Atlas Resource Partners’ (ARP) net production has currently reached approximately 260 Mmcfed, compared to approximately 39 Mmcfed at the company’s inception in March 2012

ARP’s ongoing development of new wells in the Utica Shale, Marble Falls and Mississippi Lime regions has continued to increase oil and liquids production; oil and liquids represented approximately 40% of ARP’s total oil & gas production revenues in the second quarter 2013, up from approximately 22% in the prior year second quarter

Pro forma Adjusted EBITDA for the second quarter 2013 was $53.8 million, or $0.83 per unit, compared to $31.4 million, or $0.64 per unit, in the first quarter 2013 and $16.6 million, or $0.50 per unit, for the prior year second quarter

ARP increased its quarterly distribution to $0.54 per limited partner unit for the second quarter 2013 on pro forma distributable cash flow of $0.62 per unit, or approximately 1.14x coverage; this distribution represents a 35% increase per unit from the prior year second quarter, and a 6% increase from the first quarter 2013 distribution

Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), a non-GAAP measure, of $53.8 million⁽¹⁾, or $0.83 per common unit, for the second quarter 2013 pro forma for ARP’s acquisition of natural gas producing assets from EP Energy E&P Company, L.P. (“EP Energy”). This compares to pro forma adjusted EBITDA of $31.4 million, or $0.64 per unit, in the first quarter 2013 and $16.6 million, or $0.50 per unit, for the prior year second quarter;

Distributable cash flow, a non-GAAP measure, of $41.0 million⁽¹⁾, or $0.62 per common unit for the second quarter pro forma for the EP Energy acquisition, compared to $25.1 million, or $0.52 per unit, in the first quarter 2013 and $16.6 million, or $0.43 per unit, in the prior year second quarter;

ARP declared a cash distribution of $0.54 per limited partner unit for the second quarter 2013, an approximate 6%, over the first quarter 2013 and a 35% increase from the prior year second quarter distribution. The second quarter 2013 ARP distribution will be paid on August 14, 2013 to holders of record as of August 6, 2013; and

On a GAAP basis, net loss was $6.2 million for the second quarter 2013 compared to a net loss of $16.7 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.⁽¹⁾

Average net daily production for the second quarter 2013 was 133.6 million cubic feet of natural gas equivalents per day (Mmcfed). ARP continued its development activities during the quarter in the Mississippi Lime (OK) and Marble Falls (TX) regions, which have increased ARP’s net oil and liquids production. Additionally, ARP is currently in the process of connecting eight newly completed Marcellus Shale wells in Lycoming County, PA. ARP had substantial indications from these wells, which had average peak test rates of approximately 20 Mmcfd per well, with one well

having a peak rate as high as 32 Mmcfd. ARP also continued to increase the oil and liquid component of its production, which accounted for 21% of total volume for the second quarter 2013 compared with 7% for the prior year comparable period and 19% for the first quarter 2013.

Investment partnership margin⁽²⁾ contributed $9.2 million to Adjusted EBITDA for the second quarter 2013.

ARP continued to expand its commodity hedge positions on its legacy production during the second quarter 2013. In addition, ARP executed the vast majority of the commodity hedge positions it expected to put in place for its acquired production from the Raton and Black Warrior Basin assets. Overall, ARP currently has approximately 222.7 billion cubic feet of equivalents (“Bcfe”) of its future production hedged through 2018, including an average floor price for its natural gas production of over $4.20 per thousand cubic feet (“mcf”) and over $88 per barrel for its crude oil production through 2018. A summary of ARP’s derivative positions as of August 8, 2013 is provided in the financial tables of this release.

Cash general and administrative expense was $8.4 million for the second quarter 2013, $1.2 million lower than the first quarter 2013 and slightly lower compared with the prior year second quarter. The decrease compared with the first quarter 2013 was due primarily to higher seasonal corporate expenses incurred earlier in the year, including yearend compliance costs.

Cash interest expense was $3.4 million for the second quarter 2013, an increase of $1.1 million compared to the first quarter 2013. The increase was primarily due to increased borrowings on the Company’s revolving credit facility from continued deployment of drilling capital in the Marcellus, Utica, Mississippi Lime and Marble Falls operating regions.

As of June 30, 2013, pro forma for ARP’s most recent bond issuance in July 2013 of $250 million of 9.25% senior notes due 2021, ARP had $929 million of total debt, including $404 million outstanding under its revolving credit facility. As a result of the EP Energy transaction, ARP’s borrowing base on its credit facility was increased from $430 million to $835 million, providing ARP with pro forma availability of approximately $421 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)

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

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

Transportation and compression expenses 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 63,276,000 and 32,228,000 limited partner units for the three months ended June 30, 2013 and 2012, respectively, and 57,988,000 and 31,490,000 limited partner units for the six months ended June 30, 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 $3.47 per Mcf and $2.03 per Mcf for the three months ended June 30, 2013 and 2012, respectively, and $3.18 per Mcf and $2.76 per Mcf for the six months ended June 30, 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 $2.95 per Mcf ($3.10 per Mcf before the effects of financial hedging) and $2.87 per Mcf ($1.40 per Mcf before the effects of financial hedging) for the three months ended June 30, 2013 and 2012, respectively, and $2.98 per Mcf ($2.85 per Mcf before the effects of financial hedging) and $3.29 per Mcf ($2.24 per Mcf before the effects of financial hedging) for the six months ended June 30, 2013 and 2012, respectively.

ARP’s average sales prices for oil before the effects of financial hedging were $92.33 per barrel and $94.39 per barrel for the three months ended June 30, 2013 and 2012, respectively, and $91.63 per barrel and $97.60 per barrel for the six months ended June 30, 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, production overhead and transportation expenses. 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 $1.10 per Mcfe ($1.57 per Mcfe for total production costs) and $0.38 per Mcfe ($0.78 per Mcfe for total production costs) for the three months ended June 30, 2013 and 2012, respectively, and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) and $0.56 per Mcfe ($0.96 per Mcfe for total production costs) for the six months ended June 30, 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

Gross Margin for Acquisitions⁽¹⁾

Adjusted Gross Margin

Cash general and administrative expenses

Other, net

Adjusted EBITDA⁽²⁾

Cash interest expense⁽³⁾

Cash interest expense on acquisition financing⁽¹⁾

Maintenance capital expenditures⁽¹⁾

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)⁽⁴⁾

Distributable Cash Flow attributable to limited partners⁽²⁾

Distributions Paid⁽⁵⁾

per limited partner unit

Reconciliation of non-GAAP measures to net loss ⁽²⁾:

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⁾

Gross Margin for Acquisitions⁽¹⁾

Cash interest expense on acquisition financing⁽¹⁾

Acquisition and related costs

Depreciation, depletion and amortization

Amortization of deferred finance costs

Non-cash stock compensation expense

Maintenance capital expenditures⁽¹⁾

Loss on asset sales and disposal

Adjustment to reflect cash impact of derivatives

Premiums paid on swaption derivative contracts associated with asset acquisitions

Net loss

Includes gross margin generated and maintenance capital expenditures for the three months ended June 30, 2013 for the Raton, Black Warrior and County Line assets, which were acquired by ARP on July 31, 2013. Pursuant to the terms of the acquisition agreements, ARP is entitled to receipt of cash flows from EP Energy for the period after the acquisition effective date of May 1, 2013 through the closing date of July 31, 2013 as an acquisition adjustment, which is not recognized within ARP’s earnings under generally accepted accounting principles (“GAAP”). For purposes of declaring ARP’s quarterly distribution for the second quarter 2013, the Partnership evaluated its distributable cash flow for the full quarterly period including the gross margin for the Raton, Black Warrior and County Line assets acquired, pro forma cash interest expense on the borrowings to fund the acquisition purchase price, and estimated maintenance capital expenditures associated with the Raton, Black Warrior and County Line assets’ gross margin.

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.

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.

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.

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

2018

Production Period Ended December 31,

2013^(b)

2014

2015

Production Period Ended December 31,

2013^(b)

2014

2015

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

Production Period Ended December 31,

2014

Production Period Ended December 31,

2013^(b)

2014

2015

2016

2017

Production Period Ended December 31,

2013^(b)

2014