The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with "Item 6: Selected Financial Data" and "Item 8: Financial Statements and Supplemental Data", which contains our consolidated combined financial statements.

Unless the context otherwise requires, references below to "Atlas Resource Partners, L.P.," "Atlas Resource Partners," "the partnership," "we," "us," "our" and "our company", when used for periods prior to March 5, 2012, refer to the subsidiaries and operations that Atlas Energy, L.P. contributed to Atlas Resource Partners in connection with the separation and, when used for periods after that date, refer to Atlas Resource Partners, L.P. and its consolidated subsidiaries. References below to "Atlas Energy" or "ATLS" refers to Atlas Energy, L.P. and its consolidated subsidiaries, unless the context otherwise requires.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and in "Item 1A: Risk Factors". We believe the assumptions underlying the consolidated combined financial statements are reasonable. However, our consolidated combined financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what they would have been had our predecessor been a separate, stand-alone company during the periods presented.

BUSINESS OVERVIEW

We are a publicly-traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids ("NGL"), with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance a portion of our natural gas, crude oil and NGL production activities.

At December 31, 2012, Atlas Energy, L.P. ("ATLS"), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of our general partner Class A units and incentive distribution rights through which it manages and effectively controls us, and an approximate 43.0% limited partner ownership interest (20,962,485 limited partner units) in us.

We were formed in October 2011 to own and operate substantially all of ATLS' exploration and production assets ("Atlas Energy E&P Operations"), which were transferred to us on March 5, 2012. In February 2012, the board of directors of ATLS' general partner approved the distribution of approximately 5.24 million of our common units which were distributed on March 13, 2012 to ATLS' unitholders using a ratio of 0.1021 of our limited partner units for each of ATLS' common units owned on the record date of February 28, 2012. The distribution of our limited partner units represented approximately 20% of the common limited partner units outstanding.

On February 17, 2011, ATLS acquired certain assets and liabilities (the "Transferred Business") from Atlas Energy, Inc. ("AEI"), the former owner of ATLS' general partner. These assets principally included the following exploration and production assets which were included within Atlas Energy's E&P Operations:

• AEI's investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we fund a portion of our natural gas and oil well drilling;

• proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee; and

• certain producing natural gas and oil properties, upon which we are developers and producers.

FINANCIAL PRESENTATION

Our consolidated combined balance sheet at December 31, 2012 and the portion of the consolidated combined statement of operations for the year ended December 31, 2012 subsequent to the transfer of assets on March 5, 2012 include our accounts and our wholly-owned subsidiaries. Our combined balance sheet at December 31, 2011, the portion of the consolidated combined statements of operations for the year ended December 31, 2012 prior to the transfer of assets on March 5, 2012 and the combined statement of operations for the years ended December 31, 2011 and 2010 were derived from the separate records maintained by ATLS and may not necessarily be indicative of the conditions that would have existed if

we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the combined financial statements, Atlas Energy's net investment in us is shown as equity in the combined financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated combined balance sheets and related consolidated combined statements of operations. Such estimates included allocations made from the historical accounting records of ATLS, based on management's best estimates, in order to derive our financial statements for the periods presented prior to the transfer of assets. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.

Upon the acquisition of the Transferred Business on February 17, 2011, ATLS' management determined that the acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners' capital/equity. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

• Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners' capital/equity;

• Retrospectively adjusted our consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of our consolidated combined statements of operations for any date prior to February 17, 2011 to reflect the results of operations attributable to the Transferred Business as a reduction of net income (loss) to determine income (loss) attributable to common limited partners and the general partner. The Transferred Business' historical financial statements prior to the date of acquisition reflect an allocation of general and administrative expenses determined by AEI to the underlying business segments, including the Transferred Business. We have reviewed AEI's general and administrative expense allocation methodology, which is based on the relative total assets of AEI and the Transferred Business, for the Transferred Business' historical financial statements prior to the date of acquisition and believe the methodology is reasonable and reflects the approximate general and administrative costs of our underlying business segments.

SUBSEQUENT EVENTS

Cash Distribution. On January 24, 2013, we declared a cash distribution of $0.48 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $23.6 million distribution, including $0.6 million and $1.8 million to the general partner and preferred limited partners, respectively, was paid on February 14, 2013 to unitholders of record at the close of business on February 6, 2013.

Senior Notes. On January 23, 2013, we issued $275.0 million of 7.75% senior unsecured notes due on January 15, 2021 ("7.75% Senior Notes"). We used the net proceeds of approximately $268.3 million, net of underwriting fees and other offering costs of $6.7 million, to repay all of the indebtedness and accrued interest outstanding under our term loan credit facility and a portion of that outstanding under our revolving credit facility (see "Credit Facilities"). Under the terms of our revolving credit facility, the borrowing base was reduced by 15% of the 7.75% Senior Notes to $368.8 million. In connection with the retirement of our term loan credit facility and the reduction in our revolving credit facility borrowing base, we accelerated $2.2 million of amortization expense related to deferred financing costs in January 2013. Interest on the 7.75% Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 18 months. At any time prior to January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a "make whole" redemption price as defined in the indenture, plus accrued and unpaid interest and additional

interest, if any. On and after January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. The indenture governing the 7.75% Senior Notes contains covenants, including limitations of our ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets.

RECENT DEVELOPMENTS

DTE Acquisition. On December 20, 2012, we completed the acquisition of DTE Gas Resources, LLC from DTE Energy Company (NYSE: DTE; "DTE") for $257.4 million, subject to certain post-closing adjustments (the "DTE Acquisition"). The cash paid at closing was funded through $179.8 million of borrowings under our revolving credit facility and $77.6 million through borrowings under our term loan credit facility.

Amendment to our revolving credit facility and new term loan credit facility. Also on December 20, 2012, in connection with the completion of the DTE Acquisition, we entered into an amendment to our revolving credit facility and a new term loan credit facility.

The amendment to our revolving credit facility:

• increased the borrowing base from $310.0 million to $410.0 million;

• stated that borrowings under the revolving credit facility bear interest, at our election, are at either LIBOR plus an applicable margin between 2.00% and 3.25% per annum or the base rate (which is the higher of the bank's prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 1.00% and 2.25% per annum;

• revised the maturity date to be the earlier of March 22, 2016 or February 19, 2014 (the date that is 91 days before the May 19, 2014 maturity date of our term loan credit facility) if any portion of the term loan debt is outstanding on that date; and

• amended the financial covenants to require that our ratio of Total Funded Debt (as defined in the credit agreement) to four quarters of EBITDA (as defined in the credit agreement) not be greater than 4.25 to 1.0 as of the last day of fiscal quarters ending on or before June 30, 2013, 4.00 to 1.0 as of September 30, 2013 and December 31, 2013, and 3.75 to 1.0 as of the last day of fiscal quarters ending after that date.

Our $77.6 term loan credit facility matures May 19, 2014, and contains terms substantially similar to our revolving credit facility except:

• our obligations are secured by second lien mortgages on our oil and gas properties and security interest in substantially all of our assets, and guarantees by substantially all of our subsidiaries;

• borrowings bear interest, at our option, at either the prime rate plus 6.5% or LIBOR plus 7.5%;

• we will be required to prepay borrowings with 100% of the net proceeds from any senior notes offering and 33% of the net proceeds from any equity offering; and

• requires us to maintain a ratio of Total Funded Debt to EBITDA 0.50 higher than that required under our revolving credit facility, a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0 as of the last day of any fiscal quarter, and a minimum asset coverage ratio (as defined in the credit agreement) of at least 1.5 to 1.0.

We borrowed $179.8 million under our revolving credit facility and $77.6 million under our term loan facility to partially fund the DTE acquisition. We repaid the term loan credit facility in full with the proceeds from the sale of the 7.75% Senior Notes (see "Subsequent Events").

Equity Offering. In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, we sold an aggregate of 7,898,210 of our common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. We utilized the net proceeds from the sale to repay a portion of the outstanding balance under our revolving credit facility and $2.2 million under our term loan credit facility.

Acquisition of Titan Operating, L.L.C. In July 2012, we completed the acquisition of Titan Operating, L.L.C. ("Titan") in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of our publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see "Issuance of Units"). The cash paid at closing was funded through borrowings under our credit facility (see "Credit Facilities"). The common units and preferred units were issued and sold in a private transaction exempt from registration under
Section 4(2) of the Securities Act of 1933, as amended (the "Securities Act") (see "Issuance of Units").

Acquisition of Assets from Carrizo Oil & Gas, Inc. In April 2012, we acquired certain oil and natural gas assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; "Carrizo") for approximately $187.0 million in cash. The purchase price was funded through borrowing under our credit facility and $119.5 million of net proceeds from the sale of 6.0 million of our common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of our executives. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see "Issuance of Units").

Equal Acquisition. In April 2012, we acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; "Equal"). The transaction was funded through borrowings under our revolving credit facility (see "Credit Facilities"). Concurrent with the purchase of acreage, we and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. We served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, we acquired Equal's remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were funded through borrowings under our revolving credit facility (see "Credit Facilities"). As a result of our acquisition of Equal's remaining interest in the undeveloped acres, the existing joint venture agreement between us and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by us.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the New York Mercantile Exchange ("NYMEX") spot market price; Barnett Shale and Marble Falls, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGL's are extracted from the natural gas stream by processing and fractionation plants enabling the remaining "dry" gas (low Btu content) to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as mentioned above and our NGLs are generally priced using the Mont Belvieu (TX) regional processing hub. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2012, Chevron and Atmos Energy Marketing, LLC accounted for approximately 43% and 11% of our total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Investment Partnerships. We generally fund a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, we receive the following fees:

• Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well;

• Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well;

• Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the wells; and

• Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which in general is equivalent to the fees we remit. In Appalachia, a majority of our Drilling Partnership wells are subject to a gathering agreement, whereby we remit a gathering fee of 16%. However, based on the respective investment partnership agreements, we charge our Drilling Partnership wells a 13% gathering fee. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from Drilling Partnerships by approximately 3%.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The areas in which we operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic natural gas prices. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our revolving credit facility and our ability to make distributions to our unitholders, including ATLS, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. Currently, we have focused our natural gas, crude oil and NGL production operations in various shale plays throughout the United States. As part of ATLS' agreement with AEI to acquire the Transferred Business on February 17, 2011, we have certain agreements which restrict our ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which will expire on February 17, 2014. Through December 31, 2012, we have established production positions in the following operating areas:

• the Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which we established a position following our acquisitions of assets from Carrizo, Titan and DTE during 2012 (see "Recent Developments");

• the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region;

• other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone; the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale; and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the years ended December 31, 2012, 2011 and 2010:

                                                    Years Ended December 31,
                                                  2012           2011       2010
         Gross wells drilled:
         Appalachia                                   22             17        18
         Barnett/Marble Falls                         21             -         -
         Mississippi Lime/Hunton                      11             -         -
         Tennessee                                    -               5         4
         New Albany/Antrim                            -              -         66
         Niobrara                                     51            138        29

         Total                                       105            160       117


         Our share of gross wells drilled(1):
         Appalachia                                    6              3         5
         Barnett/Marble Falls                         18             -         -
. . .