UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 20182019

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.

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

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

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

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

Indicate by check mark whether the registrant 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 November 16, 201813, 2019 was 23,300,410.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS GROWTH PARTNERS, L.P.

INDEX TO ANNUALQUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

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” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.2018.  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.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in thousands, except unitunits and warrants data)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATEDCONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 Southsouth Texas. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.

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 its 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

At September 30, 2019, we had 23,300,410 common limited partner units issued and outstanding.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission (the “SEC”) regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The condensed consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.2018.

Principles of Consolidation

Our condensed 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 condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.

Use of Estimates

The preparation of our condensed 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 condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals and depletion of gas and oil properties, and fair value of derivative instruments.properties. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results weremay be recorded using estimated volumes and contract market prices. Actual results may differ from those estimates.

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.

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 condensed consolidated statement of operations. Upon the sale of an individual well, we credit the proceeds to accumulated depreciation and depletion within our condensed 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 condensed 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.

Derivative Instruments

We enterentered into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the condensed consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments arewere recognized in the current periodcurrently within gain (loss) on mark-to-market derivatives in our condensed consolidated statements of operations.

We useused a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments. We managemanaged and reportreported derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments arewere 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.

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

As ofFor the three and nine months ended September 30, 2018,2019, we haddid not have any commodity derivatives for 17,900 barrels at an average fixed price of $52.66 which mature throughout the remaining three months of 2018.  The fair value of our commodity derivatives resulted in a liability of $0.4 million as of September 30, 2018.outstanding.

Segment Reporting

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

Revenue Recognition

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

Oil, Natural Gas, and NGL Revenues

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

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

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

Transaction Price Allocated to Remaining Performance Obligations

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

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

Contract Balances

Under our sales contracts, customers are invoiced once performance obligations have been satisfied, at which point our right to payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $0.9$0.3 million and $0.6 million at September 30, 20182019 and December 31, 2017,2018, respectively.

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 following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (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.

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 holderslimited partners per unit with those used to compute diluted net income (loss) attributable to common unit holderslimited partners per unit (in thousands):

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases.issued Update 2016-02, “Leases (Topic 842)”. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019We have evaluated our existing arrangements and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginningservice contracts and determined that none of the earliest period presented. In January 2018,agreements meet the FASB issued additional amendmentsdefinition of a lease as defined in Topic 842. As such, there was no impact to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for under current leasing guidance. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the dateour consolidated results of adoption. We do not currently account for any land easements under the current leasing guidanceoperations, financial position and plan to utilize this practical expedient in conjunction with thefinancial disclosures upon adoption of the updatednew accounting guidance related to leases. We are currently in the process of determining the impact that the updated accounting guidance will havestandard on our condensed consolidated financial statements and will continue to monitor relevant industry guidance regarding the implementation of the standard.January 1, 2019.

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

During the nine months ended September 30, 2018, we deployed $6.8 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line in May 2018. During the nine months ended September 30, 20182019 and 2017,2018, we did not have any material non-cash investing activity capital expenditures.

During the nine months ended September 30, 2019, we sold property, plant and equipment with net book value of $0.4 million.  

NOTE 4 – 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 Energy, LLC (“Titan”). Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During both of the three months ended September 30, 20182019 and 2017,2018, we paid a management fee of $0.6 million to our general partner;partner and during both of the nine months ended September 30, 20182019 and 20172018 we paid a management fee of $1.7 million to our general partner. 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 condensed consolidated statements of operations. As of September 30, 20182019 and December 31, 2017,2018, we had no payables to ATLS, of zero and $0.6 million, respectively, related to the management fee, direct costs and allocated indirect costs, which were recorded in advances from affiliates in the condensed consolidated balance sheets.

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 September 30, 20182019 and December 31, 2017,2018, we had receivables from Titan of $0.5 million and payables to Titan of $0.2 million and $0.1 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for reimbursement of operating activities and capital expenditures, which were recorded in advances to/from affiliates in the condensed consolidated balance sheets.

NOTE 5 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of September 30, 2018,2019, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits to such executives. The agreements provide for severance payments under certain circumstances.

As of September 30, 2018,2019, 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 in the ordinary course of business. Our management and our subsidiaries believebelieves 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 September 30, 2018 or2019 and December 31, 2017.2018.

NOTE 6 – CORRECTION OF AN IMMATERIAL ERROR

In connection with the preparation of our condensed consolidated financial statements for the three and nine months ended September 30, 2019, we identified an error in the amounts settled from our purchaser for the production periods June 2018 to July 2019.  The purchaser is issuing revised settlement statements for this period, which will result in a reduction of revenues of $0.8 million and depletion expense of $0.3 million for a net increase in our net loss of $0.5 million.  The adjustment changed our advances to (from) affiliates from a receivable of $0.5 million to a payable of $0.2 million for the period ended September 30, 2019. In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, we evaluated the errors and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to our condensed consolidated financial statements for any prior annual or interim period. Therefore, amendments of previously filed reports are not required. If the settlement statement correction had been recognized in the respective production months of 2018, the revenue reported for 2018 would have been decreased $0.4 million from $8.2 million to $7.8 million, net loss would have increased $0.4 million from $44.1 million to $44.5 million and total assets would have decreased $0.4 million from $28.9 million to $28.5 million.  If the settlement statement correction had been recognized in the respective production months, for the nine months ended September 30, 2019, revenue would have been increased by $0.4 million from $4.6 million to $5.0 million, net loss would have decreased $0.4 million from $3.3 million to $2.9 million.  For the three months ended September 30, 2019, revenue would have been increased by $0.8 million from $0.8 million to $1.6 million, net loss would have decreased $0.4 million from $1.5 million to $1.1 million.  The total assets as of September 30, 2019 would have decreased $0.2 million from $25.2 million to $25 million.

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 Southsouth Texas. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.

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.south Texas.  While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses.  AsAt September 30, 2018,2019, we have $2.5had $3.2 million of cash on our balance sheet and no long-term debt.

During the nine months ended September 30, 2018, we deployed $6.8 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line during May 2018. The well is expected to significantly increasehas increased our production and provide substantialprovided additional cash flow.flow to our business. With this additional well, 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 Shale wells or take on other strategic initiatives and transactions should favorable conditions arise.

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

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

ThroughoutSince 2017, and 2018, the natural gas, oil and natural gas liquids commodity price markets have been marked by volatility. While we anticipate high levels of exploration and production activities over the long-term in the 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 our acreage position in the Eagle Ford Shale in Southsouth Texas have improved substantially over the last twelve months,past two years, 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.

RESULTS OF OPERATIONS

Gas and Oil Production

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

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:

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:

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