Atlas Energy announces the formation of a new E&P master limited partnership, Atlas Resource Partners, L.P., which will allow for growth both through accretive acquisitions and organic expansion

Atlas Energy reports $22.8 million in Adjusted EBITDA for the third quarter 2011

Distributable cash flow was $20.3 million for the current quarter, or $0.40 per common unit

Adjusted earnings before interest, income taxes, depreciation and amortization (“EBITDA”), a non-GAAP measure, of $22.8 million⁽¹⁾⁽²⁾;

Distributable cash flow, a non-GAAP measure, of $20.3 million, or $0.40 per common unit⁽¹⁾⁽²⁾;

ATLS declared a cash distribution of $0.24 per limited partner unit based on the financial results for the third quarter 2011, a $0.02 per unit, or 9%, increase from the preceding quarter;

On a GAAP basis, consolidated income from continuing operations of $50.9 million for the third quarter 2011 compared with a loss of $3.2 million for the prior year comparable period; and,

Total net production of 34.8 million cubic feet equivalents per day (“mmcfed”).

Average net daily production for the third quarter 2011 for the Appalachia segment was 31.3 mmcfed.

ATLS expects to connect 16 Marcellus horizontal wells, drilled through the partnership management business, during the first quarter 2012. Eleven of these wells were drilled in 2011, and five of these Marcellus wells have been previously drilled and completed and are awaiting pipeline connection.

Average net daily production for the New Albany/Antrim segment for the third quarter 2011 was 3.1 mmcfed.

Average net daily production for the third quarter 2011 for the Niobrara segment was 461 thousand cubic feet equivalents per day (“mcfed”).

Partnership management margin⁽²⁾ contributed $10.4 million to distributable cash flow for the third quarter 2011 compared with $6.2 million for the second 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.

Partnership management margin is comprised of Well Construction and Completion margin, Well Services margin and Administration and Oversight Fee revenues.

On October 26, 2011, APL declared a cash distribution of $0.54 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2011, a $0.07 per unit, or 14.9%, increase from the preceding quarter. ATLS will receive $4.9 million of cash distributions from APL on November 14, 2011, the date of payment for the APL third quarter 2011 distribution.

During the third quarter 2011, APL operated at or above nameplate capacity on all of its gathering and processing systems in the Mid Continent. APL processed approximately 567 mmcfd of natural gas, a 21% increase over the prior year comparable quarter’s volumes, amongst its WestOK, WestTX and Velma systems in the third quarter 2011. Record volumes of approximately 53,000 bbl per day of gross natural gas liquids were generated from APL’s three processing systems.

At September 30, 2011, ATLS owned a 2.0% general partner interest, all of the incentive distribution rights, and an 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 $5.1 million for the third quarter 2011. The current period is presented net of $5.6 million of fees received, net of $0.6 million of associated costs, from ATLS’ Transition Service Agreement with Chevron Corp. (NYSE: CVX), through which ATLS provides accounting and other services. ATLS will recognize these fees over the period the services are provided, which generally extends through the fourth quarter of 2011. 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 third quarter 2011. As of September 30, 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 $72.2 million.

ATLS entered into derivative contracts during the third quarter 2011 for its natural gas and oil production. ATLS currently has approximately 24.6 billion cubic feet equivalents of its future production hedged through 2015. A summary of the ATLS’ current derivative positions as of November 1, 2011 is as follows:

Fixed Price Swaps

Production
Period Ended
December 31,

Costless Collars

Production
Period Ended
December 31,

   2011^(c)

2012

2013

2014

2015

Costless Collars

Production
Period Ended
December 31,

   2011^(c)

2012

2013

2014

2015

“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 three months of 2011.

Hedge percentages based on Q3 2011 average production rates.

Revenues:

Gas and oil production

Well construction and completion

Gathering and processing

Administration and oversight

Well services

Gain (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

Total costs and expenses

Operating income

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 income

Income attributable to non-controlling interests

Net income after non-controlling interests

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 attributable to common limited partners

Net income 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 attributable to common limited partners

Net income 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 attributable to common limited partners

Weighted average common limited partner units outstanding:

Basic

Diluted

Net income attributable to common limited partners:

Income (loss) from continuing operations

Income (loss) from discontinued operations

Net income 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 attributable to common limited partners per unit - basic

Distributable cash flow per unit⁽²⁾⁽³⁾

Cash distributions paid per unit⁽²⁾⁽⁴⁾

Production revenues (in thousands):

Natural gas

Oil⁽⁵⁾

Total production revenues⁽⁵⁾

Production volume:⁽⁶⁾⁽⁷⁾

Appalachia⁽⁸⁾:

Natural gas (Mcfd)

Oil (Bpd)⁽⁹⁾

Total (Mcfed)

New Albany/Antrim:

Natural gas (Mcfd)

Oil (Bpd)

Total (Mcfed)

Niobrara:

Natural gas (Mcfd)

Oil (Bpd)

Total (Mcfed)

Total:

Natural gas (Mcfd)

Oil (Bpd)⁽⁹⁾

Total (Mcfed)

Average sales prices:⁽⁷⁾

Natural gas (per Mcf) ⁽¹⁰⁾

Oil (per Bbl)⁽¹¹⁾

Production costs:^(7)(12)

Lease operating expenses per Mcfe

Production taxes per Mcfe

Total production costs per Mcfe

Depletion per Mcfe⁽⁷⁾

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 51,257,000 weighted average common limited partner units outstanding for the 3^rd quarter 2011 and 51,242,000, which 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 paid per limited partner unit by the Partnership within 50 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter.

Includes NGL production revenue.

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.

Includes NGL production volume.

The Partnership’s average sales price for natural gas before the effects of financial hedging was $4.90 per Mcf and $4.12 per Mcf for the three months ended September 30, 2011 and 2010, respectively, and $4.69 per Mcf and $4.74 per Mcf for the nine months ended September 30, 2011 and 2010, respectively. These amounts exclude the impact of certain allocations of production revenues to investor partners within the investor partnerships. Including the effects of these allocations, average natural gas sales prices were $4.33 per Mcf ($4.13 per Mcf before the effects of financial hedging) and $4.88 per Mcf ($2.41 per Mcf before the effects of financial hedging) for the three months ended September 30, 2011 and 2010, respectively, and $4.44 per Mcf ($3.89 per Mcf before the effects of financial hedging) and $5.78 per Mcf ($3.47 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2011 and 2010, respectively.

The Partnership’s average sales price for oil before the effects of financial hedging was $81.85 per barrel and $66.36 per barrel for the three months ended September 30, 2011 and 2010, respectively, and $89.79 per barrel and $69.07 per barrel for the nine months ended September 30, 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 certain allocations of production revenue to investor partners within the Partnership’s investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $0.73 per Mcfe ($0.79 per Mcfe for total production costs) and $1.05 per Mcfe ($1.08 per Mcfe for total production costs) for the three months ended September 30, 2011 and 2010, respectively, and $0.67 per Mcfe ($0.72 per Mcfe for total production costs) and $0.86 per Mcfe ($0.89 per Mcfe for total production costs) for the nine months ended September 30, 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.

Maintenance capital expenditures⁽²⁾

Expansion capital expenditures

Total

Maintenance capital expenditures

Expansion capital expenditures

Total

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

Gross Margin

Cash general and administrative expenses⁽¹⁾

Atlas Pipeline cash distributions⁽²⁾

Other, net

Adjusted EBITDA⁽³⁾