interest from our Conflicts Committee, it is presumed that in making its decision, the Conflicts Committee acted in good faith in the best interest of our company. All of the members of the Conflicts Committee meet the independence standards established by the board. The members of the Conflicts Committee are Messrs. Flannery, Maleh and Abbate.

We have adopted a code of business conduct and ethics applicable to our directors, officers and employees in accordance with applicable federal securities laws. A copy of the code of business conduct and ethics is filed as an exhibit to this report. You may also obtain a copy of this code of business conduct and ethics without charge by writing to Atlas Growth Partners, L.P., 2400 Market Street, Suite 230, Philadelphia, Pennsylvania 19103.

The role in risk oversight of the board of directors of our general partner (the “Board”) recognizes the multifaceted nature of risk management. We administer our risk oversight function primarily through the Audit Committee, which monitors material enterprise risks. The Audit Committee meets with the members of management as needed to discuss our risk management framework and related areas. It also reviews any major transactions or decisions affecting our risk profile or exposure, and reviews with counsel legal compliance and legal matters that could have a significant impact on our financial statements. The Audit Committee also works with our internal audit function and is responsible for monitoring the integrity and ensuring the transparency of our financial reporting processes and systems of internal controls regarding finance, accounting and regulatory compliance. The Audit Committee incorporates its risk oversight function into its regular reports to the Board.

In addition to the Audit Committee’s role in risk management, the full Board regularly engages in discussions of the most significant risks that we face and how these risks are being managed. Our general partner’s senior executives provide regular updates about our strategies and objectives and the risks inherent within them at board and committee meetings and in regular reports. Board and committee meetings also provide a venue for directors to discuss issues of concern with management. The Board and committees may call special meetings when necessary to address specific issues or matters that should be addressed before the next regularly scheduled meeting. In addition, our directors have access to our management at all levels to discuss any matters of interest, including those related to risk. Those members of management most knowledgeable of the issues will attend board meetings to provide additional insight into items being discussed, including risk exposures.

We do not directly employ any of the persons responsible for our management or operation. Rather, personnel employed by PCA and Westbrook manage and operate our business. PCA provides financial, advisory and consultation services and employs Mr. Jeffrey Slotterback who serves as the Chief Executive Officer and Chief Financial Officer of the Company. Westbrook provides technical and advisory services and employs Mr. Christopher Walker who serves as the Chief Operating Officer of the Company.

For purposes of the following, the individuals listed below are collectively referred to as our “Named Executive Officers” or “NEOs.”

We do not directly employ any of the persons responsible for managing our business. All of the executive officers that are responsible for managing our day-to-day affairs are employed by PCA or Westbrook. PCA provides financial, advisory and consultation services to the Company. As a principal at PCA, Mr. Jeffrey Slotterback serves as the Chief Executive Officer and Chief Financial Officer of the Company. Mr. Edward Cohen served as our Chairman and Chief Executive Officer until the date of the Debt Exchange.

These executive officers devote as much time to the management of our business as is necessary for the proper conduct of our business and affairs. The amount of time that each of our executive officers devotes to our business is subject to change depending on our activities. Compensation is determined by our general partner. Neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.

Responsibility and authority for compensation-related decisions for executive officers and other personnel resides with our general partner. Our general partner has the ultimate decision-making authority with respect to the total compensation of its employees, including the individuals who serve as our executive officers, and with respect to the portion of that compensation that is allocated to us. Any such compensation decisions are not subject to any approval by the board of directors of our general partner.

Employment Agreements and Potential Payments Upon Termination or Change of Control

The agreement with PCA is renewable on a month to month basis. If PCA is serving as the Principal Executive Officer of the Company through the closing of the sale of its Eagle Ford shale position, the Company will pay to PCA a transaction fee equivalent to 2.0% of the gross purchase price upon closing of the transaction.

Effective September 4, 2015, Atlas Energy Group entered into an employment agreement with Edward E. Cohen, Atlas Energy Group’s Chief Executive Officer (the “Atlas Employment Agreement”).

The Atlas Employment Agreement with Mr. E. Cohen provided for a term of three years (which automatically renews daily unless earlier terminated) and an initial base salary of $350,000, subject to periodic increases by the Compensation Committee.

Under the Atlas Employment Agreements, Mr. E. Cohen was entitled to receive cash and non-cash bonus compensation in such amounts as the Atlas Energy Group board or Compensation Committee may approve or under the terms of any incentive plan that we maintain for the Atlas Energy Group senior level executives. Atlas Energy Group is required to maintain a term life insurance policy for Mr. E. Cohen’s life that provided a death benefit of $3 million to one or more beneficiaries designated by Mr. E. Cohen, which such policy, can be assumed by such individual upon a termination of employment, if and as allowed by the applicable insurance company.

Under the Atlas Employment Agreement, if the executive is terminated without cause or resigns with good reason, then, subject to his execution and non-revocation of a release of claims in favor of us and related parties, the executive will be entitled to receive (a) three times the sum of the executive’s base salary plus his average incentive compensation for the previous three years (or such lesser period as applicable), (b) a pro rata cash bonus for the year of termination, (c) 36 months of continued health and life insurance, and (d) accelerated vesting of all equity-based compensation. Pursuant to the Atlas Employment Agreement, in the event of death, Mr. E. Cohen was entitled to receive (a) a pro rata cash bonus for the year of termination and (b) accelerated vesting of all equity-based compensation. Under the Atlas Employment Agreement, in the event of disability, Mr. E. Cohen was entitled to receive (a) a pro rata cash bonus for the year of termination, (b) 36 months of life and health insurance, and (c) accelerated vesting of all equity-based compensation.

In addition, the Atlas Employment Agreement contained certain restrictive covenants, including in the case of Mr. E. Cohen, a 12 month post termination noncompetition covenant and 24 month post termination nonsolicitation covenant if the executive is terminated with cause or resigns without good reason, if prior to a change in control or after the first anniversary of a change in control, the executive is terminated with cause or resigns without good reason, or within one year following a change in control, the executive’s employment terminates for any reason.

Under the Atlas Employment Agreement, any payments or benefits payable to the executive will be cut back to the extent that such payments or benefits would result in the imposition of excise taxes under Section 4999 of the Internal Revenue Code, unless the executive would be better off on an after-tax basis receiving all such payments or benefits.

Effective July 1, 2011, Atlas Energy Group established the Excess 401(k) Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees. The Excess 401(k) Plan provided Mr. E. Cohen, one of the plan’s participants, with the opportunity to defer, annually, the receipt of a portion of his compensation, and to permit him to designate investment indices for the purpose of crediting earnings and losses on any amounts deferred under the Excess 401(k) Plan. Mr. E. Cohen may defer up to 10% of his total annual cash compensation (which means base salary and non-performance-based bonus) and up to 100% of all performance-based bonuses, and Atlas Energy Group is obligated to match such deferrals on a dollar-for-dollar basis (i.e., 100% of the deferral) up to a total of 50% of their base salary for any calendar year. Effective July 2016, Atlas Energy suspended deferrals and allocations to the accounts. Account balances remain payable as specified in original deferral elections. The account is invested in a mutual fund and cash balances are invested daily in a money market account. Atlas Energy Group established a “rabbi” trust to serve as the funding vehicle for the Excess 401(k) Plan and Atlas Energy Group will, not later than the last day of the first month of each calendar quarter, make contributions to the trust in the amount of the compensation deferred, along with the corresponding match, during the preceding calendar quarter. Notwithstanding the establishment of the rabbi trust, Atlas Energy Group’s obligation to pay the amounts due under the Excess 401(k) Plan constitutes a general, unsecured obligation, payable out of its general assets, and Mr. E. Cohen does not have any rights to any specific asset of the Company.

On January 18, 2019, Mr. E. Cohen received a final distribution of $0.1 million from the Excess 401(k) Plan.

In 2020 as non-employee directors of our general partner, Messrs. Daniel P. Flannery, Jack Maleh, and Christopher A. Abbate did not receive any fees earned or paid in cash, stock awards, or any other compensation.

In 2020 as non-employee directors of our general partner, William R. Bagnell, Walter A. Jones, and Jeffrey Kupfer each received $25,000 fees paid in cash. These payments were for services from January 1, 2020 through April 30, 2020. Messrs Bagnell, Jones, and Kupfer did not received any stock awards or any other compensation.

Directors receive no meeting fees, but each director will be reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Board or its committees.

The board of directors of our general partner does not have a standing compensation committee. None of our executive officers has served on the board of directors or compensation committee of any entity that had one or more of its executive officers serving on the board of directors of our general partner.

The following table sets forth the number and percentage of common units owned as of March 26, 2021 by (a) each of our general partner’s directors and named executive officers, (b) all of our general partner’s directors and executive officers as a group, and (c) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding common units. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.

We and certain of our affiliates have entered from time to time into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

We do not directly employ any persons to manage or operate our business. These functions were provided by ATLS and its affiliates through April 30, 2020. On May 1, 2020, pursuant to the Debt Exchange, Riverstone has the ability to control the Company’s management and operations.

Our general partner receives an annual management fee in connection with managing us equivalent to 1% of capital contributions per annum. During the year ended December 31, 2020, we paid $0.6 million for this management fee to ATLS. Through April 30, 2020, ATLS charged us direct costs, such as salary and wages, and allocated indirect costs to us, such as rent for offices, based on the number of its employees who devoted substantially all their time to activities on our behalf. We reimbursed ATLS at cost for direct costs incurred on our behalf (including costs incurred by Titan). We will reimburse all necessary and reasonable costs allocated by our general partner.

At December 31, 2020, we have unpaid management fees to our general partner of $1.7 million.

In our Second Amended and Restated Agreement of Limited Partnership, which will not become effective unless a listing event occurs, we will agree to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner or any of its respective affiliates if an exemption from the registration requirements is not otherwise available. There is no limit on the number of times that we may be required to file registration statements pursuant to this obligation. We will also agree to include any securities held by our general partner or any of its respective affiliates in any registration statement that we file to offer securities for cash, other than an offering relating solely to an employee benefit plan. These registration rights continue for two years following any withdrawal or removal of our general partner. We must pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our Partnership Agreement.

The board of directors of our general partner consists of three directors. The board of directors has determined that Messrs. Flannery, Maleh, and Jones each satisfy the requirement for independence set out in the rules of the New York Stock Exchange and those set forth in Rule 10A-3(b)(1) of the Exchange Act. The board of directors has established a conflicts committee, which is composed of the independent directors, for purposes of reviewing potential conflicts of interest between us and our general partner.

For the years ended December 31, 2020 and 2019, the accounting fees and services charged by our independent auditors, were as follows (in thousands):

The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by our independent auditors, as well as the fees charged by the auditors for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2020 and 2019.

The financial statements required by this Item 15(a)(1) are set forth in “Item 8. Financial Statements and Supplementary Data”

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated as of March 31, 2021.

Delaware		80-0906030
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2400 Market Street, Suite 230 Philadelphia, PA		19103
(Address of principal executive offices)		(Zip code)


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	N/A	N/A

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

	Developed acreage ⁽¹⁾		Undeveloped acreage⁽²⁾
	Gross ⁽³⁾	Net ⁽⁴⁾	Gross ⁽³⁾	Net ⁽⁴⁾
Texas	2,844	2,840	—	—
Total	2,844	2,840	—	—

	December 31, 2020			December 31, 2019
Natural gas and oil properties:
Proved properties	$	137,627		$	137,627
Support equipment and other		3,188			3,188
		140,815			140,815
Less – accumulated depreciation, depletion, amortization and impairment		(136,033	)		(131,133	)
	$	4,782		$	9,682

Atlas Growth Partners, L.P. – ‘10-K’ for 12/31/20

On: Wednesday, 3/31/21, at 2:46pm ET · For: 12/31/20 · Accession #: 1564590-21-17014 · File #: 0-55603

Previous ‘10-K’: ‘10-K’ on 4/16/20 for 12/31/19 · Latest ‘10-K’: This Filing · 9 References:

Annual Report — Form 10-K
Filing Table of Contents

‘10-K’ — Annual Report
Document Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

9 Previous Filings that this Filing References

			Page
PART I	Item 1:	Business	8
	Item 1A:	Risk Factors	20
	Item 1B:	Unresolved Staff Comments	42
	Item 2:	Properties	42
	Item 3:	Legal Proceedings	42
	Item 4:	Mine Safety Disclosures	42

PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	43
	Item 6:	Selected Financial Data	44
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	52
	Item 8:	Financial Statements and Supplementary Data	54
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
	Item 9A:	Controls and Procedures	77
	Item 9B:	Other Information	77

PART III	Item 10:	Directors, Executive Officers and Corporate Governance	78
	Item 11:	Executive Compensation	81
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	83
	Item 13:	Certain Relationships and Related Transactions, and Director Independence	84
	Item 14:	Principal Accountant Fees and Services	85

PART IV	Item 15:	Exhibits and Financial Statement Schedules	86

SIGNATURES			88

	Number of productive wells⁽¹⁾
	Gross	Net
Gas wells	—	—
Oil wells	11	11
Total	11	11

Name	Age		Position(s)
Daniel P. Flannery		37	Chairman of the Board
Jack S. Maleh		28	Director
Christopher A. Abbate		50	Director
Jeffrey M. Slotterback		39	Chief Executive Officer and Chief Financial Officer
Christopher K. Walker		39	Chief Operating Officer

				Stock awards ($)
Name	Year	Salary ($)⁽¹⁾	Bonus ($)	Stock awards ($)	Non-equity incentive plan compensation ($)	All other compensation ($)	Total ($)

Jeffrey M. Slotterback	2020	14,817	—	—	—	—	14,817
	2019	38,277	—	—	—	—	38,227
	2018	38,227	—	—	—	—	38,277

Edward E. Cohen⁽²⁾	2020	—	—	—	—	—	—
	2019	—	—	—	—	—	—
	2018	55,785	—	—	—	—	55,785

	Common unit amount and nature of beneficial ownership⁽²⁾	Percent of class
Beneficial owner
Directors ⁽¹⁾
Edward E. Cohen ⁽³⁾	30,000	*
Daniel P. Flannery	—	—
Jack S. Maleh	—	—
Christopher A. Abbate	—	—
Jeffrey M. Slotterback	—	—
All executive officers, directors and nominees as a group (5 persons)	—	*

		Year Ended December 31,
		2020	2019
Audit fees⁽¹⁾	$	108	$	114
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total accounting fees and services	$	108	$	114

Exhibit No.		Description

1.1		Form of Soliciting Dealer Agreement (incorporated by reference to the registration statement on Form S-1 (File No. 333-207357) filed on January 11, 2016).

2.1		Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of September 24, 2014. The schedules to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request (incorporated by reference to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

2.2		Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of July 1, 2015. The schedules to Addendum #2 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request (incorporated by reference to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

2.3		Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement by and among ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Eagle Ford Operating Company, LLC, effective as of September 30, 2015. The schedules to Addendum #3 to the Amended and Restated Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request (incorporated by reference to Atlas Resource Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

3.1		Certificate of Limited Partnership of Atlas Growth Partners, L.P.(incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).

3.2		Partnership Agreement of Atlas Growth Partners, L.P., dated February 11, 2013 (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).

3.3		First Amended and Restated Limited Partnership Agreement of Atlas Growth Partners, L.P.(incorporated by reference to our Current Report on Form 8-K filed on April 6, 2016).

3.4		Form of Second Amended and Restated Agreement of Limited Partnership of Atlas Growth Partners, L.P. (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).

3.5		Certificate of Formation of Atlas Growth Partners GP, LLC (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).

3.6		Amended and Restated Limited Liability Company Agreement of Atlas Growth Partners GP, LLC, dated as of November 26, 2013 (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).

4.1		Form of Warrant Agreement (included as Exhibit D to the Prospectus filed pursuant to Rule 424(b)(1) filed on April 5, 2016).

Exhibit No.		Description

10.1		Form of Subscription Agreement (included as Exhibit C to the Prospectus filed pursuant to Rule 424(b)(1) filed on April 5, 2016).

10.2		Credit Agreement among Atlas Growth Partners, L.P., as borrower, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, dated as of May 1, 2015 (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on March 25, 2016).

10.3		Atlas Growth Partners, L.P. Long Term Incentive Plan (included as Exhibit F to the Prospectus filed pursuant to Rule 424(b)(1) filed on April 5, 2016).

10.4		Exclusive Dealer Manager Agreement by and among Atlas Growth Partners, L.P., Atlas Growth Partners GP, LLC and Anthem Securities, Inc., dated April 5, 2016 (incorporated by reference to our Current Report on Form 8-K filed on April 6, 2016).

10.5		Atlas Growth Partners, L.P. Distribution Reinvestment Plan (incorporated by reference to our Current Report on Form 8-K filed on May 4, 2020)

10.6		Engagement Letter, dated as of April 29, 2020, by and between Atlas Growth Partners, L.P. and PhiCap Advisors, LLC (incorporated by reference to our Current Report on Form 8-K filed on May 4, 2020)

10.7		Engagement Letter, dated as of April 30, 2020, by and between Atlas Growth Partners, L.P. and Westbrook Energy Partners, LLC (incorporated by reference to our Current Report on Form 8-K filed on May 4, 2020)

10.8		Contract Operating Agreement, dated as of June 19, 2020, by and between Atlas Growth Eagle Ford, LLC and Texas American Resources Company (incorporated by reference to our Current Report on Form 8-K filed on June 25, 2020)

14.1*		AGP Code of Business Conduct and Ethics

21.1*		List of Subsidiaries of Atlas Growth Partners, L.P.

23.1*		Consent of VSO Petroleum Consultants, Inc.

31.1*		Rule 13(a)-14(a)/15(d)-14(a) Certification

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

32.1*		Section 1350 Certification

99.1*		Summary Reserve Report of VSO Petroleum Consultants, Inc.

101.INS*		XBRL Instance Document⁽¹⁾

101.SCH*		XBRL Schema Document⁽¹⁾

101.CAL*		XBRL Calculation Linkbase Document⁽¹⁾

101.LAB*		XBRL Label Linkbase Document⁽¹⁾

101.PRE*		XBRL Presentation Linkbase Document⁽¹⁾

101.DEF*		XBRL Definition Linkbase Document⁽¹⁾

	ATLAS GROWTH PARTNERS, L.P.

	By: Atlas Growth Partners GP, LLC, its general partner

Date: March 31, 2021	By:	/s/ *Daniel P. Flannery*
		Daniel P. Flannery Chairman of the Board

This ‘10-K’ Filing	Date	Other Filings

	12/31/22
	12/31/21
Filed on:	3/31/21	10-Q
	3/26/21
For Period end:	12/31/20
	6/30/20	10-Q, NT 10-Q
	6/19/20	8-K
	5/1/20	8-K
	4/30/20
	4/29/20
	3/31/20	10-Q, NT 10-K
	1/1/20
	12/31/19	10-K, NT 10-K
	9/30/19	10-Q
	6/19/19
	4/16/19	10-K
	1/18/19
	1/1/19
	12/31/18	10-K, NT 10-K
	9/25/18
	1/1/18
	12/22/17
	3/28/17
	11/2/16
	9/30/16	10-Q
	9/4/15
	5/8/15
	5/1/15
	3/26/15
	7/1/11
		List all Filings

Atlas Growth Partners, L.P. – ‘10-K’ for 12/31/20

On: Wednesday, 3/31/21, at 2:46pm ET · For: 12/31/20 · Accession #: 1564590-21-17014 · File #: 0-55603

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Dates Referenced Herein and Documents Incorporated by Reference

9 Previous Filings that this Filing References

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