Atlas Resource Partners (ARP) reached record average net production of 96.3 Mmcfed for the third quarter 2012, a 54% increase from the sequential quarter and over a 175% increase from the prior year quarter

ARP acquired the remaining interest in its Mississippi Lime (OK) joint venture from Equal Energy, Ltd. during the quarter, increasing ARP’s position to approximately 20,000 net acres in the oil and liquids rich play

ARP increased its quarterly distribution to $0.43 per limited partner unit for the third quarter 2012, an 8% increase from the second quarter 2012 distribution

ARP closed its acquisition of Titan Operating, LLC during the quarter, its second acquisition in the Barnett Shale (TX) this year

Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), a non-GAAP measure, of $22.7 million⁽¹⁾, or $0.56 per common unit, for the third quarter 2012, an increase of 37% from the second quarter 2012;

Distributable cash flow, a non-GAAP measure, of $18.5 million⁽¹⁾, or $0.45 per common unit, for the third quarter 2012, an increase of approximately 30% from the second quarter 2012;

ARP declared a cash distribution of $0.43 per limited partner unit for the third quarter 2012, at a coverage ratio of approximately 1.1x; and,

On a GAAP basis, net loss was $10.1 million for the third quarter 2012. The loss for the third quarter 2012 included the recognition of a $7.7 million estimated expense regarding the Partnership’s reconciliation process with Chevron Corporation (“Chevron”) over certain liabilities assumed in the February 2011 transaction with Chevron. Please see the reconciliation of GAAP net loss to adjusted EBITDA in the financial tables of this release for further information.

Average net daily production for the third quarter 2012 was 96.3 Mmcfed, an increase of approximately 33.7 Mmcfed, or 54%, compared with the second quarter 2012. The increase was primarily due to the acquisition of Titan Operating, LLC (“Titan”) in the Barnett Shale in July 2012, a full quarter’s volume from the Partnership’s initial acquisition in the Barnett Shale in April 2012, and additional legacy Marcellus Shale wells connected in southwestern Pennsylvania during the quarter.

During the third quarter 2012, ARP continued drilling on initial locations in the oil & natural gas liquids (NGL) rich Mississippi Lime basin in northwestern Oklahoma. Two wells in ARP’s recently expanded Mississippi Lime position have been completed and are currently producing into a sales line, and one well is awaiting completion. ARP also drilled six wells this quarter in Hood County, Texas in the wet gas window of its Barnett Shale position. An additional two wells in the wet gas region of Tarrant County, Texas were also turned into line.

ARP expanded its natural gas and oil hedge positions during the third quarter 2012. ARP currently has approximately 86.8 billion cubic feet equivalents of its future production hedged through 2017. A summary of ARP’s current derivative positions as of October 31, 2012 is provided in the financial tables of this release.

Cash general and administrative expense was $9.0 million for the third quarter 2012, a $4.2 million increase from $4.8 million for the prior year third quarter and an increase of $0.2 million from the second quarter 2012. The increase from prior year third quarter was principally due to approximately $6.2 million of fees recognized in the prior year related to the transition service agreement with Chevron, which expired in the fourth quarter 2011.

Cash interest expense was $0.9 million for the third quarter 2012. As of September 30, 2012, ARP had $222.0 million outstanding under its revolving credit facility, which has a current borrowing base of $310 million, and a cash position of $24.3 million.

Revenues:

Gas and oil production

Well construction and completion

Gathering and processing

Administration and oversight

Well services

Other, net

Total revenues

Costs and expenses:

Gas and oil production

Well construction and completion

Gathering and processing

Well services

General and administrative

Estimated expense on Chevron transaction

Depreciation, depletion and amortization

Total costs and expenses

Operating income (loss)

Gain (loss) on asset sales and disposal

Interest expense

Net income (loss)

Preferred limited partner dividends

Net income (loss) attributable to owner’s interest, common limited partners and the general partner

Allocation of net income (loss):

Portion applicable to owner’s interest (period prior to the transfer of assets on March 5, 2012)

Portion applicable to common limited partners and general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)

Net income (loss) attributable to owner’s interest, common limited partners and the general partner

Allocation of net loss attributable to common limited partners and the general partner:

General partner’s interest

Common limited partners’ interest

Net loss attributable to common limited partners and the general partner

Net loss attributable to common limited partners per unit:

Basic

Diluted

Weighted average common limited partner units outstanding:

Basic

Diluted

Current assets:

Cash and cash equivalents

Accounts receivable

Current portion of derivative asset

Subscriptions receivable

Prepaid expenses and other

Total current assets

Property, plant and equipment, net

Goodwill and intangible assets, net

Long-term derivative asset

Other assets, net

Current liabilities:

Accounts payable

Liabilities associated with drilling contracts

Current portion of derivative liability

Current portion of derivative payable to Drilling Partnerships

Accrued well drilling and completion costs

Accrued liabilities

Total current liabilities

Long-term debt

Long-term derivative liability

Long-term derivative payable to Drilling Partnerships

Asset retirement obligations and other

Commitments and contingencies

Partners’ Capital/Equity:

General partner’s interest

Preferred limited partners’ interests

Common limited partners’ interests

Equity

Accumulated other comprehensive income

Total partners’ capital/equity

Net loss attributable to common limited partners per unit - basic

Distributable cash flow per unit⁽¹⁾⁽²⁾

Cash distributions paid per unit⁽³⁾

Production revenues (in thousands):

Natural gas

Oil

Natural gas liquids

Total production revenues

Production volume:⁽⁴⁾⁽⁵⁾

Appalachia: ⁽⁶⁾

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Barnett: ⁽⁷⁾

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Mississippi Lime⁽⁸⁾:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

New Albany/Antrim:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Niobrara:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Total⁽⁷⁾⁽⁸⁾:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Average sales prices:⁽⁵⁾

Natural gas (per Mcf) ⁽⁹⁾

Oil (per Bbl)⁽¹⁰⁾

Natural gas liquids (per Bbl)

Production costs:^(5)(11)

Lease operating expenses per Mcfe⁽¹²⁾

Production taxes per Mcfe

Total production costs per Mcfe⁽¹²⁾

Depletion per Mcfe⁽⁵⁾

A reconciliation from net income to distributable cash flow is provided in the financial tables of this release.

Calculation consists of distributable cash flow divided by 40,726,017 and 35,466,019 limited partner and Class A general partner units for the three and nine months ended September 30, 2012, respectively, which represent the weighted average limited partner and Class A general partner units which were paid cash distributions for the respective period subsequent to March 5, 2012, the date of the transfer of assets. Prior to March 5, 2012, no limited partner or Class A general partner units were outstanding.

Represents the cash distributions declared per limited partner unit for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The cash distribution declared of $0.12 per limited partner unit for the 1^st quarter 2012 reflects a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.

Production quantities consist of the sum of (i) ARP’s proportionate share of production from wells in which it has a direct interest, based on ARP’s proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the investment partnerships in which ARP has an interest, based on its equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

“Mcf” and “Mcfd” represent thousand cubic feet and thousand cubic feet per day; “Mcfe” and “Mcfed” represent thousand cubic feet equivalents and thousand cubic feet equivalents per day, and “Bbl” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of six Mcf’s to one barrel.

Appalachia consists of ARP’s production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

Volumetric production per day for Barnett for the three months ended September 30, 2012 includes production per day associated with the Titan operational assets for the 68-day period from July 25, 2012, the date of acquisition, through September 30, 2012. Total Barnett production per day for the nine months ended September 30, 2012 represents Barnett volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

Volumetric production per day for Mississippi Lime for the three months ended September 30, 2012 includes production per day associated with the acquisition of the remaining 50% interest in Equal’s operational assets for the 7-day period from September 24, 2012, the date of acquisition, through September 30, 2012. Total Mississippi Lime production per day for the nine months ended September 30, 2012 represents volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.

ARP’s average sales prices for natural gas before the effects of financial hedging were $2.46 per Mcf and $4.90 per Mcf for the three months ended September 30, 2012 and 2011, respectively, and $2.60 per Mcf and $4.69 per Mcf for the nine months ended September 30, 2012 and 2011, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships. Including the effects of subordination, average natural gas sales prices were $2.46 per Mcf ($1.91 per Mcf before the effects of financial hedging) and $4.33 per Mcf ($4.13 per Mcf before the effects of financial hedging) for the three months ended September 30, 2012 and 2011, respectively, and $2.88 per Mcf ($2.07 per Mcf before the effects of financial hedging) and $4.44 per Mcf ($3.89 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2012 and 2011, respectively.

ARP’s average sales prices for oil before the effects of financial hedging were $84.30 per barrel and $81.85 per barrel for the three months ended September 30, 2012 and 2011, respectively, and $93.38 per barrel and $89.79 per barrel for the nine months ended September 30, 2012 and 2011, respectively.

Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead. These amounts exclude the effects of ARP’s proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within ARP’s investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $0.45 per Mcfe ($0.58 per Mcfe for total production costs) and $0.73 per Mcfe ($0.84 per Mcfe for total production costs) for the three months ended September 30, 2012 and 2011, respectively, and $0.51 per Mcfe ($0.63 per Mcfe for total production costs) and $0.71 per Mcfe ($0.82 per Mcfe for total production costs) for the nine months ended September 30, 2012 and 2011, respectively.

The amount for the nine months ended September 30, 2011 was adjusted to reflect current period classification resulting from the misclassification of lease operating production expenses and transportation production expenses.

Total debt

Less: Cash

Total net debt/(cash)

Partners’ capital/equity

Total capitalization

Ratio of net debt to capitalization

Maintenance capital expenditures

Expansion capital expenditures

Total

Adjusted EBITDA and Distributable Cash Flow Summary:

Gas and oil production margin

Well construction and completion margin

Administration and oversight margin

Well services margin

Gathering

Gross Margin

Estimated Gross Margin for Acquisitions⁽¹⁾

Adjusted Gross Margin

Cash general and administrative expenses

Other, net

Adjusted EBITDA⁽²⁾

Cash interest expense⁽³⁾

Maintenance capital expenditures

Distributable Cash Flow⁽²⁾

Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)⁽⁵⁾

Distributable Cash Flow attributable to limited partners⁽²⁾

Distributions Paid⁽⁴⁾

per limited partner unit

Reconciliation of non-GAAP measures to net income (loss)⁽⁴⁾:

Distributable cash flow attributable to limited partners and the general partner

Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)⁽⁵⁾

Estimated gross margin for acquisitions⁽¹⁾

Acquisition and related costs

Depreciation, depletion and amortization

Amortization of deferred finance costs

Non-cash stock compensation expense

Maintenance capital expenditures

Gain (loss) on asset disposal

Estimated expense on Chevron transaction

Adjustment to reflect cash impact of derivatives

Premiums paid on swaption derivative contracts (Carrizo Barnett acquisition)

Other non-cash adjustments⁽⁶⁾

Net income (loss)

Includes estimated gross margin generated for the month of April 2012 for Carrizo, estimated gross margin for the majority of July for Titan, and the majority of the 3^rd quarter 2012 for Equal. ARP consummated the acquisition of the Barnett assets from Carrizo on April 30, 2012, with ARP receiving all of the net cash generated by the assets from January 1, 2012 through April 30, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. In addition, ARP consummated the acquisition of the Barnett assets from Titan on July 25, 2012, with ARP receiving all of the net cash generated by the assets from July 1, 2012 through July 25, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. Also, ARP consummated the acquisition of the remainder of the Equal assets on September 24, 2012, with ARP receiving all of the net cash generated by the assets from July 1, 2012 through September 24, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. As such, ARP has included the portion of cash received attributable to the month of April 2012 for Carrizo, the 25 days in July for Titan, and the 85 days for the 3^rd quarter 2012 for Equal as it paid or will pay a full quarter’s cash distribution for the respective quarterly period.

Adjusted EBITDA and distributable cash flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of ARP believes that adjusted EBITDA and distributable cash flow provide additional information for evaluating ARP’s performance, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. Adjusted EBITDA is also a financial measurement that, with certain negotiated adjustments, is utilized within ARP’s financial covenants under its credit facility. Adjusted EBITDA and distributable cash flow are not measures of financial performance under GAAP and, accordingly, should not be considered as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.

Excludes non-cash amortization of deferred financing costs.

Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The nine months ended September 30, 2012 includes a cash distribution payment of $0.12 per limited partner unit for the 1^st quarter 2012, which reflected a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.

In accordance with prevailing accounting literature, ARP has adjusted its historical financial statements to present them combined with the historical financial results of the spin-off assets for all periods prior to its spin-off date of March 5, 2012.

Includes $0.2 million and $0.5 million of Pennsylvania impact fee for the three and nine months ended September 30, 2011, respectively. The fee was instituted by the state of Pennsylvania subsequent to December 31, 2011 for the full year 2011. ARP allocated the fee pro rata to each of the quarterly periods for 2011.

Production Period Ended December 31,

2012^(c)

2013

2014

2015

2016

2017

Production Period Ended December 31,

2012^(c)

2013

2014

2015

Production Period Ended December 31,

2012^(c)

2013

Production Period Ended December 31,

2012^(c)

2013

2014

2015