UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

For the fiscal year ended December 31, 2017

OR

For the transition period from               to              

Commission file number: 000-55603

 

Atlas Growth Partners, L.P.

(Exact name of registrant as specified in its charter)

 

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

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

None 

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

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 Section 15(d) of the Act.    Yes  ☐    No  ☒

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The number of outstanding common limited partner units of the registrant on May 4, 2018 was 23,300,410.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

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ATLAS GROWTH PARTNERS, L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

 

 

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GLOSSARY OF TERMS

Unless the context otherwise requires, references below to “Atlas Growth Partners, L.P.,” “Atlas Growth Partners,” “the Partnership,” “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.

Bpd. Barrels per day.

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.

DRIP. Distribution reinvestment plan.

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).

FASB. Financial Accounting Standards Board.

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

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

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

gross acres or gross wells. A gross well or gross acre is a well or acre in which the registrant owns a working interest.

IDR. Incentive distribution rights.

MLP. Master limited partnership.

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.

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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.

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

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

MMBtu. One million British thermal units.

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.

MMcfed. One MMcfe per day.

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

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

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

oil. Crude oil and condensate.

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.

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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.

SEC. Securities and Exchange Commission.

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 publicly traded Delaware limited liability company (OTCQX: TTEN).

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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.

FORWARD-LOOKING STATEMENTS

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

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PART I

 

 

General

We are 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.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls 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 own the remaining 20% member interest in our general partner.

Management Overview and Outlook

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, 2017, we have $8.2 million of cash on our balance sheet and no debt. Our general and administrative expenses decreased $5.0 million, or 50%, to $4.9 million for the year ended December 31, 2017 from $9.9 million for the year ended December 31, 2016.

In 2018, we are deploying $6.5 million of cash on hand to drill and complete one Eagle Ford shale well, expected to be in-line during the second quarter of 2018. The well is expected to significantly increase our production, and provide substantial cash flow. We believe that waiting throughout 2017 to restart development of our Eagle Ford shale position was prudent. The economics of drilling new oil wells across the our acreage position in the Eagle Ford shale in South Texas have improved substantially over the last twelve months, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.

We look forward to drilling 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.  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.

Geographic and Geologic Overview

Through December 31, 2017, 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 31 Bcfe of total proved reserves for our Eagle Ford position, of which 87% are oil. Over 92% of our production volumes and 96% of our revenues are derived from our Eagle Ford operations.

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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.

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.

Gas and Oil Production

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.

Natural Gas, Oil and NGL Reserves

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 10 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.

 

 

 

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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.

Proved Undeveloped Reserves (“PUDs”)

PUD Locations. As of December 31, 2017, we had 10 PUD locations totaling approximately 25 net Bcfe’s of natural gas, oil and NGLs. 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.

Material changes in PUDs. As of January 1, 2017, we had 10 PUD locations totaling approximately 17 net Bcfe’s of natural gas, oil, and NGLs.  Material changes in PUDs that occurred during the year ended December 31, 2017 were due to development plan modifications focused on longer lateral lengths, resulting in positive revisions of approximately 8 Bcfe.

Development Costs. There were no costs incurred for the development of PUDs for the year ended December 31, 2017. As of December 31, 2017, there were no PUDs that had remained undeveloped for five years or more.  The proved undeveloped reserves disclosed at December 31, 2017 are included within our five-year development plan and are expected to be developed within five years of the initial disclosure.

Productive Wells

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

 

 

Developed and Undeveloped Acreage

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

 

 

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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 are no concessions for undeveloped acreage as of December 31, 2017. As of December 31, 2017, there are no leases set to expire on or before December 31, 2018 and 2019.

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.

Drilling Activities

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.

As of December 31, 2017, we did not have any ongoing drilling activities.  In 2018, we are deploying $6.5 million of cash on hand to drill and complete one Eagle Ford shale well, expected to be turned in-line during the second quarter of 2018.

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Natural Gas and Oil Leases

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 Oklahoma (Mississippi Lime play) and Texas (Eagle Ford Shale and Marble Falls play), both states 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 and Oklahoma Mississippi Lime 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.

Contractual Revenue Arrangements

Natural Gas and Oil Production

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 index for our Eagle Ford production is primarily Houston Ship Channel, primarily Waha for our Marble Falls production and primarily Southern Star for our Mississippi Lime production.

We sell the majority of natural gas produced at monthly, fixed index first of the month prices and a smaller portion at index 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) or Conway (KS) 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, 2017, Shell Trading Co individually accounted for approximately 91% 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.

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Oil Hedging

We seek to provide greater stability in our cash flows through our 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.

Natural Gas Gathering Agreements

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

Marble Falls production in Texas is gathered/processed by a variety of companies depending on the location of the production. As in the case of Mississippi Lime production, either a fee is charged for the gathering activity alone, or a gatherer/processor may provide a combination of services to include processing, fractionation and/or compression. In some instances, the market to which the gas is sold will deduct the third-party gathering fees from the proceeds payable and pay the third-party gatherers directly.

Mississippi Lime production is currently gathered and processed by SemGas and plant products including gas and NGL’s are sold to SemGas. SemGas returns 95 Percent of Proceeds of the revenues it receives to us from the sale of gas and NGL’s. The remaining 5% and a $0.3276 MMBtu gathering fee are paid to SemGas for all services provided.

Availability of Energy Field Services

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.

Competition

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.

 

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Environmental Matters and Regulation

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

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 not have material adverse effects 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 assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

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

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

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Hydraulic Fracturing.  In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased.  Regulation of the practice remains largely the province of state governments, except for a few federal initiatives proposing disclosure of hydraulic fracturing chemicals, establishing effluent limitations produced water must meet before being discharged to a publicly owned treatment plant, and imposing conditions fracturing operations on federal lands.  This last initiative, under the Bureau of Land Management’s jurisdiction, has been hotly contested and remains unsettled, a federal district court in California invalidating the Trump Administration’s initial efforts to rescind the rule but the Administration proceeding with its plans to rescind.  In December 2016, EPA released the final report of its study of the impacts of hydraulic fracturing on drinking water in the U.S., finding that the hydraulic fracturing water cycle can impact drinking water resources under some circumstances.  Those circumstances included where (1) there are water withdrawals for hydraulic fracturing in times or areas of low water availability, (2) hydraulic fracturing fluids and chemicals or produced water are spilled, (3) hydraulic fracturing fluids are injected into wells with inadequate mechanical integrity, and (4) hydraulic fracturing wastewater is stored or disposed in unlined pits.  While we do not currently expect new federal regulations to be adopted as a result of these findings, if they were, they could increase our cost to operate.

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 seimiscity, including putting certain areas off limits for hydraulic fracturing.  

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

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations a number of different types of requirements on our operations.  First, these laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Second, the Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers.  The precise definition of waters and wetland subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to 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 also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills.   Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. 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.

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States are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations. For example, in January 2016, the Governor of Pennsylvania announced a comprehensive new regulatory strategy for reducing methane emissions from new and existing oil and natural gas operations, including well sites, compressor stations, and pipelines. Implementation of this strategy will result in significant changes to the air permitting and pollution control standards that apply to the oil and gas industry in Pennsylvania.  It may also influence air programs in other oil and gas-producing states.  In addition, West Virginia issued a sequence of general permits for natural gas production facilities at the well site over recent years.  Industry has expressed its concerns regarding the restrictiveness of versions of general permit, the most recent iteration of which is designated General Permit 70-D.

While we believe that compliance with existing with the 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 the prior Administration, several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple foundational finding were upheld by the courts.  During his first year in office, President Trump took steps to rescind and reconsider nearly all of the prior Administration’s initiatives to reduce the nation’s emissions of greenhouse gases.  Some of the foundations, however, appear unyielding.  It would be a significant departure from the principle of stare decisis for the Supreme Court to reverse its decision in Massachusetts v. EPA, 549 U.S. 497 (2007) holding that greenhouse gases are “air pollutants” covered by the Clean Air Act.  Similarly, reversing EPA’s final determination that greenhouse gases “endanger” public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009), upheld in Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir. 2012), would seem to require development of new scientific evidence that runs counter to general discoveries since that determination.  

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 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.  As described in connection with the foregoing discussion of federal regulation of hydraulic fracturing operations, a similar pattern of court rejection of initial efforts followed by rehabilitative rule-making has occurred. 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 an advanced notice of proposed rule-making seeking comment on whether a replacement for the 2015 Clean Power Plan – the rule aimed at reducing greenhouse gas emissions from existing power plants by one-third (compared to 2005 levels) – was needed.  

While we generally foresee a less stringent approach to the regulation of greenhouse gases, undoing the prior Administration’s greenhouse gas emissions regulations will 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 do regulate their emissions, then it is possible that a court would find common law nuisance claims are no longer displaced.    

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 RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. With authority granted by federal EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,”

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which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA or comparable state law requirements.  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 persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal.  While we are not presently aware the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition, 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.  On March 25, 2016, OSHA published its final Occupational Exposure to Respirable Crystalline Silica final rule, which imposes specific requirements to protect workers engaged in hydraulic fracturing.  81 Fed. Reg. 16,285.  The requirements of that final rule as it applies to hydraulic fracturing become effective June 23, 2018, except for the engineering controls component of the final rule, which has a compliance date of June 23, 2021.  We expect implementation of the rule to result in significant costs.  The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.  If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase.  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 are in substantial compliance with all such requirements.

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

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

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

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

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

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

Employees

We do not directly employ any of the persons responsible for our management or operation which is performed by  personnel employed by ATLS. As of December 31, 2017, approximately 204 ATLS employees provided direct management and support to our operations.

Available Information

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 425 Houston Street, Suite 300, Fort Worth, Texas 76102, telephone number (800) 251-0171. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

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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.

Risks Related to an Investment in the Partnership

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, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order 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 ATLS to provide us with its 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 ATLS, to provide its facilities and personnel and to conduct operations. Our general partner and, through it, ATLS, have 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 ATLS’s management team. The departure of any of the members of this management team 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. We anticipate that a liquidity event will occur within five years. However, there is no requirement that a liquidity event will occur within a specified timeframe or at all.

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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 determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order 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 liquidity event will occur within a specified timeframe or at all.

Increases in the costs of the wells or cost overruns may adversely affect your return.

Our general partner anticipates that it may use a portion of the net proceeds from our primary offering, if available, or seek debt financing to pay for any cost overrun in drilling or completing a well or wells. Using offering proceeds to pay for cost overruns may result in us drilling fewer wells or, if debt financing is used, incurring on-going debt service expenses. As a result of either situation, the amount of our cash available for distributions may be less than the amount that otherwise would have been available.

Compensation and fees to our general partner will reduce cash distributions.

Our general partner has received its general partner interest and its IDRs for only nominal consideration. In addition, our general partner will receive 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: (1) the reimbursements of organization and offering costs to our general partner are limited to 2% of the aggregate proceeds of the primary offering if less than $500 million is raised or 1.5% if $500 million or more is raised, in each case excluding the DRIP; and (2) the reimbursements 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.

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The intended quarterly distributions may be reduced or delayed.

Cash distributions may not be paid each quarter. Distributions may be reduced or deferred, 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:

On November 2, 2016, our management decided to temporarily suspend our current 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.

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.

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We may issue an unlimited number of common units and other equity securities, including interests that are senior to the common units offered hereby, 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, including those issued pursuant to our DRIP. 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. To the extent new interests are senior to the interests offered hereby, their issuance will increase the uncertainty of the payment of distributions.

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 generally will not be 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 within the expected five-year time frame following the completion of our private placement offering in June 2015 or at all. 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 expect to either sell our properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to our partners, with the approval of our general partner, or list the common units on a national securities exchange by June 30, 2020. 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.

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We are an “emerging growth company” under the federal securities laws and will be 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.

Risks Related to Conflicts of Interest

 

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:

ATLS, 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. Certain of the directors and officers of ATLS and our general partner are key executives of other publicly traded entities, including Titan, and in other programs sponsored by ATLS and its affiliates. As a result of their interests in other programs sponsored by our sponsor, 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 programs sponsored by ATLS, Titan and ATLS’s other affiliates and other business activities in which they are involved. In addition, ATLS, Titan and ATLS’s other affiliates operate in the same industry as us and thus remain subject to all of the same risks that our business faces. The NYSE suspended the trading of ATLS’s common units at the close of trading on March 18, 2016, and ATLS’s common units currently trade on the OCTQB. ATLS’s delisting from the NYSE could have a negative effect on ATLS and its affiliates’ ability to operate our business and could impact our securities, as well. As a result, the returns on our investments, and the value of our unitholders’ investments, may decline.

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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 (including ATLS 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 its unitholders. The directors and officers of ATLS have duties to manage ATLS and our general partner in a manner beneficial to its owners. In addition, many of the officers and directors of our general partner serve in similar capacities with ATLS and its affiliates, 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, depending on the nature of the conflict, although we may choose not to do so.

Risks Related to Our Oil and Gas Operations

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

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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, 2017, the NYMEX Henry Hub natural gas index price ranged from a high of $3.42 per MMBtu to a low of $2.56 per MMBtu, and West Texas Intermediate (“WTI”) oil prices ranged from a high of $60.42 per bbl to a low of $42.53 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.

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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.

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.

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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, 2017, Shell Trading Co individually accounted for approximately 91% 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

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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 other sources of capital, including our primary offering, 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.  

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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 can 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.

Hedging transactions may limit our potential gains or cause us to lose money.

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.

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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.

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

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

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 combined 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

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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.

We may not be able to identify suitable oil and gas properties.

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.

Also, the more common units we sell in our primary offering, the greater our challenge will be to invest all of the net offering proceeds on attractive terms. 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. If we are unable to identify and acquire suitable properties promptly, we will hold the proceeds from our primary offering in an interest-bearing account or invest the proceeds in short-term assets. 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.

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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 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 intended operations will be regulated extensively at the federal, state and local levels. Our operations, wells and other facilities will be 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 anticipate that we will use trucks to transport the water to water disposal wells or water treatment or recycling facilities, in certain areas, and that it will 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

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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. States outside the geographic area in which we intend to initiate our activities have imposed a variety of restrictions on hydraulic fracturing that could be adopted in jurisdictions in which we intend to 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.

If we fail to comply with environmental laws governing our operations, we may incur significant costs or be unable to operate.

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.

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.

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Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

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.  Reports of greater Congressional activity with respect to greenhouse gas emissions are scare.

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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

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, considering whether a replacement for the 2015 Clean Power Plan is needed, 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 U.S., 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 output.  Diminished demand could put additional downward pressure on the price of the natural gas we produce.

If fully implemented, environmental policies the new President supported during his campaign could increase supply in the overall markets for fuels, thereby potentially reducing prices for the Company’s output.

During the election campaign, President Trump pledged to implement policies that would reinvigorate coal’s use for energy production and ease restrictions on production and transportation of petroleum.  If fully implemented, these policies could have the effect of increasing the overall fuel supply, thereby reducing prices for the Company’s output.  For example, President Trump pledged to reverse the prior Administration’s policies that disadvantaged coal as a fuel for energy production.  President Trump promised to take several actions to encourage burning coal for energy production and lessen the

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financial burden of environmental regulations on coal-fired plants’ operations.  The President pledged to withdraw from the Paris Climate Agreement, withdraw or re-write the Clean Power Plan, withdraw mercury limits on coal plants’ air emissions, lift the prior Administration’s ban on new coal leases on federal lands and end the review of the program’s greenhouse gas impacts, and withdraw the “Waters of the United States” stream protection rule.  The new Administration has taken this final action.  President Trump also indicated his Administration would open more federal lands for oil and gas production, approve the construction of the Keystone Pipeline to facilitate refining of Alberta oil shale in the U.S., license the Dakota Access Pipeline, and open areas in the Arctic and Atlantic Ocean to drilling.  If fully implemented, these policies would increase the overall fuel supply and could have the effect of diminishing demand for our natural gas output.  Diminished demand could put additional downward pressure on the price of the natural gas 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 regulation. 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, 2017, 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 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. Once established, our borrowing base will 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.

 

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

 

Terrorist activities, anti-terrorist efforts, cyber-attacks 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

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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. Additionally, as an oil and natural gas producer, we face various cybersecurity threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable, and there can be no assurance that our implementation of various procedures and controls to monitor and mitigate security threats will be sufficient to prevent security breaches from occurring. 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:

 

 

 

 

 

 

 

 

 

 

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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.

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, 2017, 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

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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 it has 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, natural gas liquids 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 it acquired the working interest in the well from a third party under arrangements that required the third party to be named operator.

Federal Income Tax Risks

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,

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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, 2017, 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.

Changes in the law may reduce your tax benefits from an investment in us.

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 owe taxes in excess of your cash distributions from us.

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:

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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. We presently anticipate that substantially all of our income will be generated in Texas and Oklahoma, 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.

Your tax benefits from an investment in us are not contractually protected.

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 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.

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 the federal information income tax returns of us could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from us.

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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 the federal information income tax returns of us 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.

 

None.

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See Item 1: Business.

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 Item 8: Financial Statements and Supplementary Data - Note 7.

Not applicable.

PART II

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. 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.

At the close of business on May 4, 2018, there were 2,964 holders of record.

On November 2, 2016, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order 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.  

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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.

 

 

 

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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.

BUSINESS OVERVIEW

We are 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.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls 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 own the remaining 20% member interest in our general partner.

MANAGEMENT OVERVIEW AND OUTLOOK

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, 2017, we have $8.2 million of cash on our balance sheet and no debt. Our general and administrative expenses decreased $5.0 million, or 50%, to $4.9 million for the year ended December 31, 2017 from $9.9 million for the year ended December 31, 2016. By reducing our general and administrative expenses, we have enhanced ability to generate positive cash flow from our operations, grow our cash balance, and take advantage of opportunities to drill new Eagle Ford wells or take on other strategic initiatives and transactions should favorable conditions arise.

In 2018, we are deploying $6.5 million of cash on hand to drill and complete one Eagle Ford shale well, expected to be in-line during the second quarter of 2018. The well is expected to significantly increase our production and provide substantial cash flow.  We believe that waiting to restart development of our Eagle Ford shale position was prudent. The economics of drilling new oil wells across the our acreage position in the Eagle Ford shale in South Texas have improved substantially over the last twelve months, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.

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 look forward to drilling 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.  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.

GENERAL TRENDS AND OUTLOOK

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

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Throughout 2017, the natural gas, oil and natural gas liquids commodity price markets were marked by volatility. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves. The economics of drilling new oil wells across the our acreage position in the Eagle Ford shale in South Texas have improved substantially over the last twelve months, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.

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.

For additional information, please see “—Liquidity and Capital Resources.”

RESULTS OF OPERATIONS

Gas and Oil Production

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

 

 

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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 natural gas liquids production, along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, for the periods indicated:

 

 

 

 

Our gas and oil production revenues were lower in the current year as compared to the prior year due to a $3.9 million decrease attributable to production from our Eagle Ford operations, primarily related to natural production decline without our having drilled any additional wells to offset such decline.

The increase in gas and oil production revenues for the year ended December 31, 2016 as compared to the prior year consisted of a $0.9 million increase attributable to production from our Eagle Ford operations, primarily related to two more wells being turned in line during 2016 and a full year of production for the wells that were turned in line during 2015, partially offset by an $0.8 million decrease attributable to our Marble Falls operations primarily related to lower volumes and a $0.1 million decrease attributable to our Mississippi Lime operations primarily related to lower volumes.

Our gas and oil production costs were lower in the current year as compared to the prior year due to a $0.1 million decrease in maintenance, materials, and treating costs in our Marble Falls operations.

The increase in gas and oil production expenses for the year ended December 31, 2016 as compared to the prior year consisted of consisted of a $1.1 million increase attributable to our Eagle Ford operations, partially offset by a decrease of $0.7 million attributable to our Marble Falls operations.  

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OTHER REVENUES AND EXPENSES

 

 

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, 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior period end. The recognized losses and gains during the years ended December 31, 2016 and 2015, respectively, are related to the changes in oil prices during the years ended December 31, 2016 and 2015 as compared to the prior year periods.

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 $5.0 million decrease in salaries, wages and other corporate activity costs allocated to us as a result of the suspension of our current primary offering efforts and management’s plan to reduce general and administrative expenses.

The decrease in general and administrative expenses for the year ended December 31, 2016 as compared to the prior year was due to a $2.8 million decrease in salaries, wages and other corporate activity costs allocated to us in connection with the completion of our private placement offering in June 2015.

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization for the current year as compared to the prior year was primarily due to a $11.3 million decrease in our depletion expense resulting from the asset impairments recorded in the 4^th quarter of 2016, which lowered our depletable base, and lower production volumes.  

The increase in depreciation, depletion and amortization for the year ended December 31, 2016 as compared to the prior year was primarily due to a $5.9 million increase in our depletion expense related to two more wells being turned in line during 2016 and a full year of depletion for the wells that were turned in line during 2015.  

Asset Impairment.  For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $7.3 million of asset impairment related to our proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices.

Other loss. Other loss for the year ended December 31, 2016 was due to a $5.4 million write-off of issuer costs related to the suspension of our primary offering 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.  There was no other loss for the years ended December 31, 2017 and 2015.

LIQUIDITY AND CAPITAL RESOURCES

General

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including our private placement offering completed in June 2015. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas remain volatile but have improved during 2017 as compared to prior years.

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On November 2, 2016, our management decided to suspend our current 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. In addition, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain our cash flow.  

As of December 31, 2017, we have $8.2 million of cash on our balance sheet and no debt.

Cash Flows

 

 

Year Ended December 31, 2017 Compared with the Year Ended December 31, 2016

Cash Flows from Operating Activities:

The change in cash flows used in operating activities compared with the prior year period was due to:

Cash Flows from Investing Activities:

The change in cash flows used in investing activities compared with the prior year period was due to a decrease of $6.6 million in capital expenditures related to our development activities as we did not drill or complete any new wells during 2017.

Cash Flows from Financing Activities:

The change in cash flows used in financing activities compared with the prior year period was due to:

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Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

Cash Flows from Operating Activities:

The change in cash flows provided by (used in) operating activities when compared with the comparable prior year period was primarily due to:

Cash Flows from Investing Activities:

The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:

Cash Flows from Financing Activities:

The change in cash flows (used in) provided by financing activities when compared with the comparable prior year period was primarily due to:

Capital Requirements

During the years ended December 31, 2016 and 2015, our capital expenditures were approximately $6.2 million and $29.2 million, respectively, related to our well drilling and completion costs.

We did not have any capital expenditures during the year ended December 31, 2017. As of December 31, 2017, we did not have any commitments for our drilling and completion and capital expenditures.

OFF BALANCE SHEET ARRANGEMENTS

As of December 31, 2017, we did not have any off-balance sheet commitment arrangements for our drilling and completion and capital expenditures.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

As of December 31, 2017, we did not have any contractual obligations or commercial commitments.

CREDIT FACILITY

On May 1, 2015, we entered into a secured credit facility agreement with syndicate of banks. As of December 31, 2017, the lenders under the credit facility have no commitment to lend to us under the credit facility and we have a zero

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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 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, 2017. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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, 3 and 5 included in this report. The critical accounting policies and estimates we have identified are discussed below.

Gas and Oil Properties – Depletion and Impairment

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 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. 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 of the properties related to the unsuccessful work is charged to exploration expense. The

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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. As discussed in “General Trends and Outlook” within this section, recent increases in natural gas and oil drilling have driven an increase in the supply of natural gas and oil and put a downward pressure on domestic prices. Further declines in commodity prices may result in additional impairment charges in future periods.

Reserve Estimates

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 2: Properties).

Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas, 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.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Item 8: Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements for additional information related to recently issued accounting standards. As stated in our Form S-1, we qualify for emerging growth company status; however, we do not elect this exemption in relation to accounting standards.

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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.

General

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 manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. 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, 2017. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity derivative contracts are banking institutions or their affiliates. The creditworthiness of our counterparties is monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

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 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.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our net loss for the twelve-month period ending December 31, 2018 of $0.5 million.

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

As of December 31, 2017, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

 

 

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Index

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Unitholders

Atlas Growth Partners, L.P.

Opinion on the financial statements

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, 2017 and 2016, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

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.

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

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2013.

 

Cleveland, Ohio

May 8, 2018

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

See accompanying notes to consolidated financial statements.

 

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

 

See accompanying notes to consolidated financial statements.

 

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in thousands, except unit data)

 

 

See accompanying notes to consolidated financial statements.

 

 

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ATLAS GROWTH PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

See accompanying notes to consolidated financial statements.

 

 

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ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 – BASIS OF PRESENTATION

We are 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.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls 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 own the remaining 20% member interest in our general partner.

In addition to its general and limited partner interest in us, ATLS also holds a Series A Preferred Share (which entitles it to receive 2% of distributions, subject to potential dilution in the event of future equity interests and to appoint four of seven directors) in Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States, and a general and limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. Titan is the successor to the business and operations of Atlas Resource Partners, L.P.

At December 31, 2017, we had 23,300,410 common limited partner units issued and outstanding.

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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 material intercompany transactions have been eliminated.

Use of Estimates

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, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Cash Equivalents

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.

Receivables

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, 2017 and 2016, we had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets.

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Property, Plant and Equipment

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.

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. 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 statement 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.

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

Impairment of Property, Plant and Equipment

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 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

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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.

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. 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.

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

Derivative Instruments

We enter 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 are 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.

Asset Retirement Obligations

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 both December 31, 2017 and 2016, our asset retirement obligation was $0.2 million. For the years ended December 31, 2017, 2016 and 2015, we recorded $16,000, $15,000 and $14,000, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our consolidated statements of operations.

Other Non-current Liabilities

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 to be $0.5 million which was recorded as a non-current liability on our consolidated balance sheet as of December 31, 2016. As of December 31, 2017, we presented $0.1 million as current accrued liabilities, to reflect the estimated amount owed within one year, and $0.3 million as the estimated remaining non-current liability on our consolidated balance sheet.  

Income Taxes

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.

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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 any tax positions taken 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 its consolidated financial statements for the years ended December 31, 2017 and 2016.

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 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 is not expected to have a material impact on us.

Segment Reporting

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

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (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 general partner’s interest in net income (loss) is calculated on a quarterly basis based upon our general partner units and incentive distributions to be distributed for the quarter (see Note 9), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with our Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

We present net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security. The two-class method considers whether our Partnership Agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under our Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, our management believes our Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

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 income (loss) attributable to common limited partners per unit is calculated by dividing net income (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.

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

 

 

Concentration of Credit Risk

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, 2017 and 2016, we had $8.3 million and $10.3 million, respectively, in deposits at various banks, of which $8.0 million and $9.7 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, 2017, 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. For the year ended December 31, 2016, Shell Trading Co and Enterprise Crude Oil, LLC individually accounted for approximately 64% and 29%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, Enterprise Crude Oil, LLC, Shell Trading Co. and Midcoast Energy Partners individually accounted for approximately 59%, 28% and 12%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

We are subject to the risk of loss on our derivative instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil counterparties’ credit exposures; (iii) comprehensive credit reviews of significant counterparties to physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our liabilities related to derivatives as of December 31, 2017 represent financial instruments from one counterparty, which is a financial institution that has an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our credit facility. Subject to the terms of our credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the credit facility.

Revenue Recognition

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

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We accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from our records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. We had unbilled revenues of $0.6 million and $0.9 million at December 31, 2017 and 2016, respectively, which were included in accounts receivable within our consolidated balance sheets.

Recently Issued Accounting Standards

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

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We have completed our detailed contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. We adopted the new accounting guidance using the modified retrospective method of adoption on January 1, 2018.  We do not expect the new accounting guidance to have a material impact on our financial position, results of operations or cash flows in 2018.  The new accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers including disaggregation of revenues, beginning with our Form 10-Q for the three months ended March 31, 2018.

 

 

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

 

 

As of December 31, 2017, we transferred $63.3 million of our unproved properties to proved natural gas and oil properties as management finalized capital plans for drilling and developing the wells within our Eagle Ford operating area. For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. There were no impairments of unproved gas and oil properties for the year ended December 31, 2015. For the year ended December 31, 2015, we recognized $7.3 million of asset impairment related to proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices.

During the year ended December 31, 2016, we recognized $0.4 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our consolidated statements of cash flows. During the year ended December 31, 2015, we assigned a portion of our non-operating Eagle Ford

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assets to ARP in exchange for ARP funding our remaining $36.3 million of deferred Eagle Ford Acquisition purchase price, which represented a non-cash transaction within our consolidated statement of cash flows.

 

 

NOTE 4 – DERIVATIVE INSTRUMENTS

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

We enter 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 include regulated New York Mercantile Exchange (“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.

The following table summarizes the commodity derivative activity for the period indicated (in thousands):

 

 

The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our consolidated balance sheets as of the date indicated (in thousands):

 

 

As of December 31, 2017, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

 

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On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2017, the lenders under the credit facility have 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 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, 2017. 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.

NOTE 5 – FAIR VALUE OF FINANCIAL INSTRUMENTS

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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments (see Note 4). We manage and report 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.

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Information for financial instruments measured at fair value was as follows (in thousands):

 

 

Other Financial Instruments

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.

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

Warrants. The fair value of the warrants associated with the issuance of common limited partner units in 2015 (see Note 8) was measured using a Black-Scholes pricing model which was based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.5%, an expected term of 1.5 years, expected dividend yield of 7.0% and estimated volatility rate of 50%. The volatility rate used was consistent with that of ARP at the time the warrants were issued. The estimated fair value per warrant was $1.47, which included a $0.37 liquidity adjustment.

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.

 

NOTE 6 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates, including Titan. Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum.  During each of the years ended December 31, 2017 and 2016, we paid a management fee of $2.3 million. 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. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse 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 each of December 31, 2017 and December 31, 2016, we had payables to ATLS of $0.6 million, related to the management fee, direct costs and allocated indirect costs, which was recorded in advances from affiliates in the consolidated balance sheets.

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Relationship with Titan. At the direction of ATLS, we reimburse 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, 2017 and 2016, we had payables to Titan of $0.1 million and $0.8 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the consolidated balance sheets.

 

NOTE 7 – COMMITMENTS AND CONTINGENCIES

General Commitments

We lease office space and equipment under leases with varying expiration dates. Rental expense was $0.2 million, $0.3 million and $0.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. We do not have any future minimum rental commitments as of  December 31, 2017.

As of December 31, 2017, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances.

As of December 31, 2017, we did not have any commitments related to our drilling and completion and capital expenditures.

Legal Proceedings

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

Environmental Matters

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, 2017 and 2016.

 

 

NOTE 8 – ISSUANCES OF UNITS

On November 2, 2016, our management decided to temporarily suspend our current 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.

As a result of management’s decision to temporarily suspend our current primary offering efforts (see Note 2), we reclassified $5.3 million of offering costs to other loss on our consolidated statement of operations for the year ended December 31, 2016. These offering costs were previously capitalized within our consolidated statement of changes in partners’ capital as an offset to any proceeds raised in our current primary offering and included $1.5 million that were previously capitalized in our consolidated statement of changes in partners’ capital as of December 31, 2015.

Private Placement Offering. Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date

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that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets.

Through the completion of our private placement offering on June 30, 2015, we issued $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the private placement offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit.

During the year ended December 31, 2015, we sold an aggregate of 12,623,500 of our common units at a gross offering price of $10.00 per unit, resulting in proceeds of $112.7 million to us, net of dealer manager fees and commissions and expenses of $12.7 million, of which ATLS had purchased $2.7 million, or 300,000 common units. In connection with the issuance of common limited partner units during the year ended December 31, 2015, unitholders received 1,262,350 warrants to purchase our common units at an exercise price of $10.00 per unit.  

 

NOTE 9 – CASH DISTRIBUTIONS

We have a cash distribution policy under which we distribute 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 have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are 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, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain our cash flow and reinvest in our business and assets.

During the year ended December 31, 2016, we paid distributions of $12.2 million to common limited partners ($0.1750 per unit for each of the first and second quarters) and $0.3 million to the general partner units ($0.1750 per unit for each of the first and second quarters). During the year ended December 31, 2015, we paid distributions of $10.5 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner units ($0.1750 per unit per quarter).

 

NOTE 10—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the our natural gas, oil and NGL reserve estimates was completed in accordance with the prescribed internal control procedures by our reserve engineers. Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to us. The independent reserve engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by the Executive Vice President of Operations.

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

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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, 2017, 2016 and 2015, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of 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:

 

 

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Revisions of Previous Estimates

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, 2017, we had positive revisions of 8,585 MMcfe due to modifications in our Eagle Ford development plan, focusing on longer lateral lengths, and 1,208 MMcfe due to increases in pricing, partially offset by negative revisions of 844 MMcfe due to production underperforming previous year’s forecast.

 

For the year ended December 31, 2016, we had negative revisions of 23,794 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, 3,582 MMcfe due to production underperforming previous year’s forecast and 731 MMcfe due to decreases in pricing.

For the year ended December 31, 2015, we had negative revisions of 4,543 MMcfe due to decreases in pricing and 3,268 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by 1,497 MMcfe due to our production outperforming the comparable period’s forecast.

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):

 

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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):

 

 

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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:

 

 

 

NOTE 11 — QUARTERLY RESULTS (UNAUDITED)

 

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None.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our 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, 2017, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

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).

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

There have been no changes in our internal control over financial reporting during the fourth quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2017.

 

None.

 

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PART III

 

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, Walter Jones. Correspondence to Mr. Jones should be marked “Confidential” and sent to Mr. Jones’ attention, c/o Atlas Growth Partners, L.P., 1845 Walnut Street, 10^th Floor, 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 Atlas Energy Group manage and operate our business. Some of our general partner’s officers may spend a substantial amount of time managing the business and affairs of Atlas Energy Group and its affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

 

Reimbursement of Expenses of Our General Partner and Its Affiliates

 

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. Our general partner allocates 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.

 

Board of Directors and Officers of Our General Partner

 

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

 

 

Edward E. Cohen has been the Chairman of the board of directors and Chief Executive Officer of our general partner since its inception in February 2013.  In addition, Mr. Cohen has served as the Executive Chairman and a Class A Director of Titan Energy, LLC since September 2016. Before then, he served as the Executive Chairman of Titan Energy, LLC’s predecessor, Atlas Resource Partners, L.P., since August 2015 and the Chief Executive Officer and Executive Vice Chairman of Atlas Energy Group, LLC, Titan Energy, LLC’s predecessor’s general partner, since February 2015. Mr. Cohen served as President of Atlas Energy Group from February 2015 to April 2015, and before that he was Chairman and Chief Executive

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Officer since February 2012.  Mr. Cohen was the Chairman of the board of directors of Atlas Energy, L.P.’s general partner from its formation in January 2006 until February 2011, when he became its Chief Executive Officer and President until February 2015. Mr. Cohen served as the Chief Executive Officer of Atlas Energy’s general partner from its formation in January 2006 until February 2009. Mr. Cohen served on the executive committee of Atlas Energy’s general partner from 2006 until February 2015. Mr. Cohen also was the Chairman of the board of directors and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until February 2011and also served as its President from September 2000 to October 2009. Mr. Cohen was the Executive Chair of the managing board of directors of Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”) from its formation in 1999 until February 2015. Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP from 1999 to January 2009. Mr. Cohen was the Chairman of the board of directors and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc. from their formation in June 2006 until February 2011. Mr. Cohen has served as the Chairman of Osprey Energy Acquisition Corporation, a special purpose acquisition company, since April 2017.  In addition, Mr. Cohen was a director of Resource America, Inc. (formerly a publicly-traded specialized asset management company) from 1988 until September 2016 and its Chairman of its board of directors from 1990 until September 2016 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the board of directors of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in 2005 until November 2009 and served on its board of directors until September 2016; and Chairman of the board of directors of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen has been active in the energy business for over 30 years. Mr. Cohen’s strong financial and energy industry experience, along with his deep knowledge of the company resulting from his long tenure with the company and its predecessors, enables Mr. Cohen to provide valuable perspectives on many issues facing the company. Mr. Cohen’s service on the Board creates an important link between management and the Board and provides the company with decisive and effective leadership. Mr. Cohen’s extensive experience in founding, operating and managing public and private companies of varying size and complexity enables him to provide valuable expertise to the company. Additionally, among the reasons for his appointment as a director, Mr. Cohen brings to the Board the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country. These diverse experiences have enabled Mr. Cohen to bring unique perspectives to the Board, particularly with respect to business management, financial markets and financing transactions and corporate governance issues.

Jonathan Z. Cohen has served as the Executive Vice Chairman of the board of directors of our general partner since its inception in February 2013.  In addition, Mr. Cohen has served as the Executive Vice Chairman and a Class A Director of Titan Energy, LLC since September 2016. Before then, he served as Titan Energy, LLC’s predecessor’s Executive Vice Chairman since August 2015 and the Executive Chairman of the board of directors of Atlas Energy Group, LLC, Titan Energy, LLC’s predecessor’s general partner, since February 2015, and before that was Vice Chairman of Titan Energy, LLC’s predecessor’s general partner since February 2012.   Mr. Cohen served as Executive Chairman of the board of directors of Atlas Energy, L.P.’s general partner from January 2012 until February 2015. Before that, he served as Chairman of the board of directors of Atlas Energy’s general partner from February 2011 until January 2012 and as Vice Chairman of the board of directors of its general partner from its formation in January 2006 until February 2011. Mr. Cohen served as chairman of the executive committee of Atlas Energy’s general partner from 2006 until February 2015. Mr. Cohen was the Vice Chairman of the board of directors of Atlas Energy, Inc. from its incorporation in September 2000 until February 2011. Mr. Cohen was the Executive Vice Chair of the managing board of directors of Atlas Pipeline GP from its formation in 1999 until February 2015. Mr. Cohen was the Vice Chairman of the board of directors of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc. from their formation in June 2006 until February 2011. Mr. Cohen was a senior officer of Resource America, Inc. (formerly a publicly-traded specialized asset management company) from 1998 until September 2016, serving as the Chief Executive Officer from 2004 to September 2016, President from 2003 to September 2016 and a director from 2002 to September 2016. Mr. Cohen served as Chief Executive Officer, President and a director of Resource Capital Corp. from its formation in 2005 until September 2016. Since September 2016, Mr. Cohen has served as the founder and Chief Executive Officer of Hepco Capital Management, LLC, a recently formed private investment firm. Mr. Cohen has served as the Chief Executive Officer of Osprey Energy Acquisition Corporation, a special purpose acquisition company, since April 2017.  Mr. Cohen has served on the board of directors of Energen Corporation since March 2018.  Mr. Cohen is a son of Edward E. Cohen. Mr. Cohen’s extensive knowledge of the company resulting from his long length of service with the company and its predecessors, as well as his strong financial and industry experience, allow him to contribute valuable perspectives on many issues facing the Company. Mr. Cohen’s service on the Board creates an important link between management and the Board and provides the company with decisive and effective leadership. Mr. Cohen’s involvement with public and private entities of varying size, complexity and focus and raising debt and equity for such entities provides him with extensive experience and contacts that are valuable to the company. Additionally, among the reasons for his appointment as a director, Mr. Cohen’s financial, business, operational and energy experience as well as the experience that he has accumulated through his activities as a financier and investor, add strategic vision to our Board to

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assist with our growth, operations and development. Mr. Cohen is able to draw upon these diverse experiences to provide guidance and leadership with respect to exploration and production operations, capital markets and corporate finance transactions and corporate governance issues.  

 

William R. Bagnell has been a director of our general partner since its inception in 2013. Mr. Bagnell served as a director of Atlas Energy, Inc. from July 2009 through February 2011 and was a director of Atlas America, Inc. from February 2004 until July 2009. Mr. Bagnell has been Director of Sales – Northeast of Nordic Energy Services, LLC, an alternative electric and gas supplier, since October 2013. From October 2012 to October 2013, he was an Account Executive of Procurian Energy, an end-to-end energy management solutions company. Before that, he was Vice President of Energy for Planalytics, Inc., an energy industry risk management and software company, since March 2000. Before that, he served as Director of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until February 2000.

 

Walter C. Jones has been a director of our general partner since July 2017 and serves as our audit committee chair.  Mr. Jones served as a director of Atlas Energy Group, LLC, from February 2015 until July 2017. Mr. Jones served as a director of the general partner of Atlas Energy, L.P. from October 2013 until February 2015, a director and chair of the audit committee of Atlas Energy Resources, LLC from December 2006 until September 2009, and a director of Atlas Energy, Inc. from September 2009 until March 2010.  Since November 2013, Mr. Jones has been the managing director of the Jones Pohl Group, an investment firm based in Dubai, UAE, that invests in clean energy projects, primarily in developing and developed markets around the globe.  JPG is also the majority shareholder of a Dubai-based geothermal energy developer, RG Safa Energy.  From April 2010 to October 2013, Mr. Jones served as the U.S. Executive Director and Chief-of-Mission to the African Development Bank in Tunis, Tunisia, having been nominated for the position by President Barack Obama in 2009 and confirmed by the U.S. Senate in 2010.  In that position, he represented the United States on the African Development Bank’s Board of Directors, and served as chair of the bank’s audit committee and vice-chair of both the ethics and development effectiveness committees. Mr. Jones served as the Head of Private Equity and General Counsel at GRAVITAS Capital Advisors, LLC from June 2005 until May 2007. Mr. Jones served in a number of positions at the Overseas Private Investment Corporation from May 1994 to May 2005, and then again from September 2007 until April 2010, including Manager for Asia, Africa, the Middle East, Latin America and the Caribbean and Senior Investment Officer in the Finance Department; and was an International Consultant at the Washington, D.C. firm of Neill & Co. before that.  Mr. Jones began his career at the law firm of Sidley & Austin, where he was a transactions attorney specializing in leveraged buyouts. Mr. Jones is a seasoned energy company director, having previously served as a director and chair of the audit committee of Atlas Energy Resources, LLC and a director of Atlas Energy, Inc. Mr. Jones’ combination of private and public sector experience, as well as his international work, has afforded him a unique combination of management and leadership experience.  Our board of directors benefits from his investment and transaction expertise as well as his valuable financial experience.

Jeffrey F. Kupfer has been a director of our general partner since July 2017.  Mr. Kupfer served as a director of Atlas Energy Group, LLC, from February 2015 until July 2017. Mr. Kupfer served as a director of the general partner of Atlas Energy, L.P. from March 2014 until February 2015.  Since 2015, Mr. Kupfer has been the co-founder of Starling Trust Sciences, an applied behavioral sciences technology company.  He has been an Adjunct Professor of Policy and Management at Carnegie Mellon University’s H. John Heinz III College since October 2009. Mr. Kupfer served as a senior advisor for policy and government affairs at Chevron from February 2011 to January 2014, and a Senior Vice President at Atlas Energy, Inc. from September 2009 to February 2011. Before that, Mr. Kupfer held a number of high level positions in the U.S. Department of Energy, including Acting Deputy Secretary and Chief Operating Officer from March 2008 to January 2009, and Chief of Staff from October 2006 to March 2008. Mr. Kupfer also worked in the White House as a Special Assistant to the President for Economic Policy in 2006, as the Executive Director of the President’s Panel on Federal Tax Reform in 2005, and as Deputy Chief of Staff at the U.S. Treasury Department from 2001 to 2005. Mr. Kupfer brings to the board of directors extensive experience in the energy industry, as well his perspective as a former senior official in the U.S. government, which we view as complementary to the industry perspective of other members of the board of directors.

Daniel C. Herz has served as President and a director of our general partner since its inception in February 2013.  In addition, Mr. Herz has served as the Chief Executive 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 Executive Officer since August 2015 and as President of Atlas Energy Group, LLC, Titan Energy, LLC’s predecessor’s general partner since April 2015.  Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Titan Energy LLC’s predecessor’s general partner from March 2012 to April 2015. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of Atlas Energy, L.P.’s general partner from February 2011 until February 2015. Mr. Herz was Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC from August 2007 until February 2015. He also was Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until February 2011.

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Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004. Mr. Herz has served as the President and a director of Osprey Energy Acquisition Corporation, a special purpose acquisition company, since April 2017.  Mr. Herz’s significant experience as a chief executive officer for the Company and related entities, together with his corporate development experience, enables him to provide the Board with executive counsel on a full range of business, strategic and professional matters.

Jeffrey M. Slotterback has 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.

Lisa Washington has been the Chief Legal Officer and Secretary of our general partner since its inception in February 2013.  In addition, Ms. Washington has served as the Vice President, Chief Legal Officer and Secretary of Titan Energy, LLC since September 2016. Before then, she served as Titan Energy, LLC’s predecessor’s Vice President, Chief Legal Officer and Secretary since August 2015 and served as Senior Vice President of Atlas Energy Group, Titan Energy, LLC’s predecessor’s general partner, since September 2015, Chief Legal Officer and Secretary of Titan Energy, LLC’s predecessor’s general partner since February 2012 and served as Vice President of Titan Energy, LLC’s predecessor’s general partner from February 2015 to September 2015.  Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy GP, LLC from January 2006 to October 2009, and as a Senior Vice President from October 2008 to October 2009, and as Vice President, Chief Legal Officer and Secretary from February 2011 to February 2015. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Pipeline Partners GP, LLC from November 2005 to October 2009, a Senior Vice President from October 2008 to October 2009 and a Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy, Inc. from November 2005 until February 2011, a Senior Vice President from October 2008 until February 2011, and a Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, a Senior President from July 2008 until February 2011 and a Vice President from 2006 until July 2008. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.  

Matthew J. Finkbeiner has been the Chief Accounting Officer of our general partner since October 2015.  In addition, Mr. Finkbeiner has served as the Chief Accounting Officer of Titan Energy, LLC since September 2016. Before then, he served as Titan Energy, LLC’s predecessor’s Chief Accounting Officer since October 2015. Mr. Finkbeiner has been the Chief Accounting Officer of Atlas Energy Group, Titan Energy, LLC’s predecessor’s general partner since October 2015.  Mr. Finkbeiner has held positions with Deloitte & Touche LLP, including Audit Senior Manager from September 2010 until joining us in October 2015, Audit Manager from September 2007 to September 2010, and Audit Senior/Staff from September 2002 until September 2007. While at Deloitte & Touche LLP, Mr. Finkbeiner managed audits for a diversified base of clients in the oil and gas industry, including master limited partnerships. Mr. Finkbeiner is a Certified Public Accountant.

Section 16(a) Beneficial Ownership Reporting Compliance

 

           Because we did not have any securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the fiscal year ended December 31, 2017, no persons were required to file forms or reports required by Section 16(a) of the Exchange Act during that period.

 

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Committees of the Board of Directors of our General Partner

 

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. Bagnell, Kupfer and Jones. Mr. Jones 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 NYSE and the board. The members of the Conflicts Committee are Messrs. Bagnell, Kupfer and Jones.

Code of Business Conduct and Ethics

Because we do not employ any persons, we rely on the code of business conduct and ethics adopted by Atlas Energy Group that applies to the executive officers, employees and other persons performing services for Atlas Energy Group and its affiliates generally. You may obtain a copy of this code of business conduct and ethics without charge at www.atlasenergy.com.

 

Role in Risk Oversight

 

General

 

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. However, the Atlas Energy Group Audit Committee has ultimate responsibility for overseeing the internal audit function. The Audit Committee incorporates its risk oversight function into its regular reports to the board of directors of our general partner.

 

In addition to the Audit Committee’s role in risk management, the full board of directors of our general partner 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.

 

Compensation Programs

 

Atlas Energy Group’s compensation policies and programs are intended to encourage those employees who provide

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services to us to remain focused on both our short-term and long-term goals.  Because we do not employ any persons, we rely on Atlas Energy Group’s Code of Business Conduct and Ethics, which applies to all our officers and our general partner’s directors, further seeks to mitigate the potential for inappropriate risk taking. We also prohibit hedging transactions involving our units so our officers and our general partner’s directors cannot insulate themselves from the effects of our unit price performance.

 

Atlas Energy Group’s compensation committee, together with senior management, also reviews compensation programs and benefits plans affecting employees generally (in addition to those applicable to executive officers who provide services to us), and Atlas Energy Group has concluded that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the company. Atlas Energy Group also believes that its incentive compensation arrangements provide incentives that do not encourage risk-taking beyond its ability to effectively identify and manage significant risks; are compatible with effective internal controls and its and our risk management practices; and are supported by the oversight and administration of Atlas Energy Group’s compensation committee with regard to executive compensation programs.

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 also current officers of Atlas Energy Group or its affiliates, and therefore will have responsibilities for both us and Atlas Energy Group or such affiliate.

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, the activities of Atlas Energy Group and its affiliates, and any acquisitions or dispositions made by us, Atlas Energy Group or its affiliates. Because the executive officers of our general partner are employees of Atlas Energy Group or its affiliates, compensation is determined and paid by Atlas Energy Group or the appropriate affiliate, and reimbursed by us to the extent determined by our general partner. The executive officers of our general partner, as well as the employees of Atlas Energy Group or its affiliates who provide services to us, may participate in employee benefit plans and arrangements sponsored by Atlas Energy Group, including plans that may be established in the future. 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. We have adopted a long-term incentive plan, but no grants may be made thereunder until a listing event occurs.

Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by Atlas Energy Group or its affiliates reside with Atlas Energy Group or the appropriate affiliate. Atlas Energy Group 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. Although we bear an allocated portion of the costs of compensation and benefits provided to the Atlas Energy Group and/or Atlas Energy Group affiliate employees who serve as the executive officers of our general partner, we have no control over such costs. Each of these executive officers perform services for our general partner, as well as Atlas Energy Group and its affiliates.

 

 

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SUMMARY COMPENSATION TABLE

 

 

 

Employment Agreements and Potential Payments Upon Termination or Change of Control

Atlas Energy Group has employment agreements with certain of our NEOs that provide for severance compensation to be paid if such NEO’s employment is terminated under certain conditions.

Atlas Energy Group Employment Agreements

Effective September 4, 2015, Atlas Energy Group entered into an employment agreement with each of Edward E. Cohen, Atlas Energy Group’s Chief Executive Officer, Jonathan Z. Cohen, Atlas Energy Group’s Executive Chairman of the board of directors, Daniel C. Herz, Atlas Energy Group’s President, and Mark Schumacher, Atlas Energy Group’s Senior Vice President (collectively, the “Atlas Employment Agreements”).

The Atlas Employment Agreements with Messrs. E. Cohen and J. Cohen each provide for a term of three years (which automatically renews daily unless earlier terminated) and an initial base salary of $350,000, subject to periodic

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increases by the compensation committee.  The Atlas Employment Agreements with Messrs. Herz and Schumacher each provide for a term of two years (which automatically renews daily for one-year terms after the first anniversary of the effective date of the agreement unless earlier terminated) and an initial base salary of $350,000 (in the case of Mr. Herz) and $375,000 (in the case of Mr. Schumacher), subject to increases, but not decreases, by the Compensation Committee.

Under the Atlas Employment Agreements, Messrs. E. Cohen and J. Cohen are 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 each of Mr. E. Cohen’s and Mr. J. Cohen’s respective lives that each separate policy provide a death benefit of $3 million to one or more beneficiaries designated by Messrs. E. Cohen and J. Cohen respectively, which such policy, at each individual’s request, can be assumed by such individual upon a termination of employment, if and as allowed by the applicable insurance company.

Pursuant to the Atlas Employment Agreements, Messrs. Herz and Schumacher are each entitled to receive a bonus determined in accordance with procedures established by Atlas Energy Group’s board or Compensation Committee.  In addition Messrs. Herz and Schumacher are each eligible to receive grants of equity-based compensation as determined by Atlas Energy Group’s board or Compensation Committee.

Under the Atlas Employment Agreements, 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) two times (or three times in the case of Messrs. E. Cohen and J. Cohen) 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) 24 months of continued health insurance (or 36 months in the case of Messrs. E. Cohen and J. Cohen of continued health and life insurance), and (d) accelerated vesting of all equity-based compensation.

Pursuant to the Atlas Employment Agreements, in the event of death, Messrs. E. Cohen and J. Cohen are each 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 Agreements, in the event of disability, Messrs. E. Cohen and J. Cohen are each 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.

Under the Atlas Employment Agreements, in the event of death or disability, Messrs. Herz and Schumacher are each entitled to receive (a) a pro rata cash bonus for the year of termination, (b) 12 months of continued health insurance for the executive and his dependents, and (c) accelerated vesting of all equity-based compensation.

In addition, the Atlas Employment Agreements each contain certain restrictive covenants, including (a) in the case of Messrs. E. Cohen and J. 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, (b) in the case of Mr. Herz an 18 month post termination noncompetition covenant and a 24 month post termination nonsolicitation covenant if the executive is terminated without cause or resigns without good reason, and (c) in the case of Mr. Schumacher, an 18 month post termination noncompetition covenant and 24 month post termination nonsolicitation covenant, 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 each of the Atlas Employment Agreements, 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.

Long-Term Incentive Plans

Atlas Energy Group’s 2015 Long-Term Incentive Plan

In February 2015, Atlas Energy Group adopted the Atlas Energy Group, LLC 2015 Long-Term Incentive Plan, which we refer to as the “2015 LTIP.” The following is a brief description of the principal features of the 2015 LTIP.

Purpose

The 2015 LTIP is intended to promote Atlas Energy Group’s interests by providing to Atlas Energy Group’s officers, employees, and directors, employees of its affiliates, consultants, and joint venture partners who perform services for Atlas Energy Group incentive awards for superior performance that are based on its common units.  The 2015 LTIP is intended to enhance Atlas Energy Group’s ability to attract and retain the services of individuals who are essential for its growth and profitability, and to encourage them to devote their best efforts to Atlas Energy Group’s business and advancing its interests.

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Administration

Grants made under the 2015 LTIP are determined by Atlas Energy Group’s Board of Directors or a committee appointed by the Board of Directors to administer the 2015 LTIP.  Atlas Energy Group’s Board has appointed the Compensation Committee to administer the 2015 LTIP, which we refer to as the “Committee.”

Subject to the provisions of the 2015 LTIP, the Committee is authorized to administer and interpret the 2015 LTIP, to make factual determinations, and to adopt or amend its rules, regulations, agreements, and instruments for implementing the 2015 LTIP.  The Committee also has the full power and authority to determine the recipients of grants under the 2015 LTIP as well as the terms and provisions of restrictions relating to grants.

Subject to any applicable law, the Committee, in its sole discretion, may delegate any or all of its powers and duties under the 2015 LTIP, including the power to award grants under the 2015 LTIP, to Atlas Energy Group’s Chief Executive Officer, subject to such limitations as the Committee may impose, if any.  However, the Chief Executive Officer may not make awards to, or take any action with respect to any grant previously awarded to, himself or a person who is subject to Rule 16b-3 under the Exchange Act.

Eligibility

Persons eligible to receive grants under the 2015 LTIP are (a) officers and employees of us, Atlas Energy Group’s affiliates, consultants, or joint venture partners who perform services for Atlas Energy Group or an affiliate or in furtherance of Atlas Energy Group’s business (we refer to each such officer and employee as an “eligible employee”) and (b) Atlas Energy Group’s non-employee directors.

Unit Reserve; Adjustments

Awards in respect of up to 5.25 million of Atlas Energy Group’s common units may be issued under the 2015 LTIP.  This amount is subject to adjustment as provided in the 2015 LTIP for events such as distributions (in common units or other securities or property, including cash), unit splits (including reverse splits), recapitalizations, mergers, consolidations, reorganizations, reclassifications, and other extraordinary events affecting our outstanding common units such that an adjustment is necessary in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the 2015 LTIP.  Common units issued under the 2015 LTIP may consist of newly issued common units, common units acquired in the open market or from any of our affiliates, or any other person, or any combination of the foregoing.  If any award granted under the 2015 LTIP is forfeited or otherwise terminates or is cancelled or paid without the delivery of common units, then the common units covered by the award will (to the extent of the forfeiture, termination, or cancellation, as the case may be) again be available for grants of awards under the 2015 LTIP.  Common units surrendered in payment of the exercise price of an option, and withheld or surrendered for payment of taxes, will not be available for re-issuance under the 2015 LTIP.

Awards

Awards granted under the 2015 LTIP may consist of options to purchase common units, phantom units, and restricted units.  All grants are subject to such terms and conditions as the Committee deems appropriate, including vesting conditions.

Options.  An option is the right to purchase a common unit in the future at a predetermined price (which we refer to as the “exercise price”).  The exercise price of each option is determined by the Committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted.  The Committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method or methods by which payment of the exercise price may be made, which may include, without limitation, cash, check acceptable to Atlas Energy Group’s Board of Directors, a tender of common units having a fair market value equal to the exercise price, a “cashless” broker-assisted exercise, a recourse note in a form acceptable to Atlas Energy Group’s Board of Directors and that does not violate the Sarbanes-Oxley Act of 2002, a “net exercise” that permits Atlas Energy Group to withhold a number of common units that otherwise would be issued to the holder of the option pursuant to the exercise of the option having a fair market value equal to the exercise price, or any combination of the methods described above.

Phantom Units.  Phantom units represent rights to receive common units, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property.  Phantom units are subject to terms and conditions determined by the Committee, which may include vesting restrictions.  In addition, the Committee may grant distribution equivalent rights in connection with a grant of phantom units.  Distribution equivalent rights represent the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by us with respect to common units during

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the period that the underlying phantom unit is outstanding.  Distribution equivalents may (a) be paid currently or may be deferred and, if deferred, may accrue interest, (b) accrue as a cash obligation or may convert into additional phantom units for the holder of the underlying phantom units, (c) be payable based on the achievement of specific goals, and (d) be payable in cash or common units or in a combination of cash and common units, in each case as determined by the Committee.

Restricted Units.  Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates.  Prior to or upon the grant of an award of restricted units, the Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals, or both.  Unless otherwise determined by the Committee, a holder of restricted units will have certain rights of holders of Atlas Energy Group’s common units in general, including the right to vote the restricted units.  During the period during which the restricted units are subject to vesting restrictions, however, the holder will not be permitted to sell, assign, transfer, pledge, or otherwise encumber the restricted units.  As determined by the Committee, cash dividends on restricted units may be automatically deferred or reinvested in additional restricted units and held subject to the vesting of the underlying restricted units, and dividends payable in common units may be paid in the form of restricted units of the same class as the restricted units with respect to which the dividend is paid and may be subject to vesting of the underlying restricted units.

 

Change in Control

 

No Assignment

Except as otherwise determined by the Committee, no award granted under the 2015 LTIP is assignable or transferable except by will or the laws of descent and distribution.  When a participant dies, the personal representative or other person entitled to succeed to the rights of the participant may exercise the participant’s rights under his or her awards.

Withholding

All awards granted under the 2015 LTIP are subject to applicable federal (including FICA), state, and local tax withholding requirements.  If we so permit, common units may be withheld to satisfy tax withholding obligations with respect to awards paid in common units, at the time such awards become subject to employment taxes and tax withholding, as applicable, up to an amount that does not exceed the minimum required withholding for federal (including FICA), state, and local tax liabilities.  Atlas Energy Group may require forfeiture of any award for which the participant does not timely pay the applicable withholding taxes.

Amendment and Termination

Subject to the limitations described below, the Committee may amend, alter, suspend, discontinue, or terminate the 2015 LTIP at any time without the consent of participants, except that the Committee may not amend the 2015 LTIP without approval of the unitholders if such approval is required in order to comply with applicable stock exchange requirements.  Atlas Energy Group may waive any conditions or rights under, amend any terms of, or alter any award previously granted under the 2015 LTIP; however, no change to any award previously granted under the 2015 LTIP may materially reduce the benefit to a participant, unless the participant has consented or such change is explicitly allowed in the 2015 LTIP or the applicable award agreements.  The Committee may not reprice options, nor may the 2015 LTIP be amended to permit option repricing, unless the unitholders approve such repricing or amendment.

Plan Term

The 2015 LTIP will continue until the date terminated by Atlas Energy Group’s Board of Directors or the date upon which common units are no longer available for the grant of awards, whichever occurs first.

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2017 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

 

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2017 NONQUALIFIED DEFERRED COMPENSATION

 

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Effective July 1, 2011, Atlas Energy established the Excess 401(k) Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees.  The Excess 401(k) Plan provides Messrs. E. and J. Cohen, the plan’s current participants, with the opportunity to defer, annually, the receipt of a portion of their compensation, and to permit them to designate investment indices for the purpose of crediting earnings and losses on any amounts deferred under the Excess 401(k) Plan.  Messrs. E. and J. Cohen may defer up to 10% of their 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 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 Messrs. E. and J. Cohen do not have any rights to any specific asset of the Company.  

The Excess 401(k) Plan has the following additional provisions:

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The table above reflects salary and matching contribution costs allocated to us.

 

DIRECTOR COMPENSATION

 

The following table sets forth compensation for 2017 for our directors.

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Director Compensation

Any member of the board of directors of our general partner who is also an employee of our general partner, Atlas Energy Group or their affiliates does not receive additional compensation for serving on the board of directors of our general partner.

Effective July 25, 2017, (i) Messrs. Karis and Mesznik stepped down as directors, (ii) Messrs. Jones and Kupfer were appointed to serve as directors; and (iii) the annual compensation for our non-employee directors was reduced to a $75,000 cash retainer from a $100,000 cash retainer.

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.

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The following table sets forth the number and percentage of common units owned as of May 8, 2018 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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The following table provides information with respect to the beneficial ownership of the common units of ATLS as of May 8, 2018 by each of our general partner’s directors and named executive officers and all of our general partner’s directors and executive officers as a group.

 

 

 

 

 

 

 

* Less than 1%

 

Related Party Agreements

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 are provided by our employees and affiliates. AGP GP receives an annual management fee in connection with managing us equivalent to 1% of capital contributions per annum. During the year ended December 31, 2017, we paid $2.3 million for this management fee. ATLS charges us direct costs, such as salary and wages, and allocates 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 reimburse 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 AGP GP.

Registration Rights in Partnership Agreement

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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, ATLS or any of their 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, ATLS or any of their 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. No registration rights will be given to the dealer manager.

 

Review, Approval or Ratification of Transactions with Related Parties

Because the Partnership does not employ any persons, the Partnership relies on the code of business conduct and ethics adopted by ATLS that applies to the executive officers, employees and other persons performing services for ATLS and its affiliates generally. You may obtain a copy of this code of business conduct and ethics without charge at www.atlasenergy.com.

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.

 

Director Independence

 

The board of directors of our general partner consists of seven directors. The board of directors has determined that Messrs. Bagnell, Jones and Kupfer 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, 2017 and 2016, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows (in thousands):

 

 

Audit Committee Pre-Approval Policies and Procedures

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

 

PART IV

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SIGNATURES

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 May 8, 2018.

 

 

 

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