Atlas Resource Partners (ARP) achieved record average net production of 133.0 Mmcfed for the first quarter 2013, a 21% increase over the fourth quarter 2012

ARP recently completed seven horizontal wells in the Marcellus Shale in Lycoming Co., PA yielding aggregate initial flow rate production of approximately 140 MMcfd, in which ARP owns an approximate 35% interest; ARP expects these wells to be online in early third quarter 2013

ARP increased its quarterly distribution to $0.51 per limited partner unit for the first quarter 2013, an 6% increase from the fourth quarter 2012 distribution

ARP reaffirms distribution guidance of at least $2.35 per unit for full year 2013

Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), a non-GAAP measure, of $31.4 million⁽¹⁾, or $0.64 per common unit, for the first quarter 2013, which represents a 133% increase from the prior year 1^st quarter. Adjusted EBITDA for the period was impacted negatively by an estimated $2.5 million to $3.0 million impact of storms that affected our production in Texas and Oklahoma;

Distributable cash flow, a non-GAAP measure, of $25.1 million⁽¹⁾, or $0.52 per common unit, for the first quarter 2013;

ARP declared a cash distribution of $0.51 per limited partner unit for the first quarter 2013, an increase of $0.03, or 6%, over the fourth quarter 2012. The first quarter 2013 ARP distribution will be paid on May 15, 2013 to holders of record as of May 6, 2013; and,

On a GAAP basis, net loss was $5.4 million for the first quarter 2013 compared to a net loss of $6.2 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, including depreciation, depletion and non-cash compensation expense. 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 2013 was 133.0 million cubic feet of natural gas equivalents per day (Mmcfed), an increase of 22.9 Mmcfed, or approximately 21%, compared with the fourth quarter 2012, and an increase of approximately 240% compared to the prior year first quarter. The production increase from fourth quarter 2012 was primarily due to a full quarter’s volume from the acquisition of the Marble Falls oil & gas properties in the Fort Worth basin (TX) from DTE Energy in December 2012. The increase compared to the prior year quarter is due primarily to ARP’s acquisitions of producing oil & gas properties in the Barnett Shale and Fort Worth basin in Texas and Hunton formation in Oklahoma. Oil and natural gas liquids production accounted for approximately 20% of total production volume for the period, compared with 13% for the fourth quarter 2012 and 10% for the prior year first quarter.

During the quarter, ARP’s production in parts of Texas and Oklahoma experienced the impact from severe winter weather for several weeks. As a result, some production was curtailed and shut in at various locations due to the conditions and loss of power in certain areas.

Investment partnership margin⁽²⁾ contributed $10.9 million to Adjusted EBITDA and distributable cash flow for the first quarter 2013.

ARP continued to expand its commodity hedge positions during the first quarter 2013 and currently has approximately 130.5 billion cubic feet of equivalents (“Bcfe”) of its future production hedged through 2017, including an average floor price for its natural gas production of over $4.20 per thousand cubic feet (“mcf”) and $90 per barrel for its crude oil production through 2017. A summary of ARP’s current derivative positions as of May 8, 2013 is provided in the financial tables of this release.

Cash general and administrative expense was $9.6 million for the first quarter 2013, $0.6 million higher than the fourth quarter 2012 and slightly higher compared with the prior year first quarter. The increase compared with the fourth quarter 2012 was due primarily to higher seasonal corporate expenses incurred earlier in the year, including yearend compliance costs.

Cash interest expense was $2.2 million for the first quarter 2013, an increase of $1.4 million compared to the fourth quarter 2012. The increase was due to ARP’s issuance of $275.0 million of 7.75% senior notes due 2021 in January 2013. As of March 31, 2013, ARP had $420.0 million of total debt, including $145.0 million outstanding under its revolving credit facility, and a cash position of $1.1 million. ARP’s credit facility has a current borrowing base of $368.8 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

Depreciation, depletion and amortization

Total costs and expenses

Operating income

Loss on asset sales and disposal

Interest expense

Net loss

Preferred limited partner dividends

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

Allocation of net 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 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 and Diluted

Weighted average common limited partner units outstanding:

Basic and 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

Advances from affiliates

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:

General partner’s interest

Preferred limited partners’ interests

Common limited partners’ interests

Accumulated other comprehensive income (loss)

Total partners’ capital

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/Marble Falls:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Mississippi Lime/Hunton:

Natural gas (Mcfd)

Oil (Bpd)

Natural gas liquids (Bpd)

Total (Mcfed)

Other Operating Areas:⁽⁶⁾

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

Production taxes per Mcfe

Total production costs per Mcfe

Depletion per Mcfe⁽⁵⁾

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

Calculation consists of distributable cash flow, less amounts attributable to the general partner, divided by 47,813,000 and 26,200,000 limited partner units for the three months ended March 31, 2013 and 2012, respectively, which represent the weighted average limited 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 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 includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia. Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

ARP’s average sales prices for natural gas before the effects of financial hedging were $2.90 per Mcf and $2.88 per Mcf for the three months ended March 31, 2013 and 2012, 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 $3.01 per Mcf ($2.59 per Mcf before the effects of financial hedging) and $3.98 per Mcf ($2.53 per Mcf before the effects of financial hedging) for the three months ended March 31, 2013 and 2012, respectively.

ARP’s average sales prices for oil before the effects of financial hedging were $90.80 per barrel and $100.41 per barrel for the three months ended March 31, 2013 and 2012, 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 $0.90 per Mcfe ($1.12 per Mcfe for total production costs) and $0.84 per Mcfe ($0.95 per Mcfe for total production costs) for the three months ended March 31, 2013 and 2012, respectively.

Total debt

Less: Cash

Total net debt/(cash)

Partners’ capital

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 limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets)⁽⁴⁾

Distributable Cash Flow attributable to limited partners⁽¹⁾

Distributions Paid⁽³⁾

per limited partner unit

Reconciliation of non-GAAP measures to net loss ⁽¹⁾:

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)⁽⁴⁾

Acquisition and related costs

Depreciation, depletion and amortization

Amortization of deferred finance costs

Non-cash stock compensation expense

Maintenance capital expenditures

Loss on asset sales and disposal

Premiums paid on swaption derivative contracts (Carrizo assets acquisition)

Net 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 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.

Fixed Price Swaps

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

Costless Collars

Production Period Ended December 31,

2013^(b)

2014

2015

Put Options

Production Period Ended December 31,

2013^(b)

Crude Oil Fixed Price Swaps

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

Mt Belvieu Ethane Purity Swaps

Production Period Ended December 31,

2014

Fixed Price Swaps

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

Costless Collars

Production Period Ended December 31,

2013^(b)

2014

2015

“mmbtu” represents million metric British thermal units.; “bbl” represents barrel.

Reflects hedges covering the last nine months of 2013.