Atlas Resource Partners (ARP) acquired the exploration and production business from Atlas Energy in March 2012

Acquired 277 Bcfe of proved reserves in the Barnett Shale for $190 million, expanding its net reserves over 160% to approximately 450 Bcfe

Announced a joint venture with Equal Energy to develop 14,500 acres in the core of the Mississippi Lime play in Oklahoma, increasing ARP’s oil & liquids exposure

Average net daily production increased to 39.4 Mmcfe/d, approximately 12% higher than the fourth quarter 2011

Borrowing base increased to $250 million in conjunction with the Barnett Shale acquisition; $17 million drawn at period end

In March 2012, ARP acquired the exploration and production business from Atlas Energy, L.P. (NYSE: ATLS), the owner of ARP’s general partner and an approximate 64% limited partner interest in ARP.

Adjusted earnings before interest, income taxes, depreciation and amortization (“EBITDA”), a non-GAAP measure, of $13.5 million⁽¹⁾, or $0.50 per common unit, for the full first quarter 2012;

Distributable cash flow, a non-GAAP measure, of $3.8 million, or $0.14 per common unit⁽¹⁾ for the period from March 5, 2012, the effective date of the spinoff from ATLS, to March 31, 2012;

ARP declared a pro-rated cash distribution of $0.12 per limited partner unit for the partial first quarter 2012. Coverage on the first quarter 2012 distribution was 1.2x; and,

On a GAAP basis, net loss was $6.2 million for the first quarter 2012. The loss for the first quarter 2012 included a non-cash asset impairment of approximately $7 million related to a legacy contract initiated prior to the acquisition from Chevron Corp., and subject to immediate writeoff. 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 first quarter 2012 was 39.4 million cubic feet equivalents per day (“Mmcfed”), an increase of approximately 4.2 Mmcfed, or 12%, compared with the fourth quarter 2011. The increase was primarily due to additional Marcellus Shale wells connected in southwestern Pennsylvania during the quarter.

Drilled 60 net wells within ARP’s investment partnerships during the first quarter 2012 compared with 20 net wells for the prior year comparable period, a 300% increase. At March 31, 2012, ARP had $28.0 million of funds raised from its investment partnerships that had not been applied to the completion of wells at period end, and thus at quarter end had not yet been recognized as well construction and completion revenue on its consolidated combined statements of operations. ARP expects to recognize this amount as revenue during the remainder of 2012.

Cash general and administrative expense was $9.3 million for the first quarter 2012, a $5.1 million increase from $4.2 million for the prior year first quarter and a decrease of $0.1 million from the fourth quarter 2011. The increase from prior year first quarter was principally due to $2.7 million of reimbursements received in the prior year from a transition service agreement with Chevron Corp. Additionally, Chevron assumed the majority of Atlas’ expenses in the prior year comparable quarter, as the transaction was completed midway through that period.

Cash interest expense was $0.1 million for the first quarter 2012. As of March 31, 2012, ARP had $17.0 million outstanding under its revolving credit facility, which has a current borrowing base of $250 million, and had a cash position of $33.7 million.

ARP recognized a $7.0 million loss on asset disposal during the first quarter 2012 pertaining to its decision to terminate a farm out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm out agreement, which was a legacy contract initiated prior to the

acquisition from Chevron Corp. in February 2011, contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 not to pursue due to the current natural gas price environment. As a result, ARP yielded ownership of the processing plant and recorded a loss related to the net book values of those assets as of March 31, 2012.

ARP entered into additional derivative contracts during the first quarter 2012 for its natural gas and oil production. ARP currently has approximately 64.7 billion cubic feet equivalents of its future production hedged through 2016. A summary of the ARP current derivative positions as of May 7, 2012 is as follows:

Fixed Price Swaps

Production Period Ended December 31,

2012^(c)

2013

2014

2015

2016

Costless Collars

Production Period Ended December 31,

2012^(c)

2013

2014

2015

Put Options^(d)

Production Period Ended December 31,

2012^(c)

2013

Swaptions^(d)

Production Period Ended December 31,

2012^(c)

2013

2014

2015

2016

Fixed Price Swaps

Production Period Ended December 31,

2012^(c)

2013

2014

2015

2016

Costless Collars

Production Period Ended December 31,

2012^(c)

2013

2014

2015

2016

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

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

Reflects hedges covering the last nine months of 2012.

These derivative contracts reflect the additional hedge positions which ARP entered related to its acquisition of Barnett Shale assets. Swaptions are contracts which provide ARP the option to enter into swap contracts up through May 31, 2012 for the reported natural gas volumes and prices.

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

Depreciation, depletion and amortization

Total costs and expenses

Operating income

Loss on asset disposal

Interest expense

Net income (loss)

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)

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

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 payable to Drilling Partnerships

Accrued well drilling and completion costs

Accrued liabilities

Total current liabilities

Long-term debt

Long-term derivative payable to Drilling Partnerships

Asset retirement obligations and other

Commitments and contingencies

Partners’ Capital/Equity:

General partner’s interest

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)

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:⁽⁵⁾

Natural gas (per Mcf) ⁽⁷⁾

Oil (per Bbl)⁽⁸⁾

Natural gas liquids (per Bbl)

Production costs:⁽⁵⁾⁽⁹⁾

Lease operating expenses per Mcfe⁽¹⁰⁾

Production taxes per Mcfe

Total production costs per Mcfe⁽¹⁰⁾

Depletion per Mcfe⁽⁵⁾

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

For the three months ended March 31, 2012, 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 March 5,

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.

ARP’s average sales prices for natural gas before the effects of financial hedging were $2.88 per Mcf and $4.47 per Mcf for the three months ended March 31, 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 $3.98 per Mcf ($2.53 per Mcf before the effects of financial hedging) and $4.67 per Mcf ($3.68 per Mcf before the effects of financial hedging) for the three months ended March 31, 2012 and 2011, respectively.

ARP’s average sales prices for oil before the effects of financial hedging were $100.41 per barrel and $87.39 per barrel for the three months ended March 31, 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 $0.84 per Mcfe ($0.95 per Mcfe for total production costs) and $0.69 per Mcfe ($0.80 per Mcfe for total production costs) for the three months ended March 31, 2012 and 2011, respectively.

First quarter 2011 amount was adjusted to reflect current period classification resulting from the misclassification of amounts 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

Cash general and administrative expenses

Other, net

Adjusted EBITDA⁽¹⁾

Cash interest expense⁽²⁾

Maintenance capital expenditures

Distributable Cash Flow⁽¹⁾

Distributable cash flow not attributable to common limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)⁽⁴⁾

Distributable Cash Flow attributable to common limited partners⁽¹⁾

Distributions Paid⁽³⁾

per limited partner unit

Reconciliation of non-GAAP measures to net income (loss)⁽³⁾:

Distributable cash flow attributable to common limited partners and the general partner

Distributable cash flow not attributable to common limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)⁽⁴⁾

Acquisition and related costs

Depreciation, depletion and amortization

Amortization of deferred finance costs

Maintenance capital expenditures

Loss on asset disposal

Non-cash impact of derivatives

Other non-cash adjustments⁽⁵⁾

Net income (loss)

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 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.

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 of Pennsylvania impact fee for the three months ended March 31, 2011. The fee was instituted by the state of Pennsylvania subsequent to December 31, 2011 for the full year 2011. ARP allocated the fee prorata to each of the quarterly periods during 2011.