The five most recent horizontal Marcellus Shale wells turned into line before the end of the fourth quarter were assigned proved reserves that averaged 5.6 billion cubic feet (“Bcfe”) per well by the Company’s third-party reserve engineer. This compares to the Company’s recent reserve estimate of 4 Bcfe per Marcellus Shale horizontal well.

Due to production, reserve results and additional acreage evaluations, the Company has increased its estimate of net recoverable reserves from the Marcellus Shale to approximately 13 trillion cubic feet of natural gas equivalents (“Tcfe”) from the previous estimate of 9 Tcfe.

Adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”), a non-GAAP measure, for the Company’s exploration and production operations (“E&P Operations”) of $72.1 million exceeded the high-end of the previously issued guidance range of $68 million to $72 million. A reconciliation from net income to adjusted EBITDA is provided in the financial tables of this release.

Total production guidance for 2010 was reaffirmed between 45 and 50 Bcfe, representing an increase of approximately 29% at the midpoint compared to full year 2009 production.

Total daily net production grew to an average of 102.8 million cubic feet equivalents (“Mmcfe”) per day, up 3% over the sequential quarter due to increasing production from the Company’s development of the Marcellus Shale.

Average Appalachia net production grew to a record of 45.2 Mmcfe per day, up 16% over the prior year quarter and 9% over the third quarter of 2009.

Gross Marcellus Shale production reached 60 MMcfe per day.

The 2010 capital budget is estimated to range between $250 million and $270 million, of which approximately 70% is allocated to Marcellus Shale activities.

Atlas Resources Public #18-2009 (C) drilling program raised $222.9 million of investor funds during the fourth quarter of 2009, bringing total funds raised for the year to $351.9 million.⁽²⁾

Adjusted diluted net income per share, a non-GAAP measure, was $0.20 for the fourth quarter 2009 compared with $0.16 per share for the fourth quarter 2008.

During 2009, the Company successfully initiated its horizontal drilling program in the Marcellus Shale.

As of December 31, 2009, the five most recent horizontal Marcellus wells turned into line were exhibiting shallower declines than the Company’s original estimated well profile. The most recent results for these wells are as follows:

Well

County

1

2

3

4

5

Atlas has identified the lower Marcellus, which exhibits the highest total organic content readings, as the optimal zone for lateral placement (wells #1 and #5 were placed low in the section).

While fracing well #3, a contractor experienced significant equipment problems that resulted in reduced injection rates. This well continues to clean up and is still on steady production incline after 120 days.

Well #4 has been constrained by freeze-offs and limited plant capacity.

As of December 31, 2009, the Company controlled leasehold acreage of approximately 584,000 acres in Pennsylvania, West Virginia, and New York that are prospective for the Marcellus Shale, of which approximately 314,000 acres are in areas of active Marcellus Shale development (includes 270,000 acres located in the Company’s traditional focus area of southwestern Pennsylvania).

For 2010, the Company has scheduled to frac and turn into line 43 horizontal Marcellus Shale wells.

Laurel Mountain Midstream Partners, LLC (‘LMM”), a joint venture between The Williams Companies (NYSE:WMB) and Atlas Pipeline Partners, L.P. (NYSE:APL), is in the process of constructing a new large diameter gathering system in southwestern Pennsylvania that will ultimately be capable of transporting over 500 million cubic feet (“Mmcf”) per day.

The Company recently contracted for firm capacity to deliver up to 100 Mmcf per day into the M3 market area of the Texas Eastern interstate pipeline at either a fixed basis to NYMEX or an M3 index price for ten years.

Atlas expects its per well costs to decline to $3.75 million this year primarily as a result of increased pad drilling, more targeted completion techniques and the Company’s commitment to reuse 100% of its flow back and production water.

The Company has added to its senior management, as Senior Vice President, the former Shale Development Manager of Marathon Oil Company. Greg D. Muse, 50, spent his entire 28-year career with Marathon Oil Company in engineering and operations and most recently was Shale Development Manager where he led integrated teams of technical experts in the exploration and development of unconventional shale plays worldwide including the Haynesville, Marcellus, Woodford, and Bakken Shale plays of North America, as well as Marathon’s recent entry into an emerging shale in Poland. He joins 22 other professionals who have joined Atlas in the last two years to work on the Company’s growing Marcellus Shale development.

Natural gas production from the Michigan/Indiana Segment averaged 57.6 Mmcfe per day during the fourth quarter 2009.

Production of 58.1 Mmcfe per day during 2009 was down 3.3% year over year due to sharply reduced capital expenditures of $6 million in 2009 compared with $57 million in 2008. All but four of the 55 wells drilled in Michigan during the year were funded through the Company’s drilling partnership programs.

At December 31, 2009, the Company had approximately 270,800 net acres in the Antrim Shale of Michigan, of which approximately 22,800 were undeveloped.

The Company spud 42 horizontal wells in Indiana’s biogenic New Albany Shale in 2009.

The Company had access to approximately 123,000 net acres in the biogenic New Albany Shale as of December 31, 2009, with over 450 potential locations.

Adjusted EBITDA, a non-GAAP measure, was $72.1 million for the Company’s E&P Operations for the fourth quarter 2009, as compared with $68.7 million for the prior year comparable quarter. The fourth quarter 2009 adjusted EBITDA exceeded the high-end of the Company’s previously issued guidance range of $68 million to $72 million. The increase from the prior year comparable quarter was primarily related to an increase in well drilling fees and other fees generated from the deployment of funds raised in our direct investment programs, and higher natural gas production volumes with price realizations significantly enhanced by the Company’s hedge portfolio. These items were partially offset by lower spot commodity prices compared with the prior year comparable period ($4.24/mcf during the fourth quarter 2009 compared with $6.95/mcf during the fourth quarter 2008). A reconciliation from net income to adjusted EBITDA is provided in the financial tables of this release.

Adjusted net income, a non-GAAP measure, was $15.8 million for the fourth quarter 2009 compared with $6.4 million for the prior year fourth quarter. Adjusted diluted net income per share was $0.20 for the fourth quarter 2009 compared with $0.16 per share for the fourth quarter 2008. Inclusive of a non-cash impairment charge associated with certain of the Company’s legacy Upper Devonian shallow wells, the consolidation of APL and Atlas Pipeline Holdings, L.P. (“AHD”) and other items, on a GAAP basis, the Company recognized a net loss of $85.3 million for the fourth quarter 2009 compared with a net loss of $28.9 million for the prior year fourth quarter. A reconciliation of net loss to adjusted net income is provided in the financial tables of this release.

Partnership management margin⁽¹⁾ was $26.3 million for the fourth quarter 2009, compared to $16.9 million for the prior year fourth quarter.

Adjusted EBITDA was $279.3 million for the Company’s E&P Operations for the full year 2009, as compared with $295.4 million for the prior year. The decrease from the prior year was primarily related to sharply lower spot commodity prices compared with the prior year comparable period ($4.07/mcf for the full year 2009 compared to $9.23/mcf for the prior year), partially offset by the Company’s hedging program which helped stabilize cash flows despite lower commodity prices and higher production volumes. A reconciliation of net loss to adjusted EBITDA is provided in the financial tables of this release.

Adjusted net income was $40.8 million for the full year 2009 compared with $37.1 million for the prior year. Adjusted diluted net income per share was $0.81 for the full year 2009 compared with $0.89 per share for the prior year. Inclusive of the non-cash impairment charge related to certain of the Company’s legacy Upper Devonian shallow wells, the consolidation APL and AHD and other items, on a GAAP basis, the Company

Full year 2009 partnership management margin⁽¹⁾ was $83.0 million compared with $84.6 million in the prior year.

The Company raised approximately $222.9 million for its Atlas Resources Public #18-2009 (C) ⁽²⁾ drilling program during the fourth quarter 2009, bringing the total investor funds raised in 2009 to approximately $351.9 million. The $222.9 million of investor funds raised was the Company’s largest year end fundraising and 11% higher than its 2008 year end program.

In January 2010, the Company received approximately $20.1 million in proceeds from the early settlement of natural gas hedge positions related to periods from 2011 through 2013. Simultaneously, these hedge positions were effectively replaced with similar hedge contracts at current prevailing prices. The net proceeds from the hedge monetization were used to reduce indebtedness. An updated schedule of the Company’s hedge positions is provided in the financial tables of this press release.

General and administrative expense, excluding amounts attributable to APL and AHD, was $14.7 million for the fourth quarter 2009 compared with $12.1 million for the prior year comparable quarter. The increase in the fourth quarter 2009 compared to the prior year was principally related to $1.4 million of non-recurring expenses related to the merger between Atlas Energy Resources, LLC (“ATN”) and the Company (the “Merger”) and an increase in wages and other corporate activities due to the growth of its business. See consolidating statements of operations provided in the financial tables of this release.

Depreciation, depletion and amortization expense, excluding amounts attributable to APL and AHD, was $28.4 million for the fourth quarter 2009, compared to $27.1 million for the prior year comparable quarter. The increase was due primarily to the increase in production for the Company’s Appalachia segment, notably from Marcellus Shale production. See consolidating statements of operations provided in the financial tables of this release.

Interest expense, excluding amounts attributable to APL and AHD, was $17.7 million for the fourth quarter 2009 compared with $13.6 million for the prior year fourth quarter. The increase in interest expense was primarily due to ATN’s $200 million 12.5% senior note offering in July 2009, partially offset by lower average borrowings under its credit facility. See consolidating statements of operations provided in the financial tables of this release.

The Company entered into additional hedging contracts during the fourth quarter 2009 for its natural gas production. A summary of the Company’s current equity hedge positions as of February 25, 2010 is as follows:

Production Period
Ended December 31,

Production Period
Ended December 31,

Production Period
Ended December 31,

Production Period
Ended December 31,

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

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

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

Atlas Energy’s subsidiary serves as managing general partner of the partnership. A written prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. — 3rd Floor, Moon Township, PA 15108.

Revenues:

Gas and oil production

Well construction and completion

Transmission, gathering and processing

Administration and oversight

Well services

Gain (loss) on asset sales

Gain (loss) on mark-to-market derivatives⁽¹⁾

Other, net

Total revenues

Costs and expenses:

Gas and oil production

Well construction and completion

Transmission, gathering and processing

Well services

General and administrative

Depreciation, depletion and amortization

Goodwill and other asset impairment

Total costs and expenses

Operating income (loss)

Interest expense

Gain on early extinguishment of debt

Loss from continuing operations before income tax benefit

Income tax benefit

Net loss from continuing operations

Discontinued operations:

Gain on sale of discontinued operations (net of income tax provision of $2,228 for the year ended December 31, 2009)

Income (loss) from discontinued operations (net of income tax provision of $27 for the three months ended December 31, 2008 and $498 and $875 for the years ended December 31, 2009 and 2008, respectively)

Net loss

(Income) loss attributable to non-controlling interests

Net loss attributable to common shareholders

Net loss attributable to common shareholders per share — basic:

Loss from continuing operations attributable to common shareholders

Income from discontinued operations attributable to common shareholders

Net loss attributable to common shareholders

Net loss attributable to common shareholders per share — diluted:

Loss from continuing operations attributable to common shareholders

Income from discontinued operations attributable to common shareholders

Net loss attributable to common shareholders

Weighted average common shares outstanding:

Basic

Diluted

Loss attributable to common shareholders:

Loss from continuing operations (net of income tax benefit of $54,624 and $17,309 for the three months ended December 31, 2009 and 2008, respectively, and $49,069 and $5,021 for the years ended December 31, 2009 and 2008, respectively)

Discontinued operations (net of income tax provision of $27 for the three months ended December 31, 2008 and $2,726 and $875 for the years ended December 31, 2009 and 2008, respectively)

Net loss attributable to common shareholders

Consists principally of hydrocarbon derivative gains / (losses) that relate to the operating activities of the Company’s consolidated subsidiary, APL. The underlying hydrocarbon derivatives do not represent present or potential future obligations of the Company.

Current assets:

Cash and cash equivalents

Accounts receivable

Current portion of derivative asset

Subscription receivable from Partnerships

Prepaid expenses and other

Prepaid and deferred taxes

Current assets of discontinued operations

Total current assets

Property, plant and equipment, net

Goodwill and intangible assets, net

Long-term derivative asset

Investment in joint venture

Deferred tax asset

Other assets, net

Long-term assets of discontinued operations

LIABILITIES AND SHAREHOLDERS’ EQUITY

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 liability to Partnerships

Accrued interest

Accrued well drilling and completion costs

Current portion of deferred tax liability

Accrued and other current liabilities

Current liabilities of discontinued operations

Total current liabilities

Long-term debt, less current portion

Deferred tax liability

Long-term derivative liability

Long-term derivative liability to Partnerships

Other long-term liabilities

Shareholders’ equity:

Shareholders’ equity

Accumulated other comprehensive income

Non-controlling interests

Total shareholders’ equity

Net loss attributable to common shareholders per share — basic

Adjusted net income attributable to common shareholders per share — basic⁽¹⁾

Pro forma adjusted net income attributable to common shareholders per share — basic⁽¹⁾

E&P Operations Discretionary Cash Flow per share⁽²⁾

Production revenues (in thousands):

Natural gas

Oil

Production volume:⁽³⁾⁽⁴⁾

Appalachia:

Natural gas (Mcfd)

Oil (Bpd)

Total (Mcfed)

Michigan/Indiana:

Natural gas (Mcfd)

Oil (Bpd)

Total (Mcfed)

Total:

Natural gas (Mcfd)

Oil (Bpd)

Total (Mcfed)

Average sales prices:⁽⁴⁾

Natural gas (per Mcf)⁽⁶⁾⁽⁷⁾

Oil (per Bbl)⁽⁸⁾

Production costs:⁽⁴⁾⁽⁹⁾

Lease operating expenses per Mcfe

Production taxes per Mcfe

Total production costs per Mcfe

Depletion per Mcfe⁽⁴⁾

A reconciliation from net loss to adjusted net income attributable to common shareholders per share and pro forma adjusted net income attributable to common shareholders per share is provided in the financial tables of this release.

Calculation consists of discretionary cash flow divided by pro forma weighted average common shares outstanding for the respective period. A reconciliation from net loss to discretionary cash flow is provided in the financial tables of this release. Pro forma weighted average common shares outstanding for the respective period consists of the historical basic weighted average shares of the Company for the respective period, adjusted for the 38.8 million shares of the Company’s common stock issued in connection with the Merger.

Production quantities consist of the sum of (i) the Company’s proportionate share of production from wells in which it has a direct interest, based on the Company’s proportionate net revenue interest in such wells, and (ii) the Company’s proportionate share of production from wells owned by the investment partnerships in which the Company 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.

Includes NGL production volume of 400 bpd and 101 bpd for the fourth quarter 2009 and year ended December 31, 2009, respectively.

The Company’s average sales price for gas before the effects of financial hedging was $4.24 and $6.95 per Mcf for the three months ended December 31, 2009 and 2008, respectively, and $4.07 and $9.23 per Mcf for the year ended December 31, 2009 and 2008, respectively. Including the effects of certain allocations of the Company’s production revenue to the investor partners within the Company’s investment partnerships, average gas sales prices for the three months and year ended December 31, 2009 was $7.37 per Mcf ($3.95 per Mcf before the effects of financial hedging) and $7.50 per Mcf ($3.91 per Mcf before the effects of financial hedging), respectively.

Includes cash proceeds of $0.4 million and $1.9 million for the three months ended December 31, 2009 and 2008, respectively, and $2.8 million and $12.4 million for the years ended December 31, 2009 and 2008, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of the Company’s Michigan operations but not reflected in the consolidated statements of operations.

The Company’s average sales price for oil before the effects of financial hedging was $72.69 and $48.23 per barrel for the three months ended December 31, 2009 and 2008, respectively, and $57.26 and $91.79 per barrel for the years ended December 31, 2009 and 2008, 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. Including the effects of the Company’s proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within its investment partnerships, lease operating expenses per Mcfe for the three months and year ended December 31, 2009 was $0.83 per Mcfe (total production costs per Mcfe were $0.98) and $0.81 per Mcfe (total production costs per Mcfe were $0.97), respectively.

Total debt

Less: Cash

Total net debt

Shareholders’ equity

Total capitalization

Ratio of net debt to capitalization

Net of eliminated amounts.

Atlas Energy

Atlas Pipeline Partners

Consolidated capital expenditures

Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

E&P Operations:

Gas and oil production margin⁽¹⁾

Well construction and completion margin

Administration and oversight margin

Well services margin

Gathering

E&P Operations Gross Margin

Cash general and administrative expenses⁽²⁾

Other, net

E&P Operations Adjusted EBITDA⁽³⁾

Cash interest expense⁽⁴⁾

Cash income tax refunds (payments)

E&P Operations Discretionary Cash Flow⁽³⁾

Capital expenditures

E&P Operations Free Cash Flow⁽³⁾⁽⁵⁾

Reconciliation of non-GAAP measures to net loss attributable to common shareholders⁽³⁾:

E&P Operations Discretionary Cash Flow

Atlas Pipeline and Atlas Pipeline Holdings net (income)

loss attributable to common shareholders

Cash income tax payments (refunds)

Income tax benefit

Non-recurring Merger costs

Depreciation, depletion and amortization

Asset impairment

Amortization of deferred finance costs

Non-cash stock compensation expense

Non-cash net loss on sale of assets

Income attributable to ATN non-controlling interests⁽⁶⁾