Brian J. Begley

Vice President - Investor Relations

Atlas Energy, L.P.

(877) 280-2857

(215) 405-2718 (fax)

On February 15, 2012, Atlas Energy’s board of directors approved the distribution to ATLS unitholders of approximately 19.6% of the common units of Atlas Resource Partners, L.P., a newly-formed E&P MLP which will hold substantially all of Atlas’ oil & gas assets and investment partnership business

5,240,000 Atlas Resource Partners’ units will be distributed proportionately on March 13, 2012 to ATLS unitholders of record as of February 28, 2012

Atlas Energy reports $21.5 million in Adjusted EBITDA for the fourth quarter 2011

Distributable cash flow was $19.0 million for the current quarter, or $0.37 per common unit

ATLS declared a cash distribution of $0.24 per limited partner unit for the fourth quarter 2011, at a distribution coverage ratio of 1.5x

Adjusted earnings before interest, income taxes, depreciation and amortization (“EBITDA”), a non-GAAP measure, of $21.5 million⁽¹⁾⁽²⁾ for the fourth quarter 2011 and $80.2 million for the full year 2011;

Distributable cash flow, a non-GAAP measure, of $19.0 million, or $0.37 per common unit⁽¹⁾⁽²⁾ for the fourth quarter 2011 and $69.9 million, or $1.44 per common unit, for the full year 2011;

ATLS declared a cash distribution of $0.24 per limited partner unit for the fourth quarter 2011, a $0.17 per unit increase, or over 200%, from the prior year comparable quarter. Coverage on the fourth quarter 2011 distribution was 1.5x; and,

On a GAAP basis, net loss was $9.6 million for the fourth quarter 2011 compared to $47.0 million for the prior year comparable period. The loss for each period was caused primarily by non-cash expenses, including asset impairment write downs on certain oil & gas properties and losses on mark-to-market derivatives. 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 fourth quarter 2011 was 35.2 million cubic feet equivalents per day (“mmcfed”), including net daily production of 31.5 mmcfed for the Appalachia segment.

As of December 31, 2011, ATLS had approximately 167.6 billion cubic feet equivalents in net proved natural gas & oil reserves, valued at a PV-10 amount of approximately $219.9 million, which does not include the value of ATLS’ commodity derivatives. The fair value of ATLS’ commodity derivatives at December 31, 2011 was approximately $29.9 million.

Investment partnership margin⁽³⁾ contributed $14.8 million to distributable cash flow for the fourth quarter 2011 compared with $10.4 million for the third quarter 2011. The increase compared with the sequential quarter was primarily due to the increase in funds raised and capital deployed for the direct investment programs.

In December 2011, ATLS completed fundraising for Atlas Resources Series 31 - 2011, raising a total of approximately $42.1 million in investor capital for future drilling activity, bringing total funds raised in 2011 to approximately $141.9 million. ATLS expects to raise approximately $250 million in investor funds in 2012.

Investment partnership margin is comprised of Well Construction and Completion margin, Well Services margin and Administration and Oversight Fee revenues.

On January 26, 2012, APL declared a cash distribution of $0.55 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011, an $0.18 per unit increase, or 48.6%, from the prior year comparable quarter. ATLS received $5.2 million of cash distributions from APL on February 14, 2012, the payment date for the APL fourth quarter 2011 distribution, a $2.7 million, or over 100%, increase from the prior year comparable quarter.

During the fourth quarter 2011, APL operated at or above nameplate capacity on all of its gathering and processing systems in the Mid Continent. APL processed approximately 601 mmcfd of natural gas in the fourth quarter 2011 amongst its WestOK, WestTX and Velma systems, a 23% increase over the prior year comparable quarter’s volumes. Record high volumes of approximately 58,600 bbl per day of gross natural gas liquids were generated from APL’s three processing systems in Oklahoma and Texas.

APL recently provided updated adjusted EBITDA guidance for 2012 in a range of $200 million to $225 million, and also issued 2013 adjusted EBITDA guidance in a range of $250 million to $300 million. The growth in expected cash flow through 2013 is a result of organic expansion projects underway at APL, to increase throughput capacity and efficiency on all three of APL’s operating systems.

At December 31, 2011, ATLS owned a 2.0% general partner interest, all of the incentive distribution rights, and a 10.7% common limited partner interest in APL. ATLS’ financial results are presented on a consolidated basis with those of APL. Non-controlling interests in APL are reflected as income (expense) in ATLS’ consolidated combined statements of operations and as a component of partners’ capital on its consolidated combined balance sheets. A consolidating combined statement of operations and balance sheet have also been provided in the financial tables to this release for the comparable periods presented.

Cash general and administrative expense, excluding amounts attributable to APL, was $9.8 million for the fourth quarter 2011. The current period is presented net of $3.3 million fees received, net of $0.2 million associated costs, from ATLS’ Transition Service Agreement with Chevron Corp., through which ATLS has provided accounting and other services. Please refer to the consolidating combined statements of operations provided in the financial tables of this release.

Cash interest expense, excluding amounts attributable to APL, was $0.2 million for the fourth quarter 2011. As of December 31, 2011, ATLS had no amounts outstanding under its revolving credit facility, which has a current borrowing base of $160 million, and had a cash position of $77.2 million.

ATLS entered into additional derivative contracts during the fourth quarter 2011 and the early part of the first quarter of 2012 for its natural gas and oil production. ATLS currently has approximately 35.8 billion cubic feet equivalents of its future production hedged through 2016. A summary of the ATLS’ current derivative positions as of February 27, 2012 is as follows:

Fixed Price Swaps

Production Period Ended December 31,

2012

2013

2014

2015

2016

Costless Collars

Production Period Ended December 31,

2012

2013

2014

2015

Fixed Price Swaps

Production Period Ended December 31,

2012

2013

2014

2015

2016

Costless Collars

Production Period Ended December 31,

2012

2013

2014

2015

“Mcf” represents thousand cubic feet; “bbl” represents barrel.

Includes an estimated positive basis differential and Btu (British thermal units) adjustment.

Hedge percentages based on Q4 2011 average production rates.

Revenues:

Gas and oil production

Well construction and completion

Gathering and processing

Administration and oversight

Well services

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⁾

Depreciation, depletion and amortization

Asset impairment

Total costs and expenses

Operating income (loss)

Gain (loss) on asset sales

Interest expense⁽¹⁾

Loss on early extinguishment of debt

Income (loss) from continuing operations

Income (loss) from discontinued operations

Net (loss) income

Loss (income) attributable to non-controlling interests

Net income (loss) after non-controlling interests

Loss (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

Income 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

Income 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

Income (loss) from discontinued operations

Net income (loss) attributable to common limited partners

In accordance with prevailing accounting literature, the Partnership 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 the Partnership, 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 the Partnership 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 the Partnership’s consolidated subsidiary, APL. The underlying hydrocarbon derivatives do not represent present or potential future obligations of the Partnership.

Current assets:

Cash and cash equivalents

Accounts receivable

Current portion of derivative asset

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

Advances from affiliates

Accrued liabilities

Total current liabilities

Long-term debt, less current portion

Long-term derivative liability

Long-term derivative payable to Drilling Partnerships

Other long-term liabilities

Commitments and contingencies

Partners’ Capital:

Common limited partners’ interests

Accumulated other comprehensive income

Non-controlling interests

Total partners’ capital

In accordance with prevailing accounting literature, the Partnership 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.

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

Distributable cash flow per unit⁽²⁾⁽³⁾

Cash distributions paid per unit⁽⁴⁾

Production revenues (in thousands):

Natural gas

Oil

Natural gas liquids

Total production revenues

Production volume:⁽⁵⁾⁽⁶⁾

Appalachia⁽⁷⁾:

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:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Average sales prices:⁽⁶⁾

Natural gas (per Mcf) ⁽⁸⁾

Oil (per Bbl)⁽⁹⁾

Natural gas liquids (per Bbl) total realized price

Production costs:^(6)(10)

Lease operating expenses per Mcfe

Production taxes per Mcfe

Total production costs per Mcfe

Depletion per Mcfe⁽⁶⁾

In accordance with prevailing accounting literature, the Partnership 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.

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 for the 4^th quarter 2011 and the year ended December 31, 2011 of 51,271,000 and 51,253,000, respectively. For the year ended December 31, 2011, the weighted average common limited partner units outstanding 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 the Partnership within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

Production quantities consist of the sum of (i) the Partnership’s proportionate share of production from wells in which it has a direct interest, based on the Partnership’s proportionate net revenue interest in such wells, and (ii) the Partnership’s proportionate share of production from wells owned by the investment partnerships in which the Partnership 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 the Partnership’s production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

The Partnership’s average sales price for natural gas before the effects of financial hedging was $3.68 per Mcf and $3.85 per Mcf for the three months ended December 31, 2011 and 2010, respectively, and $4.53 per Mcf and $4.60 per Mcf for the years ended December 31, 2011 and 2010, 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 $3.81 per Mcf ($3.29 per Mcf before the effects of financial hedging) and $5.76 per Mcf ($2.76 per Mcf before the effects of financial hedging) for the three months ended December 31, 2011 and 2010, respectively, and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) and $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging) for the years ended December 31, 2011 and 2010, respectively.

The Partnership’s average sales price for oil before the effects of financial hedging was $86.76 per barrel and $79.51 per barrel for the three months ended December 31, 2011 and 2010, respectively, and $89.07 per barrel and $71.37 per barrel for the year ended December 31, 2011 and 2010, 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 the Partnership’s proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within the Partnership’s investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $0.98 per Mcfe ($1.06 per Mcfe for total production costs) and $0.89 per Mcfe ($0.94 per Mcfe for total production costs) for the three months ended December 31, 2011 and 2010, respectively, and $0.75 per Mcfe ($0.85 per Mcfe for total production costs) and $0.86 per Mcfe ($0.90 per Mcfe for total production costs) for the years ended December 31, 2011 and 2010, respectively.

Total debt

Less: Cash

Total net debt/(cash)

Partners’ capital

Total capitalization

Ratio of net debt to capitalization

In accordance with prevailing accounting literature, the Partnership 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.

Net of eliminated amounts.

Atlas Energy

Maintenance capital expenditures⁽²⁾

Expansion capital expenditures

Total

Atlas Pipeline

Maintenance capital expenditures

Expansion capital expenditures

Total

Consolidated Combined

Maintenance capital expenditures

Expansion capital expenditures

Total

In accordance with prevailing accounting literature, the Partnership 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.

Prior to the Partnership’s acquisition of the Transferred Business on February 17, 2011, the Partnership had no maintenance capital requirements with regard to its oil and gas properties.

Atlas Energy Stand-Alone 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