ATLS declared a cash distribution of $0.27 per limited partner unit for the third quarter 2012. The third quarter 2012 distribution represents a $0.02 per unit increase, or 8%, over the second quarter 2012 and a 13% increase over the prior year quarter. The third quarter 2012 ATLS distribution is payable November 19, 2012 to holders of record as of November 5, 2012.

Atlas Energy’s E&P subsidiary, Atlas Resource Partners, L.P. (NYSE: 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.

In September 2012, ARP acquired the following for approximately $40 million from Equal Energy, Ltd. (NYSE: EQU), its joint venture partner in the Mississippi Lime formation in Oklahoma: the remaining 50% interest in Equal’s approximately 8,500 net undeveloped acres in the core of the oil & liquids rich Mississippi Lime play in northwestern Oklahoma, approximately 8 Mmcfe/d of net production in the Mississippi Lime region and substantial salt water disposal infrastructure. ARP now controls approximately 20,000 net acres in the play and plans to add a second rig by the end of 2012.

Atlas Pipeline Partners, L.P. (NYSE: APL), Atlas Energy’s midstream subsidiary, announced record processing volumes at each of its systems, reaching a total of 769.0 Mmcfd and natural gas liquids (NGL) production of 56,363 bpd for the third quarter 2012.

On October 25, 2012, ARP increased its quarterly cash distribution to $0.43 per unit for the third quarter 2012, which is payable November 14, 2012 to holders of record as of November 5, 2012. ATLS earned approximately $9.4 million of cash distributions based upon ARP’s recently announced third quarter 2012 distribution.

On October 24, 2012, APL declared an increased distribution for the third quarter of 2012 of $0.57 per common limited partner unit to holders of record on November 7, 2012, which will be paid on November 14, 2012. ATLS earned approximately $5.7 million of cash distributions based upon APL’s recently announced third quarter 2012 distribution.

On a GAAP basis, net loss attributable to limited partners was $11.4 million for the third quarter 2012 compared to net income of $7.1 million for the prior year comparable period. The loss for the third quarter 2012 is due primarily to Atlas Energy’s $4.3 million of non-cash stock compensation expense, and its ownership interest in ARP, which recognized a $7.7 million estimated expense regarding its reconciliation process with Chevron Corporation (“Chevron”) over certain liabilities assumed in the February 2011 transaction, as well as APL’s $18.9 million non-cash mark-to-market loss on derivative contracts. The net income in the prior year quarter was primarily attributable to ATLS’ ownership interest in APL’s $23.8 million non-cash mark-to-market gain on derivative contracts and ARP’s recognition of $6.2 million of fees recognized related to the transition service agreement with Chevron. Please see the reconciliation of GAAP net income (loss) to Adjusted EBITDA and distributable cash flow in the financial tables of this release for further information.

ARP’s 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 ARP’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.

During the third quarter 2012, APL operated near or at nameplate capacity on all of its gathering and processing systems in the Mid Continent. APL processed an average of approximately 769 Mmcfd of natural gas in the third quarter 2012 amongst its WestOK, WestTX and Velma systems, 36% higher than the prior year comparable quarter’s volumes. APL again attained record high volumes over 56,300 bbl per day of natural gas liquids generated from APL’s three processing systems in Oklahoma and Texas.

Cash general and administrative expense, excluding amounts attributable to APL and ARP, was $1.4 million for the third quarter 2012, a $0.7 million decrease from the second quarter 2012 due to the timing of third party costs. Please refer to the consolidating combined statements of operations provided in the financial tables of this release.

Revenues:

Gas and oil production

Well construction and completion

Gathering and processing

Administration and oversight

Well services

Gain (loss) on mark-to-market derivatives⁽²⁾

Other, net

Total revenues

Costs and expenses:

Gas and oil production

Well construction and completion

Gathering and processing

Well services

General and administrative⁽¹⁾

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⁽¹⁾

Loss on early extinguishment of debt

Income (loss) from continuing operations

Loss from discontinued operations

Net income (loss)

(Income) loss attributable to non-controlling interests

Net income (loss) after non-controlling interests

Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition)⁽¹⁾

Net income (loss) attributable to common limited partners

Net income (loss) attributable to common limited partners per unit – basic:

Income (loss) from continuing operations attributable to common limited partners

Loss from discontinued operations attributable to common limited partners

Net income (loss) attributable to common limited partners

Net income (loss) attributable to common limited partners per unit – diluted:

Income (loss) from continuing operations attributable to common limited partners

Loss from discontinued operations attributable to common limited partners

Net income (loss) attributable to common limited partners

Weighted average common limited partner units outstanding:

Basic

Diluted

Net income (loss) attributable to common limited partners:

Income (loss) from continuing operations

Loss from discontinued operations

Net income (loss) attributable to common limited partners

In accordance with prevailing accounting literature, ATLS has adjusted its historical financial statements to present them combined with the historical financial results of the exploration and production business acquired from Chevron (the “Transferred Business”) for all periods prior to its acquisition date of February 17, 2011. However, since the results of operations of the Transferred Business prior to its acquisition date are not attributable to the common limited partners of ATLS, these amounts have been deducted to obtain net income (loss) attributable to common limited partners for the respective period. Also, the historical results of the Transferred Business prior to the acquisition date do not reflect general and administrative expenses and interest expense as ATLS was unable to identify and allocate such amounts to the Transferred Business for the respective periods.

Consists principally of hydrocarbon derivative gains / (losses) that relate to the operating activities of ATLS’s consolidated subsidiary, APL. The underlying hydrocarbon derivatives do not represent present or potential future obligations of ATLS.

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

Intangible assets, net

Investment in joint venture

Goodwill, net

Long-term derivative asset

Other assets, net

Current liabilities:

Current portion of long-term debt

Accounts payable

Liabilities associated with drilling contracts

Accrued producer liabilities

Current portion of derivative liability

Current portion of derivative payable to Drilling Partnerships

Accrued interest

Accrued well drilling and completion costs

Accrued liabilities

Total current liabilities

Long-term debt, less current portion

Long-term derivative liability

Long-term derivative payable to Drilling Partnerships

Asset retirement obligation and other

Commitments and contingencies

Partners’ Capital:

Common limited partners’ interests

Accumulated other comprehensive income

Non-controlling interests

Total partners’ capital

Net income (loss) attributable to common limited partners per unit - basic

Distributable cash flow per unit⁽²⁾⁽³⁾

Cash distributions paid per unit⁽⁴⁾

ATLAS RESOURCE:

Production volume:⁽⁵⁾⁽⁶⁾

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Average sales prices:⁽⁶⁾

Natural gas (per Mcf) ⁽⁷⁾

Oil (per Bbl)⁽⁸⁾

Natural gas liquids (per gallon)

Production costs:⁽⁶⁾⁽⁹⁾

Lease operating expenses per Mcfe⁽¹⁰⁾

Production taxes per Mcfe

Total production costs per Mcfe⁽¹⁰⁾

ATLAS PIPELINE:

Production volume:⁽⁶⁾

Gathered gas volume(Mcfd)

Processed gas volume (Mcfd)

Residue gas volume (Mcfd)

Processed NGL volume (Bpd)

Condensate volume (Bpd)

Average sales prices:⁽⁶⁾

Natural gas (per Mcf)

Condensate (per Bbl)

Natural gas liquids (per gallon)

In accordance with prevailing accounting literature, ATLS has adjusted its historical financial statements to present them combined with the historical financial results of the Transferred Business for all periods prior to its acquisition date of February 17, 2011. However, since the results of operations of the Transferred Business prior to its acquisition date are not attributable to the common limited partners of ATLS, these amounts have been deducted to obtain net income (loss) attributable to common limited partners for the respective period. Also, the historical results of the Transferred Business prior to the acquisition date do not reflect general and administrative expenses and interest expense as ATLS was unable to identify and allocate such amounts to the Transferred Business for the respective periods.

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 the weighted average common limited partner units outstanding of 51,335,000 and 51,257,000 for the three months ended September 30, 2012 and 2011, respectively, and 51,316,000 for the nine months ended September 30, 2012. For the nine months ended September 30, 2011, the weighted average common limited partner units outstanding of 51,242,000 utilized for the calculation is the weighted average common limited partner units outstanding for the period subsequent to February 17, 2011, the date of acquisition for the Transferred Business, which includes the 23.4 million common limited partner units issued as partial consideration for the acquisition.

Represents the cash distributions declared per limited partner unit for the respective period and paid by ATLS within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The nine months ended September 30, 2011 includes a cash distribution payment of $0.11 per limited partner unit for the 1^st quarter 2011, which reflected a prorated cash distribution for the period from February 17, 2011, the date of acquisition for the Transferred Business, to March 31, 2011.

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.

ARP’s average sales price for natural gas before the effects of financial hedging was $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 price for oil before the effects of financial hedging was $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.

Adjusted EBITDA and Distributable Cash Flow Summary:

Atlas Resource Cash Distributions Earned⁽²⁾:

Limited Partner Units

Class A Units (2%)

Incentive Distribution Rights

Total Atlas Resource Cash Distributions Earned⁽²⁾

per limited partner unit

Atlas Pipeline Cash Distributions Earned⁽²⁾:

Limited Partner Units

General Partner 2% Interest

Incentive Distribution Rights

Total Atlas Pipeline Cash Distributions Earned⁽²⁾

per limited partner unit

Total Cash Distributions Earned

E&P Operations Adjusted EBITDA prior to spinoff on March 5, 2012⁽³⁾

Cash general and administrative expenses⁽⁴⁾

Other, net

Adjusted EBITDA⁽⁵⁾

Cash interest expense⁽⁶⁾

Maintenance capital expenditures⁽³⁾

Distributable Cash Flow⁽⁵⁾

Distributions Paid⁽⁷⁾

per limited partner unit

Distribution coverage ratio

Reconciliation of non-GAAP measures to net income (loss)⁽⁵⁾:

Distributable cash flow

Distributable cash flow of Transferred Business as of and prior to February 17, 2011 (the date of acquisition)⁽¹⁾

E&P Operations EBITDA prior to spinoff on March 5, 2012⁽³⁾

E&P Operations EBITDA of Transferred Business as of and prior to February 17, 2011⁽¹⁾

Atlas Resource net loss attributable to ATLS common limited partners

Atlas Resource cash distributions earned by ATLS⁽²⁾

Atlas Pipeline net income attributable to ATLS common limited partners

Atlas Pipeline cash distributions earned by ATLS⁽²⁾

Non-recurring spinoff and acquisition costs

Amortization of deferred finance costs

Non-cash stock compensation expense

Maintenance capital expenditures⁽³⁾

Other non-cash adjustments

Income attributable to non-controlling interests

Net income (loss)

In accordance with prevailing accounting literature, ATLS has adjusted its historical financial statements to present them combined with the historical financial results of the Transferred Business for all periods prior to its acquisition date of February 17, 2011. However, since the results of operations of the Transferred Business prior to its acquisition date are not attributable to the common limited partners of ATLS, these amounts have been deducted to obtain net income (loss) attributable to common limited partners for the respective period. Also, the historical results of the Transferred Business prior to the acquisition date do not reflect general and administrative expenses and interest expense as ATLS was unable to identify and allocate such amounts to the Transferred Business for the respective periods.

Represents the cash distribution paid by ARP and APL within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

Represents the E&P Operations Adjusted EBITDA generated and maintenance capital expenditures incurred by ATLS on a stand-alone basis prior to the transfer of its E&P assets to ARP on March 5, 2012.

Excludes non-cash stock-compensation expense, non-recurring spinoff costs and non-recurring acquisition costs incurred, including amounts in connection with the acquisition of the Transferred Business.

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 ATLS believes that adjusted EBITDA and distributable cash flow provide additional information for evaluating ATLS’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 ATLS’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 distribution paid within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

Total debt

Less: Cash

Total net debt /(cash)

Partners’ capital

Total capitalization

Ratio of net debt to capitalization

Net of eliminated amounts.

Total debt

Less: Cash

Total net debt /(cash)

Partners’ capital

Total capitalization

Ratio of net debt to capitalization

Net of eliminated amounts.

Revenues:

Gas and oil production

Well construction and completion

Gathering and processing

Administration and oversight

Well services

Loss on mark-to-market derivatives

Other, net

Total revenues

Costs and expenses: