UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549


FORM
10-K


(Mark
One)


x
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934





For the
fiscal year ended December 31, 2008


OR





 ̈           TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE


ACT OF 1934


For the
transition period from _________ to __________





Commission
file number:  1-33193





ATLAS ENERGY RESOURCES,
LLC


(Exact
name of registrant as specified in its charter)


Delaware
            75-3218520(State
      or other jurisdiction or
            (I.R.S.
      Employerincorporation
      or organization)
            Identification
      No.)Westpointe
      Corporate Center One1550
      Coraopolis Heights RoadMoon
      Township, PA
            15108(Address
      of principal executive offices)
            Zip
      CodeRegistrant’s
      telephone number, including area code:
            412-262-2830Securities
      registered pursuant to Section 12(b) of the Act:





Title of each class
                
                Name of each exchange on which
      registeredCommon
      units representing Class B
                
                New
      York Stock Exchangelimited
      liability company interests





Securities
registered pursuant to Section 12(g) of the Act: None





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.


Yes x                 No
 ̈





Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.


Yes  ̈                 No
x





Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.  Yes xNo ̈





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.        ̈





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer.  See definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act (Check one):





Large
      accelerated filer       x
            Accelerated
      filer        ̈
            Non-accelerated
      filer        ̈





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).  Yes  ̈ No x





The
aggregate market value of common units held by non-affiliates of the registrant
on June 30, 2008 was approximately $1.28 billion.





DOCUMENTS
INCORPORATED BY REFERENCE:  None





The
number of Class B common member units outstanding at February 23, 2009 was
63,381,249.










ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES


INDEX
TO ANNUAL REPORT


ON
FORM 10-K





PageGLOSSARY
      OF TERMSPART
      I
                                  
                                  Item
      1:
                                  
                                  Business
                                  
                                  5Item
      1A:
                                  
                                  Risk
      Factors
                                  
                                  25Item
      1B:
                                  
                                  Unresolved
      Staff Comments
                                  
                                  40Item
      2:
                                  
                                  Properties
                                  
                                  41Item
      3:
                                  
                                  Legal
      Proceedings
                                  
                                  44Item
      4:
                                  
                                  Submission
      of Matters to a Vote of Security Holders
                                  
                                  44PART
      II
                                  
                                  Item
      5:
                                  
                                  Market
      for Registrant's Common Equity Related Unit holder Matters and Issuer
      Purchases of Equity Securities
                                  
                                  45Item
      6:
                                  
                                  Selected
      Financial Data
                                  
                                  46Item
      7:
                                  
                                  Management’s
      Discussion and Analysis of Financial Condition andResults of
      Operations
                                  
                                  48Item
      7A:
                                  
                                  Quantitative
      and Qualitative Disclosures about Market Risk
                                  
                                  64Item
      8:
                                  
                                  Financial
      Statements and Supplementary
      Data
                                  
                                  68Item
      9:
                                  
                                  Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
                                  
                                  103Item
      9A:
                                  
                                  Controls
      and Procedures
                                  
                                  103Item
      9B:
                                  
                                  Other
      Information
                                  
                                  106PART
      III
                                  
                                  Item
      10:
                                  
                                  Directors
      and Executive Officers and Corporate Governance
                                  
                                  106Item
      11:
                                  
                                  Executive
      Compensation
                                  
                                  106Item
      12:
                                  
                                  Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                                  
                                  106Item
      13:
                                  
                                  Certain
      Relationships and Related Transactions, and Director
      Independence
                                  
                                  106Item
      14:
                                  
                                  Principal
      Accounting Fees and
      Services
                                  
                                  106PART
      IV
                                  
                                  Item
      15:
                                  
                                  Exhibits
      and Financial Statement Schedules
                                  
                                  107SIGNATURES
                                  
                                  109


2





GLOSSARY
OF TERMS





As
commonly used in the oil and gas industry and as used in this Annual Report on
Form 10-K, the following terms have the following meanings:





Bbl.  One stock
tank barrel or 42 United States gallons liquid volume.





Bcf.  One billion
cubic feet.





Bcfe.  One billion
cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl
oil, condensate or natural gas liquids.





Btu.  One British
thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 to 59.5 degrees Fahrenheit.





Development
well.  A well drilled within a proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be
productive.





Dth.  One
dekatherm, equivalent to one million British thermal units.





Developed
acres.  Acres spaced or assigned to productive
wells.





Dry hole or
well.  A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
would exceed production expenses and taxes.





Exploratory well.Test hole
drilled on land or in sea to ascertain the extent of recoverable gas and/or oil
in a probable but yet unproved location.





Field.  An area
consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or
stratigraphic condition.





FERC.  Federal
Energy Regulatory Commission.





Gross acres or gross
wells.  The total acres or wells, as the case may be, in which
a working interest is owned.





MBbls.  One
thousand barrels of oil or other liquid hydrocarbons.





Mcf.  One thousand
cubic feet.





Mcfe.  One thousand
cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil, condensate or natural gas liquids.





Mcf/d.  One
thousand cubic feet per day.





MMBls.  One million
barrels of oil or other liquid hydrocarbons.





MMBtu.  One million
British thermal units.





MMcf.  One million
cubic feet.





MMcfe.  One million
cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of
oil, condensate or natural gas liquids.





MMcfe/d.  One Mmcfe
per day.





Net acres or net
wells.  The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.





NGL.  Natural gas
liquids, which are the hydrocarbon liquids contained within gas.





NYMEX.  The New
York Mercantile Exchange.


3





Oil.  Crude oil,
condensate and natural gas liquids.





Productive well.  A
well that is found to be capable of producing hydrocarbons in sufficient
quantities such that proceeds from the sale of such production exceeds
production expenses and taxes.





Proved developed
reserves.  Reserves that can be expected to be recovered
through existing wells with existing equipment and operating
methods.  Additional oil and gas expected to be obtained through the
application of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery are included
in “proved developed reserves” only after testing by a pilot project or after
the operation of an installed program has confirmed through production response
that increased recovery will be achieved.





Proved
reserves.  Proved oil and gas reserves are the estimated
quantities of gas, natural gas liquids and oil which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made.  Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based on future conditions.  The
definition of proved reserves is in accordance with the Securities and Exchange
commission’s definition set forth in Regulation S-X Rule 4-10 (a) and its
subsequent staff interpretations and guidance.





Proved undeveloped drilling
location.  A site on which a development well can be drilled
consistent with spacing rules for purposes of recovering proved undeveloped
reserves.





Proved undeveloped reserves or
PUDs.  Reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.  Reserves on undrilled
acreage are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled.  Proved reserves for
other undrilled units are claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation.  Estimates for proved undeveloped reserves are not
attributed to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same
reservoir.





Recompletion.  The
completion for production of an existing wellbore in another formation from that
which the well has been previously completed.





Reservoir.  A
porous and permeable underground formation containing a natural accumulation of
economically productive oil and/or gas that is confined by impermeable rock or
water barriers and is individual and separate from other reserves.





Standardized
Measure.  Standardized Measure, or standardized measure of
discounted future net cash flows relating to proved oil and gas reserve
quantities, is the present value of estimated future net revenues to be
generated from the production of proved reserves, determined in accordance with
the rules and regulations of the Securities and Exchange commission (using
prices and costs in effect as of the date of estimation) without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation, depletion and
amortization and discounted using an annual discount rate of 10%.  Our
Standardized Measure does not include future income tax expenses because we are
not subject to income taxes.





Successful well.  A
well capable of producing oil and/or gas in commercial quantities.





Tcf.One trillion
cubic feet.





Tcfe.One trillion
cubic feet equivalent, determined using a ratio of six Mcf of gas, to one Bbl of
oil, condensate, or natural gas liquids.





Undeveloped
acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved
reserves.





Unproved
reserves.  Lease acreage on which wells have not been drilled
and where it is either probable or possible that the acreage contains
reserves.





Working
interest.  The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.





Workover.  Operations
on a producing well to restore or increase production.


4


The
matters discussed within this report include forward-looking statements. These
statements may be identified by the use of forward-looking terminology such as
“anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,”
“may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the
negative thereof or other variations thereon or comparable terminology. In
particular, statements about our expectations, beliefs, plans, objectives,
assumptions or future events or performance contained in this report are
forward-looking statements. We have based these forward-looking statements on
our current expectations, assumptions, estimates, and projections. While we
believe these expectations, assumptions, estimates, and projections are
reasonable, such forward-looking statements are only predictions and involve
known and unknown risks and uncertainties, many of which are beyond our control.
These and other important factors may cause our actual results, performance or
achievements to differ materially from any future results, performance or
achievements expressed or implied by these forward-looking
statements.





Factors
that could cause actual results to differ from those implied by the
forward-looking statements in this report are more fully described under Item
1A, “Risk Factors” in this report. Given these risks and uncertainties, you are
cautioned not to place undue reliance on these forward-looking statements. The
forward-looking statements included in this report are made only as of the date
hereof. We do not undertake and specifically decline any obligation to update
any such statements or to publicly announce the results of any revisions to any
of these statements to reflect future events or developments.





PART
I





ITEM
      1:
            BUSINESS





General





We are a
publicly-traded Delaware limited partnership (NYSE: ATN) formed in June
2006.  We are an independent developer and producer of natural gas and
oil, with operations in the Appalachian Basin, where we focus on the development
of the Marcellus Shale, northern Michigan’s Antrim Shale, and Indiana’s New
Albany Shale.  Our Appalachian Basin major operations are located in
eastern Ohio, western Pennsylvania, and north central Tennessee, and we have
additional operations  in New York, West Virginia and
Kentucky.  We specialize in the development of these natural gas
basins because they provide us with repeatable, low-risk drilling
opportunities.  We are a leading sponsor and manager of
tax-advantaged, direct investment natural gas and oil partnerships in the United
States. Our focus is to increase our own reserves, production, and cash flows
through a balanced mix of generating new opportunities of geologic prospects,
natural gas and oil exploitation and development, and sponsorship of investment
partnerships. We generate both upfront and ongoing fees from the drilling,
production, servicing, and administration of our wells in these
partnerships.





We have
access to the gas gathering facilities owned by our affiliate Atlas Pipeline
Partners, L.P. (NYSE: APL) (“Atlas Pipeline”), which is a subsidiary of our
indirect parent company, Atlas America, Inc.  (NASDAQ: ATLS), (“Atlas
America”) for our core Appalachian properties, providing ample capacity and
deliverability directly from the wellhead to interstate pipelines serving major
east coast natural gas markets. We have established expertise, recognition, and
relationships with partners, suppliers and mineral interest owners in the region
and believe our extensive geological and operating experience, coupled with our
access to Atlas Pipeline’s gas gathering infrastructure, gives us competitive
advantages in developing these natural resources to achieve annual volumetric
growth and strong financial returns on a long-term basis.





We were
formed in June 2006 to own and operate substantially all of the natural gas and
oil assets and the investment partnership management business of Atlas America,
Inc. We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary
of Atlas America.  Our class B units are traded on the New York Stock
Exchange under the symbol ATN. Unless otherwise
indicated, references in this report to we, ouror usinclude Atlas Energy
Resources, LLC, our wholly owned subsidiaries and our interests in sponsored
drilling programs.





Strategy





Our
business is structured to achieve capital appreciation through growth of our
natural gas production and reserves and ongoing fee generation through our
investment partnerships. During 2008, we achieved record production of 34.9
Bcfe, an increase of 59% from the prior year, contributing to 73% growth in our
production revenues to $311.8 million. We also increased our estimated
proved reserves as of December 31, 2008 by 12% to 1.0 Tcfe, of which 40% were
proved undeveloped reserves. Our undeveloped acreage position provides us with a
multi-year inventory of drilling locations for future growth, which may be
accelerated by emerging horizontal shale plays in our operating areas. Our
strategy for capitalizing on these opportunities includes the
following:


5





Organic
Growth through Drilling. Development drilling is the key component for
production and reserve growth. During 2008, we drilled 838 gross (789 net) wells
in Appalachia, compared to 1,117 gross (1,028 net) wells during
2007.  Our development activity in 2008 represents a shift from
drilling a large quantity of wells in the shallow Upper Devonian Shale in 2007,
to the deeper Marcellus Shale formation in 2008.  These wells were
drilled primarily for our investment partnerships, in which we own an
approximate 35% to 40% interest.  We also drilled 168 gross (141 net)
wells in the Antrim Shale for our own account during 2008, an increase of 66
gross (50 net wells), compared to 2007.  Our growth strategy during
2009 will continue to focus on drilling in our key operated areas, as well as
increasing our acreage position to take advantage of horizontal drilling
opportunities on core properties.





Development
of Additional Drilling Prospects. We follow a disciplined capital
allocation process in selecting opportunities to expand our substantial
inventory of drilling locations that meet our criteria for predictable,
long-lived reserves. Our goal is to consolidate our position in the Appalachian
Basin, while diversifying our asset base with similar plays outside the basin.
As part of this strategy, we acquired several large acreage tracts during 2008,
as follows:





·
            We
      established a position in the New Albany Shale of southwestern Indiana by
      acquiring 163,000 gross (120,000 net) acres and by entering into a
      farm-out agreement that will give us the right to drill on an additional
      121,000 gross (78,000 net) acres.  The acreage is located in
      Sullivan, Knox, Green, Davies, Owen, Clay, and Lawrence counties,
      Indiana.  We began developing our New Albany shale acreage
      beginning in November 2008 and drilled 5.0 gross (4.0 net)
      wells.





·
            We
      added approximately 85,000 acres in Tennessee to consolidate our position
      in Campbell, Scott, and Morgan Counties.  We drilled 58 gross
      vertical and 10 gross horizontal wells on our acreage known as the Lake
      City area, during 2008.





·
            We
      have leased approximately 556,400 acres in the Marcellus Shale play in
      Pennsylvania, New York, and West Virginia, and have targeted 274,500 acres
      as our core area in southwestern Pennsylvania.  As of February
      19, 2009, we drilled 126 net vertical and 5 horizontal
    wells.





We plan to continue capitalizing on
opportunities to assemble or participate in developing large tracts with
significant reserve potential.





Geographic
and Geological Advantages





Our
proved reserves, both developed and undeveloped, are concentrated in several
areas.




Marcellus
Shale Overview. In the fourth quarter of 2006, we and our investment
partnerships began drilling wells to multiple pay zones, including the Marcellus
Shale of western Pennsylvania. The Marcellus Shale is a black, organic rich
shale formation located at depths between 6,000 and 8,500 feet and ranges in
thickness from 75 to 150 feet on our acreage in western Pennsylvania. As of
February 19, 2009, we control approximately 556,000 Marcellus Shale acres in
Pennsylvania, New York and West Virginia, and we continue to expand our
position. As of that date, we had drilled 126 vertical wells and 5 horizontal
wells and are currently producing 105 wells into a pipeline.  The
remaining 26 wells are scheduled to be completed and turned into line in the
first half of 2009. We are currently focused on our approximately 274,000
existing Marcellus Shale acres in southwestern Pennsylvania, where we have
drilled all but two of our Marcellus wells and have now, through this drilling,
largely delineated our acreage. Almost all of this acreage in southwestern
Pennsylvania has or is expected to have ample pipeline capacity using our or
Atlas Pipeline’s gas gathering infrastructure.




Over the
last 4 months, we have made great strides in optimizing our completion practices
for vertical Marcellus Shale wells. We have initiated a multiple stage
completion process that isolates various portions of the Marcellus package,
giving a more effective stimulation of the reservoir. This technique has been
used on 15 wells to date, and has consistently illustrated better-than-average
peak 24-hour, 30-day, and 60-day cumulative production results. We anticipate
that, where applicable, all future vertical wells will be stimulated in this
fashion. With 8 multiple stage wells on line at year end, Wright & Company,
Inc., our independent petroleum engineering consultants, assigned an average EUR
of 1.423 Bcf  per well.  As of this date, we
have  successfully drilled, cased, and cemented 3 additional
horizontal wells in Washington County PA, with 2 of these wells stimulated and
currently flowing back frac fluid.




6




Horizontal
Drilling Overview. The value potential for many of our Appalachian
properties may be enhanced by the use of horizontal drilling, which has been
found to provide advantages in extracting natural gas in various environments,
including shale and other tight reservoirs that are challenging to produce
efficiently. In general, horizontal wells use directional drilling to create one
or more lateral legs designed to allow the well bore to stay in contact with the
reservoir longer and to intersect more vertical fractures in the formation than
conventional methods. While substantially more expensive, horizontal drilling
may improve overall returns on investment by increasing recovery volumes and
rates, limiting the number of wells necessary to develop an area through
conventional drilling and reducing the costs and surface disturbances of
multiple vertical wells.





Appalachian
Basin Overview. The Appalachian Basin includes the states of Kentucky,
Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee.
It is the most mature oil and gas producing region in the United States, having
established the first oil production in 1860. Because the Appalachian Basin is
located near the energy-consuming regions of the mid-Atlantic and northeastern
United States, Appalachian producers have historically sold their natural gas at
a premium to the benchmark price for natural gas on the NYMEX. For the twelve
months ended December 31, 2008, the average premium over NYMEX for natural
gas delivered to our primary delivery points in the Appalachian Basin was $.235
per MMBtu. In addition, our Appalachian gas production also has the advantage of
a high energy content, ranging from 1.0 to 1.15 Dth per Mcf. Historically,
because our gas sales contracts yield upward adjustments from index based
pricing for throughput with an energy content above 1 Dth per
Mcf.  This higher energy content resulted in realized premiums
averaging 6% over normal pipeline quality gas for the twelve months ended
December 31, 2008.





During
the first several years of production, shallow Appalachian Basin wells generally
experience higher initial production rates and decline rates, which are followed
by an extended period of significantly lower production rates and decline
rates.  While the wells in this area are characterized by modest
initial volumes and pressures, their geological features also account for the
low annual decline rates demonstrated by vertical wells in the region, many of
which are expected to produce for 30 years or more.





Shallow
reserves in the Appalachian Basin are typically in blanket formations and have a
high degree of step-out development success.  The primary pay zone
throughout this region is the Devonian Shale formation. As the step-out
development progresses, reserves from newly completed wells are reclassified
from the proved undeveloped to the proved developed category and additional
adjacent locations are added to proved undeveloped reserves. As a result, the
cumulative amount of total proved reserves tends to increase as development
progresses. Wells in the Appalachian Basin generally produce little or no water,
contributing to a low cost of operation. In addition, most wells produce dry
natural gas, which does not require processing.





Antrim
Shale Overview. The Antrim Shale formation is a shallow,  late
Devonian Shale that occupies about 33,000 square miles under the northern half
of Michigan’s Lower Peninsula.  Most of the Michigan wells originally
targeted oil and gas bearing reservoirs below the shale.  While the
Antrim Shale has produced oil and gas since the 1940s, it was not until the
1980s that the Antrim was purposely targeted for production on a large
scale.  The Antrim Shale is a low risk, organically rich black shale
formation that is naturally fractured and primarily contains biogenic methane
and water.  Antrim production rates vary according to the intensity of
the fracturing in the area immediately surrounding individual
wells.  The fractures provide the conduits for free gas and associated
water to flow to the borehole through the black shale which otherwise has low
permeability.  Moreover, the fractures assist in the release of gas
absorbed on the shale surface.





Antrim
Shale wells produce substantial volumes of water, especially during the early
production stages, which must be removed from the formation to initiate gas
production. Each well’s gas is transported to a centrally located separation,
compression and dehydration facility, where water is separated from it and
disposed of, usually in a dedicated salt water disposal well, to minimize water
disposal costs.





New
Albany Shale Overview.The Devonian aged New Albany Shale is a blanket
formation found at depths of 500 to 3,000 feet, with thicknesses ranging from
100 to 200 feet.  Like the Antrim Shale, the New Albany Shale in
southwestern Indiana where our leasehold acreage is located is in the “biogenic
gas window”.  However, unlike the Antrim Shale, where natural fracture
patterns are low angle, the natural fracture patterns in the New Albany Shale
are vertically oriented.  This vertical fracture orientation lends
itself to a horizontal drilling approach.


7





Recent
Developments





Acquisition
of Indiana Assets.Beginning in
July, 2008, we began establishing a position in the New Albany Shale in
southwestern Indiana by investing approximately $15.0 million.  We
acquired 120,000 net undeveloped acres and entered into a farm-out agreement
that will give us rights to an additional 78,000 net undeveloped
acres.  These leases are located in Sullivan, Knox, Greene, Owen,
Davies, Clay and Lawrence counties, in Indiana.  In addition, we
acquired a 50% undivided interest in a gas gathering system with related
compression Co2 processing and fluid disposal facilities in Sullivan
County.





Agreement
with Miller Petroleum.On June 19,
2008, we entered into a $19.6 million agreement with Miller Petroleum, Inc.
(“Miller”) whereby Miller assigned (i) 100% of the working interest in its oil
and gas leases comprising 27,620 acres in the Koppers North and Koppers South
section of Campbell County, Tennessee, (ii) 100% of the working interest in 8
existing wells, and (iii) 100% of the working interest in its oil and gas leases
comprising 1,952 acres adjacent to the Koppers acreage.  The agreement
also provides Miller with an option to participate up to 25% in up to 10 wells
to be drilled on the assigned acreage.  In addition, we entered into
two agreements with Miller whereby (i) Miller will provide drilling services to
us for a two-year term and (ii) we or our affiliates will transport and process
natural gas for Miller from its existing wells.





Public
Equity Offering.On May 16, 2008,
we sold 2,070,000 of our Class B common units at $41.50 per common unit in a
public offering with UBS Investment Bank and Wachovia Securities acting as joint
book-running managers and underwriters.  The net proceeds of
approximately $82.5 million (after underwriting expenses of $3.4 million) were
used to repay a portion of the outstanding balance under our revolving credit
facility.  We intend to use the increased borrowing capacity to fund
additional acreage acquisitions and accelerated development of the Marcellus
Shale as well as further development of our other drilling programs and lease
acquisition activities.





Senior
Unsecured Notes.  In January 2008, we completed a private
placement of $250.0 million of Senior Unsecured Notes due 2018 (“Senior Notes”)
at a 10.75% interest rate to institutional buyers pursuant to Rule 144A under
the Securities Act of 1933.  On May 5, 2008, we issued an additional
$150.0 million Senior Notes at 104.75% of par to yield 9.85% to the par call on
February 1, 2016.  We have treated both the May 2008 and the January
2008 issuances as a single class of debt securities.  We used the net
proceeds of $402.7 million (including accrued interest paid of $4.7 million and
net underwriting fees of $9.2 million) to reduce the balance outstanding on our
revolving credit facility.





Interest
on the Senior Notes is payable semi-annually in arrears on February 1 and August
1 of each year.  The Senior Notes are redeemable at any time at
specified redemption prices, together with accrued and unpaid interest to the
date of redemption.  In addition, before February 1, 2011, we may
redeem up to 35% of the aggregate principal amount of the Senior Notes with the
proceeds of certain equity offerings at a stated redemption
price.  The Senior Notes are also subject to repurchase by us at a
price equal to 101% of their 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 360 days.





The
Senior Notes are junior in right of payment to our secured debt, including our
obligations under our credit facility.  The indenture governing the
Senior Notes contains covenants, including limitations of our ability to: incur
certain liens; engage in sale/leaseback transactions; 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.





Private
Equity Offering.  On May 7,2008, we sold 600,000
Class B common units to Atlas America in a private placement at $42.00 per
common unit, increasing Atlas America’s ownership of our Class B common units to
29,952,996 common units or 46.3%.  The proceeds of $25.2 million were
used to repay a portion of our outstanding balance under our revolving credit
facility.





Interest
Rate Swap.In January 2008,
we entered into an interest rate swap contract on $150.0 million of our secured
credit facility, swapping the floating rate incurred on a portion of our
existing senior secured credit facility for a three-year fixed rate of 3.11%.
The interest rate swap contract will mature in January 2011.


8


Key Performance Indicators as of and
for the year ended December 31, 2008:





In our
Appalachia gas and oil operations:





·
            we
      have proved reserves of 373.9 Bcfe, including the reserves net to our
      equity interest in our investment partnerships and our direct interests in
      producing wells;




·
            we
      own direct and indirect working interests in approximately 8,462 gross
      productive gas and oil wells;




·
            we
      own overriding royalty interests in approximately 624 gross productive gas
      and oil wells;




·
            our
      net daily production was 35.6 Mmcfe per
day;




·
            we
      lease approximately 950,530 gross (904,890 net) acres, of which
      approximately 640,430 gross (633,490 net) acres are
      undeveloped;




·
            we
      have identified 3,626 geologically favorable shallow drilling
      locations;




·
            included
      in our undeveloped acreage are approximately 556,438 Marcellus acres in
      Pennsylvania, New York and West Virginia, of which approximately 274,495
      acres are located in our core Marcellus Shale position in southwestern
      Pennsylvania




·
            we
      drilled 838 gross (789 net) wells of which 830 gross (781 net) wells were
      productive for our investment
partnerships;




·
            as
      of February 19, 2009, we drilled 126 net vertical and 5 net horizontal
      Marcellus Shale wells (3 of which have been successfully drilled, cased
      and cemented); and




·
            we
      drilled and participated in 12 successful horizontal wells in the
      Chattanooga Shale of eastern
Tennessee.




In our
Michigan gas and oil operations:





·
            we
      have proved reserves of  617.0
Bcfe;




·
            we
      own direct and indirect working interests in approximately 2,458 gross
      producing gas and oil wells;




·
            we
      manage total proved reserves of 1,003
Bcfe;




·
            we
      own overriding royalty interests in approximately 93 gross producing gas
      and oil wells;




·
            our
      net daily production was 59.7 Mmcfe per
day;




·
            we
      lease approximately 345,680 gross (273,280 net) acres, of which
      approximately 42,390 gross (33,100 net) acres are undeveloped;
      and




·
            we
      drilled 168 gross wells (139 net wells).





In our
Indiana gas and oil operations:





·
            we
      have proved reserves of 10.3 Bcfe;




·
            we
      own direct and indirect working interests in approximately 5 gross
      producing gas and oil wells;




·
            our
      net daily production was 0.2 Mmcfe per
day;




9


·
            we
      have leased approximately 161,140 gross (119,670 net) acres, of which
      approximately 160,480 gross (119,185 net) acres are undeveloped;
      and




·
            we
      drilled 5 gross (4 net) wells.





In our
partnership management business:





·
            Our
      investment partnership business includes equity interests in 94 investment
      partnerships and a registered broker-dealer which acts as the dealer
      manager of our investment partnership
offerings;




·
            we
      raised $438.4 million in investor subscriptions and formed two new public
      partnerships;




·
            we
      manage total Appalachia proved reserves of 706
  Bcfe;




·
            we
      drilled 838 gross wells (789 net wells) on behalf of our investment
      partnerships (of which we contributed an approximately 35%
      interest).





Gas
and Oil Production





Production
Profile. The gas and oil wells in each geological basin in which we
operate  share a relatively predictable production profile, producing
high quality natural gas at low pressures from several pay zones. Wells in each
region generally demonstrate moderate annual production declines throughout
their economic life, which may continue for 30 years or more without
significant remedial work or the use of secondary recovery
techniques.


10


Production
Volumes. We increased our production volumes in 2008 by 59% over 2007
levels to a record 34.9 Bcfe. Our production in the fourth quarter of 2008 was
9.0 Bcfe, reflecting volumetric growth of 7% on a period-over-period basis and
growth of 2% compared to our production volumes for the third quarter of 2008.
The following table shows our total net gas and oil production volumes during
the last three years (in thousands, except for production per day):





Years Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006Production
      (1):Appalachia:
      (3)Natural
      gas (MMcf)
                    
                    
                    12,086
                    
                    
                    
                    9,912
                    
                    
                    
                    8,946Oil
      (000’s Bbls)
                    
                    
                    155
                    
                    
                    
                    153
                    
                    
                    
                    151Total
      (MMcfe)
                    
                    
                    13,014
                    
                    
                    
                    10,828
                    
                    
                    
                    9,850Michigan/Indiana:
      (2)Natural
      gas (MMcf)
                    
                    
                    21,816
                    
                    
                    
                    11,051
                    
                    
                    
                    —Oil
      (000’s Bbls)
                    
                    
                    4
                    
                    
                    
                    1
                    
                    
                    
                    —Total
      (MMcfe)
                    
                    
                    21,839
                    
                    
                    
                    11,056
                    
                    
                    
                    —Total:Natural
      gas (MMcf)
                    
                    
                    33,902
                    
                    
                    
                    20,963
                    
                    
                    
                    8,946Oil
      (000’s Bbls)
                    
                    
                    159
                    
                    
                    
                    154
                    
                    
                    
                    151Total
      (MMcfe)
                    
                    
                    34,853
                    
                    
                    
                    21,884
                    
                    
                    
                    9,850Production
      per day:Appalachia:Natural
      gas (Mcf/d)
                    
                    
                    33,023
                    
                    
                    
                    27,156
                    
                    
                    
                    24,511Oil
      (Bbl)
                    
                    
                    423
                    
                    
                    
                    418
                    
                    
                    
                    413Total
      (Mcfe/d)
                    
                    
                    35,558
                    
                    
                    
                    29,666
                    
                    
                    
                    26,989Michigan/Indiana:Natural
      gas (Mcf/d)
                    
                    
                    59,606
                    
                    
                    
                    59,737
                    (2)
                    
                    
                    —Oil
      (Bbl)
                    
                    
                    11
                    
                    
                    
                    4
                    
                    
                    
                    —Total
      (Mcfe/d)
                    
                    
                    59,672
                    
                    
                    
                    59,761
                    
                    
                    
                    —Total:Natural
      gas (Mcf/d)
                    
                    
                    92,629
                    
                    
                    
                    86,893
                    
                    
                    
                    24,511Oil
      (bpd)
                    
                    
                    434
                    
                    
                    
                    422
                    
                    
                    
                    413Total
      (Mcfe/d)
                    
                    
                    95,227
                    
                    
                    
                    89,425
                    
                    
                    
                    26,989





(1)
            Production
      quantities consist of the sum of (i) our proportionate share of production
      from wells in which we have a direct interest, based on our proportionate
      net revenue interest in such wells, and (ii) our proportionate share of
      production from wells owned by the investment partnerships in which we
      have an interest, based on our equity interest in each such partnership
      and based on each partnership’s proportionate net revenue interest in
      these wells.


(2)
            Amounts
      represent production volumes related to DTE Gas & Oil, LLC, now known
      as “AGO”, from the acquisition date (June 29, 2007) to December 31,
      2007.


(3)
            Appalachia
      includes our production located in Pennsylvania, Ohio, New York, West
      Virginia, and Tennessee.


11


Production
Revenues, Prices and Costs. Our production revenues and estimated gas and
oil reserves are substantially dependent on prevailing market prices for natural
gas, which comprised 99% of our proved reserves on an energy equivalent basis at
the end of 2008. The following table shows our production revenues and our
average sales prices for our oil and gas production during the last three years,
along with our average production costs, taxes, and transmission and compression
costs in each of the reported periods.





Years Ended December 31,2008
                          
                          
                          2007
                          
                          
                          2006Production
      Revenues (in thousands):Appalachia:Natural
      gas revenue
                          
                          $
                          113,595
                          
                          
                          $
                          88,269
                          
                          
                          $
                          79,016Oil
      revenue
                          
                          
                          14,275
                          
                          
                          
                          10,704
                          
                          
                          
                          9,433Total
      revenues
                          
                          $
                          127,870
                          
                          
                          $
                          98,973
                          
                          
                          $
                          88,449Michigan/Indiana:Natural
      gas revenue
                          
                          $
                          183,550
                          
                          
                          $
                          81,045
                          
                          
                          $
                          —Oil
      revenue
                          
                          
                          365
                          
                          
                          
                          64
                          
                          
                          
                          —Total
      revenues
                          
                          $
                          183,915
                          
                          
                          $
                          81,109
                          
                          
                          $
                          —Total:Natural
      gas revenue
                          
                          $
                          297,145
                          
                          
                          $
                          169,314
                          
                          
                          $
                          79,016Oil
      revenue
                          
                          
                          14,640
                          
                          
                          
                          10,768
                          
                          
                          
                          9,433Total
      revenues
                          
                          $
                          311,785
                          
                          
                          $
                          180,082
                          
                          
                          $
                          88,449Average
      Sales Price:Appalachia:Natural
      gas (per Mcf)Total
      realized price, after hedge
                          
                          $
                          9.40
                          
                          
                          $
                          8.91
                          
                          
                          $
                          8.83Total
      realized price, before hedge
                          
                          $
                          9.63
                          
                          
                          $
                          7.71
                          
                          
                          $
                          7.90Michigan/Indiana:Natural
      gas (per Mcf)Total
      realized price, after hedge
                          
                          $
                          8.98
                          
                          
                          $
                          8.44
                          
                          
                          $
                          —Total
      realized price, before hedge
                          
                          $
                          9.01
                          
                          
                          $
                          6.78
                          
                          
                          $
                          —Total:Natural
      gas (per Mcf)Total
      realized price, after hedge
                          
                          $
                          9.13
                          
                          
                          $
                          8.66
                          
                          
                          $
                          8.83Total
      realized price, before hedge
                          
                          $
                          9.23
                          
                          
                          $
                          7.22
                          
                          
                          $
                          7.90Appalachia:Oil
      (per Bbl)Total
      realized price, after hedge
                          
                          $
                          92.28
                          
                          
                          $
                          70.11
                          
                          
                          $
                          62.30Total
      realized price, before hedge
                          
                          $
                          91.71
                          
                          
                          $
                          70.11
                          
                          
                          $
                          62.30Michigan/Indiana:Oil
      (per Bbl)Total
      realized price, after hedge
                          
                          $
                          94.93
                          
                          
                          $
                          80.66
                          
                          
                          $
                          —Total
      realized price, before hedge
                          
                          $
                          94.93
                          
                          
                          $
                          80.66
                          
                          
                          $
                          —Total:Oil
      (per Bbl)Total
      realized price, after hedge
                          
                          $
                          92.35
                          
                          
                          $
                          70.16
                          
                          
                          $
                          62.30Total
      realized price, before hedge
                          
                          $
                          91.79
                          
                          
                          $
                          70.16
                          
                          
                          $
                          62.30Production
      Costs (per Mcfe):Appalachia:Lease
      operating expenses
                          
                          $
                          1.03
                          
                          
                          $
                          0.86
                          
                          
                          $
                          0.83Production
      taxes
                          
                          
                          0.03
                          
                          
                          
                          0.03
                          
                          
                          
                          0.03Transportation
      and compression
                          
                          
                          0.87
                          
                          
                          
                          0.74
                          
                          
                          
                          0.55$
                          1.93
                          
                          
                          $
                          1.63
                          
                          
                          $
                          1.41Michigan/Indiana:Lease
      operating expenses
                          
                          $
                          0.75
                          
                          
                          $
                          0.68
                          
                          
                          $
                          —Production
      taxes
                          
                          
                          0.54
                          
                          
                          
                          0.26
                          
                          
                          
                          —Transportation
      and compression
                          
                          
                          0.29
                          
                          
                          
                          0.38
                          
                          
                          
                          —$
                          1.58
                          
                          
                          $
                          1.32
                          
                          
                          $
                          —Total:Lease
      operating expenses
                          
                          $
                          0.85
                          
                          
                          $
                          0.77
                          
                          
                          $
                          0.83Production
      taxes
                          
                          
                          0.35
                          
                          
                          
                          0.21
                          
                          
                          
                          0.03Transportation
      and compression
                          
                          
                          0.51
                          
                          
                          
                          0.49
                          
                          
                          
                          0.55$
                          1.71
                          
                          
                          $
                          1.47
                          
                          
                          $
                          1.41


12





Investment
Partnerships and Drilling Operations





Drilling
Operations





At the
end of 2008, we owned working interests in approximately 10,957 gross
wells.  These wells are concentrated in the Appalachian Basin, where
we operate and control 73% through our investment partnerships, and in
Michigan’s Upper lower peninsula. We believe our long and successful operating
history in Appalachia and proven ability to drill a large number of wells year
after year have positioned us as a leading player in this region. We generally
fund our drilling activities, other than those of our Michigan business unit,
through sponsorship of tax-advantaged investment partnerships. Accordingly, the
amount of development activities we undertake depends in part upon our ability
to obtain investor subscriptions to the Partnerships. We generally structure our
investment partnerships so that, upon formation of a partnership, we coinvest in
and contribute leasehold acreage to it, enter into drilling and well operating
agreements with it and become its managing general partner. 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 natural gas
and oil prices. We receive an interest in our investment partnerships
proportionate to the amount of capital and the value of the leasehold acreage we
contribute, typically 20% to 31% of the overall capitalization in a particular
partnership. We also receive an additional interest in each partnership,
typically 7%-10%, for which we do not make any additional capital contribution,
for a total interest in our partnerships ranging from 27% to 40%.





We do not
operate any of the rigs or related equipment used in our drilling operations,
relying instead on specialized subcontractors or joint venture partners for all
drilling and completion work. This enables us to streamline our operations and
conserve capital for investments in new wells, infrastructure and property
acquisitions, while generally retaining control over all geological, drilling,
engineering and operating decisions. Other than our Marcellus Shale and
horizontal wells, the geological characteristics of our Appalachian and
Michigan  properties enable us to drill most of our vertical wells in
seven to ten days, although we usually defer completion operations until the
gathering lines are in place. We perform regular inspection, testing and
monitoring functions on our operated wells and gathering systems with our own
personnel.





Drilling
Programs





Drilling
Program Capital. During the last three years, we raised over $1.0 billion
from outside investors for participation in our drilling partnerships. Net
proceeds from these programs are used to fund the investors’ share of drilling
and completion costs under our drilling contracts with the programs. These
contract payments are recorded as “Liabilities associated with drilling
contracts” at the time of receipt. We recognize revenues from drilling
operations on the percentage-of-completion method as the wells are drilled,
rather than when funds are received. “Liabilities associated with drilling
contracts” are reflected as current liabilities in our consolidated financial
statements and represent the net unapplied advance program payments for wells
that were not yet drilled or are in progress as of the balance sheet dates. Our
fund raising activities of sponsored drilling programs during the last three
years are summarized in the following table:





Drilling Program Capital (in thousands)Years Ending December 31,
                  
                  Investor
                    Contributions
                  
                  
                  Our
                    Contributions
                  
                  
                  Total
                    Capital2008
                  
                  $
                  438.4
                  
                  
                  $
                  146.3
                  
                  
                  $
                  584.72007
                  
                  
                  363.3
                  
                  
                  
                  137.6
                  
                  
                  
                  500.92006
                  
                  
                  218.5
                  
                  
                  
                  73.6
                  
                  
                  
                  292.1Total
                  
                  $
                  1,020.2
                  
                  
                  $
                  357.5
                  
                  
                  $
                  1,377.7


13





Drilling
Program Results. The number of wells we drill will vary depending on the
amount of money we raise through our investment partnerships, the cost of each
well, the depth or type of each well, the estimated recoverable reserves
attributable to each well and accessibility to the well site. The following
table shows the number of gross and net development wells we drilled for us and
our investment partnerships during the last three years. During the fourth
quarter of 2008, we drilled 104 gross (96 net) wells in
Appalachia.  We did not drill any exploratory wells during the years
ended December 31, 2008, 2007 and 2006, respectively.





Our Share
                  
                  
                  DryYears Ended December 31,
                  
                  Gross
                  
                  
                  Net
                  
                  
                  of Net(1)
                  
                  
                  Gross
                  
                  
                  NetAppalachia2008
                  
                  
                  830
                  
                  
                  
                  786
                  
                  
                  
                  279
                  
                  
                  
                  8
                  
                  
                  
                  32007
                  
                  
                  1,106
                  
                  
                  
                  1,021
                  
                  
                  
                  378
                  
                  
                  
                  11
                  
                  
                  
                  42006
                  
                  
                  711
                  
                  
                  
                  655
                  
                  
                  
                  235
                  
                  
                  
                  4
                  
                  
                  
                  1Total
                  
                  
                  2,647
                  
                  
                  
                  2,462
                  
                  
                  
                  892
                  
                  
                  
                  23
                  
                  
                  
                  8Michigan/Indiana2008
                  
                  
                  173
                  
                  
                  
                  143
                  
                  
                  
                  140
                  
                  
                  
                  —
                  
                  
                  
                  —2007
                  
                  
                  115
                  
                  
                  
                  92
                  
                  
                  
                  92
                  
                  
                  
                  —
                  
                  
                  
                  —2006
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Total
                  
                  
                  288
                  
                  
                  
                  235
                  
                  
                  
                  232
                  
                  
                  
                  —
                  
                  
                  
                  —





(1)
              Includes
      (i) our percentage interest in wells in which we have a direct ownership
      interest and (ii) our percentage interest in the wells based on our
      percentage interest in our investment
  partnerships.





Drilling
Program Revenue Streams.As managing general partner of our
investment partnerships, we receive the following fees:





·
            Well construction and
      completion.For each well that is drilled by an investment
      partnership, we receive an 18% mark-up on those costs incurred to drill
      and complete the well.  Prior to our most recent investment
      program, Atlas Resources Public #18-2008 Program, formed in November 2008,
      the mark-up was 15%.





·
            Administration and oversight.For each well drilled by an investment partnership, we receive a
      fixed fee of $15,700 for non-Marcellus Shale wells and $62,241 for
      Marcellus Shale wells. Prior to our most recent investment program, Atlas
      Resources Public #18-2008 Program, formed in November 2008, the
      administration and oversight fees were $15,000 for a non-Marcellus Shale
      well and $60,000 for a Marcellus Shale well.  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
      $477, increasing to $975 for Marcellus Shale wells, 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.





·
            Gathering.Each
      partnership pays us a gathering fee.  We, in turn, pay this
      gathering fee to Atlas Pipeline pursuant to the terms of our contribution
      agreement with Atlas America, entered into at the time of our initial
      public offering in December 2006.  Therefore, our gathering
      revenues and costs within our partnership management segment net to $0.
      Please read “− Other Agreements with Atlas America and Its Affiliates −
      Contribution Agreement.” We also pay our proportionate share of gathering
      fees based on our percentage interest in the well, which are included in
      gas and oil production expense.





We
generally agree to subordinate up to 50% of our share of production revenues to
specified returns to the investor partners, typically 10% per year for the first
five years of distributions. We have not subordinated our share of revenues from
any of our investment partnerships since March 2005, but did subordinate $91,000
in fiscal 2005.We do not believe any amounts which may be subordinated in the
future will be material to our operations.


14





Our
investment partnerships provide tax advantages to their investors because an
investor’s share of the partnership’s intangible drilling cost deduction may be
used to offset taxable ordinary income. Intangible drilling costs include items
that do not have salvage value, such as labor, fuel, repairs, supplies and
hauling. Currently, under our most recent partnership agreement, Atlas Resources
Public #18-2008 Program, approximately 85% of the subscription proceeds received
have been used to pay 100% of the partnership’s intangible drilling costs. For
example, an investment of $10,000 generally permits the investor to deduct from
taxable ordinary income approximately $8,500 in the year in which the investor
invests.  Prior to Atlas Resources Public #18-2008 Program,
approximately 90% of the subscription proceeds received were used to pay 100% of
the partnership’s intangible drilling costs.





Natural
Gas Sales





Appalachia





In
Appalachia, we have a natural gas supply agreement with Hess Corporation, which
is valid through March 31, 2009. Subject to certain exceptions, Hess
Corporation has a last right of refusal to buy all of the natural gas produced
and delivered by us and our affiliates, including our investment partnerships,
at certain delivery points with the facilities of:






·
            East
      Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and
      Peoples Natural Gas Company, which are local distribution companies;
      and




·
            National
      Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas
      Pipeline Company, and Texas Eastern Transmission Company, which are
      interstate pipelines.




A portion
of our and our investment partnerships’ natural gas is subject to the agreement
with Hess Corporation, with the following exceptions:




·
            natural
      gas we sell to Warren Consolidated, an industrial end-user and direct
      delivery customer;




·
            natural
      gas that at the time of the agreement was already dedicated for the life
      of the well to another buyer;




·
            natural
      gas that is produced by a company which was not an affiliate of ours at
      the time of the agreement;




·
            natural
      gas sold through interconnects established subsequent to the
      agreement;




·
            natural
      gas that is delivered to interstate pipelines or local distribution
      companies other than those described above;
and




·
            natural
      gas that is produced from wells operated by a third party or subject to an
      agreement under which a third party was to arrange for the gathering and
      sale of the natural gas.




Based on
the most recent monthly production data available to us as of December 31,
2008, we anticipate that we and our affiliates, including our investment
partnerships, will sell approximately 16% of our Appalachian natural gas
production during the year ending December 31, 2009 under the Hess Corporation
agreement. The agreement requires the parties to negotiate a new pricing
arrangement at each annual delivery point. If, at the end of any applicable
period, the parties cannot agree to a new price for any delivery point, then we
may solicit offers from third parties to buy the natural gas for that delivery
point. If Hess Corporation does not match this price, then we may sell the
natural gas to the third party. We market the remainder of our natural gas,
which is principally located in the Fayette County, PA area, primarily to
Colonial Energy, Inc., UGI Energy Services, and others. See “—Major Customers.”
During the year ended December 31, 2008, we received an average price,
before the effects of financial hedges, of $9.63 per Mcf of natural gas,
compared to $7.71 per Mcf in fiscal 2007 and $7.90 per Mcf in fiscal 2006,
respectively, in our Appalachian operations.




We expect
that natural gas produced from our wells drilled in areas of the Appalachian
Basin other than those described above will be primarily tied to the spot market
price and supplied to:




·
            gas
      marketers;




·
            local
      distribution companies;




·
            industrial
      or other end-users; and/or




·
            companies
      generating electricity.


15
 
 Michigan
 
 In
Michigan, we have natural gas sales agreements with DTE Energy Company, which
are valid through December 31, 2012. DTE has the obligation to purchase all of
the natural gas produced and delivered by us and our affiliates from specific
projects at certain delivery points with the facilities of:
 
 ·
              Merit
      Plant/Michigan Consolidated Gas Company (MCGC)
  Kalkaska;
 
 ·
              MCGC
      Jordan 4, Chestonia 17, Mancelona 19, Saginaw Bay and Woolfolk;
      and
 
 ·
              Consumers
      Energy Goose Creek and Wilderness
Plant,
 
 Based on
the most recent monthly production data available to us as of December 31, 2008,
we anticipate that we and our affiliates will sell approximately 49% of our
Michigan natural gas production during the year ending December 31, 2009 under
the DTE agreements in most cases, at NYMEX pricing.  During the year
ended December 31, 2008 and the six months ended December 31, 2007, we received
an average price before the effects of financial hedges of $9.01 and $6.78 per
Mcf of natural gas, respectively, in our Michigan operations.
  Crude
Oil Sales
 
 Crude oil produced from our wells flows
directly into storage tanks where it is picked up by the oil company, a common
carrier, or pipeline companies acting for the oil company, which is purchasing
the crude oil. We sell any oil produced by our Appalachian wells to regional oil
refining companies at the prevailing spot market price for Appalachian crude
oil. In Michigan, oil production is minimal and the property operator typically
markets the oil produced.
  Asset
Retirement Obligations
  When we
determine that a well is no longer capable of producing natural gas or oil in
economic quantities, we must dismantle the well and restore and reclaim the
surrounding area before we can abandon the well. We contract these operations to
independent service providers to whom we pay a fee. The contractor will also
salvage the equipment on the well, which we then sell in the used equipment
market. Under the partnership agreements of our investment partnerships, which
own the majority of our Appalachia wells, we are allocated abandonment costs in
proportion to our partnership interest (generally between 15% and 38%) and are
allocated between 65% and 100% of the salvage proceeds. As a consequence, we
generally receive proceeds from salvaged equipment at least equal to, and
typically exceeding, our share of the related costs.
  Natural
Gas Hedging
  Financial
Hedges.We
seek to provide greater stability in our cash flows through our use of financial
hedges. The financial hedges may include purchases of regulated NYMEX futures
and options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. The futures contracts are commitments to purchase or
sell natural gas at future dates and generally cover one-month periods for up to
six years in the future. To assure that the financial instruments will be used
solely for hedging price risks and not for speculative purposes, we have a
management hedge committee to assure that all financial trading is done in
compliance with our hedging policies and procedures. We do not intend to
contract for positions that we cannot offset with actual
production.
  Physical
Hedges.  Hess
Corporation and other third-party marketers to which we sell gas, such as
Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial
instruments to hedge their pricing exposure and make price hedging opportunities
available to us through physical hedge transactions. These transactions are not
deemed hedges for accounting purposes because they require firm delivery of
natural gas and are considered normal sales of natural gas. We generally limit
these arrangements to much smaller quantities than those projected to be
available at any delivery point. The price paid by these third-party marketers
for volumes of natural gas sold under these sales agreements may be
significantly different from the underlying monthly spot market
value.
 
  16
  Natural
Gas Gathering
 
 Appalachia
  We
conduct our natural gas transportation and processing operations through Atlas
Pipeline and, to a lesser extent, the transportation and processing facilities
we own directly.  Atlas Pipeline owns approximately 1,835 miles of
gathering systems located in eastern Ohio, western New York and western
Pennsylvania serving approximately 7,440 wells.
  In connection with the completion of
our initial public offering, and the contribution by Atlas America of its
natural gas and oil development and production assets to us, we entered into the
following agreements with Atlas Pipeline.
 
 Omnibus
Agreement
 
 Under the
omnibus agreement, Atlas America and its affiliates agreed to add wells to Atlas
Pipeline's gathering systems and provide consulting services when Atlas Pipeline
constructs new gathering systems or extends existing systems. We joined the
omnibus agreement as an obligor (except for the provisions of the omnibus
agreement imposing conditions upon the disposition of the general partner
interest of Atlas Pipeline's general partner), and Atlas America became
secondarily liable as a guarantor of our performance. The omnibus agreement is a
continuing obligation, having no specified term or provisions regarding
termination except for a provision terminating the agreement if Atlas Pipeline's
general partner is removed without cause.
 
 Well
connections.  We are required to construct, at our sole cost
and expense, up to 2,500 feet of small diameter (two inches or less) sales or
flow lines from the wellhead of any well we drill and operate to a point of
connection to Atlas Pipeline’s gathering systems. Where we have extended sales
and flow lines to within 1,000 feet of one of Atlas Pipeline’s gathering
systems, we may require Atlas Pipeline to extend its system to connect to that
well. With respect to other wells that are more than 2,500 feet from Atlas
Pipeline’s gathering systems, Atlas Pipeline has the right, at its cost and
expense, to extend its gathering system to within 2,500 feet of the well and to
require us, at our cost and expense, to construct up to 2,500 feet of flow line
to connect to the gathering system extension. If Atlas Pipeline elects not to
exercise its right to extend its gathering systems, we may connect a well to a
natural gas gathering system owned by a third party or to any other delivery
point; however, Atlas Pipeline will have the right to assume the cost of
construction of the necessary flow lines, which then become its property and
part of its gathering systems.
  Consulting
services.  The omnibus agreement requires us to assist Atlas
Pipeline in identifying existing gathering systems for possible acquisition and
to provide consulting services to Atlas Pipeline in evaluating and making a bid
for these systems. We must give Atlas Pipeline notice of identification by us or
any of our affiliates of any gathering system as a potential acquisition
candidate, and must provide Atlas Pipeline with information about the gathering
system, its seller and the proposed sales price, as well as any other
information or analyses we compile with respect to the gathering system. Atlas
Pipeline must determine, within a time period specified by our notice to it,
which must be a reasonable time under the circumstances, whether it wants to
acquire the identified system and advise us of its intent. If Atlas Pipeline
advises us that it does not intend to make the acquisition, does not complete
the acquisition within a reasonable time period, or advises us that it does not
intend to acquire the system, then we may do so.
  Gathering system
construction.  We will provide Atlas Pipeline with construction
management services if Atlas Pipeline determines to expand one or more of its
gathering systems. We are entitled to reimbursement for our costs, including an
allocable portion of employee salaries, in connection with our construction
management services.
 
 Natural
Gas Gathering Agreements
 
 Under our
master natural gas gathering agreement with Atlas Pipeline, we pay gathering
fees as follows:
 
 ·
              for
      natural gas from our well interests, other than those of our investment
      partnerships, that were connected to Atlas Pipeline’s gathering systems at
      February 2, 2000, the greater of $0.40 per Mcf or 16% of the gross sales
      price of the natural gas
transported;
  ·
              for
      (i) natural gas from well interests allocable to our investment
      partnerships that drilled or drill wells on or after December 1, 1999 that
      are connected to the gathering systems; (ii) natural gas from our well
      interests, other than those of our investment partnerships, that are
      connected to the gathering systems after February 2, 2000; and (iii) well
      interests allocable to third parties in wells connected to the gathering
      systems at February 2, 2000, the greater $0.35 per Mcf or 16% of the gross
      sales price of the natural gas transported;
and
  17
  ·
              for
      natural gas from well interests we operate and drilled after December 1,
      1999 that are connected to a gathering system that is not owned by Atlas
      Pipeline and for which Atlas Pipeline assumes the cost of constructing the
      connection to that gathering system, an amount equal to the greater of
      $0.35 per Mcf or 16% of the gross sales price of the natural gas
      transported, less the gathering fee charged by the other gathering
      system.
 
 We
receive gathering fees from contracts or other arrangements with the owners of
well interests connected to Atlas Pipeline’s gathering systems. Pursuant to the
contribution agreement described below under "—Other Agreements with Atlas
America and its Affiliates—Contribution Agreement,” Atlas America agreed to
assume our obligation to pay gathering fees to Atlas Pipeline. We, in turn,
assigned to Atlas America the gathering fees we receive from our investment
partnerships and gathering fees attributable to our production interest. The
gathering fees payable to Atlas Pipeline generally exceed the amount we receive
from our investment partnerships for gathering services.  If Atlas
America fails to pay gathering fees to Atlas Pipeline as required by its
assumption agreement with us, we will have to pay to Atlas Pipeline the
difference between the gathering fee payable and the amount we receive from our
investment partnerships for gathering services out of our own
resources.
 
 The
master natural gas gathering agreement is a continuing obligation and,
accordingly, has no specified term or provisions regarding termination. However,
if Atlas Pipeline’s general partner is removed as the general partner of Atlas
Pipeline without cause, then no gathering fees will be due under the agreement
with respect to new wells drilled by us.
 
 In
addition to the master natural gas gathering agreement, we are party to three
other gas gathering agreements with Atlas Pipeline:
 
 ·
              Under
      two agreements, relating to wells located in southeastern Ohio, which were
      originally acquired from Kingston Oil Corporation, and wells located
      Fayette County, Pennsylvania, which were originally acquired from American
      Refining and Exploration Company, we pay Atlas Pipeline gathering fees of
      $0.80 per Mcf. These wells are owned directly by our subsidiaries, and
      Atlas America has not assumed any part of our obligation to pay the
      gathering fees to Atlas Pipeline under these
  agreements.
  ·
              Under
      another agreement, which covers wells owned by third parties unrelated to
      our investment partnerships and us, we pay Atlas Pipeline gathering fees
      that range between $0.20 and $0.29 per Mcf or between 10% to 16% of the
      weighted average sales price. The gathering fees payable under this
      agreement are a direct pass-through of the gathering fees we receive from
      the third party wells. Accordingly, Atlas America has not assumed any part
      of our obligation to pay the gathering fees to Atlas Pipeline under this
      agreement, and has been removed as an obligor under
  it.
 
 Michigan
 
 We
transport our natural gas from our Michigan wells through our 1,230 miles of
polypropylene flow lines to centrally located separation, compression and
dehydration facilities, which we refer to as CPFs, where water is separated from
the natural gas and disposed of. We own interests in 82 CPFs, of which we
operate 62.  The wells generally produce natural gas and water for 3
to 12 months, after which they produce only gas.
 
 We then
transport the compressed and dehydrated gas stream from CPFs via our 186 miles
of sales lines to the northern Michigan high pressure gathering system, which is
composed of a number of gathering systems owned by third party transporters that
deliver gas to delivery points. Compressed and dehydrated gas exiting the CPF
typically has carbon dioxide (CO2) levels in excess of the 2% pipeline
specifications required at the delivery point. Therefore, it is treated at CO2
processing plants located along the northern Michigan high pressure gathering
system before delivery to the delivery points. The CO2 plants utilize either an
amine or membrane treating process. We currently own and operate one amine
processing plant and operate on behalf of DTE four other amine plants and one
membrane plant. We pay third parties an average of $0.30/Mcfe on a net basis for
these transportation and treating services.
  18
  Other
Agreements with Atlas America and Its Affiliates
 
 Contribution
Agreement
 
 Contribution of assets by Atlas
America.  The substantial majority of the Appalachian assets we
own were held, directly or indirectly, by subsidiaries of Atlas America. In
connection with our initial public offering, Atlas America entered into a
contribution agreement pursuant to which it contributed to us all of the stock
of its natural gas and oil development and production subsidiaries as well as
the development and production assets owned by it.  As consideration
for this contribution, we distributed to Atlas America the net proceeds we
received from that offering, as well as 29,352,996 of our common units, the
Class A units and the management incentive interests. As part of the
contribution agreement, Atlas America has agreed to indemnify us for losses
attributable to title defects to our oil and gas property interests for three
years after the closing of the offering, and indefinitely for losses
attributable to retained liabilities and income taxes attributable to
pre-closing operations and formation transactions. Furthermore, we have agreed
to indemnify Atlas America for all losses attributable to the post-closing
operations of the assets contributed to us, to the extent not subject to its
indemnification obligations.
 
 Atlas America’s assumption of
obligations under the master natural gas gathering agreement with Atlas
Pipeline.Upon completion of our initial public offering, we
became a party to an existing master natural gas gathering agreement between
Atlas America and Atlas Pipeline pursuant to which Atlas Pipeline gathers
substantially all of the natural gas from wells operated by us. Pursuant to the
contribution agreement, Atlas America has agreed to assume our obligation to pay
gathering fees to Atlas Pipeline under the master natural gas gathering
agreement; we have agreed to pay Atlas America the gathering fees we receive
from our investment partnerships and fees associated with production to our
interest.
 
 Management
Agreement
 
 Upon
completion of our initial public offering, we entered into a management
agreement with Atlas Energy Management, a subsidiary of Atlas America, pursuant
to which Atlas Energy Management will manage our business affairs under the
supervision of our board of directors. Atlas Energy Management will provide us
with all services necessary or appropriate for the conduct of our business. In
exercising its powers and discharging its duties under the management agreement,
Atlas Energy Management must act in good faith.
 
 Before
making any distribution on our common units, we will reimburse Atlas Energy
Management for all expenses that it incurs on our behalf pursuant to the
management agreement. These expenses will include costs for providing corporate
staff and support services to us. Atlas Energy Management will charge on a fully
allocated cost basis for services provided to us. This fully allocated cost
basis is based on the percentage of time spent by personnel of Atlas Energy
Management and its affiliates on our matters and includes the compensation paid
by Atlas Energy Management and its affiliates to such persons and their
allocated overhead. The allocation of compensation expense for such persons will
be determined based on a good faith estimate of the value of each such person’s
services performed on our business and affairs, subject to the periodic review
and approval of our audit or conflicts committee.
 
 Atlas
Energy Management, its stockholders, directors, officers, employees and
affiliates will not be liable to us, our directors or unit holders for acts or
omissions performed in good faith and in accordance with and pursuant to the
management agreement, except because of acts constituting gross negligence, bad
faith, willful misconduct, fraud or a knowing violation of criminal law. We will
indemnify Atlas Energy Management, its stockholders, directors, officers,
employees and affiliates with respect to all expenses, losses, damages,
liabilities, demands, charges and claims arising from acts of Atlas Energy
Management, its stockholders, directors, officers, employees and affiliates not
constituting gross negligence, bad faith, willful misconduct, fraud or a knowing
violation of criminal law performed in good faith in accordance with and
pursuant to the management agreement. Atlas Energy Management and its affiliates
will indemnify us and our directors and officers with respect to all expenses,
losses, damages, liabilities, demands, charges and claims arising from acts of
Atlas Energy Management or its affiliates constituting gross negligence, bad
faith, willful misconduct, fraud or a knowing violation of criminal law or any
claims by employees of Atlas Energy Management or its affiliates relating to the
terms and conditions of their employment. Atlas Energy Management and/or Atlas
America will carry errors, omissions, and other customary
insurance.
 
 The
management agreement may not be amended without the prior approval of our
conflicts committee if the proposed amendment will, in the reasonable discretion
of our board, adversely affect our common unit holders.
  19
  The
management agreement does not have a specific term; however, Atlas Energy
Management may not terminate the agreement before December 18, 2016. We may
terminate the management agreement only upon the affirmative vote of holders of
at least two-thirds of our outstanding common units, including units held by
Atlas America. In the event we terminate the management agreement, Atlas Energy
Management will have the option to require thesuccessor manager, if any,
to purchase its membership interests and management incentive interests for
their fair market value as determined by agreement between the departing manager
and the successor manager.
 
 Anthem
Securities, Inc.
 
 Anthem
Securities is our registered broker-dealer subsidiary, which acts as the
dealer-manager for our investment partnership offerings. Anthem Securities is
registered as a broker-dealer solely involved in direct participation programs
such as our investment partnerships, and does not maintain customer accounts or
custody of securities.  Anthem Securities has been a member of FINRA,
formerly known as the National Association of Securities Dealers, Inc., since
1997.
  Availability
of Oil Field Services
  We
contract for drilling rigs and purchase goods and services necessary for the
drilling and completion of wells from a number of drillers and suppliers, none
of which supplies a significant portion of our annual needs. During fiscal 2008,
we faced no shortage of these goods and services.  We cannot predict
the duration or stability of the current level of supply and demand for drilling
rigs and other goods and services required for our operations with any certainty
due to numerous factors affecting the energy industry, including the demand for
natural gas and oil.
 
 Major
Customers
 
 Our
natural gas is sold under contract to various purchasers.  For the
years ended December 31, 2008 and 2007 and 2006, gas sales to Hess Corporation
(formerly First Energy Solutions Corp.) accounted for 10%, 10% and 18%,
respectively, of our total Appalachian gas and oil production
revenues.  For the year ended December 31, 2008 and the six months
ended December 31, 2007, sales to DTE accounted for 49% and 46% of our Michigan
oil and gas production revenues, respectively.  No other single
customer accounted for more than 10% of our total revenues during these
periods.
 
 Competition
 
 The
energy industry is intensely competitive in all of its aspects. We operate in a
highly competitive environment for acquiring properties and other natural gas
and oil companies, attracting capital through our investment partnerships,
contracting for drilling equipment and securing trained personnel. We also
compete with the exploration and production divisions of public utility
companies for natural gas and oil property acquisitions. Competition is intense
for the acquisition of leases considered favorable for the development of
natural gas and oil in commercial quantities. Our competitors may be able to pay
more for natural gas and oil properties and to evaluate, bid for and purchase a
greater number of properties than our financial or personnel resources permit.
Furthermore, competition arises not only from numerous domestic and foreign
sources of natural gas and oil but also from other industries that supply
alternative sources of energy. Product availability and price are the principal
means of competition in selling natural gas and oil.
 
 Many of
our competitors possess greater financial and other resources than ours, which
may enable them to identify and acquire desirable properties and market their
natural gas and oil production more effectively than we do.
 
 Moreover,
we also compete with a number of other companies that offer interests in
investment partnerships. As a result, competition for investment capital to fund
investment partnerships can be intense.
 
 Markets
 
 The
availability of a ready market for natural gas and oil and the price obtained,
depends upon numerous factors beyond our control, as described in “Risk factors”
Product availability and price are the principal means of competition in selling
natural gas and oil. During the year ended December 31, 2008, we did not
experience problems in selling our natural gas and oil, although prices have
varied significantly during this period.
  20
  Natural
Gas and Oil Leases
 
 General.  The typical
natural gas and oil lease agreement provides for the payment of royalties to the
mineral owner for all natural gas and oil produced from any well(s) drilled on
the leased premises. In the Appalachian Basin, this amount is typically 1/8th(12.5%) resulting in a 87.5% net revenue interest to us, and in
Michigan this amount is typically 1/6th
(16.67%) resulting in an 83.3% net revenue interest to us, for most leases
directly acquired by us. In certain instances, this royalty amount may increase
to 1/6thin the Appalachian Basin and to 3/16th
(18.75%) in Michigan when leases are taken from larger landowners or
mineral owners such as coal and timber companies.
 
 In almost
all of the areas we operate in the Appalachian Basin and in Michigan, the
surface owner is normally the natural gas and oil owner allowing us to deal with
a single owner. This simplifies the research process required to identify the
proper owners of the natural gas and oil rights and reduces the per acre lease
acquisition cost and the time required to successfully acquire the desired
leases.
 
 Because
the acquisition of natural gas and oil leases is a very competitive process, and
involves certain geological and business risks to identify productive areas,
prospective leases are often held by other natural gas and oil operators. In
order to gain the right to drill these leases we may elect to farm-in leases
and/or purchase leases from other natural gas and oil operators. Typically the
assignor of such leases will reserve an overriding royalty interest, ranging in
the Appalachian Basin from 1/32ndto
1/16th(3.125% to 6.25%), which further reduces the net revenue interest
available to us to between 84.375% and 81.25% and in Michigan from 3.33% to
5.33%, which further reduces the net revenue interest available to us to between
80.0% and 78.0%.
 
 Participation
rights.  These rights
give the mineral owner the right to joint venture with us and participate for up
to 50% of the wells drilled on the covered acreage.  In this event,
our working interest ownership will be reduced by the amount retained by the
third party. In all other instances, we anticipate owning a 100% working
interest in newly drilled wells.
 
 Seasonal
Nature of Business
 
 Seasonal
weather conditions and lease stipulations can limit our drilling and producing
activities and other operations in certain areas of the Appalachian region and
Michigan. These seasonal anomalies may pose challenges for meeting our well
construction objectives and increase competition for equipment, supplies and
personnel, which could lead to shortages and increase costs or delay our
operations. In the past, we have drilled a greater number of wells during the
winter months because we have typically received the majority of funds from our
investment partnerships during the fourth calendar quarter. Generally, but not
always, the demand for natural gas decreases during the summer months and
increases during the winter months. Seasonal anomalies such as mild winters or
hot summers sometimes lessen this fluctuation. In addition, certain natural gas
users utilize natural gas storage facilities and purchase some of their
anticipated winter requirements during the summer. This can also lessen seasonal
demand fluctuations.
 
 Environmental
Matters and Regulation
 
 General
 
 Our
operations are subject to comprehensive and stringent federal, state and local
laws and regulations governing, among other things, where and how we install
wells, how we handle wastes from our operations and the discharge
of
 materials
into the environment. Our operations will be subject to the same environmental
laws and regulations as other companies in the natural gas and oil industry.
Among other requirements and restrictions, these laws and
regulations:
 
 ·
              require
      the acquisition of various permits before drilling
    commences;
  ·
              require
      the installation of expensive pollution control equipment and water
      treatment facilities;
  ·
              restrict
      the types, quantities and concentration of various substances including
      fracturing and brine water, that can be released into the environment in
      connection with drilling and production
  activities;
  ·
                limit
      or prohibit drilling activities on lands lying within or, in some cases,
      adjoining wilderness, wetlands and other protected
  areas;
  ·
                require
      remedial measures to reduce, mitigate or respond to releases of pollutants
      or hazardous substances from former operations, such as pit closure and
      plugging of abandoned
wells;
  21
  ·
              impose
      substantial liabilities for pollution resulting from our operations;
      and
  ·
              with
      respect to operations affecting federal lands or leases, require
      preparation of a Resource Management Plan, an Environmental Assessment,
      and/or an Environmental Impact
Statement.
  These
laws, rules and regulations may also restrict the rate of natural gas and oil
production below the rate that would otherwise be possible. The regulatory
burden on the natural gas and oil industry increases the cost of doing business
in the industry and consequently affects profitability. Additionally, Congress
and federal and state agencies frequently enact new, and revise existing,
environmental laws and regulations, and any new laws or changes to existing laws
that result in more stringent and costly waste handling, disposal and clean-up
requirements for the natural gas and oil industry, could have a significant
impact on our operating costs. We believe that our operations overall
substantially comply with all currently applicable environmental laws and
regulations and that our continued compliance with existing requirements will
not have a material adverse impact on our financial condition and results of
operations. However, we cannot predict how environmental laws and regulations
that may take effect in the future may affect our properties or operations. For
the years ended December 31, 2008, 2007 and 2006, we did not incur any
material capital expenditures for installation of remediation or pollution
control equipment at any of our facilities. We are not aware of any
environmental issues or claims that will require material capital expenditures
during 2009, or that will otherwise have a material impact on our financial
position or results of operations.
  Environmental
laws and regulations that could have a material impact on the natural gas and
oil exploration and production industry include the following:
 
 National
Environmental Policy Act
 
 Natural
gas and oil exploration and production activities on federal lands are subject
to the National Environmental Policy Act, or NEPA. NEPA requires federal
agencies, including the Department of Interior, to evaluate major federal agency
actions having the potential to significantly affect the environment. In the
course of such evaluations, an agency will typically require an Environmental
Assessment to assess the potential direct, indirect and cumulative impacts of a
proposed project and, if necessary, will prepare a more detailed Environmental
Impact Statement that will be made available for public review and comment. All
of our proposed drilling and production activities on federal lands require
governmental permits, many of which are subject to the requirements of NEPA.
This process has the potential to delay the development of natural gas and oil
projects.
 
 Waste
Handling
 
 The Solid
Waste Disposal Act, including the Resource Conservation and Recovery Act, or
RCRA, and comparable state statutes regulate the generation, transportation,
treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal
of non-hazardous wastes. Under the auspices of the EPA individual states
administer some or all of the provisions of RCRA, sometimes in conjunction with
their own, more stringent requirements. Drilling fluids, produced waters, and
most of the other wastes associated with the exploration, development, and
production of crude oil and natural gas constitute “solid wastes”, which are
regulated under the less stringent non-hazardous waste provisions, but there is
no guarantee that the EPA or individual states will not adopt more stringent
requirements for the handling of non-hazardous wastes or categorize some
non-hazardous wastes as hazardous for future regulation.
 
 We
believe that our operations are currently in substantial compliance with the
requirements of RCRA and related state and local laws and regulations, and that
we hold all necessary and up-to-date permits, registrations and other
authorizations to the extent that our operations require them under such laws
and regulations. Although we do not believe the current costs of managing our
wastes to be significant, any more stringent regulation of natural gas and oil
exploitation and production wastes could increase our costs to manage and
dispose of such wastes.
 
 Comprehensive
Environmental Response, Compensation and Liability Act
 
 The
Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
also known as the “Superfund” law, imposes joint and several liability, without
regard to fault or legality of conduct, on persons who are considered under the
statute to be responsible for the release of a “hazardous substance” into the
environment. These persons include the owner or operator of the site where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substance at the site. Under CERCLA, such persons may be liable for
the costs of cleaning up the hazardous substances that have been released into
the environment, for damages to natural resources and for the costs of certain
health studies. In addition, it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the
environment.
  22
  Our
operations are, in many cases, conducted at properties that have been used for
natural gas and oil exploitation and production for many years. Although we
believe Atlas America utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances, wastes, or
hydrocarbons may have been released on or under the properties owned or leased
by us or on or under other locations, including off-site locations, where such
substances have been taken for disposal. In addition, some of these properties
have been operated by third parties or by previous owners or operators whose
treatment and disposal of hazardous substances, wastes, or hydrocarbons was not
under our control. These properties and the substances disposed or released on
them may be subject to CERCLA, RCRA and analogous state laws. Under such laws,
we could be required to remove previously disposed substances and wastes,
remediate contaminated property, or perform remedial plugging or pit closure
operations to prevent future contamination.
 
 Water
Discharges
 
 The
Federal Water Pollution Control Act, also known as the Clean Water Act, and
analogous state laws impose restrictions and strict controls on the discharge of
pollutants, including produced waters and other natural gas and oil wastes, into
navigable waters of the United States. The discharge of pollutants into
regulated waters is prohibited, except in accordance with the terms of a permit
issued by EPA or the relevant state.  These permits may require
pretreatment of produced waters before discharge.  Compliance with
such permits and requirements may be costly.  The Clean Water Act also
prohibits the discharge of dredge and fill material in regulated waters,
including wetlands, unless authorized by a permit issued by the U.S. Army Corps
of Engineers. The Clean Water Act also requires specified facilities to maintain
and implement spill prevention, control and countermeasure plans and to take
measures to minimize the risks of petroleum spills. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties for failure to
obtain or non-compliance with discharge permits or other requirements of the
federal Clean Water Act and analogous state laws and regulations. We believe our
operations on the whole are in substantial compliance with the requirements of
the Clean Water Act.
 
 Air
Emissions
 
 The Clean
Air Act, and associated state laws and regulations, regulate emissions of
various air pollutants through permits and other requirements. In addition, EPA
has developed, and continues to develop, stringent regulations governing
emissions of toxic and other air pollutants at specified sources. Some of our
new facilities may be required to obtain permits before work can begin, and
existing facilities may be required to incur capital costs in order to comply
with new emission limitations. These regulations may increase the costs of
compliance for some facilities, and federal and state regulatory agencies can
impose administrative, civil and criminal penalties for non-compliance. These
laws and regulations also apply to entities that use natural gas as fuel, and
may increase the costs of compliance of our customers to the point where demand
for natural gas is affected. We believe that our operations are in substantial
compliance with the requirements of the Clean Air Act.
 
 OSHA
and Other Regulations
 
 We are
subject to the requirements of the federal Occupational Safety and Health Act,
or OSHA, and comparable state statutes. The OSHA hazard communication standard,
the EPA community right-to-know regulations under the Title III of CERCLA and
similar state statutes require that we organize and/or disclose information
about hazardous materials used or produced in our operations. We believe that we
are in substantial compliance with these applicable requirements and with other
OSHA and comparable requirements.
 
 Other
Laws and Regulation
 
 The Kyoto
Protocol to the United Nations Framework Convention on Climate Change became
effective in February 2005. Under the Protocol, participating nations are
required to implement programs to reduce emissions of certain gases, generally
referred to as greenhouse gases, that are suspected of contributing to global
warming. The United States is not currently a participant in the Protocol, and
Congress has resisted recent proposed legislation directed at reducing
greenhouse gas emissions. However, there has been support in various regions of
the country for legislation that requires reductions in greenhouse gas
emissions, and some states have already adopted legislation addressing
greenhouse gas emissions from various sources, primarily power plants. The
natural gas and oil industry is a direct source of certain greenhouse gas
emissions, namely carbon dioxide and methane, and future restrictions on such
emissions could affect our future operations. Our operations are not adversely
impacted by current state and local climate change initiatives and, at this
time, it is not possible to accurately estimate how potential future laws or
regulations addressing greenhouse gas emissions would affect our
business.
  23
 
 Other
Regulation of the Natural Gas and Oil Industry
 
 The
natural gas and oil industry is extensively regulated by numerous federal, state
and local authorities. Legislation affecting the natural gas and oil industry is
under constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both federal and
state, are authorized by statute to issue rules and regulations binding on the
natural gas and oil industry and its individual members, some of which carry
substantial penalties for failure to comply. Although the regulatory burden on
the natural gas and oil industry increases our cost of doing business and,
consequently, affects our profitability, these burdens generally do not affect
us any differently or to any greater or lesser extent than they affect other
companies in the industry with similar types, quantities and locations of
production.
 
 Legislation
continues to be introduced in Congress and development of regulations continues
in the Department of Homeland Security and other agencies concerning the
security of industrial facilities, including natural gas and oil
facilities.
 
 Our
operations may be subject to such laws and regulations. Presently, it is not
possible to accurately estimate the costs we could incur to comply with any such
facility security laws or regulations, but such expenditures could be
substantial.
 
 Drilling
and Production
 
 Our
operations are subject to various types of regulation at the federal, state and
local levels. These types of regulation include requiring permits for the
drilling of wells, drilling bonds and reports concerning operations. Most
states, and some counties and municipalities, in which we will operate also
regulate one or more of the following:
 
 ·
              the
      location of wells;
  ·
              the
      manner in which water necessary to develop wells is
    managed;
  ·
              the
      method of drilling and casing
wells;
  ·
              the
      surface use and restoration of properties upon which wells are
      drilled;
  ·
              the
      plugging and abandoning of wells;
and
  ·
              notice
      to surface owners and other third
parties.
 
 State
laws regulate the size and shape of drilling and spacing units or proration
units governing the pooling of natural gas and oil properties. Some states allow
forced pooling or integration of tracts to facilitate exploitation, while other
states rely on voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and may reduce our
interest in the unitized properties. In addition, state conservation laws
establish maximum rates of production from natural gas and oil wells, generally
prohibit the venting or flaring of natural gas and impose requirements regarding
the ratability of production. These laws and regulations may limit the amount of
natural gas and oil we can produce from our wells or limit the number of wells
or the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to the production and sale of oil,
natural gas and natural gas liquids within its jurisdiction.
 
 Natural
Gas Regulation
 
 The
availability, terms and cost of transportation significantly affect sales of
natural gas. The interstate transportation and sale for resale of natural gas is
subject to federal regulation, including regulation of the terms, conditions and
rates for interstate transportation, storage and various other matters,
primarily by the Federal Energy Regulatory Commission. Federal and state
regulations govern the price and terms for access to natural gas pipeline
transportation. The Federal Energy Regulatory Commission’s regulations for
interstate natural gas transmission in some circumstances may also affect the
intrastate transportation of natural gas.
  24
  Although
natural gas prices are currently unregulated, Congress historically has been
active in the area of natural gas regulation. We cannot predict whether new
legislation to regulate natural gas might be proposed, what proposals, if any,
might actually be enacted by Congress or the various state legislatures, and
what effect, if any, the proposals might have on the operations of the
underlying properties. Sales of condensate and natural gas liquids are not
currently regulated and are made at market prices.
 
 State
Regulation
 
 The
various states regulate the drilling for, and the production, gathering and sale
of, natural gas, including imposing severance taxes and requirements for
obtaining drilling permits. For example, Michigan imposes a 4.9% severance tax
on natural gas and a 7.3% severance tax on oil, Tennessee imposes a 3% severance
tax on natural gas and oil production and Ohio imposes a severance tax of $0.25
per Mcf of natural gas and $0.10 per Bbl of oil. While Pennsylvania has
historically not imposed a severance tax, its governor recently proposed a tax
of 5% on the value of natural gas at the wellhead plus $0.047 per Mcf beginning
October 1, 2009.  States also regulate the method of developing new
fields, the spacing and operation of wells and the prevention of waste of
natural gas resources. States may regulate rates of production and may establish
maximum daily production allowables from natural gas wells based on market
demand or resource conservation, or both. States do not regulate wellhead prices
or engage in other similar direct economic regulation, but there can be no
assurance that they will not do so in the future. The effect of these
regulations may be to limit the amounts of natural gas that may be produced from
our wells, and to limit the number of wells or locations we can
drill.
 
 The
petroleum industry is also subject to compliance with various other federal,
state and local regulations and laws. Some of those laws relate to occupational
safety, resource conservation and equal employment opportunity. We do not
believe that compliance with these laws will have a material adverse effect upon
the unit holders.
 
 Employees
 
 We do not have any
employees.  To carry out our operations, our manager and its
affiliates employed approximately 602 persons as of December 31,
2008.
 
 Available
Information
  We make
our periodic reports under the Securities Exchange Act of 1934, including our
annual report on Form 10-K, our quarterly reports on Form 10-Q and our current
reports on Form 8-K, available through our website at www.atlasenergyresources.com.
To view these reports, click on “ATN Unit Holders Investor Relations”, then “SEC
Filings”. You may also receive, without charge, a paper copy of any such filings
by request to us at 1550 Coraopolis Heights Road, Moon Township, Pennsylvania
15108, telephone number (412) 262-2830. A complete list of our filings is
available on the Securities and Exchange Commission’s website at www.sec.gov. Any of
our filings are also available at the Securities and Exchange Commission’s
Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.
The Public Reference Room may be contacted at telephone number
(800) 732-0330 for further information.
 
 The NYSE
requires the chief executive officer of each listed company to certify annually
that he is not aware of any violation by the company of the NYSE corporate
governance listing standards as of the date of the certification, qualifying the
certification to the extent necessary. The Chief Executive Officer provided such
certification to the NYSE in 2008 without qualification.  In addition,
the certifications of the Chief Executive Officer and Chief Financial Officer of
our general partner required by Sections 302 and 906 of the Sarbanes-Oxley Act
have been included as exhibits to this report.
 
 ITEM
      1A:
              RISK
      FACTORS
 
 We may not have sufficient cash flow
from operations to pay quarterly distributions following the establishment of
cash reserves and payment of fees and expenses, including payments to our
manager.We may not have sufficient cash flow from operations
each quarter to pay the quarterly distributions. Under the terms of our limited
liability company agreement, the amount of cash otherwise available for
distribution will be reduced by our operating expenses and the amount of any
cash reserve amounts that our board of directors establishes to provide for
future operations, future capital expenditures, future debt service requirements
and future cash distributions to our unit holders and the holders of the
management incentive interests. The amount of cash we can distribute on our
common units principally depends upon the amount of cash we generate from our
operations, which will fluctuate from quarter to quarter based on, among other
things:
  25
  ·
              the
      amount of natural gas and oil we
produce;
  ·
              the
      price at which we sell our natural gas and
oil;
  ·
              the
      level of our operating costs;
  ·
              our
      ability to acquire, locate and produce new
  reserves;
  ·
              results
      of our hedging activities;
  ·
              the
      level of our interest expense, which depends on the amount of our
      indebtedness and the interest payable on it; and the level of our capital
      expenditures.
 
 The
actual amount of cash we will have available for distribution will depend on
other factors, some of which are beyond our control, including:
 
 ·
              our
      ability to make working capital borrowings to pay
      distributions;
  ·
              the
      cost of acquisitions, if any;
  ·
              fluctuations
      in our working capital needs;
  ·
              timing
      and collectability of receivables;
  ·
              restrictions
      on distributions imposed by
lenders;
  ·
              payments
      to our manager;
  ·
              the
      amount of our estimated maintenance capital
  expenditures;
  ·
              prevailing
      economic conditions; and
  ·
              the
      amount of cash reserves established by our board of directors for the
      proper conduct of our business.
 
 As a
result of these factors, the amount of cash we distribute in any quarter to our
unit holders may fluctuate significantly from quarter to quarter and may be
significantly less than the initial quarterly distribution amount.
 
 If commodity prices decline
significantly, our cash flow from operations will decline.Our revenue,
profitability and cash flow substantially depend upon the prices and demand for
natural gas and oil. The natural gas and oil markets are very volatile and a
drop in prices can significantly affect our financial results and impede our
growth. Changes in natural gas and oil prices will have a significant impact on
the value of our reserves and on our cash flow. Prices for natural gas and oil
may fluctuate widely in response to relatively minor changes in the supply of
and demand for natural gas or oil, market uncertainty and a variety of
additional factors that are beyond our control, such as:
 
 ·
              the
      level of the domestic and foreign supply and
  demand;
  ·
              the
      price and level of foreign imports;
  ·
              the
      level of consumer product demand;
  ·
              weather
      conditions and fluctuating and seasonal
demand;
  ·
              overall
      domestic and global economic
conditions;
  ·
              political
      and economic conditions in natural gas and oil producing countries,
      including those in the Middle East and South
  America;
  ·
              the
      ability of members of the Organization of Petroleum Exporting Countries to
      agree to and maintain oil price and production
  controls;
  ·
              the
      impact of the U.S. dollar exchange rates on natural gas and oil
      prices;
  ·
              technological
      advances affecting energy
consumption;
  ·
              domestic
      and foreign governmental relations, regulations and
    taxation;
  ·
              the
      impact of energy conservation
efforts;
  ·
              the
      cost, proximity and capacity of natural gas pipelines and other
      transportation facilities; and
  26
  ·
              the
      price and availability of alternative
fuels.
  In the past, the prices of natural gas
and oil have been extremely volatile, and we expect this volatility to continue.
For example, during the year ended December 31, 2008, the NYMEX Henry Hub
natural gas index price ranged from a high of $13.11 per MMBtu to a low of $6.47
per MMBtu, and West Texas Intermediate oil prices ranged from a high of $134.02
per Bbl to a low of $42.04 per Bbl.
 
 Unless we replace our reserves, our
reserves and production will decline, which would reduce our cash flow from
operations and impair our ability to make payments on our debt.Producing
natural gas reservoirs generally are characterized by declining production rates
that vary depending upon reservoir characteristics and other factors. Based on
our December 31, 2008 reserve reports, our average annual decline rate for
proved developed producing reserves is approximately 7.8% during the first
five years, approximately 5.3% in the next five years and less than
5.5% thereafter. Because our total estimated proved reserves include proved
undeveloped reserves at December 31, 2008, production will decline at this rate
even if those proved undeveloped reserves are developed and the wells produce as
expected. This rate of decline will change if production from our existing wells
declines in a different manner than we have estimated and can change when we
drill additional wells, make acquisitions and under other circumstances. Thus,
our future natural gas reserves and production and, therefore, our cash flow and
income are highly dependent on our success in efficiently developing and
exploiting our current reserves and economically finding or acquiring additional
recoverable reserves. Our ability to find and acquire additional recoverable
reserves to replace current and future production at acceptable costs depends on
our generating sufficient cash flow from operations and other sources of
capital, including our investment partnerships, all of which are subject to the
risks discussed elsewhere in this section.
 
 Our estimated reserves are based on
many assumptions that may prove to be inaccurate. Any material inaccuracies in
these reserve estimates or underlying assumptions will materially affect the
quantities and present value of our reserves.Underground accumulations
of natural gas and oil cannot be measured in an exact way. Natural gas and oil
reserve engineering requires subjective estimates of underground accumulations
of natural gas and oil and assumptions concerning future natural gas prices,
production levels, and operating and development costs. As a result, estimated
quantities of proved reserves and projections of future production rates and the
timing of development expenditures may prove to be inaccurate. Our independent
petroleum engineers prepare estimates of our proved reserves. Over time, our
internal engineers may make material changes to reserve estimates, taking into
account the results of actual drilling and production. Some of our reserve
estimates are made without the benefit of a lengthy production history, which
are less reliable than estimates based on a long-term production
history.  Also, we make certain assumptions regarding future natural
gas prices, production levels, and operating and development costs that may
prove incorrect. Any significant variance from these assumptions by actual
figures could greatly affect our estimates of reserves, the economically
recoverable quantities of natural gas and oil attributable to any particular
group of properties, the classifications of reserves based on risk of recovery
and estimates of the future net cash flows. For example, if natural gas prices
decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of
December 31, 2008 would decrease from $1.128 billion to $800.0 million. Our
PV-10 is calculated using natural gas prices that include our physical hedges
but not our financial hedges. Numerous changes over time to the assumptions on
which our reserve estimates are based, as described above, often result in the
actual quantities of natural gas and oil we ultimately recover being different
from our reserve estimates. The present value of future net cash flows from our
proved reserves is not necessarily the same as the current market value of our
estimated natural gas reserves. We base the estimated discounted future net cash
flows from our proved reserves on prices and costs in effect on the day of
estimate. However, actual future net cash flows from our natural gas properties
also will be affected by factors such as:
 
 ·
              actual
      prices we receive for natural gas;
  ·
              the
      amount and timing of actual
production;
  ·
              the
      amount and timing of our capital
expenditures;
  ·
              supply
      of and demand for natural gas; and
  ·
              changes
      in governmental regulations or
taxation.
  27
  The
timing of both our production and our incurrence of expenses in connection with
the development and production of natural gas properties will affect the timing
of actual future net cash flows from proved reserves, and thus their actual
present value. In addition, the 10% discount factor we use when calculating
discounted future net cash flows may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the natural gas and oil industry in general.  Any significant
variance in our assumptions could materially affect the quantity and value of
reserves, the amount of PV-10 described in this report, and our financial
condition and results of operations. In addition, our reserves or PV-10 may be
revised downward or upward based upon production history, results of future
exploitation and development activities, prevailing natural gas and oil prices
and other factors. A material decline in prices paid for our production can
reduce the estimated volumes of our reserves because the economic life of our
wells could end sooner. Similarly, a decline in market prices for natural gas or
oil may reduce our PV-10.
 
 Our operations require substantial
capital expenditures, which will reduce our cash available for distribution.
Additionally, each quarter we are required to deduct estimated maintenance
capital expenditures from operating surplus, which may result in less cash
available to unit holders than if actual maintenance capital expenditures were
deducted.We will need to make substantial capital
expenditures to maintain our capital asset base over the long term. These
maintenance capital expenditures may include the drilling and completion of
additional wells to offset the production decline from our producing properties
or additions to our inventory of unproved or proved reserves. These expenditures
could increase as a result of:
 
 ·
              changes
      in our reserves;
  ·
              changes
      in natural gas prices;
  ·
              changes
      in labor and drilling costs;
  ·
              our
      ability to acquire, locate and produce
reserves;
  ·
              changes
      in leasehold acquisition costs; and
  ·
              government
      regulations relating to safety and the
  environment.
 
 Our
significant maintenance capital expenditures will reduce the amount of cash we
have available for distribution to our unit holders. Additionally, our actual
maintenance capital expenditures will vary from quarter to quarter. Our limited
liability company agreement requires us to deduct estimated, rather than actual,
maintenance capital expenditures from operating surplus. The amount of estimated
maintenance capital expenditures deducted from operating surplus will be subject
to review and approval by our board of directors, including a majority of our
conflicts committee, at least once a year. In years when our estimated
maintenance capital expenditures are higher than actual maintenance capital
expenditures, the amount of cash available for distribution to unit holders will
be lower than if we deducted actual maintenance capital expenditures from
operating surplus. If we underestimate the appropriate level of estimated
maintenance capital expenditures, we may have less cash available for
distribution in future periods when actual capital expenditures begin to exceed
our previous estimates. Over time, if we do not set aside sufficient cash
reserves or have available sufficient sources of financing and make sufficient
expenditures to maintain our capital asset base, we will be unable to pay
distributions at the anticipated level and may have to reduce our
distributions.
 
 The scope and costs of the risks
involved in making acquisitions may prove greater than estimated at the time of
the acquisition.Any acquisition involves potential risks, including,
among other things:
  ·
                mistaken
      assumptions about revenues and costs, including
  synergies;
 ·
                significant
      increases in our indebtedness and working capital
      requirements;
 ·
                an
      inability to integrate successfully or timely the businesses we
      acquire;
 ·
                the
      assumption of unknown liabilities;
 ·
                limitations
      on rights to indemnity from the seller;
 ·
                the
      diversion of management’s attention from other business
      concerns;
 ·
                increased
      demands on existing personnel;
 ·
                customer
      or key employee losses at the acquired businesses; and
 ·
              the
      failure to realize expected growth or
  profitability.
  28
 
 The scope and cost of these risks may
ultimately be materially greater than estimated at the time of the
acquisition.   Further, our future acquisition costs may be
higher than those we have achieved historically.  Any of these factors
could adversely affect our future growth and our ability to increase
distributions.
 
 We may be unsuccessful in
integrating the operations from any future acquisitions with our operations and
in realizing all of the anticipated benefits of these acquisitions.We
acquired DTE Gas & Oil in June 2007 and have successfully integrated its
operations with ours.  We also have an active, on-going program to
identify other potential acquisitions.  The integration of previously
independent operations with ours can be a complex, costly and time-consuming
process.  The difficulties of combining these systems, as well as any
operations we may acquire in the future, with us include, among other
things:
 
 ·
              operating
      a significantly larger combined
entity;
  ·
              the
      necessity of coordinating geographically disparate organizations, systems
      and facilities;
  ·
              integrating
      personnel with diverse business backgrounds and organizational
      cultures;
  ·
              consolidating
      operational and administrative
functions;
  ·
              integrating
      internal controls, compliance under Sarbanes-Oxley Act of 2002 and other
      corporate governance matters;
  ·
                the
      diversion of management’s attention from other business
      concerns;
 ·
                customer
      or key employee loss from the acquired businesses;
 ·
                a
      significant increase in our indebtedness; and
 ·
              potential
      environmental or regulatory liabilities and title
  problems.
 
 If we
have a future acquisition, there can be no assurance that any benefits or that
the acquisition will not result in the deterioration or loss of our
business.  Costs incurred and liabilities assumed in connection with
an acquisition and increased capital expenditures and overhead costs incurred to
expand our operations could harm our business or future prospects, and result in
significant decreases in our gross margin and cash flows.
 
 The DTE Gas & Oil acquisition
has substantially changed our business, making it difficult to evaluate our
business based upon our historical financial information.  The
DTE Gas & Oil acquisition has significantly increased our size, redefined
our business plan, increased our reserve life, expanded our geographic market
and resulted in large increases to our revenues and expenses.  As a
result of this acquisition, and our continued plan to acquire and integrate
additional companies that we believe present attractive opportunities, our
financial results for any period or changes in our results across periods may
continue to dramatically change.  Our historical financial results,
therefore, should not be relied upon to accurately predict our future operating
results, thereby making the evaluation of our business more
difficult.
 
 We have limited experience in
drilling wells to the Marcellus Shale, less information regarding reserves and
decline rates in the Marcellus Shale than in other areas of our Appalachian
operations and wells drilled to the Marcellus Shale will be deeper, more
expensive and more susceptible to mechanical problems in drilling and completing
than wells in the other areas.We have limited experience in drilling
development wells to the Marcellus Shale. As of January 15, 2009, we have
drilled 121 gross wells to the Marcellus Shale,  of which 121 gross
wells have been turned on-line. Other operators in the Appalachian Basin also
have limited experience in drilling wells to the Marcellus Shale. Thus, we have
much less information with respect to the ultimate recoverable reserves and the
production decline rate in the Marcellus Shale than we have in our other areas
of operation. In addition, the wells to be drilled in the Marcellus Shale will
be drilled deeper than in our other primary areas, which makes the Marcellus
Shale wells more expensive to drill and complete. The wells will also be more
susceptible to mechanical problems associated with the drilling and completion
of the wells, such as casing collapse and lost equipment in the wellbore. In
addition, the fracturing of the Marcellus Shale will be more extensive and
complicated than fracturing the geological formations in our other areas of
operation and requires greater volumes of water than conventional gas
wells.  The management of water and the treatment of produced water
from Marcellus Shale wells may be more costly than the management of produced
water from other geologic formations.
  29
  We have a substantial amount of
indebtedness which could adversely affect our financial position.We currently have a
substantial amount of indebtedness. As of December 31, 2008, we had total debt
of approximately $873.7 million, consisting of $406.7 million of senior notes
and $467.0 million of borrowings under our credit facility. We may also incur
significant additional indebtedness in the future. Our substantial indebtedness
may:
 
 •
              make
      it difficult for us to satisfy our financial obligations, including making
      scheduled principal and interest payments on the senior notes and our
      other indebtedness;
 
 •
              limit
      our ability to borrow additional funds for working capital, capital
      expenditures, acquisitions or other general business
    purposes;
 
 •
              limit
      our ability to use our cash flow or obtain additional financing for future
      working capital, capital expenditures, acquisitions or other general
      business purposes;
 
 •
              require
      us to use a substantial portion of our cash flow from operations to make
      debt service payments;
 
 •
              limit
      our flexibility to plan for, or react to, changes in our business and
      industry;
 
 •
              place
      us at a competitive disadvantage compared to our less leveraged
      competitors; and
 
 •
              increase
      our vulnerability to the impact of adverse economic and industry
      conditions.
 
 Our
ability to service our indebtedness will depend upon, among other things, our
future financial and operating performance, which will be affected by prevailing
economic conditions and financial, business, regulatory and other factors, some
of which are beyond our control. If our operating results are not sufficient to
service our current or future indebtedness, we will be forced to take actions
such as reducing distributions, reducing or delaying business activities,
acquisitions, investments and/or capital expenditures, selling assets,
restructuring or refinancing our indebtedness, or seeking additional equity
capital or bankruptcy protection. We may not be able to affect any of these
remedies on satisfactory terms or at all.
 
 Covenants in our debt agreements
restrict our business in many ways.The indenture governing
our senior notes and our credit facility contain various covenants that limit
our ability and/or our subsidiaries’ ability to, among other
things:
 
 •
              incur
      or assume liens or additional debt or provide guarantees in respect of
      obligations of other persons;
 
 •
              issue
      redeemable stock and preferred
stock;
 
 •
              pay
      dividends or distributions or redeem or repurchase capital
      stock;
 
 •
              prepay,
      redeem or repurchase debt;
 
 •
              make
      loans, investments and capital
expenditures;
 
 •
              enter
      into agreements that restrict distributions from our
      subsidiaries;
 
 •
              sell
      assets and capital stock of our
subsidiaries;
 
 •
              enter
      into certain transactions with affiliates;
and
 
 •
              consolidate
      or merge with or into, or sell substantially all of our assets to, another
      person.
 
 In
addition, our credit facility contains restrictive covenants and requires us to
maintain specified financial ratios. Our ability to meet those financial ratios
can be affected by events beyond our control, and we may be unable to meet those
tests. A breach of any of these covenants could result in a default under our
credit facility and/or the senior notes. Upon the occurrence of an event of
default under our credit facility, the lenders could elect to declare all
amounts outstanding under our credit facility to be immediately due and payable
and terminate all commitments to extend further credit. If we were unable to
repay those amounts, the lenders could proceed against the collateral granted to
them to secure that indebtedness. We have pledged a significant portion of our
assets as collateral under our credit facility. If the lenders under our credit
facility accelerate the repayment of borrowings, we may not have sufficient
assets to repay our credit facility and our other indebtedness, including the
notes. Our borrowings under our credit facility are, and are expected to
continue to be, at variable rates of interest and expose us to interest rate
risk. If interest rates increase, our debt service obligations on the variable
rate indebtedness would increase even though the amount borrowed remained the
same, and our net income would decrease.
  30
  Changes in tax laws may impair our
ability to obtain capital funds through investment partnerships.Under
current federal tax laws, there are tax benefits to investing in investment
partnerships such as those we sponsor, including deductions for intangible
drilling costs and depletion deductions. Changes to federal tax law that reduce
or eliminate these benefits may make investment in our investment partnerships
less attractive and, thus, reduce our ability to obtain funding from this
significant source of capital funds.
 
 Recently proposed severance taxes in
Pennsylvania could materially increase our liabilities.In
2008, our liabilities for severance taxes in the states in which we operate,
other than Pennsylvania, were approximately $12.2 million.  While
Pennsylvania has historically not imposed a severance tax, with a focus on its
budget deficit and the increasing exploitation of the Marcellus Shale,
Pennsylvania’s governor recently proposed a tax of 5% of the value of natural
gas at the wellhead plus $0.047 per Mcf beginning October 1, 2009.  If
adopted, these taxes may materially increase our operating costs in
Pennsylvania.
 
 We may not be able to continue to
raise funds through our investment partnerships at the levels we have recently
experienced, which may in turn restrict our ability to maintain our drilling
activity at the levels recently experienced.We have sponsored
limited and general partnerships to raise funds from investors to finance our
development drilling activities in Appalachia. During the fourth quarter of
2008, we began development drilling activities for us and our partnership
investors in Indiana.  Accordingly, the amount of development
activities we undertake depends in large part upon our ability to obtain
investor subscriptions to invest in these partnerships. During the past three
years we have raised successively larger amounts of funds through these
investment partnerships, raising $218.5 million, $363.3 million and $438.4
million, in calendar 2006, 2007 and 2008, respectively. In the future, we may
not be successful in raising funds through these investment partnerships at the
same levels we have recently experienced, and we also may not be successful in
increasing the amount of funds we raise as we have done in recent years. Our
ability to raise funds through our investment partnerships depends in large part
upon the perception of investors of their potential return on their investment
and their tax benefits from investing in them, which perception is influenced
significantly by our historical track record of generating returns and tax
benefits to the investors in our existing partnerships.
 
 In the
event that our investment partnerships do not achieve satisfactory returns on
investment or the anticipated tax benefits, we may have difficulty in continuing
to increase the amount of funds we raise through these partnerships or in
maintaining the level of funds we have recently raised through these
partnerships. In this event, we may need to obtain financing for our drilling
activities on a less attractive basis than the financing we realize through
these partnerships or we may determine to reduce our drilling
activity.
 
 Our fee-based revenues may decline
if we are unsuccessful in continuing to sponsor investment partnerships, and our
fee-based revenue may not increase at the same rate as recently experienced if
we are unable to raise funds at the same or higher levels as we have recently
experienced.Our fee-based revenues are based on the number of investment
partnerships we sponsor and the number of partnerships and wells we manage or
operate. If we are unsuccessful in sponsoring future investment partnerships,
our fee-based revenues may decline. Additionally, our fee-based revenue may not
increase at the same rate as recently experienced if we are unable to raise
funds at the same or higher levels as we have recently experienced.
 
 Our revenues may decrease if
investors in our investment partnerships do not receive a minimum
return.  We have agreed to subordinate up to 50% of our share
of production revenues to specified returns to the investor partners in our
investment partnerships, typically 10% per year for the first five years of
distributions. Thus, our revenues from a particular partnership will decrease if
it does not achieve the specified minimum return and our ability to make
distributions to unit holders may be impaired. We have not subordinated our
share of revenues from any of our investment partnerships since March 2005, but
did subordinate $91,000 in 2005 and $335,000 in 2004.
 
 Competition in the natural gas and
oil industry is intense, which may hinder our ability to acquire gas and oil
properties and companies and to obtain capital, contract for drilling equipment
and secure trained personnel.We operate in a highly
competitive environment for acquiring properties and other natural gas and oil
companies, attracting capital through our investment partnerships, contracting
for drilling equipment and securing trained personnel. We will also compete with
the exploration and production divisions of public utility companies for natural
gas and oil property acquisitions. Our competitors may be able to pay more for
natural gas and oil properties and drilling equipment and to evaluate, bid for
and purchase a greater number of properties than our financial or personnel
resources permit. Moreover, our competitors for investment capital may have
better track records in their programs, lower costs or better connections in the
securities industry segment that markets oil and gas investment programs than we
do. All of these challenges could make it more difficult for us to execute our
growth strategy. We may not be able to compete successfully in the future in
acquiring leasehold acreage or prospective reserves or in raising additional
capital.
  31
  Furthermore,
competition arises not only from numerous domestic and foreign sources of
natural gas and oil but also from other industries that supply alternative
sources of energy. Competition is intense for the acquisition of leases
considered favorable for the development of natural gas and oil in commercial
quantities. Product availability and price are the principal means of
competition in selling natural gas and oil. Many of our competitors possess
greater financial and other resources than ours, which may enable them to
identify and acquire desirable properties and market their natural gas and oil
production more effectively than we do.
 
 We depend on certain key customers
for sales of our natural gas. To the extent these customers reduce the volumes
of natural gas they purchase from us, our revenues and cash available for
distribution could decline. In Appalachia, our natural gas is sold under
contracts with various purchasers. Under a natural gas supply agreement with
Hess Corporation, which expires on March 31, 2009, Hess Corporation has a last
right of refusal to buy all of the natural gas produced and delivered by our
affiliates, and us including our investment partnerships. During calendar year
2008, natural gas sales to Hess Corporation accounted for approximately 10% of
our total Appalachian oil and gas revenues. In Michigan, during calendar year
2008, gas under contracts to a former affiliate of Atlas Gas & Oil, which
expire at various dates through 2012, accounted for approximately 49% of our
total Michigan oil and gas revenues. To the extent these and other key customers
reduce the amount of natural gas they purchase from us, our revenues and cash
available for distributions to unit holders could temporarily decline in the
event we are unable to sell to additional purchasers.
 
 Our Appalachia business depends on
the gathering and transportation facilities of Atlas Pipeline. Any limitation in
the availability of those facilities would interfere with our ability to market
the natural gas we produce and could reduce our revenues and cash available for
distributionAtlas Pipeline gathers more than 90% of our current
Appalachia production and approximately 50% of our total production. The
marketability of our natural gas production depends in part on the availability,
proximity and capacity of gathering and pipeline systems owned by Atlas Pipeline
and other third parties. The amount of natural gas that can be produced and sold
is subject to curtailment in circumstances such as pipeline interruptions due to
scheduled and unscheduled maintenance or excessive pressure or physical damage
to the gathering or transportation system. The curtailments arising from these
and similar circumstances may last from a few days to several
months.
 
 If Atlas America fails to pay
gathering fees to Atlas Pipeline as required by its assumption agreement with
us, we will have to pay to Atlas Pipeline the difference between the gathering
fee payable and the amount we receive from our investment partnerships for
gathering services out of our own resources.We are a party to
master gas gathering agreements with Atlas Pipeline, which requires, among other
things, paying Atlas Pipeline gathering fees for gathering our gas. The
gathering agreement is a continuing obligation and not terminable by us, except
that if Atlas Pipeline’s general partner is removed without cause, then no
gathering fees will be due under the agreement with respect to new wells drilled
by us. Atlas America assumed our obligation to pay these gathering fees pursuant
to the contribution agreement entered into at the completion of our initial
public offering, and we agreed to pay Atlas America the gathering fees we
receive from our investment partnerships and fees associated with production to
our interest. The gathering fees payable to Atlas Pipeline generally exceed the
amount we receive from our investment partnerships for gathering services. For
the year ended December 31, 2008, this excess amount was approximately $24.4
million. If Atlas America defaulted on its obligation to us under the assumption
agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas
Pipeline for the payment of the fees, which would reduce our income and cash
available for distributions and payments on our debt.
 
 Shortages of drilling rigs,
equipment and crews could delay our operations.Higher natural gas and
oil prices generally increase the demand for drilling rigs, equipment and crews
and can lead to shortages of, and increasing costs for, drilling equipment,
services and personnel. Over the past three years, we and other natural gas and
oil companies have experienced higher drilling and operating costs. Shortages
of, or increasing costs for, experienced drilling crews and oil field equipment
and services could restrict our ability to drill the wells and conduct the
operations which we currently have planned. Any delay in the drilling of new
wells or significant increase in drilling costs could reduce our
revenues.
  32
  Because we handle natural gas and
oil, we may incur significant costs and liabilities in the future resulting from
a failure to comply with new or existing environmental regulations or an
accidental release of hazardous substances into the environment.The
operations of our wells and other facilities are subject to stringent and
complex federal, state and local environmental laws and regulations. These
include, for example:
  ·
              the
      federal Clean Air Act and comparable state laws and regulations that
      impose obligations related to air
emissions;
  ·
              the
      federal Clean Water Act and comparable state laws and regulations that
      impose obligations related to discharges of pollutants into regulated
      bodies of water;
  ·
              RCRA
      and comparable state laws that impose requirements for the handling and
      disposal of waste, including produced waters, from our facilities;
      and
  ·
              CERCLA
      and comparable state laws that regulate the cleanup of hazardous
      substances that may have been released at properties currently or
      previously owned or operated by us or at locations to which we have sent
      waste for disposal.
 
 Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and
analogous state laws and regulations, impose strict, joint and several liability
for costs required to clean up and restore sites where hazardous substances have
been disposed of or otherwise released. Moreover, it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances or other waste products into the environment.
 
 There is
an inherent risk that we may incur environmental costs and liabilities due to
the nature of our business and the substances we handle. For example, an
accidental release from one of our wells could subject us to substantial
liabilities arising from environmental cleanup and restoration costs, claims
made by neighboring landowners and other third parties for personal injury and
property damage, and fines or penalties for related violations of environmental
laws or regulations. Moreover, the possibility exists that stricter laws,
regulations or enforcement policies may be enacted or adopted and could
significantly increase our compliance costs and the cost of any remediation that
may become necessary. We may not be able to recover remediation costs under our
insurance policies.
 
 Many of our leases are in areas that
have been partially depleted or drained by offset wells.Our key project
areas are located in active drilling areas in the Appalachian Basin. As a
result, many of our leases are in areas that have already been partially
depleted or drained by earlier offset drilling. This may inhibit our ability to
find economically recoverable quantities of natural gas in these
areas.
 
 Our identified drilling location
inventories are susceptible to uncertainties that could materially alter the
occurrence or timing of our drilling activities, which may result in lower cash
from operations.Our management has specifically identified and scheduled
drilling locations as an estimation of our future multi-year drilling activities
on our existing acreage. As of December 31, 2008, we had identified over 3,626
potential shallow drilling locations in Appalachia. These identified drilling
locations represent a significant part of our growth strategy. Our ability to
drill and develop these locations depends on a number of factors, including the
availability of capital, seasonal conditions, regulatory approvals, natural gas
prices, costs and drilling results. Of the 3,626 potential shallow drilling
locations, our independent petroleum engineering consultants have assigned
reserves to 358 proved undeveloped locations.  Of the remaining
drilling locations we have identified, there may exist greater uncertainty with
respect to the success of drilling wells at these drilling
locations.  Our final determination on whether to drill any of these
drilling locations will be dependent upon the factors described above as well
as, to some degree, the results of our drilling activities with respect to our
proved drilling locations. Because of these uncertainties, we do not know if the
numerous drilling locations we have identified will be drilled within our
expected timeframe or will ever be drilled or if we will be able to produce
natural gas and oil from these or any other potential drilling locations. As
such, our actual drilling activities may materially differ from our anticipated
drilling activities.
 
 Some of our undeveloped leasehold
acreage is subject to leases that may expire in the near future.Leases
covering approximately 85,140 of our 422,900 shallow net acres, or 20%, are
scheduled to expire on or before December 31, 2009.  An additional 33%
of our shallow net acres are scheduled to expire in the years 2010 and
2011.  If we are unable to renew these leases or any leases scheduled
for expiration beyond December 31, 2009, on favorable terms, we will lose the
right to develop the acreage that is covered by an expired lease and our
production would decline, which would reduce our cash flows from operations and
could impair our ability to make future distribution payments on our
debt.  We do not expect that we will have significant difficulty in
renewing or replacing these leases or similar leasehold
acreage.
  33
  Drilling for and producing natural
gas are high-risk activities with many uncertainties.Our drilling
activities are subject to many risks, including the risk that we will not
discover commercially productive reservoirs. Drilling for natural gas can be
uneconomic, not only from dry holes, but also from productive wells that do not
produce sufficient revenues to be commercially viable. In addition, our drilling
and producing operations may be curtailed, delayed or canceled as a result of
other factors, including:
 
 ·
              the
      high cost, shortages or delivery delays of equipment and
      services;
  ·
              unexpected
      operational events and drilling
conditions;
  ·
              adverse
      weather conditions;
  ·
              facility
      or equipment malfunctions;
  ·
              title
      problems;
  ·
              pipeline
      ruptures or spills;
  ·
              compliance
      with environmental and other governmental
  requirements;
  ·
              unusual
      or unexpected geological
formations;
  ·
              formations
      with abnormal pressures;
  ·
              injury
      or loss of life;
  ·
              environmental
      accidents such as gas leaks, ruptures or discharges of toxic gases, brine
      or well fluids into the environment or oil leaks, including groundwater
      contamination;
  ·
              fires,
      blowouts, craterings and explosions;
and
  ·
              uncontrollable
      flows of natural gas or well
fluids.
  Any one
or more of the factors discussed above could reduce or delay our receipt of
drilling and production revenues, thereby reducing our earnings, and could
reduce revenues in one or more of our investment partnerships, which may make it
more difficult to finance our drilling operations through sponsorship of future
partnerships. In addition, any of these events can cause substantial losses,
including personal injury or loss of life, damage to or destruction of property,
natural resources and equipment, pollution, environmental contamination, loss of
wells and regulatory penalties.
 
 Although
we will maintain insurance against various losses and liabilities arising from
our operations, insurance against all operational risks is not available to us.
Additionally, we may elect not to obtain insurance if we believe that the cost
of available insurance is excessive relative to the perceived risks presented.
Losses could, therefore, occur for uninsurable or uninsured risks or in amounts
in excess of existing insurance coverage. The occurrence of an event that is not
fully covered by insurance could reduce our results of operations.
 
 Properties that we buy may not
produce as projected and we may be unable to determine reserve potential,
identify liabilities associated with the properties or obtain protection from
sellers against such liabilities.One of our growth strategies is to
capitalize on opportunistic acquisitions of natural gas reserves. However, our
reviews of acquired properties are inherently incomplete because it generally is
not feasible to review in depth every individual property involved in each
acquisition. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well we acquire. Potential problems, such as deficiencies in the mechanical
integrity of equipment or environmental conditions that may require significant
remedial expenditures, are not necessarily observable even when we inspect a
well. Any unidentified problems could result in material liabilities and costs
that negatively affect our financial condition and results of
operations.
 
 Even if
we are able to identify problems with an acquisition, the seller may be
unwilling or unable to provide effective contractual protection or indemnity
against all or part of these problems. Even if a seller agrees to provide
indemnity, the indemnity may not be fully enforceable and may be limited by
floors and caps on such indemnity.
  34
  Hedging transactions may limit our
potential gains or cause us to lose money.Pricing for natural gas and
oil has been volatile and unpredictable for many years. To limit exposure to
changing natural gas and oil prices, we use financial and physical hedges for
our natural gas, and to a lesser extent, our oil production. Physical hedges are
not deemed hedges for accounting purposes because they require firm delivery of
natural gas and are considered normal sales of natural gas. We generally limit
these arrangements to smaller quantities than those projected to be available at
any delivery point. In addition, we may enter into financial hedges, which may
include purchases of regulated NYMEX futures and options contracts and
non-regulated over-the-counter futures contracts with qualified counterparties.
The futures contracts are commitments to purchase or sell natural gas at future
dates and generally cover one-month periods for up to six years in the future.
By removing the price volatility from a significant portion of our natural gas
production, and to a lesser extent, our oil production, we have reduced, but not
eliminated, the potential effects of changing natural gas and oil prices on our
cash flow from operations for those periods. Furthermore, while intended to help
reduce the effects of volatile natural gas and oil prices, such transactions,
depending on the hedging instrument used, may limit our potential gains if
natural gas and oil prices were to rise substantially over the price established
by the hedge. Under circumstances in which, among other things, production is
substantially less than expected, the counterparties to our futures contracts
fail to perform under the contracts or a sudden, unexpected event materially
impacts natural gas or oil prices, we may be exposed to the risk of financial
loss.
 
 We may be exposed to financial and
other liabilities as the managing general partner in investment partnerships.We serve as the managing general partner of 94 investment partnerships
and will be the managing general partner of new investment partnerships that we
sponsor. As a general partner, we are contingently liable for the obligations of
these partnerships to the extent that partnership assets or insurance proceeds
are insufficient. We have agreed to indemnify each investor partner in our
investment partnerships from any liability that exceeds such partner’s share of
the investment partnership’s assets.
 
 We are subject to comprehensive
federal, state, local and other laws and regulations that could increase the
cost and alter the manner or feasibility of our doing business.Our
operations are regulated extensively at the federal, state and local levels.
Environmental and other governmental laws and regulations have increased the
costs to plan, design, drill, install, operate and abandon natural gas and oil
wells. Under these laws and regulations, we could also be liable for personal
injuries, property damage and other damages. Failure to comply with these laws
and regulations may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Moreover, public
interest in environmental protection has increased in recent years, and
environmental organizations have opposed, with some success, certain drilling
projects.
 
 Part of
the regulatory environment in which we operate includes, in some cases, legal
requirements for obtaining environmental assessments, environmental impact
studies and/or plans of development before commencing drilling and production
activities. In addition, our activities are subject to the regulations regarding
conservation practices and protection of correlative rights. These regulations
affect our operations and limit the quantity of natural gas we may produce and
sell. A major risk inherent in our drilling plans is the need to obtain drilling
permits from state and local authorities. Delays in obtaining regulatory
approvals or drilling permits, the failure to obtain a drilling permit for a
well or the receipt of a permit with unreasonable conditions or costs could
inhibit our ability to develop our properties. Additionally, the natural gas and
oil regulatory environment could change in ways that might substantially
increase the financial and managerial costs of compliance with these laws and
regulations and, consequently, reduce our profitability. Furthermore, we may be
put at a competitive disadvantage to larger companies in our industry who can
spread these additional costs over a greater number of wells and larger
operating staff. Please read “Business—Environmental Matters and Regulation” and
“Business—Other Regulation of the Natural Gas and Oil Industry” for a
description of the laws and regulations that affect us.
 
 Our limited liability company
agreement limits and modifies our directors’ and officers’ fiduciary
duties.Our limited liability company agreement contains
provisions that modify and limit our directors’ and officers’ fiduciary duties
to our unit holders and us. For example, our limited liability company agreement
provides that:
 
 ·
              our
      directors and officers will not have any liability to us or our unit
      holders for decisions made in good faith, which is defined so as to
      require that they believed the decision was in our best interests;
      and
  ·
              our
      directors and officers will not be liable for monetary damages to us or
      our unit holders for any acts or omissions unless there has been a final
      and non-appealable judgment entered by a court of competent jurisdiction
      determining that the directors or officers acted in bad faith or engaged
      in fraud or willful misconduct or, in the case of a criminal matter, acted
      with knowledge that such conduct was
unlawful.
  35
  Members of our board of directors
and Atlas America and its affiliates, including our manager, may have conflicts
of interest with us.Conflicts of interest may arise between
us and our unit holders and members of our board of directors and Atlas America
and its affiliates, including our manager. These potential conflicts may relate
to the divergent interests of these parties. Situations in which the interests
of members of our board of directors and Atlas America and its affiliates, may
differ from interests of owners of common units include, among others, the
following situations:
 
 ·
              Our
      limited liability company agreement gives our board of directors broad
      discretion in establishing cash reserves for the proper conduct of our
      business, which will affect the amount of cash available for distribution.
      For example, our board of directors will use its reasonable discretion to
      establish and maintain cash reserves sufficient to maintain our asset
      base.
  ·
              Our
      manager will recommend to our board of directors the timing and extent of
      our drilling program and related capital expenditures, asset purchases and
      sales, and financing alternatives and reserve adjustments, all of which
      will affect the amount of cash that we distribute to our unit
      holders.
  ·
              In
      some instances our board of directors may cause us to borrow funds in
      order to permit us to pay cash distributions to our unit holders, even if
      the purpose or effect of the borrowing is to make management incentive
      distributions.
  ·
              Except
      as provided in our omnibus agreement with Atlas America, members of our
      board of directors and Atlas America and its affiliates, including our
      manager, are not prohibited from investing or engaging in other businesses
      or activities that compete with us.
  ·
              We
      do not have any employees and rely solely on employees of our manager and
      its affiliates. Our officers and the officers of our manager who provide
      services to us are not required to work full time on our affairs. These
      officers may devote significant time to the affairs of our manager’s
      affiliates. There may be significant conflicts between us and our
      affiliates regarding the availability of these officers to manage
      us.
 
 Our limited liability company
agreement provides for a limited call right that may require unit holders to
sell their common units at an undesirable time or price.If,
at any time, any person owns more than 87.5% of the common units then
outstanding, such person has the right, but not the obligation, which it may
assign to any of its affiliates or to us, to acquire all, but not less than all,
of the remaining common units then outstanding at a price not less than the
then-current market price of the common units. As a result, our unit holders may
be required to sell their common units at an undesirable time or price and
therefore may receive a lower or no return on their investment. Unit holders may
also incur tax liability upon a sale of their units.
 
 Our manager may transfer its
interests in us to a third party without common unit holder
consent.Our manager may transfer its Class A units and
management incentive interests to a third party in a merger or in a sale of all
or substantially all of its assets without the consent of our common unit
holders. Furthermore, Atlas America is not restricted from transferring its
equity interest in our manager.
 
 Atlas America may sell common units
in the future, which could reduce the market price of our outstanding
units.Atlas America owns 29,952,996 Class B common units. In
addition, our manager has the right to convert its Class A units and
management incentive interests into common units if we terminate the management
agreement, and its Class A units will automatically convert into common units,
and it will have the option of converting its management incentive interests, if
the common unit holders vote to eliminate the special voting rights of our
Class A units. We have agreed to register for sale common units held by
Atlas America and its affiliates. These registration rights allow Atlas America,
our manager and their affiliates to request registration of their common units
and to include any of those units in a registration of other securities by us.
If Atlas America and its affiliates were to sell a substantial portion of their
units, it could reduce the market price of our outstanding common
units.
 
 We depend on our manager and Atlas
America, and may not find suitable replacements if the management agreement
terminates.We have no employees. Our support personnel are
employees of Atlas America. We have no separate facilities and completely rely
on our manager and, our manager has no direct employees.  If our
management agreement terminates with Atlas America, we may be unable to find a
suitable replacement for them.
  36
  Our management agreement was not
negotiated at arm’s-length and, as a result, may not be as favorable to us as if
it had been negotiated with a third party.Our officers and
three of our directors, Edward E. Cohen, Jonathan Z. Cohen and Richard D. Weber,
are officers or directors of our manager, and Messrs. Cohen are directors of
Atlas America. As a consequence, our management agreement was not the result of
arm’s-length negotiations and its terms may not be as favorable to us as if it
had been negotiated with an unaffiliated third party.
 
 Expense reimbursements due to our
manager under our management agreement will reduce cash available for
distribution to our unit holders.Before making any
distribution on our common units, we will reimburse our manager for all expenses
that it incurs on our behalf pursuant to the management agreement. These
expenses will include all costs incurred on our behalf, including costs for
providing corporate staff and support services to us. Our manager will charge on
a fully allocated cost basis for services provided to us. This fully allocated
cost basis is based on the percentage of time spent by personnel of our manager
and its affiliates on our matters and includes the compensation paid by our
manager and its affiliates to such persons and their allocated overhead. The
allocation of compensation expense for such persons will be determined based on
a good faith estimate of the value of each such person’s services performed on
our business and affairs, subject to the periodic review and approval of our
audit or conflicts committee.
 
 Termination of the management
agreement by us is difficult.We may terminate our management agreement
only upon the affirmative vote of at least two-thirds of our outstanding common
units, including units owned by Atlas America and its affiliates. Upon any
termination, our manager will have the right to convert its Class A units
into common units on a one-for-one basis and convert its management incentive
interests into common units based on their fair market value, if the successor
manager does not purchase them. Atlas America will be able to prevent the
removal of our manager so long as it owns at least two-thirds of our common
units.
 
 Our manager’s liability is limited
under the management agreement, and we have agreed to indemnify our manager
against certain liabilities.Our manager will not assume any
responsibility under the management agreement other than to render the services
called for under it, and will not be responsible for any action of our board of
directors in following or declining to follow its advice or recommendations. Our
manager, its directors, officers, employees and affiliates will not be liable to
us, any subsidiary of ours, our directors or our unit holders for acts performed
in good faith and in accordance with the management agreement, except by reason
of acts constituting bad faith, willful misconduct, fraud or criminal conduct.
We have agreed to indemnify the parties for all damages and claims arising from
acts not constituting bad faith, willful misconduct, fraud or criminal conduct
and performed in good faith in accordance with and pursuant to the management
agreement.
 
 Our limited liability company
agreement restricts the voting rights of unit holders owning 20% or more of our
common units.Our limited liability company agreement
restricts the voting rights of common unit holders by providing that any units
held by a person that owns 20% or more of any class of units then outstanding,
other than Atlas America, our manager, their affiliates or transferees and
persons who acquire such units with the prior approval of our board of
directors, cannot vote on any matter. Our limited liability company agreement
also contains provisions limiting the ability of common unit holders to call
meetings or to acquire information about our operations, as well as other
provisions limiting common unit holders’ ability to influence the manner or
direction of management.
 
 We may issue additional units
without the approval of the common unit holders, which would dilute the common
unit holder’s existing ownership interests.  Our limited
liability company agreement permits us to issue an unlimited number of units of
any type, including common units, without the approval of our unit
holders.  The issuance of additional units or other equity securities
may have the following effects:
 
 ·
              the
      proportionate ownership of the existing common unit holders’ interest in
      us may decrease;
 
 ·
              the
      amount of cash distributed on each common unit may
    decrease;
 
 ·
              the
      relative voting strength of each previously outstanding unit may be
      diminished; and
 
 ·
              the
      market price of the common units may
decline.
  37
  An increase in interest rates may
cause the market price of our common units to decline. Like all equity
investments, an investment in our common units is subject to
risks.  In exchange for accepting these risks, investors may expect to
receive a higher rate of return than would otherwise be obtainable from
lower-risk investments.  Accordingly, as interest rates rise, the
ability of investors to obtain higher risk-adjusted rates of return by
purchasing government-backed debt securities may cause a corresponding decline
in demand for riskier investments generally, including yield-based equity
investments such as publicly-traded limited liability company
interests.  Reduced demand for our common units resulting from
investors seeking other investment opportunities may cause the trading price of
our common units to decline.
 
 Unit holders may have liability to
repay distributions.  Under certain circumstances, unit holders
may have to repay amounts wrongfully returned or distributed to
them.  Under Section 18-607 of the Delaware Revised Limited Liability
Company Act, we may not make a distribution to the common unit holders if the
distribution would cause our liabilities to exceed the fair value of our
assets.  Delaware law provides that for a period of three years from
the date of an impermissible distribution, unit holders who received the
distribution and who knew at the time of the distribution that it violated
Delaware law will be liable to the limited liability company for the
distribution amount.  A purchaser of common units who becomes a unit
holder is liable for the obligations of the transferring unit holder to make
contributions to the limited liability company that are known to such purchaser
of units at the time it became a member and for unknown obligations if the
liabilities could be determined from our limited liability company
agreement.
 
 If our unit price declines, the
common unit holders could lose a significant part of their investment.The market price of our common units could be subject to wide
fluctuations in response to a number of factors, most of which we cannot control
including:
 
 ·
                Changes
      in securities analysts’ recommendations and their estimates of our
      financial performance;
 
 ·
                The
      public’s reaction to our press releases, announcements and our filings
      with the SEC;
 
 ·
                  Fluctuations
      in broader securities market prices and volumes, particularly among
      securities of natural gas and oil companies and securities of
      publicly-traded limited partnerships and limited liability
      companies;
 
 ·
                Changes
      in market valuations of similar
companies;
 
 ·
                Departures
      of key personnel;
 
 ·
                Commencement
      of or involvement in
litigation;
 
 ·
                Variations
      in our quarterly results of operations or those of other natural gas and
      oil companies;
 
 ·
                Variations
      in the amount of our quarterly cash
  distributions;
 
 ·
                Future
      issuances and sales of our units;
and
 
 ·
                Changes
      in general conditions in the U.S. economy, financial markets or the
      natural gas and oil industry.
 
 In recent
years the securities market has experienced extreme price and volume
fluctuations.  This volatility has had a significant effect on the
market price of securities issued by many companies for reasons unrelated to the
operating performance of these companies.  Future market fluctuations
may result in a lower price of our common units.
 
 If the holders of our common units
vote to eliminate the special voting rights of the holders of our Class A
units, the Class A units will automatically convert into common units on a
one-for-one basis and our manager will have the option of converting the
management incentive interests into common units at their fair market value,
which may be dilutive to you.The holders of our Class A
units have the right to vote as a separate class on extraordinary transactions
submitted to a unit holder vote such as a merger or sale of all or substantially
all of our assets. This right can be eliminated upon a vote of the holders of
not less than two-thirds of our outstanding common units. If such elimination is
so approved, the Class A units will automatically convert into common units
on a one-for-one basis and our manager will have the right to convert its
management incentive interests into common units based on their then fair market
value, which may be dilutive to you.
  38
  Our tax treatment depends on our
status as a partnership for federal income tax purposes, as well as our not
being subject to entity-level taxation by individual states. If the IRS were to
treat us as a corporation for federal income tax purposes or we were to become
subject to entity-level taxation for state tax purposes, taxes paid, if any,
would reduce the amount of cash available for
distribution.The anticipated after-tax benefit of an
investment in our common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the IRS on this or any other tax matter that
affects us. If we were treated as a corporation for federal income tax purposes,
we would pay federal income tax on our taxable income at the corporate tax
rates, currently at a maximum rate of 35%, and would likely pay state income tax
at varying rates. Distributions to you would generally be taxed as corporate
distributions, and no income, gain, loss, deduction or credit would flow through
to you. Because a tax may be imposed on us as a corporation, our cash available
for distribution to our unit holders could be reduced. Therefore, our treatment
as a corporation could result in a material reduction in the anticipated cash
flow and after-tax return to our unit holders and therefore result in a
substantial reduction in the value of our common units. Current law or our
business may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level taxation. In
addition, because of widespread state budget deficits, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution
to you would be reduced. Our limited liability company agreement provides that
if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to
entity-level taxation for federal, state or local income tax purposes, the cash
distribution amounts and the incentive distribution amounts will be adjusted to
reflect the impact of that law on us.
 
 Our common unit holders may be
required to pay taxes on income from us even if they do not receive any cash
distributions from us.  Our common unit holders will be
required to pay federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income, whether or not they receive cash
distributions from us.  Our common unit holders may not receive cash
distributions from us equal to their share of our taxable income or even equal
to the actual tax liability that results from their share of our taxable
income.
 
 A successful IRS contest of the
federal income tax positions we take may harm the market for our common units,
and the costs of any contest will reduce cash available for
distribution.We have not requested a ruling from the IRS with
respect to our treatment as a partnership for federal income tax purposes or any
other matter that affects us.  The IRS may adopt positions that differ
from the positions we take.  It may be necessary to resort to
administrative or court proceedings to sustain some or all of the positions we
take and a court may disagree with some or all of those
positions.  Any contest with the IRS may lower the price at which our
common units trade.  In addition, our costs of any contest with the
IRS will result in a reduction in cash available for distribution to our unit
holders and thus will be borne indirectly by our unit holders.
 
 Tax-exempt entities and foreign
persons face unique tax issues from owning common units that may result in
adverse tax consequences to them.Investment in common units
by tax-exempt entities, including employee benefit plans and individual
retirement accounts, or IRAs, and non-U.S. persons raises issues unique to
them.  For example, virtually all of our income allocated to
organizations exempt from federal income tax, including individual retirement
accounts and other retirement plans, will be unrelated business taxable income
and will be taxable to such a unit holder.  Distributions to non-U.S.
persons will be reduced by withholding taxes imposed at the highest effective
applicable tax rate, and non-U.S. persons will be required to file United States
federal income tax returns and pay tax on their share of our taxable
income.
 
 We will treat each purchaser of our
common units as having the same tax benefits without regard to the common units
purchased.  The IRS may challenge this treatment, which could reduce
the value of the common units.  Because we cannot match
transferors and transferees of common units, we will adopt depreciation and
amortization positions that may not conform with all aspects of existing
Treasury Regulations.  A successful IRS challenge to those positions
could reduce the amount of tax benefits available to our unit
holders.  It also could affect the timing of these tax benefits or the
amount of gain on the sale of common units and could have a negative impact on
the value of our common units or result in audits of and adjustments to our unit
holders’ tax returns.
  39
  Tax gain or loss on the disposition
of our common units could be more or less than expected because prior
distributions in excess of allocations of income will decrease your tax basis in
your units.If our common unit holders sell any of your common
units, they will recognize gain or loss equal to the difference between the
amount realized and their tax basis in those units.  Prior
distributions to them in excess of the total net taxable income they were
allocated for a common unit, which decreased their tax basis in that unit, will,
in effect, become taxable income to them if the unit is sold at a price greater
than their tax basis in that unit, even if the price they receive is less than
their original cost.  A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income to them.  In
addition, they may incur a tax liability in excess of the amount of cash they
receive from the sale.
 
 Our common unit holders may be
subject to state and local taxes and return filing requirements in states where
they do not live as a result of investing in our common
units.In addition to federal income taxes, our common unit
holders will likely be subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that
are imposed by the various jurisdictions in which we do business or own property
now or in the future, even if they do not reside in any of those
jurisdictions.  Our common unit holders will likely be required to
file foreign, state and local income tax returns and pay state and local income
taxes in some or all of these jurisdictions.  Further, they may be
subject to penalties for failure to comply with those
requirements.  It is the responsibility of each unit holder to file
all United States federal, foreign, state and local tax returns that may be
require of such unit holder.  Our counsel has not rendered an opinion
on the state or local tax consequences of an investment in the common
units.
 
 We prorate our items of income,
gain, loss and deduction between transferors and transferees of our units each
month based upon the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred.  The IRS may challenge this treatment, which could change
the allocation of items of income, gain, loss and deduction among our unit
holders.We prorate our items of income, gain, loss and
deduction between transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred.  The use of this
proration method may not be permitted under existing IRS Treasury Regulations,
and, accordingly, our counsel is unable to opine as to the validity of this
method.  If the IRS were to challenge this method or new Treasury
Regulations were issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unit holders.
 
 A unit holder whose units are loaned
to a “short seller” to cover a short sale of units may be considered as having
disposed of those units.  If so, the unit holder would no longer be
treated for tax purposes as a partner with respect to those units during the
period of the loan and may recognize gain or loss from the
disposition.Because a unit holder whose units are loaned to a
“short seller” to cover a short sale of units may be considered as having
disposed of the loaned units, the unit holder may no longer be treated for tax
purposes as a partner with respect to those units during the period of the loan
to the short seller and the unit holder may recognize gain or loss from such
disposition.  Moreover, during the period of the loan to the short
seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unit holder and any cash distributions received by
the unit holder as to those units could be fully taxable as ordinary
income.  Our counsel has not rendered an opinion regarding the
treatment of a unit holder where common units are loaned to a short seller to
cover a short sale of common units; therefore, unit holders desiring to assure
their status as partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage account agreements to
prohibit their brokers from borrowing their units.
 
 We will be considered to have
terminated our business for tax purposes due to a sale or exchange of 50% or
more of our interests within a twelve-month period.We will be
considered to have terminated for tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits within a
twelve-month period. A constructive termination results in the closing of our
taxable year for all unit holders and in the case of a unit holder reporting on
a taxable year other than a fiscal year ending December 31, may result in
more than 12 months of our taxable income or loss being includable in
taxable income for the year of termination. A constructive termination occurring
on a date other than December 31 will result in us filing two tax returns,
and unit holders receiving two Schedule K-1s, for one fiscal year and the cost
of the preparation of these returns will be borne by all unit
holders.
 
 ITEM
      1B:
              UNRESOLVED
      STAFF COMMENTS
 
 None
  40
  ITEM
      2:
              PROPERTIES
 
 Office
Properties
 
 We lease a 27,000 square foot office
building in Moon Township, Pennsylvania. We own a 17,000 square foot field
office and warehouse facility in Jackson Center, Pennsylvania, a 24,000 square
foot office in Fayette County, Pennsylvania and an office in Deerfield,
Ohio.  We lease a 13,800 square foot office building in Traverse City,
Michigan under a lease expiring in 2010, an 1,800 square foot field office in
Gaylord, Michigan under a lease expiring in 2010 and a 1,200 square foot field
office in Sullivan, Indiana under a lease expiring in 2010. We also lease a
6,500 square foot field office in Knoxville, Tennessee under a lease expiring in
2014, and a 1,400 square foot field office in Ohio under a lease expiring in
2009.  We rent 17,200 square feet of office space in Uniontown, Ohio
and lease other field offices in Ohio, Philadelphia and New York on a
month-to-month basis.
 
 Natural
Gas and Oil Reserves
 
 The
following tables summarize information regarding our estimated proved natural
gas and oil reserves as of the dates indicated. Proved reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids, which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based upon future
conditions. The estimated reserves include reserves attributable to our direct
ownership interests in oil and gas properties as well as the reserves
attributable to our percentage interests in the oil and gas properties owned by
investment partnerships in which we own partnership interests. All of the
reserves are generally located in the Appalachian Basin, in Michigan’s Lower
Peninsula and in the southwestern corner of Indiana. We base these estimated
proved natural gas and oil reserves and future net revenues of natural gas and
oil reserves upon reports prepared by independent petroleum engineers.In accordance with SEC
guidelines, we make the standardized measure and PV-10 estimates of future net
cash flows from proved reserves using natural gas and oil sales prices in effect
as of the dates of the estimates, which are held constant throughout the life of
the properties. We based our estimates of proved reserves upon the following
weighted average prices as of the dates indicated:
 
 At
      December 31,2008
                        
                        
                        2007
                        
                        
                        2006Natural
      gas (per
      Mcf)
                        
                        $
                        5.71
                        
                        
                        $
                        6.93
                        
                        
                        $
                        6.33Oil
      (per
      Bbl)
                        
                        $
                        44.80
                        
                        
                        $
                        90.30
                        
                        
                        $
                        57.26
 
 Reserve
estimates are imprecise and may change as additional information becomes
available. Furthermore, estimates of natural gas and oil reserves are
projections based on engineering data. There are uncertainties inherent in the
interpretation of this data as well as the projection of future rates of
production and the timing of development expenditures. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact way and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Reserve reports of other engineers might
differ from the reports of our consultants, Wright & Company. Results
of drilling, testing and production subsequent to the date of the estimate may
justify revision of this estimate. Future prices received from the sale of
natural gas and oil may be different from those estimated by our independent
petroleum engineering firm in preparing their reports. The amounts and timing of
future operating and development costs may also differ from those used.
Accordingly, the reserves set forth in the following tables ultimately may not
be produced and the proved undeveloped reserves may not be developed within the
periods anticipated. Please read “Item1A: Risk Factors”. You should not construe
the estimated PV-10 and standardized measure values as representative of the
current or future fair market value of our proved natural gas and oil
properties. PV-10 and standardized measure values are based upon projected cash
inflows, which do not provide for changes in natural gas and oil prices or for
the escalation of expenses and capital costs. The meaningfulness of these
estimates depends upon the accuracy of the assumptions upon which they were
based.
 
 We
evaluate natural gas reserves at constant temperature and pressure. A change in
either of these factors can affect the measurement of natural gas reserves. We
deduct operating costs, development costs and production-related and ad valorem
taxes in arriving at the estimated future cash flows. The following table
presents our reserve information for the previous three years.  We
base the estimates on operating methods and conditions prevailing as of the
dates indicated.
  41
  Proved
      naturalgas
      and oil reserves at December 31,2008
                  
                  
                  2007
                  
                  
                  2006Proved
      reserves (in thousands):Michigan/Indiana:Natural
      gas reserves(Mmcf):Proved
      developed reserves
                  
                  
                  446,996
                  
                  
                  
                  463,609
                  
                  
                  
                  —Proved
      undeveloped reserves (1)
                  
                  
                  180,220
                  
                  
                  
                  203,074
                  
                  
                  
                  —Total
      proved reserves of natural gas
                  
                  
                  627,216
                  
                  
                  
                  666,683
                  
                  
                  
                  —Oil
      reserves (Mbbl):Proved
      developed reserves
                  
                  
                  8
                  
                  
                  
                  11
                  
                  
                  
                  —Proved
      undeveloped reserves
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Total
      proved reserves of oil
                  
                  
                  8
                  
                  
                  
                  11
                  
                  
                  
                  —Appalachia:Natural
      gas reserves (Mmcf):Proved
      developed reserves
                  
                  
                  139,659
                  
                  
                  
                  131,100
                  
                  
                  
                  107,683Proved
      undeveloped reserves (1)
                  
                  
                  223,930
                  
                  
                  
                  86,976
                  
                  
                  
                  60,859Total
      proved reserves of natural gas
                  
                  
                  363,589
                  
                  
                  
                  218,076
                  
                  
                  
                  168,542Oil
      reserves (Mbbl):Proved
      developed reserves
                  
                  
                  1,678
                  
                  
                  
                  1,966
                  
                  
                  
                  2,064Proved
      undeveloped reserves
                  
                  
                  48
                  
                  
                  
                  6
                  
                  
                  
                  4Total
      proved reserves of oil
                  
                  
                  1,726
                  
                  
                  
                  1,972
                  
                  
                  
                  2,068Total
      natural gas reserves (Mmcf):Proved
      developed reserves
                  
                  
                  586,655
                  
                  
                  
                  594,709
                  
                  
                  
                  107,683Proved
      undeveloped reserves(1)
                  
                  
                  404,150
                  
                  
                  
                  290,050
                  
                  
                  
                  60,859Total
      proved reserves of natural gas
                  
                  
                  990,805
                  
                  
                  
                  884,759
                  
                  
                  
                  168,542Total
      oil reserves (Mbbl):Proved
      developed reserves
                  
                  
                  1,686
                  
                  
                  
                  1,977
                  
                  
                  
                  2,064Proved
      undeveloped reserves
                  
                  
                  48
                  
                  
                  
                  6
                  
                  
                  
                  4Total
      proved reserves of oil
                  
                  
                  1,734
                  
                  
                  
                  1,983
                  
                  
                  
                  2,068Total
      proved reserves (Mmcfe)
                  
                  
                  1,001,209
                  
                  
                  
                  896,657
                  
                  
                  
                  180,950Total  PV-10
      estimate of cash flows of proved reserves (in thousands) (2):Michigan/Indiana:Proved
      developed reserves
                  
                  $
                  728,245
                  
                  
                  $
                  869,310
                  
                  
                  $
                  —Proved
      undeveloped reserves
                  
                  
                  149,239
                  
                  
                  
                  208,056
                  
                  
                  
                  —Total
      PV-10 estimate
                  
                  $
                  877,484
                  
                  
                  $
                  1,077,366
                  
                  
                  $
                  —Appalachia:Proved
      developed reserves
                  
                  $
                  288,637
                  
                  
                  $
                  394,999
                  
                  
                  $
                  279,330Proved
      undeveloped reserves
                  
                  
                  (34,180
                  )(3)
                  
                  
                  8,813
                  
                  
                  
                  4,111Total
      PV-10 estimate
                  
                  $
                  254,457
                  
                  
                  $
                  403,812
                  
                  
                  $
                  283,441Proved
      developed reserves
                  
                  $
                  1,016,882
                  
                  
                  $
                  1,264,309
                  
                  
                  $
                  279,330Proved
      undeveloped reserves
                  
                  
                  115,059
                  
                  
                  
                  216,869
                  
                  
                  
                  4,111Total
      PV-10 estimate
                  
                  $
                  1,131,941
                  
                  
                  $
                  1,481,178
                  
                  
                  $
                  283,441Standardized
      measure of discounted future cash flows (in thousands) (2)
                  
                  $
                  1,131,941
                  
                  
                  $
                  1,481,178
                  
                  
                  $
                  283,441
 
 (1)
              Our
      ownership in these reserves is subject to reduction as we generally
      contribute leasehold acreage associated with our proved undeveloped
      reserves to our investment partnerships in exchange for an approximate 30%
      equity interest in these partnerships, which effectively will reduce our
      ownership interest in these reserves from 100% to 30% as we make these
      contributions.
 (2)
              Since
      we are a limited liability company that allocates our taxable income to
      our unit holders, no provision for federal or state income taxes has been
      included in the December 31, 2008, 2007, and 2006 calculations of
      standardized measure which is, therefore, the same as the PV-10 value.
      Amounts include physical hedges but not financial hedging
      transactions.(3)
              Represents
      increased projected higher capital costs related to deeper wells and
      horizontal drilling techniques.
  Proved
developed reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are proved reserves that are expected to be recovered from new wells
drilled to known reservoirs on undrilled acreage for which the existence and
recoverability of such reserves can be estimated with reasonable certainty, or
from existing wells on which a relatively major expenditure is required to
establish production.
  42
  Productive
Wells
 
 The following table sets forth
information as of December 31, 2008, regarding productive natural gas and oil
wells in which we have a working interest. Productive wells consist of producing
wells and wells capable of production, including natural gas wells awaiting
pipeline connections to commence deliveries and oil wells awaiting connection to
production facilities. Gross wells are the total number of producing wells in
which we have an interest, directly or through our ownership interests in
investment partnerships, and net wells are the sum of our fractional working
interests in gross wells, based on the percentage interest we own in an
investment partnership or with other joint venturers that own an interest in the
well.
 
 Number
      of Productive WellsGross
      (1)
                  
                  
                  Net
      (1)Oil
      wells:Michigan/Indiana
                  
                  
                  —
                  
                  
                  
                  —Appalachia
                  
                  
                  509
                  
                  
                  
                  366509
                  
                  
                  
                  366Gas
      wells:Michigan/Indiana
                  
                  
                  2,495
                  
                  
                  
                  1,947Appalachia
                  
                  
                  7,953
                  
                  
                  
                  3,63610,448
                  
                  
                  
                  5,583Total
                  
                  
                  10,957
                  
                  
                  
                  5,949
  
 (1)
              Includes
      our proportionate interest in wells owned by 94 investment partnerships
      for which we serve as managing general partner and various joint ventures.
      Does not include royalty or overriding interests in 717
    wells.
 
 Developed
and Undeveloped Acreage
 
 The following table sets forth
information about our developed and undeveloped natural gas and oil acreage as
of December 31, 2008.  The information in this table includes our
proportionate interest in acreage owned by our investment
partnerships.
 
 Developed
      acreage
                    
                    
                    Undeveloped
      acreageGross
                    
                    
                    Net
                    
                    
                    Gross
                    
                    
                    NetArkansas
                    
                    
                    2,560
                    
                    
                    
                    403
                    
                    
                    
                    0
                    
                    
                    
                    0Indiana
                    
                    
                    673
                    
                    
                    
                    483
                    
                    
                    
                    160,480
                    
                    
                    
                    119,185Kansas
                    
                    
                    160
                    
                    
                    
                    20
                    
                    
                    
                    0
                    
                    
                    
                    0Kentucky
                    
                    
                    924
                    
                    
                    
                    462
                    
                    
                    
                    9,060
                    
                    
                    
                    4,530Louisiana
                    
                    
                    1,819
                    
                    
                    
                    206
                    
                    
                    
                    0
                    
                    
                    
                    0Michigan
                    
                    
                    303,290
                    
                    
                    
                    240,180
                    
                    
                    
                    42,390
                    
                    
                    
                    33,100Mississippi
                    
                    
                    40
                    
                    
                    
                    3
                    
                    
                    
                    0
                    
                    
                    
                    0Montana
                    
                    
                    0
                    
                    
                    
                    0
                    
                    
                    
                    2,650
                    
                    
                    
                    2,650New
      York
                    
                    
                    20,517
                    
                    
                    
                    14,989
                    
                    
                    
                    45,035
                    
                    
                    
                    45,035North
      Dakota
                    
                    
                    639
                    
                    
                    
                    96
                    
                    
                    
                    0
                    
                    
                    
                    0Ohio
                    
                    
                    113,529
                    
                    
                    
                    95,408
                    
                    
                    
                    31,984
                    
                    
                    
                    31,984Oklahoma
                    
                    
                    4,323
                    
                    
                    
                    468
                    
                    
                    
                    0
                    
                    
                    
                    0Pennsylvania
                    
                    
                    140,692
                    
                    
                    
                    140,692
                    
                    
                    
                    428,476
                    
                    
                    
                    428,476Tennessee
                    
                    
                    19,303
                    
                    
                    
                    17,785
                    
                    
                    
                    108,783
                    
                    
                    
                    108,783Texas
                    
                    
                    4,520
                    
                    
                    
                    329
                    
                    
                    
                    0
                    
                    
                    
                    0West
      Virginia
                    
                    
                    1,078
                    
                    
                    
                    539
                    
                    
                    
                    14,362
                    
                    
                    
                    11,948Wyoming
                    
                    
                    0
                    
                    
                    
                    0
                    
                    
                    
                    80
                    
                    
                    
                    80614,067
                    
                    
                    
                    512,063
                    
                    
                    
                    843,300
                    
                    
                    
                    785,771
 
 The
leases for our developed acreage generally have terms that extend for the life
of the wells, while the leases on our undeveloped acreage have terms that vary
from less than one year to five years. We paid rentals of approximately $3.9
million in fiscal 2008 to maintain our leases.
  43
  We
believe that we hold good and indefeasible title to our producing properties, in
accordance with standards generally accepted in the natural gas industry,
subject to exceptions stated in the opinions of counsel employed by us in the
various areas in which we conduct our activities. We do not believe that these
exceptions detract substantially from our use of any property. As is customary
in the natural gas industry, we conduct only a perfunctory title examination at
the time we acquire a property. Before we commence drilling operations, we
conduct an extensive title examination and we perform curative work on defects
that we deem significant. We have obtained title examinations for substantially
all of our managed producing properties. No single property represents a
material portion of our holdings.
 
 Our
properties are subject to royalty, overriding royalty drilling participation
rights and other outstanding interests customary in the industry. Our properties
are also subject to burdens such as liens incident to operating agreements,
taxes, development obligations under natural gas and oil leases, farm-out
arrangements and other encumbrances, easements and restrictions. We do not
believe that any of these burdens will materially interfere with our use of our
properties.
 
 ITEM
      3:
              LEGAL
      PROCEEDINGS
 
 On June
20, 2008, our wholly-owned subsidiary, Atlas America, LLC, was named as a
co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”)
v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell
County, Tennessee).  In its complaint, CNX alleged that Miller
breached a contract to assign to CNX certain leasehold rights (“Leases”)
representing approximately 30,000 acres in Campbell County, Tennessee and that
we and another defendant, Wind City Oil & Gas, LLC, interfered with the
closing of this assignment on June 6, 2008.  We purchased the Leases
from Miller for approximately $19.1 million.  On December 15, 2008,
the Chancery Court dismissed the matter in its entirety, holding that there had
been no breach of the contract by Miller and, therefore, that Atlas America
could not have tortuously interfered with the contract.  The Chancery
Court dismissed all claims against Atlas America, LLC; however, CNX has appealed
this decision.
 
 One of our subsidiaries, Resource
Energy, LLC, together with Resource America, Inc., (the former parent of Atlas
America), was a defendant in a class action originally filed in February 2000 in
the New York Supreme Court, Chautauqua County, by individuals, putatively on
their own behalf and on behalf of similarly situated individuals, who leased
property to us.  The complaint alleged that we were not paying
landowners the proper amount of royalty revenues with respect to natural gas
produced from the leased properties.  The complaint was seeking
damages in an unspecified amount for the alleged difference between the amount
of royalties actually paid and the amount of royalties that allegedly should
have been paid.  In April 2007, a settlement of this lawsuit was
approved by the court. Pursuant to the settlement terms, we paid $300,000 in May
2007, upgraded certain gathering systems and capped certain transportation
expenses chargeable to the landowners.  We were indemnified by Atlas
America for this matter.
 
 Atlas Gas
& Oil Company LLC, as successor to DTE Gas & Oil Company, was one of
four defendants in a personal injury action filed in Antrim County Circuit Court
in northern Michigan in August 2006.  The complaint alleged that plaintiff
suffered serious personal injuries as a result of the defendants’
negligence.  We paid $125,000 to the plaintiff in October 2007 in full
settlement of this action.
 
 We are also a party to various routine
legal proceedings arising in the ordinary course of our business. Management
believes that none of these actions, individually or in the aggregate, will have
a material adverse effect on our financial condition or results of results of
operations.
 
 ITEM
      4:
              SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY
HOLDERS
 
 No matters were submitted to a vote of
security holders during the fourth quarter of 2008.
  44
 
 PART
II
 
 ITEM
      5:
              MARKET
      FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER
      PURCHASES OF EQUITY SECURITIES
 
 Our common units are quoted on the New
York Stock Exchange (“NYSE”) under the symbol "ATN."  The following
table sets forth the high and low sale prices, as reported by the NYSE, on a
quarterly basis since our initial public offering in December 2006.
 
 Fiscal
      2008
                          
                          High
                          
                          
                          LowFourth
      Quarter
                          
                          $
                          26.50
                          
                          
                          $
                          10.23Third
      Quarter
                          
                          $
                          40.25
                          
                          
                          $
                          22.41Second
      Quarter
                          
                          $
                          45.40
                          
                          
                          $
                          31.76First
      Quarter
                          
                          $
                          34.87
                          
                          
                          $
                          23.65Fiscal
      2007
                          
                          High
                          
                          
                          LowFourth
      Quarter
                          
                          $
                          36.00
                          
                          
                          $
                          28.50Third
      Quarter
                          
                          $
                          38.85
                          
                          
                          $
                          28.75Second
      Quarter
                          
                          $
                          37.47
                          
                          
                          $
                          26.26First
      Quarter
                          
                          $
                          27.46
                          
                          
                          $
                          22.10Fiscal
      2006
                          
                          High
                          
                          
                          LowFourth
      Quarter
                          
                          $
                          22.88
                          
                          
                          $
                          21.80
 
 As of February 23, 2009, there were
63,381,249 Class B common units outstanding held by 67 holders of
record.  For a description of our recent sale of unregistered
securities, see our Form 8-K filed May 5, 2008.
 
 Our
Cash Distribution Policy
 
 Our limited liability company agreement
requires that, within 45 days after the end of each quarter, beginning with the
quarter ending December 31, 2006, we distribute all of our available cash to
unit holders of record on the applicable record date.
 
 Available cash generally means, for
each fiscal quarter, all cash on hand at the end of the quarter:
 
 ·
              less
      the amount of cash reserves established by our board of directors
      to:
 o
              provide
      for the proper conduct of our business (including reserves for future
      capital expenditures and credit
needs);
 o
              comply
      with applicable law and any of our debt instruments or other agreements;
      and
 o
              provide
      funds for distributions (1) to our unit holders for any one or more of the
      next four quarters or (2) with respect to our management incentive
      interests;
 ·
              plus
      all cash on hand on the date of determination of available cash for the
      quarter resulting from working capital borrowings made after the end of
      the quarter.
 
 Working capital borrowings are
borrowings that are made under our credit facility or another arrangement and
used solely for working capital purposes or to pay distributions to unit
holders.
 
 On January 28, 2009, we declared a
quarterly cash distribution for the fourth quarter of 2008 of $0.61 per common
unit, which was paid on February 13, 2009 to common unit holders of record as of
February 9, 2009.
 
 For information concerning common units
authorized for issuance under our incentive plan, see “Item 12: Security
Ownership or Certain Beneficial Owners and Management─Equity Compensation Plan
Information.”
  45
  ITEM
      6.
              SELECTED
      FINANCIAL DATA
 
 The
following table sets forth selected historical combined and consolidated
financial operating data for our predecessor, Atlas America E&P Operations
before the date of our initial public offering on December 18, 2006 and our
historical combined and consolidated financial and operating data after that
date for the periods indicated. Atlas America E&P Operations represents the
subsidiaries of Atlas America which held its natural gas and oil development and
production assets and liabilities, substantially all of which Atlas America
transferred to us upon the completion of our initial public offering. We derived
the historical financial data as of December 31, 2008 and 2007, and for the
years ended December 31, 2008, 2007, and 2006 from Atlas Energy Resources, LLC’s
and Atlas America’s E&P Operations financial statements, which were audited
by Grant Thornton LLP, an independent registered public accounting firm,
and are included in this report.  We derived the historical financial
data as of and for the three months ended December 31, 2005 and, as of and for
the years ended September 30, 2005 and 2004, respectively, from the Atlas
America E&P Operation’s financial statements, which are not included in this
report.
 
 You
should read the following financial data in conjunction with “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and
our financial statements and related notes appearing elsewhere in this
report.
  Three
      MonthsEndedYears
      Ended December 31,
                      
                      
                      December
      31,
                      
                      
                      Years
      Ended September 30,2008
                      
                      
                      2007
                      
                      
                      2006
                      
                      
                      2005
                      
                      
                      2005
                      
                      
                      2004(in
      thousands)Income
      statement data:Revenues:Gas
      and oil production
                      
                      $
                      311,850
                      
                      
                      $
                      180,125
                      
                      
                      $
                      88,449
                      
                      
                      $
                      24,086
                      
                      
                      $
                      63,499
                      
                      
                      $
                      48,526Partnership
      management:Well
      construction and completion
                      
                      
                      415,036
                      
                      
                      
                      321,471
                      
                      
                      
                      198,567
                      
                      
                      
                      42,145
                      
                      
                      
                      134,338
                      
                      
                      
                      86,880Administration
      and oversight
                      
                      
                      19,362
                      
                      
                      
                      18,138
                      
                      
                      
                      11,762
                      
                      
                      
                      2,964
                      
                      
                      
                      9,590
                      
                      
                      
                      8,396Well
      services
                      
                      
                      20,482
                      
                      
                      
                      17,592
                      
                      
                      
                      12,953
                      
                      
                      
                      2,561
                      
                      
                      
                      9,552
                      
                      
                      
                      8,430Gathering (1)
                      
                      
                      20,670
                      
                      
                      
                      14,314
                      
                      
                      
                      9,251
                      
                      
                      
                      1,407
                      
                      
                      
                      4,359
                      
                      
                      
                      4,191Gain
      on mark-to-market derivatives
                      
                      
                      —
                      
                      
                      
                      26,257
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      –Total
      revenues
                      
                      
                      787,400
                      
                      
                      
                      577,897
                      
                      
                      
                      320,982
                      
                      
                      
                      73,163
                      
                      
                      
                      221,338
                      
                      
                      
                      156,423Expenses:Gas and oil
      production (1)
                      
                      
                      59,579
                      
                      
                      
                      32,193
                      
                      
                      
                      13,881
                      
                      
                      
                      2,441
                      
                      
                      
                      8,165
                      
                      
                      
                      7,289Partnership
      management:Well
      construction and completion
                      
                      
                      359,609
                      
                      
                      
                      279,540
                      
                      
                      
                      172,666
                      
                      
                      
                      36,648
                      
                      
                      
                      116,816
                      
                      
                      
                      75,548Well
      services
                      
                      
                      10,654
                      
                      
                      
                      9,062
                      
                      
                      
                      7,337
                      
                      
                      
                      1,487
                      
                      
                      
                      5,167
                      
                      
                      
                      4,398Gathering (1)
                      
                      
                      441
                      
                      
                      
                      214
                      
                      
                      
                      —
                      
                      
                      
                      38
                      
                      
                      
                      52
                      
                      
                      
                      53Gathering fee – Atlas
      Pipeline (1)
                      
                      
                      19,098
                      
                      
                      
                      13,781
                      
                      
                      
                      29,545
                      
                      
                      
                      7,930
                      
                      
                      
                      21,929
                      
                      
                      
                      17,189General
      and administrative
                      
                      
                      44,659
                      
                      
                      
                      39,414
                      
                      
                      
                      23,367
                      
                      
                      
                      5,818
                      
                      
                      
                      13,202
                      
                      
                      
                      11,708Net
      expense reimbursement – affiliate
                      
                      
                      —
                      
                      
                      
                      –
                      
                      
                      
                      1,237
                      
                      
                      
                      163
                      
                      
                      
                      602
                      
                      
                      
                      1,050Depreciation,
      depletion and amortization
                      
                      
                      95,434
                      
                      
                      
                      56,942
                      
                      
                      
                      22,491
                      
                      
                      
                      4,916
                      
                      
                      
                      14,061
                      
                      
                      
                      12,064Total
      operating expenses
                      
                      
                      589,474
                      
                      
                      
                      431,146
                      
                      
                      
                      270,524
                      
                      
                      
                      59,441
                      
                      
                      
                      179,994
                      
                      
                      
                      129,299Operating
      income
                      
                      
                      197,926
                      
                      
                      
                      146,751
                      
                      
                      
                      50,458
                      
                      
                      
                      13,722
                      
                      
                      
                      41,344
                      
                      
                      
                      27,124Other
      income (expenses):Interest
      expense
                      
                      
                      (56,306
                      )
                      
                      
                      (30,096
                      )
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      –
                      
                      
                      
                      –Other
      – net
                      
                      
                      1,159
                      
                      
                      
                      849
                      
                      
                      
                      1,369
                      
                      
                      
                      57
                      
                      
                      
                      79
                      
                      
                      
                      444Total
      other income(expense)
                      
                      
                      (55,147
                      )
                      
                      
                      (29,247
                      )
                      
                      
                      1,369
                      
                      
                      
                      57
                      
                      
                      
                      79
                      
                      
                      
                      444Net
      income before cumulative effect of accounting change
                      
                      
                      142,779
                      
                      
                      
                      117,504
                      
                      
                      
                      51,827
                      
                      
                      
                      13,779
                      
                      
                      
                      41,423
                      
                      
                      
                      27,568Cumulative effect of
      accounting change (2)
                      
                      
                      —
                      
                      
                      
                      –
                      
                      
                      
                      6,355
                      
                      
                      
                      —
                      
                      
                      
                      —
                      
                      
                      
                      —Net
      income
                      
                      $
                      142,779
                      
                      
                      $
                      117,504
                      
                      
                      $
                      58,182
                      
                      
                      $
                      13,779
                      
                      
                      $
                      41,423
                      
                      
                      $
                      27,568Cash
      flow data:Cash
      provided by operating activities
                      
                      $
                      249,923
                      
                      
                      $
                      230,982
                      
                      
                      $
                      80,536
                      
                      
                      $
                      43,596
                      
                      
                      $
                      90,525
                      
                      
                      $
                      42,523Cash
      used in investing activities
                      
                      
                      (341,108
                      )
                      
                      
                      (1,468,434
                      )
                      
                      
                      (75,588
                      )
                      
                      
                      (17,185
                      )
                      
                      
                      (59,050
                      )
                      
                      
                      (32,709
                      )Cash
      provided by (used in) financing activities
                      
                      
                      71,582
                      
                      
                      
                      1,253,877
                      
                      
                      
                      (17,033
                      )
                      
                      
                      (11,739
                      )
                      
                      
                      (25,401
                      )
                      
                      
                      (14,916
                      )Capital
      expenditures
                      
                      $
                      340,975
                      
                      
                      $
                      196,735
                      
                      
                      $
                      75,635
                      
                      
                      $
                      17,187
                      
                      
                      $
                      59,124
                      
                      
                      $
                      33,252Other
      financial information (unaudited):EBITDA
                      
                      $
                      294,519
                      
                      
                      $
                      204,542
                      
                      
                      $
                      74,318
                      
                      
                      $
                      18,695
                      
                      
                      $
                      55,484
                      
                      
                      $
                      39,632Adjusted
      EBITDA
                      
                      $
                      312,434
                      
                      
                      $
                      199,099
                      
                      
                      $
                      94,949
                      
                      
                      $
                      25,649
                      
                      
                      $
                      73,406
                      
                      
                      $
                      52,747Balance
      sheet data (at period end):Total
      assets
                      
                      $
                      2,270,685
                      
                      
                      $
                      1,891,234
                      
                      
                      $
                      415,463
                      
                      
                      $
                      315,052
                      
                      
                      $
                      270,402
                      
                      
                      $
                      198,454Liabilities
      associated with drilling contracts
                      
                      
                      96,700
                      
                      
                      
                      132,517
                      
                      
                      
                      86,765
                      
                      
                      
                      70,514
                      
                      
                      
                      60,971
                      
                      
                      
                      29,375Advances
      from affiliates
                      
                      
                      1,712
                      
                      
                      
                      8,696
                      
                      
                      
                      12,502
                      
                      
                      
                      4,257
                      
                      
                      
                      13,897
                      
                      
                      
                      30,008Long-term
      debt, including current maturities
                      
                      
                      873,655
                      
                      
                      
                      740,030
                      
                      
                      
                      68
                      
                      
                      
                      156
                      
                      
                      
                      81
                      
                      
                      
                      420Total
      equity
                      
                      $
                      1,039,336
                      
                      
                      $
                      836,115
                      
                      
                      $
                      212,682
                      
                      
                      $
                      154,519
                      
                      
                      $
                      146,142
                      
                      
                      $
                      109,461
 (1)
                    We charge gathering fees to our
      investment partnership wells that are connected to Atlas Pipeline’s
      gathering systems. Historically, we in turn paid these fees, plus an
      additional amount to bring the total gathering charge up to, generally,
      16% of the gas sales price, to Atlas Pipeline in accordance with our
      gathering agreements with it. Upon the completion of our initial public
      offering, Atlas America assumed our obligation to pay gathering fees to
      Atlas Pipeline. We are obligated to pay the gathering fees we receive from
      our investment partnerships to Atlas America, with the result that our
      gathering revenues and expenses within our partnership management segment
      net to $0. We also pay our proportionate share of gathering fees based on
      our percentage interest in the well, which are included in gas and oil
      production expense. Atlas America E & P Operations also owned several
      small gathering systems. The expenses associated with these systems are
      shown as gathering fees on our combined statements of income. We do not
      own these gathering systems after the completion of our initial public
      offering.
 
 (2)
                      The cumulative effect of
      accounting change results from our adoption of FIN 47 (see Notes 2 and 5
      to our combined and consolidated financial
    statements).
 46
  EBITDA
AND ADJUSTED EBITDA
 
 We define
EBITDA as earnings before interest, taxes, depreciation, depletion, and
amortization and cumulative effect of accounting change. We calculate Adjusted
EBITDA by adjusting EBITDA for other non-cash items such as equity compensation.
EBITDA and Adjusted EBITDA are not measures of performance calculated in
accordance with GAAP. Although not prescribed under GAAP, we believe the
presentation of EBITDA and Adjusted EBITDA are relevant and useful because they
help our investors to understand our operating performance and make it easier to
compare our results with other companies that have different financing and
capital structures or tax rates. EBITDA and Adjusted EBITDA should not be
considered in isolation of, or as a substitute for, net income as an indicator
of operating performance or cash flows from operating activities as a measure of
liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures
reported by other companies and may be different from the EBITDA calculation
under our credit facility. In addition, EBITDA and Adjusted EBITDA do not
represent funds available for discretionary use. The following reconciles our
net income before taxes and cumulative effect of accounting change to our EBITDA
and Adjusted EBITDA for the periods indicated:
 
 Three
      MonthsEnded
                        
                        
                        Years
      EndedYears
      Ended December 31,
                        
                        
                        December
      31,
                        
                        
                        September
      30,2008
                        
                        
                        2007
                        
                        
                        2006
                        
                        
                        2005
                        
                        
                        2005
                        
                        
                        2004(in
      thousands)Net
      income before cumulative effect of accounting change
                        
                        $
                        142,779
                        
                        
                        $
                        117,504
                        
                        
                        $
                        51,827
                        
                        
                        $
                        13,779
                        
                        
                        $
                        41,423
                        
                        
                        $
                        27,568Interest
      expense
                        
                        
                        56,306
                        
                        
                        
                        30,096
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —Depreciation,
      depletion and amortization
                        
                        
                        95,434
                        
                        
                        
                        56,942
                        
                        
                        
                        22,491
                        
                        
                        
                        4,916
                        
                        
                        
                        14,061
                        
                        
                        
                        12,064EBITDA
                        
                        
                        294,519
                        
                        
                        
                        204,542
                        
                        
                        
                        74,318
                        
                        
                        
                        18,695
                        
                        
                        
                        55,484
                        
                        
                        
                        39,632Adjustment
      to reflect cash impact of derivatives (1)
                        
                        
                        12,430
                        
                        
                        
                        12,257
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —Gain
      on mark-to-market derivatives (2)
                        
                        
                        —
                        
                        
                        
                        (26,257
                        )
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —Non-recurring
      derivative fees
                        
                        
                        —
                        
                        
                        
                        3,873Non-cash
      stock compensation
                        
                        
                        5,485
                        
                        
                        
                        4,684
                        
                        
                        
                        337
                        
                        
                        
                        393
                        
                        
                        
                        300
                        
                        
                        
                        64Gathering
      fee
                        
                        
                        —
                        
                        
                        
                        –
                        
                        
                        
                        20,294
                        
                        
                        
                        6,561
                        
                        
                        
                        17,622
                        
                        
                        
                        13,051Adjusted
      EBITDA
                        
                        $
                        312,434
                        
                        
                        $
                        199,099
                        
                        
                        $
                        94,949
                        
                        
                        $
                        25,649
                        
                        
                        $
                        73,406
                        
                        
                        $
                        52,747
  
 (1)
              Represents
      cash proceeds received from the settlement of ineffective derivative gains
      recognized in fiscal 2007 associated with the acquisition of AGO from
      natural gas produced during the year but not reflected in the twelve
      months ended December 31, 2008 and 2007 consolidated statements of
      income.
 (2)
              Representsineffective
      non-cash gains related to the change in value of derivative contracts
      associated with the acquisition of AGO on June 29,
  2007.
  47
  ITEM
      7:
              Management’s Discussion and
      Analysis of Financial Condition and Results of
      Operations
 
 GENERAL
 
 We had
record revenues of $787.4 million and record net income of $142.8 million in
2008.  Our well construction and completion margin of $55.4 million
and gas and oil production margin of $252.3 million both contributed to an
increase in net income of $25.3 million.
 
 We also
experienced increases in costs associated with drilling and leasing activities
due to the increased competition for the availability of drilling rigs and
development activities of the Marcellus Shale formation in southwestern
Pennsylvania.
 
 Manner
of Presentation
 
 The
historical financial statements for the year ended December 31, 2006 included in
this report reflect substantially all the assets, liabilities and operations of
various wholly-owned subsidiaries of Atlas America, which were contributed to us
upon the closing of our initial public offering on December 18, 2006. We refer
to these subsidiaries’ assets, liabilities and operations as Atlas America E
& P Operations, or our predecessor. The following discussion analyzes and
includes the financial condition and results of operations of both Atlas America
E & P Operations before the date of our initial public offering on December
18, 2006 and our results after the date of our initial public offering. You
should read the following discussion of the financial condition and results of
operations in conjunction with the historical combined and consolidated
financial statements and notes to combined and consolidated financial statements
included elsewhere in this report. Additionally, you should read
“Forward-looking statements” and “Item 1A: Risk Factors” for information
regarding some of the risks inherent in our business.
 
 Comparability
of Financial Statements
 
 The
historical financial statements of Atlas America E & P Operations (from
January 1, 2006 to December 17, 2006) included in this report are not comparable
to our results of operations following our initial public offering on December
18, 2006 for the following reasons:
 
 ·
              Historically,
      pursuant to an agreement with Atlas America, Atlas Pipeline received
      gathering fees generally equal to 16% of the gas sales price of gas
      gathered through its system. Each partnership pays us gathering fees
      generally equal to 13% of the gas sales price. After the closing of our
      initial public offering, we pay the amount we receive from the
      partnerships to Atlas America so that our gathering revenues and expenses
      within our partnership management segment net to $0. Atlas America then
      remits the full amount due to Atlas Pipeline pursuant to our contribution
      agreement with it. We also pay our proportionate share of gathering fees
      based on our percentage interest in the well, which are included in gas
      and oil production expense.
  ·
              Atlas
      America retained a small gathering system, which accounted for the
      gathering expense in our predecessor’s income
  statement.
  ·
              Because
      Atlas America did not previously allocate debt or interest expense to its
      subsidiaries, our historical results of operations do not include interest
      expense. We incurred indebtedness after the closing of our initial public
      offering, which created interest
expense.
  ·
              Because
      we report our items of taxable income, loss, deductions and credits as a
      master limited partnership, we now incur additional general and
      administrative expense each year for costs associated with Schedule K-1
      preparation and distribution to our unit
  holders.
  ·
              We
      acquired DTE Gas & Oil, which we refer to as AGO, on June 29, 2007,
      which significantly increased our assets, debt and equity, revenues,
      expenses and cash flows from June 29, 2007 to December 31, 2007 and for
      the full fiscal year 2008.
  48
  OVERVIEW
 
 We are a
limited liability company focused on the development and production of natural
gas and, to a lesser extent, oil principally in northern Michigan, Indiana, and
the Appalachian Basin. In northern Michigan, we drill wells for our own account.
In the Appalachian Basin and Indiana, we sponsor and manage tax-advantaged
investment partnerships, in which we coinvest, to finance the exploitation and
development of our acreage.
 
 We were
formed in June 2006 to own and operate substantially all of the natural gas and
oil assets and the investment partnership management business of Atlas
America.  Atlas America has been involved in the energy industry since
1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc.
and in 1999 when it acquired Viking Resources Corporation, both engaged in the
development and production of natural gas and oil and the sponsorship of
investment partnerships. We are managed by Atlas Energy Management, a
wholly-owned subsidiary of Atlas America.  We operate two oil and gas
production business segments in Michigan/Indiana (“Michigan”) and Appalachia as
well as our partnership management segment.
 
 Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
 Gas
and Oil Production
 
 Our
natural gas revenues were $297.1 million in the year ended December 31, 2008, an
increase of $127.8 million (75%) from $169.3 million in the year ended December
31, 2007. The increase was generally attributable to volumes associated with our
Michigan operations, acquired on June 29, 2007, of $102.4 million and a 22%
increase in the production volumes of our Appalachian operating area. The $127.8
million increase in natural gas revenues consisted of $113.4 million
attributable to increases in production volumes and $14.4 million attributable
to increases in natural gas prices.
 
 We
believe that gas volumes will continue to be favorably impacted in 2009 with a
planned expansion of our Marcellus Shale drilling efforts, the acquisition of
acreage in Indiana added to our Michigan business unit, the expansion of acreage
and operations in our Tennessee area and continued enhancement in our
Appalachian operations as ongoing projects to extend and enhance the gathering
systems of Atlas Pipeline are completed and recently drilled wells are connected
to these systems.
 
 Our oil
revenues were $14.7 million in the year ended December 31, 2008, an increase of
$3.9 million (36%) from $10.8 million in the year ended December 31,
2007.  The increase resulted from a 33% increase in the average sales
price of oil, and a 3% increase in production volumes. The $3.8 million increase
consisted of $3.4 million attributable to increases in sales prices, and
$468,000 attributable to volume increases.
 
 Our
production costs were $59.6 million in the year ended December 31, 2008, an
increase of $27.4 million (85%) from $32.2 million in the year ended December
31, 2007. This increase is attributable to an increase of $19.9 million of
production costs associated with our acquisition of AGO on June 29, 2007 which
we have owned for a full calendar year, compared to a six-month period in
calendar year 2007, and a $7.5 million increase in transportation charges, water
hauling and labor and maintenance costs associated with an increase in the
number of wells we own in Appalachia from the prior year period.
  49
  Partnership
Management
 
 Our well
construction and completion revenues and costs and expenses incurred represent
the billings and costs associated with the completion of wells for investment
partnerships we sponsor.  The following table sets forth information
relating to these revenues and the related costs and number of net wells drilled
during the periods indicated (dollars in thousands):
 
 Years
      Ended December 31,2008
                      
                      
                      2007
                      
                      
                      2006Average
      construction and completion revenue per well
                      
                      $
                      535
                      
                      
                      $
                      317
                      
                      
                      $
                      307Average
      construction and completion cost per well
                      
                      
                      463
                      
                      
                      
                      276
                      
                      
                      
                      267Average
      construction and completion segment margin per well
                      
                      $
                      72
                      
                      
                      $
                      41
                      
                      
                      $
                      40Gross
      profit margin
                      
                      $
                      55,427
                      
                      
                      $
                      41,931
                      
                      
                      $
                      25,901Net
      wells drilled
                      
                      
                      776
                      
                      
                      
                      1,014
                      
                      
                      
                      647
 
 Well
Construction and Completion
 
 Our well
construction and completion margin was $55.4 million in the year ended December
31, 2008, an increase of $13.5 million (32%) from $41.9 million in the year
ended December 31, 2007. During the year ended December 31, 2008, the increase
of $13.5 million in segment margin was attributable to an increase in the gross
profit per well ($30.5 million), partially offset by a decrease in the number of
wells we drilled ($17.0 million). Since our drilling contracts are on a
“cost-plus” basis (typically cost plus 15% to 18%), an increase in our average
costs per well also results in an increase in our average revenue per
well.  Our average costs and revenues per well has increased due to an
increase in the number of Marcellus Shale and horizontal wells drilled during
the year ended December 31, 2008.
 
 It should
be noted that “Liabilities associated with drilling contracts” on our balance
sheet includes $96.7 million of funds raised in our investment programs that
have not been applied to the completion of wells as of December 31, 2008 due to
the timing of drilling operations, and thus have not been recognized as well
construction and completion revenue. We expect to recognize this amount as
revenue in the first half of 2009. During the year ended December 31, 2008, we
raised $438.4 million and we have budgeted to raise approximately $400.0 million
in fiscal 2009.
 
 Administration
and Oversight
 
 Administration
and oversight represents supervision and administrative fees earned for the
drilling and subsequent management of wells for our investment partnerships. Our
administration and oversight fees were $19.4 million in the year ended December
31, 2008, an increase of $1.3 million (7%) from $18.1 million in the year ended
December 31, 2007. This increase resulted from an increase in the fee we charge
to drill Marcellus Shale and horizontal wells in comparison to our shallow well
administrative fee.  The number of wells we manage for our investment
partnerships has also increased by approximately 630 net wells (15%) in the year
ended December 31, 2008, as compared to the year ended December 31,
2007.
 
 Well
Services
 
 Our well
services revenues were $20.5 million in the year ended December 31, 2008, an
increase of $2.9 million (16%) from $17.6 million in the year ended December 31,
2007. This increase resulted from an increase in the number of wells operated
for our investment partnerships due to additional wells drilled in the year
ended December 31, 2008.
 
 Our well
services expenses were $10.7 million in year ended December 31, 2008, an
increase of $1.6 million (18%) from $9.1 million in the year ended December 31,
2007. This increase was attributable to an increase in wages, benefits, and
field office expenses associated with an increase in employees due to the
increase in the number of wells we operate for our investment
partnerships.
  50
  Gathering
 
 We charge transportation fees to our
investment partnership wells that are connected to Atlas Pipeline’s Appalachian
gathering systems. Prior to our initial public offering, our predecessor, Atlas
America, paid these fees, plus an additional amount to bring the total
transportation charge up to, generally, 16% of the gas sales price, to Atlas
Pipeline in accordance with its gathering agreements with it. In connection with
the completion of our initial public offering, Atlas America assumed our
obligation to pay gathering fees to Atlas Pipeline. We are obligated to pay 100%
of the gathering fees we receive from our investment partnerships to Atlas
America, with the result that our Appalachian gathering revenues and expenses
within our partnership management segment net to $0. We also pay our
proportionate share of gathering fees based on our percentage interest in the
well, which are included in gas and oil production expense. During the year
ended December 31, 2008, we also received $1.6 million in transportation and
natural gas liquid revenues from our Michigan operations.
 
 Our
gathering fee paid to Atlas Pipeline was $19.1 million for the year ended
December 31, 2008, an increase of $5.3 million (39%) from $13.8 million in the
year ended December 31, 2007. The increase in the year ended December 31, 2008
is primarily a result of the increase in the number of wells drilled, completed,
and connected to Atlas Pipeline’s gathering systems.
  Other Income, Costs and
Expenses
 
 General
and Administrative
 
 Our
general and administrative expenses were $44.7 million in the year ended
December 31, 2008, an increase of $5.3 million (13%) from $39.4 million in the
year ended December 31, 2007. These expenses include, among other things,
salaries and benefits not allocated to a specific segment, costs of running our
corporate offices, partnership syndication activities and outside services. The
increase of $5.3 million in the year ended December 31, 2008 is principally
attributed to the following:
 
 ·
              costs
      associated with  AGO were $8.1 million in the current year, an
      increase of $4.8 million from the prior year.  The prior year
      included costs from our acquisition date, June 29, 2007 to December 31,
      2007;
  ·
              land
      and leasing costs in Appalachia increased $1.6 million due to an increase
      in activities of our land department as we acquired additional acreage and
      well sites;
  ·
              outside
      services, professional fees, insurance and office operations increased
      $2.9 million due to the growth of our business and syndication activities;
      and
  ·
              partially
      offset by the payment of $3.9 million in fees in 2007 related to hedging
      natural gas volumes associated with the acquisition of AGO on June 29,
      2007; we did not pay any hedging fees during the year ended December 31,
      2008.
  Depletion
 
 Our
depletion (including accretion of our asset retirement obligations) of oil and
gas properties as a percentage of oil and gas revenues was 29% in the year ended
December 31, 2008, compared to 30% in the year ended December 31, 2007.
Depletion expense was $2.64 per Mcfe in the year ended December 31, 2008, an
increase of $0.15 (6%) from $2.49 per Mcfe in the year ended December 31, 2007.
Increases in our depletable basis associated with the AGO acquisition and wells
drilled for our investment partnerships and associated production volumes caused
depletion expense to increase $37.6 million (69%) to $92.0 million in the year
ended December 31, 2008 compared to $54.4 million in the year ended December 31,
2007. Depletion expense associated with our Michigan asset base was $54.8
million for the year ended December 31, 2008, compared to $28.3 million for the
year ended December 31, 2007. The variances from period to period are directly
attributable to changes in our oil and gas reserve quantities, production
levels, product prices and changes in the depletable cost basis of our oil and
gas properties.
 
 Interest
Expense
 
 Our
interest expense was $56.3 million in the year ended December 31, 2008, an
increase of $26.2 million (87%) compared to $30.1 million in the year ended
December 31, 2007.  This increase consists of an increase of $36.1
million associated with the issuance of our senior notes in January and May
2008, offset by a decrease of $9.9 million in interest expense on our revolving
credit facility.  The borrowings on our credit facility were used to
fund the acquisition of AGO in June 2007 and to fund our acreage and drilling
capital expenditures.  The issuance of our senior notes was used to
pay down borrowings on our revolving credit facility.
  51
  Year
Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
 Gas
and Oil Production
 
 Our
natural gas revenues were $169.3 million in the year ended December 31, 2007, an
increase of $90.3 million (114%) from $79.0 million in the year ended December
31, 2006. The increase was attributable to volumes associated with our Michigan
operations acquired on June 29, 2007 and an 11% increase in the production
volumes of our Appalachian operating area. The $90.3 million increase in natural
gas revenues consisted of $97.1 million attributable to increases in production
volumes partially, offset by $6.8 million attributable to decreases in natural
gas prices.
  Our oil
revenues were $10.8 million in the year ended December 31, 2007, an increase of
$1.4 million (15%) from $9.4 million in the year ended December 31,
2006.  The increase resulted from a 13% increase in the average sales
price of oil, and a 2% increase in production volumes. The $1.4 million increase
consisted of $1.2 million attributable to increases in sales prices, and
$199,000 attributable to volume increases. We drill primarily for natural gas
rather than oil.
 
 Our
production costs were $32.2 million in the year ended December 31, 2007, an
increase of $18.3 million (132%) from $13.9 million in the year ended December
31, 2006. This increase is attributable to $14.6 million of production costs
associated with our acquisition of DTE Gas & Oil on June 29, 2007 and a $3.1
million increase in transportation charges, water hauling and labor and
maintenance costs associated with an increase in the number of wells we own in
Appalachia from the prior year period.
 
 Partnership
Management
 
 Well
Construction and Completion
 
 Our well
construction and completion margin was $41.9 million in the year ended December
31, 2007, an increase of $16.0 million (62%) from $25.9 million in the year
ended December 31, 2006. During the year ended December 31, 2007, the increase
of $16.0 million in segment margin was attributable to an increase in the number
of wells we drilled ($15.2 million) and an increase in the gross profit per well
($864,000). The increase in the number of wells we drilled of 367 is a result of
an increase in our fundraising in 2007. Since our drilling contracts are on a
“cost plus” basis (typically cost-plus 15%), an increase in our average costs
per well also results in an increase in our average revenue per well. During the
year ended December 31, 2007, we raised $363.3 million.
 
 Administration
and Oversight
 
 Administration
and oversight represents supervision and administrative fees earned for the
drilling and subsequent management of wells for our investment partnerships. Our
administration and oversight fees were $18.1 million in the year ended December
31, 2007, an increase of $6.3 million (53%) from $11.8 million in the year ended
December 31, 2006. This increase resulted from an increase in the number of
wells drilled and managed for our investment partnerships in the year ended
December 31, 2007 as compared to the year ended December 31, 2006.
 
 Well
Services
 
 Our well
services revenues were $17.6 million in the year ended December 31, 2007, an
increase of $4.6 million (35%) from $13.0 million in the year ended December 31,
2006. This increase resulted from an increase in the number of wells operated
for our investment partnerships due to additional wells drilled in the year
ended December 31, 2007.
  52
  Our well
services expenses were $9.1 million in year ended December 31, 2007, an increase
of $1.8 million (25%) from $7.3 million in the year ended December 31, 2006.
This increase was attributable to an increase in wages, benefits, and field
office expenses associated with an increase in employees due to the increase in
the number of wells we operate for our investment partnerships.
 
 Gathering
 
 We charge transportation fees to our
investment partnership wells that are connected to Atlas Pipeline’s Appalachian
gathering systems. Prior to our initial public offering, our predecessor paid
these fees, plus an additional amount to bring the total transportation charge
up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance
with its gathering agreements with it. In connection with the completion of our
initial public offering, Atlas America assumed our obligation to pay gathering
fees to Atlas Pipeline. We are obligated to pay the gathering fees we receive
from our investment partnerships to Atlas America, with the result that our
Appalachian gathering revenues and expenses within our partnership management
segment net to $0. We also pay our proportionate share of gathering fees based
on our percentage interest in the well, which are included in gas and oil
production expense. During the year ended December 31, 2007, we also received
$327,000 in transportation and natural gas liquid revenues from our Michigan
operations.
 
 Our
gathering fee paid to Atlas Pipeline was $13.8 million for the year ended
December 31, 2007, a decrease of $15.7 million (53%) from $29.5 million in the
year ended December 31, 2006. The decrease in the year ended December 31, 2007
is primarily a result of the assumption by Atlas America of our obligation to
pay Atlas Pipeline under our gas gathering agreement with it.
 
 Other
Income, Costs and Expenses
 
 Gain
on mark-to-market derivatives
 
 Our gain on mark-to-market derivatives
represents a $26.3 million non-cash gain recognized on derivatives related to
the change in value of derivative contracts associated with the acquisition of
AGO on June 29, 2007. The contracts entered into were derivative contracts to
hedge the projected production volume of AGO before the closing of the
acquisition. The production volumes of the assets to be acquired were not
considered to be “probable forecasted production” under SFAS No. 133 at the date
these derivatives were entered into because the acquisition of the assets had
not yet been completed. Accordingly, we recorded the instruments as
non-qualifying for hedge accounting at inception with subsequent changes in the
derivative values recorded within our combined and consolidated statements of
income. Upon closing of the acquisition, the production volumes of the assets
acquired was considered “probable forecasted production” under SFAS No. 133 and
we evaluated these derivatives under the cash flow hedge criteria in accordance
with SFAS No. 133. For the year ended December 31, 2007, we received $18.4
million in proceeds on derivative contracts that settled, including, $12.3
million related to our mark-to-market non-cash derivative gain of $26.3 million,
for a net gain included in gas revenues of $6.1 million.
 
 General
and Administrative
 
 Our
general and administrative expenses were $39.4 million in the year ended
December 31, 2007, an increase of $16.0 million (69%) from $23.4 million in the
year ended December 31, 2006. These expenses include, among other things,
salaries and benefits not allocated to a specific segment, costs of running our
corporate offices, partnership syndication activities and outside services. The
increase of $16.0 million in the year ended December 31, 2007 is principally
attributed to the following:
 
 ·
              costs
      associated with  AGO were $3.3 million in the current
      year;
  ·
              land
      and leasing costs in Appalachia increased $1.0 million due to an increase
      in activities of our land department as we acquire additional acreage and
      well sites;
  ·
              salaries
      and wages increased $1.1 million due to an increase in executive salaries
      and in the number of employees as a result of our initial public offering
      and growth of our business;
  53
  ·
              noncash
      stock compensation increased $4.4 million as a result
      of  options and units granted upon our initial public offering
      and the acquisition of AGO;
  ·
              we
      paid $3.9 million in fees related to hedging natural gas volumes
      associated with the acquisition of AGO on June 29, 2007;
    and
 
 ·
              accounting
      and professional fees increased $1.8 million due to the growth of our
      business, higher audit fees and the implementation of Sarbanes-Oxley
      Section 404 compliance.
  Depletion
 
 Our
depletion (including accretion of our asset retirement obligations) of oil and
gas properties as a percentage of oil and gas revenues was 30% in the year ended
December 31, 2007, compared to 23% in the year ended December 31, 2006.
Depletion expense was $2.49 per Mcfe in the year ended December 31, 2007, an
increase of $0.41 (20%) from $2.08 per Mcfe in the year ended December 31, 2006.
Increases in our depletable basis associated with the AGO acquisition and wells
drilled for our investment partnerships and associated production volumes caused
depletion expense to increase $33.9 million (165%) to $54.4 million in the year
ended December 31, 2007 compared to $20.5 million in the year ended December 31,
2006. Depletion expense associated with our Michigan asset base was $28.3
million for the year ended December 31, 2007. The variances from period to
period are directly attributable to changes in our oil and gas reserve
quantities, production levels, product prices and changes in the depletable cost
basis of our oil and gas properties.
 
 Interest
Expense
 
 Interest
expense was $30.1 million in the year ended December 31, 2007 which was incurred
on our new credit facility.  Atlas America did not allocate interest
expense associated with its credit facility to us prior to our initial public
offering in December 2006.
 
 Cumulative
Effect of Accounting Change
 
 We
adopted FASB Interpretation No. 47, “Accounting for Conditional Asset
Retirement Obligations,” or FIN 47 as of December 31, 2006 and recognized $6.4
million as the cumulative effect of an accounting change.   FIN
47 required us to record our retirement obligation without considering the
probability of whether our wells would either be sold or otherwise disposed of
without incurring a disposal charge.
 
 LIQUIDITY
AND CAPITAL RESOURCES
 
 General
  We fund
our development and production operations with a combination of cash generated
by operations, capital raised through investment Partnerships, issuance of our
equity, issuance of Senior Unsecured Notes, and use of our credit
facility. The following table sets forth our sources and uses of cash (in
thousands):
 
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Provided
      by operations
                  
                  $
                  249,923
                  
                  
                  $
                  230,982
                  
                  
                  $
                  80,536Used
      in investing activities
                  
                  
                  (341,108
                  )
                  
                  
                  (1,468,434
                  )
                  
                  
                  (75,588
                  )Provided
      by (used in) financing activities
                  
                  
                  71,582
                  
                  
                  
                  1,253,877
                  
                  
                  
                  (17,033
                  )Increase
      (decrease) in cash and cash equivalents
                  
                  $
                  (19,603
                  )
                  
                  $
                  16,425
                  
                  
                  $
                  (12,085
                  )
 
 We had
$5.7 million in cash and cash equivalents at December 31, 2008, compared to
$25.3 million at December 31, 2007.  We had a working capital deficit
of $69.3 million at December 31, 2008, a decrease of $24.0 million from a
working capital deficit of $93.3 million at December 31, 2007.  The
decrease in our working capital deficit is principally due to the
following:
  ·
              an
      increase of $16.7 million in accounts receivable and prepaid
      expenses;
  54
  ·
              net
      current unrealized hedge receivables increased $34.0
    million;
  ·
              a
      decrease of $35.8 million in liabilities associated with drilling
      contracts;
  ·
              a
      decrease of cash and cash equivalents of $19.6
  million;
  ·
              an
      increase in accounts payable and accrued liabilities of $26.9 million;
      and
  ·
              an
      increase in accrued interest payable of $16.1
  million.
  Our level
of liabilities associated with drilling contracts is dependent upon the
remaining amount of our drilling obligations at any balance sheet date, which is
dependent upon the timing and level of funds raised through our investment
partnerships. At December 31, 2008, we have $229.3 million available under our
credit facility to fund working capital obligations.
  Capital
Requirements
 
 Capital expenditures. During
the year ended December 31, 2008, our capital expenditures consisted of
maintenance capital expenditures and expansion capital expenditures, as defined
below:
 
 ·
              maintenance
      capital expenditures are those capital expenditures we made on an ongoing
      basis to maintain our capital asset base and our current production
      volumes at a steady level; and
  ·
              expansion
      capital expenditures are those capital expenditures we made to expand our
      capital asset base for longer than the short-term and include new
      leasehold interests and the development and exploitation of existing
      leasehold interests through acquisitions and investments in our drilling
      partnerships.
  During the year ended December 31,
2008, 2007 and 2006, our capital expenditures in Appalachia related primarily to
investments in our investment partnerships, in which we invested $146.3 million,
$137.6 million, and $73.6 million, respectively.   We funded and
expect to continue to fund these capital expenditures through cash on hand, from
operations and from amounts available under our credit facility.
 
 The level
of capital expenditures we devote to our exploration and production operations
depends upon any acquisitions made and the level of funds raised through our
investment partnerships.  During the year ended December 31, 2008, we
raised $438.4 million.  For the years ended December 31, 2007 and
2006, we had raised $363.3 million and $218.5 million,
respectively.
 
 We expect to fund our maintenance
capital expenditures with cash flow from operations and the temporary use of
funds raised in our investment partnerships in the period before we invest these
funds.  We also expect to fund our investment capital expenditures and
any expansion capital expenditures that we might incur with borrowings under our
credit facility and with the temporary use of funds raised in our investment
partnerships in the period before we invest the funds. We believe cash flows
from operations and amounts available under our credit facility will be adequate
to fund our capital expenditures.  However, the amount of funds we raise
and the level of our capital expenditures will vary in the future depending on
market conditions for natural gas and other factors.
 
 We believe that we have sufficient
liquid assets, cash from operations and borrowing capacity to meet our financial
commitments, debt service obligations, distribution requirements, contingencies
and anticipated capital expenditures. However, we are subject to business and
operational risks that could adversely affect our cash flow. We may need to
supplement our cash generation with proceeds from financing activities,
including borrowings under our credit facilities and other borrowings and the
issuance of additional common units.
 
 We
continuously evaluate acquisitions of gas and oil assets. In order to make
any acquisition, we believe we will be required to access outside capital either
through debt or equity placements or through joint venture operations with other
energy companies. There can be no assurance that we will be successful in our
efforts to obtain outside capital.
  55
  The following table summarizes
maintenance and expansion capital expenditures for the periods indicated (in
thousands): 
 Years
      Ended December 31,2008
                                                
                                                
                                                2007
                                                
                                                
                                                2006Maintenance
      capital expenditures (1)
                                                
                                                $
                                                51,900
                                                
                                                
                                                $
                                                43,450
                                                
                                                
                                                $
                                                –Expansion
      capital expenditures (1)
                                                
                                                
                                                289,075
                                                
                                                
                                                
                                                1,421,186
                                                
                                                
                                                
                                                –Total
                                                
                                                $
                                                340,975
                                                
                                                
                                                $
                                                1,464,636
                                                
                                                
                                                $
                                                75,635
 
 (1)
              We
      did not characterize capital expenditures as maintenance or expansion and
      did not plan capital expenditures in a manner intended to maintain or
      expand our asset base or production before our initial public offering on
      December 31, 2006.
 
 Credit
Facility
 
 At December 31, 2008, we have a credit
facility with a syndicate of banks with a borrowing base of $697.5 million that
matures in June 2012 ($467.0 million outstanding at December 31,
2008).  The borrowing base is redetermined semiannually on April 1 and
October 1 subject to changes in the our oil and gas reserves.  The
facility is secured by substantially all of our assets and is guaranteed by each
of our subsidiaries and bears interest at either the base rate plus the
applicable margin or at adjusted LIBOR plus the applicable margin, elected at
our option.  At December 31, 2008, the weighted average interest rate
on outstanding borrowings was 2.8%.  The credit facility requires us
to maintain a ratio of current assets (as defined in the credit facility) to
current liabilities (as defined in the credit facility) of not less than 1.0 to
1.0, and a ratio of total debt (as defined in the credit facility) to earnings
before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as
defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0
commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1,
2010 and thereafter.  According to the definitions contained in our
credit facility, our ratio of current assets to current liabilities was 1.6 to
1.0 and our ratio of total debt to EBITDA was 2.9 to 1.0, at December 31,
2008.
 
 CASH
FLOWS
 
 Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
 Cash flows from operating
activities.Cash provided by operations is an important source of short-term
liquidity for us.  It is directly affected by changes in the price of
natural gas and oil, interest rates and our ability to raise funds from our
drilling investment partnerships.  Netcash provided by
operating activities increased $18.9 million in the year ended December 31, 2008
to $249.9 million from $231.0 million for the prior year due principally to the
following:
 
 ·
              an
      increase in net income before depreciation, depletion and amortization of
      $63.6 million during the year ended December 31, 2008 as compared to the
      prior year period, principally due to the contribution of our Michigan
      operations acquired in June 2007 and increases in net income from our
      partnership management operations and our Appalachian production segment;
      and
  ·
              an
      increase in non-cash items of $27.2 million related to our compensation
      expense resulting from grants under long-term incentive plans and non-cash
      gains on mark-to-market derivatives;
and
  ·
              partially
      offset by changes in operating assets and liabilities which decreased
      operating cash flows by $71.2 million in the year ended December 31, 2008,
      compared to the prior year.
  The
decrease in operating cash flows from changes in operating assets and
liabilities is primarily a result of the following:
  ·
              an
      increase of $19.7 million in accounts receivable and prepaid expenses;
      and
  ·
              a
      decrease of $81.6 million in liabilities associated with our drilling
      contracts.  Our level of liabilities associated with drilling
      contracts is dependent upon the remaining amount of our drilling
      obligations at any balance sheet date, which is dependent upon the timing
      and level of funds raised through our investment
    partnerships;
  56
  ·
              These
      amounts were partially offset by an increase of $30.1 million in accounts
      payable and accrued expenses
  Cash flows used in investing
activities.Cash used in our
investing activities decreased $1.13 billion during the year ended December 31,
2008 to $341.1 million from $1.47 billion in the year ended December 31, 2007
due to our $1.27 billion acquisition of AGO on June 29, 2007, partially offset
by a $144.2 million increase in capital expenditures related to the increase in
the number of wells we drilled in during the year ended December 31,
2008.
 
 Cash flows provided by financing
activities.Cash provided by our financing activities decreased $1.18
billion for the year ended December 31, 2008 to $71.6 million from $1.25 billion
in the year ended December 31, 2007, primarily as a result of the
following:
 
 ·
              net
      borrowing decreased $1.01 billion in the year ended December 31, 2008, due
      to the funding of our AGO acquisition on June 29, 2007 during the prior
      year;
  ·
              we
      received proceeds of $107.7 million from the sale of our Class B common
      units in the year ended December 31, 2008 compared to proceeds of $597.5
      million received in the year ended December 31,
  2007;
  ·
              net
      monies borrowed from Atlas America decreased $3.2 million in the
      year  ended December 31, 2008, compared to the year ended
      December 31, 2007;
  ·
              we
      paid $151.1 million in distributions to our unit holders in the year ended
      December 31, 2008, an increase of $81.8 million from $69.3 million in the
      year ended December 31, 2007; and
  ·
              These
      amounts were partially offset by the proceeds of $407.1 million we
      received from the issuance of our Senior Notes including a premium of $7.1
      million in the year ended December 31,
2008.
  Year
Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
 Cash flows from operating
activities.Netcash
provided by operating activities increased $150.5 million during the year ended
December 31, 2007 to $231.0 million from $80.5 million for the year ended
December 31, 2006, due principally to the following:
 
 ·
              an
      increase in net income before depreciation, depletion and amortization of
      $96.8 million during the year ended December 31, 2007 as compared to the
      prior year, principally due to the contributions from our Michigan
      operations acquired in June 2007 and increases in net income from our
      partnership management operations and our Appalachian production
      segment;
  ·
              a
      decrease in non-cash items of $3.3 million related to our compensation
      expense resulting from grants under long-term incentive plans, non-cash
      gains of derivatives and the impact of cumulative change in accounting
      principle; and
  ·
              changes
      in operating assets and liabilities which increased operating cash flows
      by $56.6 million in the year ended December 31, 2007, compared to the
      prior year.
  The
change in operating assets and liabilities is primarily a result of the
following:
  ·
              a
      decrease of $12.1 million in accounts receivable and prepaid
      expenses;
  ·
              an
      increase of $15.0 million in accounts payable and accrued expenses;
      and
  ·
              an
      increase of $29.5 million in liabilities associated with our drilling
      contracts.  Our level of liabilities associated with drilling
      contracts is dependent upon the remaining amount of our drilling
      obligations at any balance sheet date, which is dependent upon the timing
      and level of funds raised through our investment
    partnerships.
  57
  Cash flows used in investing
activities.Cash used in our investing activities increased $1.4 billion during the
year ended December 31, 2007 to $1.5 billion from $75.6 million for the prior
year due primarily to our $1.3 billion acquisition of DTE Gas & Oil and a
$121.1 million increase in capital expenditures when compared to the prior year
related to the increase in the number of wells we drilled in fiscal
2007.
 
 Cash flows from financing
activities.  Cash provided by our financing activities
increased $1.3 billion in the year ended December 31, 2007 to $1.3 billion from
cash used of $17,000 in the year ended December 31, 2006, principally as a
result of the following:
 
 ·
              to
      fund the acquisition of DTE Gas & Oil on June 29, 2007, we borrowed
      $713.9 million on our credit
facility;
  ·
              we
      borrowed additional funds on our credit facility, net of repayments of
      $26.1 million, to fund our investments in our
  partnerships;
  ·
              net
      monies remitted to Atlas America during the year  ended December
      31, 2007, as compared to the year ended December 31, 2006 increased
      financing cash flows by $12.9
million;
  ·
              in
      the year ended December 31, 2006, we distributed $139.9 million to Atlas
      America;
  ·
              net
      proceeds from issuances of units increased $457.6 million in the year
      ended December 31, 2007 as compared to December 31,
  2006;
  ·
              deferred
      financing costs increased $10.3 million in the year ended December 31,
      2007 due to our new credit facility used to fund our acquisition of AGO;
      and
  ·
              we
      paid $69.3 million in distributions to our unit holders in the year ended
      December 31, 2007.
  CHANGES
IN PRICES AND INFLATION
 
 Our revenues, the value of our assets,
our ability to obtain bank loans or additional capital on attractive terms and
our ability to finance our drilling activities through investment partnerships
have been and will continue to be affected by changes in oil and gas market
prices. Natural gas and oil prices are subject to significant fluctuations that
are beyond our ability to control or predict.
 
 Inflation affects the operating
expenses of our operations.  In addition, inflationary trends may
occur if commodity prices were to increase since such an increase may cause the
demand of energy equipment and services to increase, thereby increasing the
costs of acquiring or obtaining such equipment and
services.  Increases in those expenses are not necessarily offset by
increases in revenues and fees that our operations are able to
charge.  While we anticipate that inflation will affect our future
operating costs, we cannot predict the timing or amounts of any such
effects
 
 ENVIRONMENTAL
REGULATION
 
 Our operations are subject to federal,
state and local laws and regulations governing the release of regulated
materials into the environment or otherwise relating to environmental protection
or human health or safety. We believe that our operations and facilities are in
substantial compliance with applicable environmental laws and regulations. Any
failure to comply with these laws and regulations may result in the assessment
of administrative, civil and criminal penalties, imposition of remedial
requirements, and issuance of injunctions as to future compliance or other
mandatory or consensual measures. We have ongoing environmental compliance
programs. However, risks of accidental leaks or spills are associated with our
operations. There can be no assurance that we will not incur significant costs
and liabilities relating to claims for damages to property, the environment,
natural resources, or persons resulting from the operation of our business.
Moreover, it is possible that other developments, such as increasingly strict
environmental laws and regulations and enforcement policies hereunder, could
result in increased costs and liabilities to us.
  58
 Environmental
laws and regulations have changed substantially and rapidly over the last 25
years, and we anticipate that there will be continuing changes. One trend in
environmental regulation is to increase reporting obligations and place more
restrictions and limitations on activities, such as emissions of pollutants,
generation and disposal of wastes and use, storage and handling of chemical
substances, that may impact human health, the environment and/or endangered
species. Increasingly strict environmental restrictions and limitations have
resulted in increased operating costs for us and other similar businesses
throughout the United States. It is possible that the costs of compliance with
environmental laws and regulations may continue to increase. We will attempt to
anticipate future regulatory requirements that might be imposed and to plan
accordingly, but there can be no assurance that we will identify and properly
anticipate each such charge, or that our efforts will prevent material costs, if
any, from arising.
 
 CASH
DISTRIBUTIONS
 
 We do not have a contractual obligation
to make distributions to our unit holders.  We distribute our
“available cash,” to our unit holders each quarter in accordance with their
respective percentage interests. “Available cash” is defined in our operating
agreement, and it generally means, for each fiscal quarter:
 
 ·
              all
      cash on hand at the end of the
quarter;
  ·
              less
      the amount of cash that our board of directors determines in its
      reasonable discretion is necessary or appropriate
  to:
  ·
              provide
      for the proper conduct of our business (including reserves for future
      capital expenditures and credit
needs);
  ·
              comply
      with applicable law, any of our debt instruments, or other agreements;
      or
  ·
              provide
      funds for distributions to our unit holders for any one more of the next
      four quarters or with respect to our management incentive
      interests;
  ·
              plus
      all cash on hand on the date of determination of available cash for the
      quarter resulting from working capital borrowings made after the end of
      the quarter.
  Working capital borrowings are
generally borrowings that are made under our credit facility and in all cases
are used solely for working capital purposes or to pay distributions to unit
holders.
 
 All cash we distribute to unit holders
will be characterized as either operating surplus or capital surplus, as defined
in our limited liability company agreement and is subject to different
distribution rules.  We will treat all available cash distributed as
coming from operating surplus until the sum of all available cash distributed
since we began operations equals the operating surplus as of the most recent
date of determination of available cash.  We do not anticipate
distributing any cash from capital surplus.
 
 Available cash is initially distributed
98% to our common unit holders and 2% to Atlas Energy
Management.  These distribution percentages are modified to provide
for incentive distributions (any distribution paid to Atlas Energy Management in
excess of 2% of the aggregate amount of cash being distributed) to be paid to
Atlas Energy Management if quarterly distributions to the common unit holders
exceed specified targets as defined in our limited liability company
agreement.
  59
  CONTRACTUAL
OBLIGATIONS AND COMMERCIAL COMMITMENTS
 
 The
following table summarizes our contractual obligations at December 31, 2008 (in
thousands):
 Payments
      due by period(in
      thousands)Less
      than
                          
                          
                          2
      - 3
                          
                          
                          4
      - 5
                          
                          
                          After
      5Contractual
      cash obligations:
                          
                          Total
                          
                          
                          1
      Year
                          
                          
                          Years
                          
                          
                          Years
                          
                          
                          YearsSenior
      unsecured notes
                          
                          $
                          400,000
                          
                          
                          $
                          —
                          
                          
                          $
                          —
                          
                          
                          $
                          —
                          
                          
                          $
                          400,000Revolving
      credit facilities
                          
                          
                          467,000
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          467,000
                          
                          
                          
                          —Operating
      lease obligations
                          
                          
                          14,368
                          
                          
                          
                          3,178
                          
                          
                          
                          4,841
                          
                          
                          
                          2,496
                          
                          
                          
                          3,853Capital
      lease obligations
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —Interest
      payments
                          
                          
                          445,222
                          
                          
                          
                          58,614
                          
                          
                          
                          117,228
                          
                          
                          
                          93,797
                          
                          
                          
                          175,583Unconditional
      purchase obligations
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —Other
      long-term obligation
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —Total
      contractual cash obligations
                          
                          $
                          1,326,590
                          
                          
                          $
                          61,792
                          
                          
                          $
                          122,069
                          
                          
                          $
                          563,293
                          
                          
                          $
                          579,436
 
 Payments
      due by period(in
      thousands)Less
      than
                          
                          
                          2
      - 3
                          
                          
                          4
      - 5
                          
                          
                          After
      5Other
      commercial commitments:
                          
                          Total
                          
                          
                          1
      Year
                          
                          
                          Years
                          
                          
                          Years
                          
                          
                          YearsStandby
      letters of credit
                          
                          $
                          1,159
                          
                          
                          $
                          1,159
                          
                          
                          $
                          —
                          
                          
                          $
                          —
                          
                          
                          $
                          —Guarantees
                          
                          
                          5,110
                          
                          
                          
                          525
                          
                          
                          
                          1,116
                          
                          
                          
                          1,001
                          
                          
                          
                          2,468Standby
      replacement commitments
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —Other
      commercial commitments
                          
                          
                          41,124
                          
                          
                          
                          41,124
                          
                          
                          
                          —
                          
                          
                          
                          —
                          
                          
                          
                          —Total
      commercial commitments
                          
                          $
                          47,393
                          
                          
                          $
                          42,808
                          
                          
                          $
                          1,116
                          
                          
                          $
                          1,001
                          
                          
                          $
                          2,468
 
 OFF
BALANCE SHEET ARRANGEMENTS
 
 As of
December 31, 2008, our off balance sheet arrangements are limited to our
guarantee of Crown Drilling of Pennsylvania, LLC’s $5.1 million credit
arrangement and our letters of credit outstanding of $1.2 million.  In
addition, our estimated capital contribution for the drilling and completion
costs related to Atlas Resources Public #18-2008 Program is
approximately $41.1 million.
 
 CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
  The
discussion and analysis of our financial condition and results of operations are
based upon our combined and consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements requires
us to make estimates and judgments that affect the reported amounts of our
assets, liabilities, revenues and cost and expenses, and related disclosure of
contingent assets and liabilities. On an on-going basis, we evaluate our
estimates, including those related to the provision for possible losses,
goodwill and identifiable intangible assets, and certain accrued liabilities. We
base our estimates on historical experience and on various other assumptions
that we believe reasonable under the circumstances, the results of which form
the basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results may
differ from these estimates under different assumptions or
conditions.
 
 We
consider accounting policies related to fair value of derivative instruments;
oil and gas properties and reserve estimates and impairment, asset retirement
obligations; goodwill and other long-lived assets  to be critical
policies.  These policies are summarized below and in “Note 2 –
Summary of Significant Accounting Policies”, to our financial statements
included herein on our annual Form 10-K for the year ended December 31,
2008.
 Fair
Value of Financial Instruments
 
 The
Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157
establishes a fair value hierarchy which requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be
used to measure fair value:
 
 Level 1–Quoted prices in
active markets for identical assets and liabilities that the reporting entity
has the ability to access at the measurement date.
  60
  Level 2 –Inputs other than
quoted prices included within Level 1 that are observable for the asset and
liability or can be corroborated with observable market data for substantially
the entire contractual term of the asset or liability.
 
 Level 3 –Unobservable inputs
that reflect the entity’s own assumptions about the assumptions that market
participants would use in the pricing of the asset or liability and are
consequently not based on market activity, but rather through particular
valuation techniques.
 
 The
Company uses the fair value methodology outlined in SFAS No. 157 to value the
assets and liabilities for its outstanding derivative contracts. All of the
Company’s derivative contracts are defined as Level 2. The Company’s natural gas
and crude oil derivative contracts are valued based on prices quoted on the
NYMEX or WTI and adjusted by the respective counterparty using various
assumptions including quoted forward prices, time value, volatility factors, and
contractual prices for the underlying instruments. The Company’s interest rate
derivative contracts are valued using a LIBOR rate-based forward price curve
model.
 
 Reserve
Estimates
 
 Our estimates of our proved natural gas
and oil reserves and future net revenues from them are based upon reserve
analyses that rely upon various assumptions, including those required by the
SEC, as to natural gas and oil prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Any significant variance in these
assumptions could materially affect the estimated quantity of our reserves. As a
result, our estimates of our proved natural gas and oil reserves are inherently
imprecise. Actual future production, natural gas and oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and oil reserves may vary substantially from our
estimates or estimates contained in the reserve reports and may affect our
ability to pay amounts due under our credit facilities or cause a reduction in
our energy credit facilities. In addition, our proved reserves may be subject to
downward or upward revision based upon production history, results of future
exploration and development, prevailing natural gas and oil prices, mechanical
difficulties, governmental regulation and other factors, many of which are
beyond our control.
 
 Impairment
of Oil and Gas Properties
 
 We review our producing oil and gas
properties for impairment on an annual basis and whenever events and
circumstances indicate a decline in the recoverability of their carrying values.
We estimate the expected future cash flows from our oil and gas properties and
compare such future cash flows to the carrying amount of the oil and gas
properties to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, we will adjust the
carrying amount of the oil and gas properties to their fair value in the current
period. The factors used to determine fair value include, but are not limited
to, estimates of reserves, future production estimates, anticipated capital
expenditures, and a discount rate commensurate with the risk associated with
realizing the expected cash flows projected. Because of the complexities
associated with oil and gas reserve estimates and the history of price
volatility in the oil and gas markets, events may arise that will require us to
record an impairment of our oil and gas properties. Any such impairment may
affect or cause a reduction in our credit facilities. See — “Impairment
of Oil and Gas Properties” in Note 2, under
Item 8, “Financial
Statements and Supplementary Data” for more
information.
 Asset
Retirement Obligations
 
 As described in Note 4 to our combined
and consolidated financial statements, we follow SFAS No. 143, “Accounting for
Asset Retirement Obligations,” and on December 31, 2006, we adopted FASB
Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations,”
which resulted in a cumulative effect adjustment of $6.4 million in the year
ended December 31, 2006. Under SFAS No. 143, estimated asset retirement costs
are recognized when the asset is placed in service, and are amortized using the
units-of-production method. On an annual basis, we review our estimates of the
costs of future dismantlement, restoration, reclamation and abandonment of our
natural gas and oil-producing properties. We also review our estimates of the
salvage value of equipment recoverable upon abandonment. As of December 31, 2008
and 2007, our estimate of salvage values was greater than or equal to our
estimate of the costs of future dismantlement, restoration, reclamation and
abandonment.  A decrease in our salvage value or an increase in
dismantlement, restoration, reclamation and abandonment costs from those we have
estimated could reduce our gross profit from operations.
  61
  Inherent in the fair value calculation
of asset retirement obligations are numerous assumptions and judgments including
the estimated remaining lives of the wells, the estimated cost to plug and
abandon the wells in the future, inflation factors, credit adjusted discount
rates and changes in the legal regulatory requirements. To the extent future
revisions to these assumptions impact the fair value of our existing asset
retirement obligation, a corresponding adjustment is made to our oil and gas
properties.
 
 Impairment
of Long-Lived Assets and Goodwill
 
 We have
recorded goodwill of $35.2 million in connection with several acquisitions of
assets.  Goodwill and intangibles with infinite lives must be tested
for impairment annually or more frequently if events or changes in circumstances
indicate that the related asset might be impaired. Under the principles of SFAS
No. 142, an impairment loss should be recognized if the carrying value of an
entity’s reporting units exceeds its estimated fair value.  Because
quoted market prices for our reporting units are not available, management must
apply judgment in determining the estimated fair value of these reporting
units.  Management uses all available information to make these fair
value determinations, including the present values of expected future cash flows
using discount rates commensurate with the risks involved in the
assets.  A key component of these fair value determinations is a
reconciliation of the sum of the fair value calculations to our market
capitalization.  The principles of SFAS No. 142 and its
interpretations acknowledge that the observed market prices of individual trades
of an entity’s equity securities (and thus its computed market capitalization)
may not be representative of the fair value of the entity as a
whole.  Substantial value may arise from the ability to take advantage
of synergies and other benefits that flow from control over another
entity.  Consequently, measuring the fair value of a collection of
assets and liabilities that operate together in a controlled entity is different
from measuring the fair value of that entity’s individual equity
securities.  In most industries, including ours, an acquiring entity
typically is willing to pay more for equity securities that give it a
controlling interest than an investor would pay for a number of equity
securities representing less than a controlling interest.  Therefore,
once the above fair value calculations have been determined, we also consider a
control premium to the calculations.  This control premium is
judgmental and is based on, among other items, observed acquisitions in our
industry.  The resultant fair values calculated for the reporting
units are then compared to observable metrics on large mergers and acquisitions
in our industry to determine whether those valuations appear reasonable in
management’s judgment.  Our evaluation of goodwill at December 31,
2008, 2007 and 2006, respectively, indicated there was no impairment
loss.
 
 In assessing impairment of long-lived
assets other than goodwill, where there has been a change in circumstances
indicating that the carrying amount of a long-lived asset may not be
recoverable, we have estimated future undiscounted net cash flows from the use
of the asset based on actual historical results and expectations about future
economic circumstances, including natural gas and oil prices and operating
costs. Our estimate of future net cash flows from the use of an asset could
change if actual prices and costs differ due to industry conditions or other
factors affecting our performance.
 
 GENERAL
TRENDS AND OUTLOOK
 
 Drilling
Activities
  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.
 62
 Financial
Markets
 
 Currently,
there is an unprecedented uncertainty in the financial markets.  This
uncertainty presents additional potential risks to us.  These risks
include the availability and costs associated with our borrowing capabilities
and raising additional capital, and an increase in the volatility of the market
price of our common unit.  While we have no plans to access debt or
equity in the capital markets, should we decide to do so in the near future, the
terms, size, and cost of new debt or equity could be less favorable than in
previous transactions.
 
 Commodity
Prices
 
 Significant
factors that may impact future commodity prices include developments in the
issues currently impacting Iraq and Iran and the Middle East in general; the
extent to which members of the Organization of Petroleum Exporting Countries and
other oil exporting nations are able to continue to manage oil supply through
export quotas; and overall North American gas supply and demand fundamentals,
including the impact of increasing liquefied natural gas deliveries to the
United States. Although we cannot predict the occurrence of events that will
affect future commodity prices or the degree to which these prices will be
affected, the prices for commodities that we produce will generally approximate
market prices in the geographic region of the
production.
  63
 In order
to address, in part, volatility in commodity prices, we have implemented a
hedging program that is intended to reduce the volatility in our revenues. This
program mitigates, but does not eliminate, our sensitivity to short-term changes
in commodity prices.  Please read “Item 3:  Quantitative and
Qualitative Disclosures About Market Risk.”
 
 Natural
Gas Supply and Outlook
 
 We
believe that current natural gas demand will continue to cause relatively high
levels of natural gas-related drilling in the United States as producers seek to
increase their level of natural gas production.  Although the number
of natural gas wells drilled in the United States has increased overall in
recent years, a corresponding increase in production has not been realized,
primarily as a result of smaller discoveries and the decline in production from
existing wells. The areas in which we operate are experiencing significant
drilling activity as a result of promising prospects from the drilling into
deeper natural gas formations  and the implementation of new
exploration and production techniques, including horizontal and multiple
fracturing techniques .
 
 While we
anticipate continued high levels of exploration and production activities 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 reserves. Drilling activity generally decreases as natural gas
prices decrease. We have no control over the level of drilling activity in the
areas of our operations.
 
 Reserve
Outlook
 
 Our
future oil and gas reserves, production, cash flow and our ability to make
payments on our debt and distributions 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. As initial reservoir pressures are depleted,
natural gas production from a given well decreases. We attempt to overcome this
natural decline by drilling to find additional reserves and acquiring more
reserves than we produce. In order to sustain and grow our level of
distributions, we may need to make acquisitions that are accretive to
distributable cash flow per unit.  In addition, we reserve a portion
of our cash flow from operations to allow us to develop our oil and gas
properties at a level that will allow us to maintain a flat production profile
and reserve levels.
  ITEM
7A:  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
 
 The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in interest rates and oil and gas prices. The disclosures are not meant
to be precise indicators of expected future losses, but rather indicators of
reasonable possible losses. This forward-looking information provides indicators
of how we view and manage our ongoing market risk exposures. All of our market
risk sensitive instruments were entered into for purposes other than
trading.
  64
  General
 
 We are
exposed to various market risks, principally fluctuating interest rates and
changes in commodity prices. These risks can impact our results of operations,
cash flows and financial position. We manage these risks through regular
operating and financing activities and periodically use derivative financial
instruments such as forward contracts and swap agreements.
 
 Current
market conditions elevate our concern over counterparty risks and may adversely
affect the ability of these counterparties to fulfill their obligations to
us.  The counterparties related to our commodity and interest-rate
derivative contracts are banking institutions which also participate in our
revolving credit facility.  The creditworthiness of our counterparties
is constantly monitored, and we currently believe them to be financially
viable.  We are not aware of any inability on the part of our
counterparties to perform under our contracts and believe our exposure to
non-performance is remote.
 
 The
following analysis presents the effect on our earnings, cash flows and financial
position as if hypothetical changes in market risk factors occurred on December
31, 2008. Only the potential impacts of hypothetical assumptions are analyzed.
The analysis does not consider other possible effects that could impact our
business.
  Interest
Rate Risk
 
 At
December 31, 2008, we had an outstanding balance of $467.0 million on our
revolving credit facility with a current borrowing base at December 31, 2008 of
$697.5 million. The weighted average interest rate for borrowings under this
credit facility was 4.5% for the twelve months ended December 30, 2008 and 7.2%
at December 31, 2007.  At December 31, 2008, we had interest rate
derivative contracts having aggregate notional principal amounts of $150.0
million.  Under the terms of this agreement, we will pay weighted
average interest rates of 3.11% plus the applicable margin as defined under the
terms of our revolving credit facility, and will receive LIBOR, plus the
applicable margin on the notional principal amounts.  These
derivatives effectively convert $150.0 million of our floating rate debt under
our revolving credit facility to fixed rate debt.  The interest rate
swap agreements are effective as of December 31, 2008, and expire during periods
through January 2011.
 
 Holding
all other variables constant, including the effect of interest rate derivatives,
a hypothetical 10% change in the weighted average interest rate would change our
net income by $907,000.
 
 Commodity
Price Risk
 
 Our major
market risk exposure in commodities is fluctuations in the pricing of our gas
and oil production. Realized pricing is primarily driven by the prevailing
worldwide prices for crude oil and spot market prices applicable to United
States natural gas production. Pricing for gas and oil production has been
volatile and unpredictable for many years. To limit our exposure to changing
natural gas and oil prices, we enter into natural gas and oil costless collar,
and option contracts. At any point in time, such contracts may include regulated
NYMEX futures and options contracts and non-regulated over-the-counter futures
contracts with qualified, approved counterparties. NYMEX contracts are generally
settled with offsetting positions, but may be settled by the delivery of natural
gas. Oil contracts are based on a West Texas Intermediate, or WTI
index.
 
 Our risk
management objective regarding commodity price risk is to utilize available
instruments, including financial derivatives and physical forward contracts, to
maximize the value of the company’s production while also reducing its exposure
to the volatility of commodity markets. Considering those volumes for which we
have entered into financial derivative agreements for the twelve-month period
ending December 31, 2009, and current indices, a theoretical 10% upward or
downward change in the price of natural gas and crude oil would result in a
change in net income of approximately $4.8 million.
 
  65
  We
formally document all relationships between derivative instruments and the items
being hedged, including the risk management objective and strategy for
undertaking the derivative transactions. This includes matching the natural gas
and oil futures and options contracts to the forecasted transactions. We assess,
both at the inception of the derivative transaction and on an ongoing basis,
whether the derivatives are highly effective in offsetting changes in the fair
value of hedged items. Historically these contracts have qualified and been
designated as cash flow hedges in accordance with SFAS No. 133, and are recorded
at their fair values. Gains or losses on future contracts are determined as the
difference between the contract price and a reference price, generally prices on
NYMEX or WTI. Changes in fair value are recognized in consolidated equity
and recognized within the consolidated statements of income in the
month the hedged commodity is sold. If it is determined that a derivative
is not highly effective as a hedge or it has ceased to be a highly effective
derivative, due to the loss of correlation between changes in reference
prices underlying a derivative instrument and actual commodity prices, we
will discontinue hedge accounting for the derivative and subsequent changes in
fair value for the derivative will be recognized immediately into
earnings.
 
 We
recognized a loss of $25.1 million and gains of $17.6 million and $7.1 million
on settled contracts covering natural gas production for the years ended
December 31, 2008, 2007 and 2006, respectively. We recognized a loss of $312,000
on settled oil production for the year ended December 31, 2008. There were no
gains (losses) on oil settlements for the year ended December 31, 2007 and
2006.  As the underlying prices and terms in our derivative contracts
were consistent with the indices used to sell our natural gas and oil, there
were no gains or losses recognized during the years ended December 31, 2008 and
2007 for hedge ineffectiveness or as a result of the discontinuance of any cash
flow hedges.
 
 On May
18, 2007, we signed a definitive agreement to acquire AGO.  In
connection with the financing of this transaction, we agreed as a condition
precedent to closing that we would hedge 80% of our projected natural gas
volumes for no less than three years from the closing date of the transaction.
During May 2007, we entered into derivative instruments to hedge 80% of the
projected production of the assets to be acquired as required under the
financing agreement. The production volume of the assets to be acquired was not
considered to be “probable forecasted production” under SFAS No. 133 at the date
these derivatives were entered into because the acquisition of the assets had
not yet been completed. Accordingly, we recognized the instruments as
non-qualifying for hedge accounting at inception with subsequent changes in the
derivative value recorded within revenues in our consolidated statements of
income. We recognized a non-cash gain on mark-to-market derivatives of $26.3
million related to the change in value of these derivatives from May 22, 2007
through June 28, 2007. Upon closing of the acquisition on June 29, 2007, the
production volume of the assets acquired was considered “probable forecasted
production” under SFAS No. 133 and we evaluated these derivatives under the cash
flow hedge criteria in accordance with SFAS No. 133.
 
 We have a
$106.1 million net unrealized asset related to financial hedges in accumulated
other comprehensive loss associated with commodity derivatives at December 31,
2008, compared to a net unrealized liability of $5.1 million at December
31, 2007.  If the fair values of the instruments remain at current market
values, we will reclassify $63.7 million of unrealized gains to our consolidated
statements of income over the next twelve-month period as these contracts settle
and $42.4 million of unrealized gains will be reclassified in later
periods.
 
 The fair
value of the derivatives at December 31, 2008 is a net unrealized hedge asset of
$159.5 million, of which our portion is $107.7 million and $51.8 million of
unrealized hedge gains have been reallocated to our investment partnerships. At
January 31, 2009, commodity prices for natural gas and crude oil have declined
further. We estimate that our unrealized net asset has increased by
approximately $50.8 million to an estimated unrealized net asset of $210.3
million at January 31, 2009, from a $159.5 million net asset at December 31,
2008.
 
 As of December 31, 2008, we had the
following natural gas and crude oil volumes hedged:
 
 Natural
Gas Fixed Price Swaps
 
 Twelve
      MonthPeriod
      Ending
                        
                        
                        
                        
                        
                        
                        
                        Average
                        
                        
                        Fair
      ValueDecember
      31,
                        
                        
                        
                        
                        Volumes
                        
                        
                        Fixed
      Price
                        
                        
                        Asset(MMBtu)
                        
                        
                        (per
      MMBtu)
                        
                        
                        (in thousands)(1)2009
                        
                        
                        
                        
                        
                        
                        38,120,000
                        
                        
                        $
                        8.55
                        
                        
                        $
                        93,2462010
                        
                        
                        
                        
                        
                        
                        26,360,000
                        
                        
                        $
                        8.11
                        
                        
                        
                        25,5372011
                        
                        
                        
                        
                        
                        
                        18,680,000
                        
                        
                        $
                        7.84
                        
                        
                        
                        9,6702012
                        
                        
                        
                        
                        
                        
                        13,800,000
                        
                        
                        $
                        8.05
                        
                        
                        
                        10,8512013
                        
                        
                        
                        
                        
                        
                        1,500,000
                        
                        
                        $
                        8.73
                        
                        
                        
                        2,098$
                        141,402
 
  66
  Natural
Gas Costless Collars
 
 Twelve
      MonthPeriod
      Ending
                        
                        
                        
                        
                        
                        
                        Average
                        
                        
                        Fair
      ValueDecember
      31,
                        
                        Option
      Type
                        
                        Volumes
                        
                        
                        Floor
      and Cap
                        
                        
                        Asset(MMBtu)
                        
                        
                        (per
      MMBtu)
                        
                        
                        (in thousands)(1)2009
                        
                        Puts
      purchased
                        
                        
                        240,000
                        
                        
                        $
                        11.00
                        
                        
                        $
                        1,1822009
                        
                        Calls
      sold
                        
                        
                        240,000
                        
                        
                        $
                        15.35
                        
                        
                        
                        —2010
                        
                        Puts
      purchased
                        
                        
                        3,360,000
                        
                        
                        $
                        7.84
                        
                        
                        
                        3,3402010
                        
                        Calls
      sold
                        
                        
                        3,360,000
                        
                        
                        $
                        9.01
                        
                        
                        
                        —2011
                        
                        Puts
      purchased
                        
                        
                        7,500,000
                        
                        
                        $
                        7.48
                        
                        
                        
                        3,7082011
                        
                        Calls
      sold
                        
                        
                        7,500,000
                        
                        
                        $
                        8.44
                        
                        
                        
                        —2012
                        
                        Puts
      purchased
                        
                        
                        1,020,000
                        
                        
                        $
                        7.00
                        
                        
                        
                        2232012
                        
                        Calls
      sold
                        
                        
                        1,020,000
                        
                        
                        $
                        8.32
                        
                        
                        
                        —2013
                        
                        Puts
      purchased
                        
                        
                        300,000
                        
                        
                        $
                        7.00
                        
                        
                        
                        722013
                        
                        Calls
      sold
                        
                        
                        300,000
                        
                        
                        $
                        8.25
                        
                        
                        
                        —$
                        8,525
 
 Crude
Oil Fixed Price Swaps
 
 Twelve
      MonthPeriod
      Ending
                    
                    
                    
                    
                    
                    
                    
                    Average
                    
                    
                    Fair
      ValueDecember
      31,
                    
                    
                    
                    
                    Volumes
                    
                    
                    Fixed
      Price
                    
                    
                    Asset(Bbl)
                    
                    
                    (per
      Bbl)
                    
                    
                    (in thousands)(2)2009
                    
                    
                    
                    
                    
                    
                    59,900
                    
                    
                    $
                    100.14
                    
                    
                    $
                    2,7902010
                    
                    
                    
                    
                    
                    
                    48,900
                    
                    
                    $
                    97.40
                    
                    
                    
                    1,6242011
                    
                    
                    
                    
                    
                    
                    42,600
                    
                    
                    $
                    96.44
                    
                    
                    
                    1,1412012
                    
                    
                    
                    
                    
                    
                    33,500
                    
                    
                    $
                    96.00
                    
                    
                    
                    7852013
                    
                    
                    
                    
                    
                    
                    10,000
                    
                    
                    $
                    96.06
                    
                    
                    
                    221$
                    6,561
 
 Crude
Oil Costless Collars
 
 Twelve
      MonthPeriod
      Ending
                      
                      
                      
                      
                      
                      
                      Average
                      
                      
                      Fair
      ValueDecember
      31,
                      
                      Option
      Type
                      
                      Volumes
                      
                      
                      Floor
      and Cap
                      
                      
                      Asset(Bbl)
                      
                      
                      (per
      Bbl)
                      
                      
                      (in thousands)(2)2009
                      
                      Puts
      purchased
                      
                      
                      36,500
                      
                      
                      $
                      85.00
                      
                      
                      $
                      1,2002009
                      
                      Calls
      sold
                      
                      
                      36,500
                      
                      
                      $
                      118.63
                      
                      
                      
                      —2010
                      
                      Puts
      purchased
                      
                      
                      31,000
                      
                      
                      $
                      85.00
                      
                      
                      
                      7542010
                      
                      Calls
      sold
                      
                      
                      31,000
                      
                      
                      $
                      112.92
                      
                      
                      
                      —2011
                      
                      Puts
      purchased
                      
                      
                      27,000
                      
                      
                      $
                      85.00
                      
                      
                      
                      5382011
                      
                      Calls
      sold
                      
                      
                      27,000
                      
                      
                      $
                      110.81
                      
                      
                      
                      —2012
                      
                      Puts
      purchased
                      
                      
                      21,500
                      
                      
                      $
                      85.00
                      
                      
                      
                      3792012
                      
                      Calls
      sold
                      
                      
                      21,500
                      
                      
                      $
                      110.06
                      
                      
                      
                      —2013
                      
                      Puts
      purchased
                      
                      
                      6,000
                      
                      
                      $
                      85.00
                      
                      
                      
                      1002013
                      
                      Calls
      sold
                      
                      
                      6,000
                      
                      
                      $
                      110.09
                      
                      
                      
                      —2,971Total
      Net Asset
                      
                      
                      $
                      159,459
 
 (1)  Fair
value based on forward NYMEX natural gas prices, as applicable.
 (2)  Fair
value based on forward WTI crude oil prices, as applicable.
  67
  
 ITEM
8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 [THE
REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]
  68
  REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 Board of
Directors and Unit holders
 Atlas
Energy Resources, LLC
 
 We have
audited the accompanying consolidated balance sheets of Atlas Energy Resources,
LLC (a Delaware limited liability company) and subsidiaries as of December 31,
2008 and 2007, and the related combined and consolidated statements of income,
comprehensive income, members' equity, and cash flows for each of the three
years in the period ended December 31, 2008. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States).Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements.An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation.We
believe that our audits provide a reasonable basis for our opinion.
 
 In our
opinion, the combined and consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Atlas Energy
Resources, LLC and subsidiaries as of December 31, 2008 and 2007, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 2008, in conformity with accounting
principles generally accepted in the United States of America.
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Atlas Energy Resources, LLC’s internal control
over financial reporting as of December 31, 2008, based on criteria established
in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO)and our report
dated March 2, 2009 expressed an unqualified opinion on the effectiveness
of internal control over the financial reporting.
 
 Discussed
in Note 2 to the combined and consolidated financial statements, the Company
recorded a cumulative effect adjustment in 2006 in connection with the adoption
of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement
Obligations.”
 
 /s/ GRANT
THORNTON LLP
 
 Cleveland,
Ohio
 March 2,
2009
 
  69
 
 ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 CONSOLIDATED
BALANCE SHEETS
 (in
thousands)
 
 December
      31,2008
                      
                      
                      2007ASSETSCurrent
      assets:Cash
      and cash equivalents
                      
                      $
                      5,655
                      
                      
                      $
                      25,258Accounts
      receivable
                      
                      
                      70,573
                      
                      
                      
                      57,524Current
      portion of derivative asset
                      
                      
                      107,766
                      
                      
                      
                      38,181Prepaid
      expenses and other
                      
                      
                      14,714
                      
                      
                      
                      8,265Total
      current assets
                      
                      
                      198,708
                      
                      
                      
                      129,228Property,
      plant and equipment, net
                      
                      
                      1,945,119
                      
                      
                      
                      1,693,467Other
      assets, net
                      
                      
                      18,403
                      
                      
                      
                      21,430Long-term
      derivative asset
                      
                      
                      69,451
                      
                      
                      
                      6,882Intangible
      assets, net
                      
                      
                      3,838
                      
                      
                      
                      5,061Goodwill
                      
                      
                      35,166
                      
                      
                      
                      35,166$
                      2,270,685
                      
                      
                      $
                      1,891,234LIABILITIES
      AND MEMBERS’ EQUITYCurrent
      liabilities:Current
      portion of long-term debt
                      
                      $
                      —
                      
                      
                      $
                      30Accounts
      payable
                      
                      
                      74,262
                      
                      
                      
                      55,051Accrued
      liabilities – interest
                      
                      
                      19,878
                      
                      
                      
                      3,816Accrued
      liabilities – other
                      
                      
                      29,369
                      
                      
                      
                      21,706Liabilities
      associated with drilling contracts
                      
                      
                      96,700
                      
                      
                      
                      132,517Derivative
      payable to Partnerships – short-term
                      
                      
                      34,932
                      
                      
                      
                      9,013Current
      portion of derivative liability
                      
                      
                      12,829
                      
                      
                      
                      356Total
      current liabilities
                      
                      
                      267,970
                      
                      
                      
                      222,489Long-term
      debt, less current portion
                      
                      
                      873,655
                      
                      
                      
                      740,000Other
      long-term liabilities
                      
                      
                      6,524
                      
                      
                      
                      1,024Derivative
      payable to Partnerships – long-term
                      
                      
                      22,581
                      
                      
                      
                      1,348Advances
      from affiliates
                      
                      
                      1,712
                      
                      
                      
                      8,696Long-term
      derivative liability
                      
                      
                      10,771
                      
                      
                      
                      39,204Asset
      retirement obligations
                      
                      
                      48,136
                      
                      
                      
                      42,358Commitments
      and contingenciesMembers’
      equity:Class
      B members’ interests
                      
                      
                      932,804
                      
                      
                      
                      835,447Class
      A member’s interest
                      
                      
                      6,257
                      
                      
                      
                      5,770Accumulated
      other comprehensive income (loss)
                      
                      
                      100,275
                      
                      
                      
                      (5,102
                      )Total
      members’ equity
                      
                      
                      1,039,336
                      
                      
                      
                      836,115$
                      2,270,685
                      
                      
                      $
                      1,891,234
 
 See
accompanying notes to combined and consolidated financial
statements
  70
 
 ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 COMBINED
AND CONSOLIDATED STATEMENTS OF INCOME
 (in
thousands, except per unit data)
 
 Years
      Ended December 31,2008
                                        
                                        
                                        2007
                                        
                                        
                                        2006REVENUESWell
      construction and completion
                                        
                                        $
                                        415,036
                                        
                                        
                                        $
                                        321,471
                                        
                                        
                                        $
                                        198,567Gas
      and oil production
                                        
                                        
                                        311,850
                                        
                                        
                                        
                                        180,125
                                        
                                        
                                        
                                        88,449Administration
      and oversight
                                        
                                        
                                        19,362
                                        
                                        
                                        
                                        18,138
                                        
                                        
                                        
                                        11,762Well
      services
                                        
                                        
                                        20,482
                                        
                                        
                                        
                                        17,592
                                        
                                        
                                        
                                        12,953Gathering
                                        
                                        
                                        20,670
                                        
                                        
                                        
                                        14,314
                                        
                                        
                                        
                                        9,251Gain
      on mark-to-market derivatives
                                        
                                        
                                        —
                                        
                                        
                                        
                                        26,257
                                        
                                        
                                        
                                        —Total
      revenues
                                        
                                        
                                        787,400
                                        
                                        
                                        
                                        577,897
                                        
                                        
                                        
                                        320,982COSTS
      AND EXPENSESWell
      construction and completion
                                        
                                        
                                        359,609
                                        
                                        
                                        
                                        279,540
                                        
                                        
                                        
                                        172,666Gas
      and oil production
                                        
                                        
                                        59,579
                                        
                                        
                                        
                                        32,193
                                        
                                        
                                        
                                        13,881Well
      services
                                        
                                        
                                        10,654
                                        
                                        
                                        
                                        9,062
                                        
                                        
                                        
                                        7,337Gathering
                                        
                                        
                                        441
                                        
                                        
                                        
                                        214
                                        
                                        
                                        
                                        —Gathering
      fee – Atlas Pipeline
                                        
                                        
                                        19,098
                                        
                                        
                                        
                                        13,781
                                        
                                        
                                        
                                        29,545General
      and administrative
                                        
                                        
                                        44,659
                                        
                                        
                                        
                                        39,414
                                        
                                        
                                        
                                        23,367Net
      expense reimbursement – affiliate
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —
                                        
                                        
                                        
                                        1,237Depreciation,
      depletion and amortization
                                        
                                        
                                        95,434
                                        
                                        
                                        
                                        56,942
                                        
                                        
                                        
                                        22,491Total
      operating expenses
                                        
                                        
                                        589,474
                                        
                                        
                                        
                                        431,146
                                        
                                        
                                        
                                        270,524OPERATING
      INCOME
                                        
                                        
                                        197,926
                                        
                                        
                                        
                                        146,751
                                        
                                        
                                        
                                        50,458OTHER
      INCOME (EXPENSE)Interest
      expense
                                        
                                        
                                        (56,306
                                        )
                                        
                                        
                                        (30,096
                                        )
                                        
                                        
                                        —Other
      – net
                                        
                                        
                                        1,159
                                        
                                        
                                        
                                        849
                                        
                                        
                                        
                                        1,369Total
      other income
                                        
                                        
                                        (55,147
                                        )
                                        
                                        
                                        (29,247
                                        )
                                        
                                        
                                        1,369Net
      income before cumulative effect of accounting change
                                        
                                        
                                        142,779
                                        
                                        
                                        
                                        117,504
                                        
                                        
                                        
                                        51,827Cumulative
      effect of accounting change
                                        
                                        
                                        —
                                        
                                        
                                        
                                        –
                                        
                                        
                                        
                                        6,355Net
      income
                                        
                                        $
                                        142,779
                                        
                                        
                                        $
                                        117,504
                                        
                                        
                                        $
                                        58,182Allocation
      of net income attributable to members’ interests/owners:Portion
      applicable to owner’s interest (period prior to the initial public
      offering on December 18, 2006)
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        55,375Portion
      applicable to members’ interests (period subsequent to the initial public
      offering on December 18, 2006)
                                        
                                        
                                        142,779
                                        
                                        
                                        
                                        117,504
                                        
                                        
                                        
                                        2,807$
                                        142,779
                                        
                                        
                                        $
                                        117,504
                                        
                                        
                                        $
                                        58,182Allocation
      of net income attributable to members’ interests:Class
      A member’s interests
                                        
                                        $
                                        9,062
                                        
                                        
                                        $
                                        4,099
                                        
                                        
                                        $
                                        56Class
      B members’ interests
                                        
                                        
                                        133,717
                                        
                                        
                                        
                                        113,405
                                        
                                        
                                        
                                        2,751Net
      income attributable to members’ interests
                                        
                                        $
                                        142,779
                                        
                                        
                                        $
                                        117,504
                                        
                                        
                                        $
                                        2,807Net
      income attributable to Class B members per unit:Basic
                                        
                                        $
                                        2.14
                                        
                                        
                                        $
                                        2.32
                                        
                                        
                                        $
                                        .08Diluted
                                        
                                        $
                                        2.12
                                        
                                        
                                        $
                                        2.29
                                        
                                        
                                        $
                                        .08Weighted
      average Class B members’ units outstanding:Basic
                                        
                                        
                                        62,409
                                        
                                        
                                        
                                        48,909
                                        
                                        
                                        
                                        36,627Diluted
                                        
                                        
                                        63,023
                                        
                                        
                                        
                                        49,449
                                        
                                        
                                        
                                        36,638
 
 See
accompanying notes to combined and consolidated financial
statements
  71
 
 ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 COMBINED
AND CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (in
thousands)
 
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Net
      income
                  
                  $
                  142,779
                  
                  
                  $
                  117,504
                  
                  
                  $
                  58,182Other
      comprehensive income:Unrealized
      holding gains (losses) on hedging contracts
                  
                  
                  79,478
                  
                  
                  
                  (8,582
                  )
                  
                  
                  31,834Less:
      reclassification adjustment for losses (gains) realized in net
      income
                  
                  
                  25,899
                  
                  
                  
                  (17,608
                  )
                  
                  
                  (7,082
                  )105,377
                  
                  
                  
                  (26,190
                  )
                  
                  
                  24,752Comprehensive
      income
                  
                  $
                  248,156
                  
                  
                  $
                  91,314
                  
                  
                  $
                  82,934
 
 See
accompanying notes to combined and consolidated financial
statements
  72
 
 ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 COMBINED
AND CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
 (in
thousands, except unit data)
  Accumulated
                                      
                                      
                                      
                                      
                                      
                                      TotalOther
                                      
                                      
                                      
                                      
                                      
                                      Owner'sComprehensive
                                      
                                      
                                      Net
                                      
                                      
                                      Equity/Owner's
                                      
                                      
                                      Class
      A Units
                                      
                                      
                                      Class
      B Common Units
                                      
                                      
                                      Class
      D Units
                                      
                                      
                                      Income
                                      
                                      
                                      Affiliate
                                      
                                      
                                      Members'Equity
                                      
                                      
                                      Units
                                      
                                      
                                      Amount
                                      
                                      
                                      Units
                                      
                                      
                                      Amount
                                      
                                      
                                      Units
                                      
                                      
                                      Amount
                                      
                                      
                                      (Loss)
                                      
                                      
                                      Investment
                                      
                                      
                                      EquityBalance,  January
      1, 2006
                                      
                                      $
                                      158,183
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      (3.664
                                      )
                                      
                                      $
                                      158,183
                                      
                                      
                                      $
                                      154,519Net
      income attributable to ownerprior to IPO on
      December 18, 2006
                                      
                                      
                                      55,375
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      55,375
                                      
                                      
                                      
                                      55,375Net
      assets retained by owner
                                      
                                      
                                      (25,108
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (25,108
                                      )
                                      
                                      
                                      (25,108
                                      )Net
      assets contributed by owner
                                      
                                      
                                      (188,450
                                      )
                                      
                                      
                                      748,456
                                      
                                      
                                      
                                      3,769
                                      
                                      
                                      
                                      29,352,996
                                      
                                      
                                      
                                      184,681
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (188,450
                                      )
                                      
                                      
                                      —Issuance
      of common units in IPO
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      7,273,750
                                      
                                      
                                      
                                      139,944
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      139,944Distribution
      to
      owner
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (139,944
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (139,944
                                      )Stock-based
      compensation
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      337
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      337Other
      compensation income
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      24,752
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      24,752Net
      income attributable to unitholders subsequent to
      IPO
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      56
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      2,751
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      2,807Balance,
      December 31, 2006
                                      
                                      $
                                      —
                                      
                                      
                                      
                                      748,456
                                      
                                      
                                      $
                                      3,825
                                      
                                      
                                      
                                      36,626,746
                                      
                                      
                                      $
                                      187,769
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      21,088
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      212,682Units
      issued
                                      
                                      
                                      —
                                      
                                      
                                      
                                      490,530
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      7,380,800
                                      
                                      
                                      
                                      181,179
                                      
                                      
                                      
                                      16,702,828
                                      
                                      
                                      
                                      416,316
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      597,495Distributions
      to members
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (2,154
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (57,941
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (9,187
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (69,282
                                      )Distributions
      paid on unissuedunits
      under incentive plan
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (778
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (778
                                      )Stock-based
      compensation
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      4,684
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      4,684Other
      comprehensive income
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (26,190
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (26,190
                                      )Conversion
      of Class D units
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      16,702,828
                                      
                                      
                                      
                                      415,845
                                      
                                      
                                      
                                      (16,702,828
                                      )
                                      
                                      
                                      (415,845
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —Net
      income
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      4,099
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      104,689
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      8,716
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      117,504Balance,
      December 31, 2007
                                      
                                      $
                                      —
                                      
                                      
                                      
                                      1,238,986
                                      
                                      
                                      $
                                      5,770
                                      
                                      
                                      
                                      60,710,374
                                      
                                      
                                      $
                                      835,447
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      (5,102
                                      )
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      836,115Units
      issued
                                      
                                      
                                      —
                                      
                                      
                                      
                                      54,500
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      2,670,375
                                      
                                      
                                      
                                      107,697
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      107,697Distribution
      to
      members
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (8,575
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (148,104
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (156,679
                                      )Distributions
      paid on unissued units under incentive plan
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (1,438
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (1,438
                                      )Stock-based  compensation
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      5,485
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      5,485Other
      comprehensive income
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      105,377
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      105,377Net
      income
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      9,062
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      133,717
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      142,779Balance,
      December 31, 2008
                                      
                                      $
                                      —
                                      
                                      
                                      
                                      1,293,486
                                      
                                      
                                      $
                                      6,257
                                      
                                      
                                      
                                      63,380,749
                                      
                                      
                                      $
                                      932,804
                                      
                                      
                                      
                                      —
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      100,275
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      1,039,336
  See
accompanying notes to combined and consolidated financial
statements
  73
  ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 COMBINED
AND CONSOLIDATED STATEMENTS OF CASH FLOWS
 (in
thousands)
 
 Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
                    
                    $
                    142,779
                    
                    
                    $
                    117,504
                    
                    
                    $
                    58,182Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Amortization
      of deferred finance costs
                    
                    
                    2,823
                    
                    
                    
                    3,040
                    
                    
                    
                    —Depreciation,
      depletion and amortization
                    
                    
                    95,434
                    
                    
                    
                    56,942
                    
                    
                    
                    22,491Non-cash
      compensation expense
                    
                    
                    5,485
                    
                    
                    
                    4,684
                    
                    
                    
                    337Loss
      (gain) on asset sales and dispositions
                    
                    
                    (32
                    )
                    
                    
                    111
                    
                    
                    
                    (39
                    )Cumulative
      effect of accounting change
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    (6,355
                    )Non-cash
      loss (gain) on derivative value
                    
                    
                    12,430
                    
                    
                    
                    (14,000
                    )
                    
                    
                    —Equity
      (income) loss of unconsolidated subsidiary
                    
                    
                    (233
                    )
                    
                    
                    158
                    
                    
                    
                    —Minority
      interest
                    
                    
                    (55
                    )
                    
                    
                    32
                    
                    
                    
                    —Changes
      in operating assets and liabilities, net of effects of
      acquisitionAccounts
      receivable, prepaid expenses and other
                    
                    
                    (16,461
                    )
                    
                    
                    3,239
                    
                    
                    
                    (8,862
                    )Accounts
      payable
                    
                    
                    19,211
                    
                    
                    
                    6
                    
                    
                    
                    (3,229
                    )Liabilities
      associated with drilling contracts
                    
                    
                    (35,817
                    )
                    
                    
                    45,752
                    
                    
                    
                    16,251Other
      operating assets and liabilities
                    
                    
                    24,359
                    
                    
                    
                    13,514
                    
                    
                    
                    1,760Net
      cash provided by operating activities
                    
                    
                    249,923
                    
                    
                    
                    230,982
                    
                    
                    
                    80,536CASH
      FLOWS FROM INVESTING ACTIVITIES:Net
      cash paid for acquisition
                    
                    
                    —
                    
                    
                    
                    (1,272,518
                    )
                    
                    
                    —Capital
      expenditures
                    
                    
                    (340,975
                    )
                    
                    
                    (196,735
                    )
                    
                    
                    (75,635
                    )Proceeds
      from sale of assets
                    
                    
                    62
                    
                    
                    
                    1,092
                    
                    
                    
                    47Other
                    
                    
                    (195
                    )
                    
                    
                    (273
                    )
                    
                    
                    —Net
      cash used in investing activities
                    
                    
                    (341,108
                    )
                    
                    
                    (1,468,434
                    )
                    
                    
                    (75,588
                    )CASH
      FLOWS FROM FINANCING ACTIVITIES:Borrowings
      under credit facility
                    
                    
                    493,000
                    
                    
                    
                    951,891
                    
                    
                    
                    —Repayments
      under credit facility
                    
                    
                    (766,030
                    )
                    
                    
                    (211,929
                    )
                    
                    
                    (88
                    )Net
      proceeds from issuance of debt
                    
                    
                    407,125
                    
                    
                    
                    —Distributions
      paid to members
                    
                    
                    (151,126
                    )
                    
                    
                    (69,282
                    )
                    
                    
                    —Distributions
      net of capital contributions to Atlas America
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    (139,944
                    )Net
      proceeds from issuance of Class B members units
                    
                    
                    107,697
                    
                    
                    
                    597,495
                    
                    
                    
                    139,944Advances
      to affiliates, net of repayments
                    
                    
                    (6,984
                    )
                    
                    
                    (3,806
                    )
                    
                    
                    (16,748
                    )Other
                    
                    
                    (12,100
                    )
                    
                    
                    (10,492
                    )
                    
                    
                    (197
                    )Net
      cash provided by (used in) financing activities
                    
                    
                    71,582
                    
                    
                    
                    1,253,877
                    
                    
                    
                    (17,033
                    )Net
      change in cash and cash equivalents
                    
                    
                    (19,603
                    )
                    
                    
                    16,425
                    
                    
                    
                    (12,085
                    )Cash
      and cash equivalents, beginning of year
                    
                    
                    25,258
                    
                    
                    
                    8,833
                    
                    
                    
                    20,918Cash
      and cash equivalents, end of year
                    
                    $
                    5,655
                    
                    
                    $
                    25,258
                    
                    
                    $
                    8,833
 
 See
accompanying notes to combined and consolidated financial
statements
  74
 
 ATLAS
ENERGY RESOURCES, LLC AND SUBSIDIARIES
 NOTES
TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
 
 NOTE
1 - NATURE OF OPERATIONS
 
 Atlas
Energy Resources, LLC (“the Company”) is a publicly-traded Delaware limited
liability company (NYSE: ATN) and an independent developer and producer of
natural gas and, to a lesser extent, oil in Northern Michigan's Antrim Shale,
Indiana’s New Albany Shale and the Appalachian Basin. The Company is also a
leading sponsor of and manages tax-advantaged direct investment partnerships, in
which it coinvests to finance the exploitation and development of its acreage
(“the Partnerships”).
 
 On
December 18, 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a
publicly-traded company (NASDAQ: ATLS), contributed all of the stock of its
natural gas and oil development and production subsidiaries and its development
and production assets in exchange for 29,352,996 Class B common units and
748,456 Class A units.  Concurrent with this transaction, the Company
completed an initial public offering of 7,273,750 units of its Class B common
units, representing a 19.4% interest at that moment, at a price of $21.00 per
common unit.  The net proceeds from the offering of $139.9 million,
after deducting underwriting discounts and costs, were distributed to Atlas
America Class A units. The Class A units are entitled to 2% of all quarterly
cash distributions by the Company, without any requirement for future capital
contributions by the holder of such Class A units, even if the Company issues
additional Class B common units or other equity securities in the
future.  The Company is managed by Atlas Energy Management, Inc. (the
“Managing Member”), a wholly-owned subsidiary of Atlas America. At December 31,
2008, the Company has 63,380,749 Class B common units and 1,293,486 Class A
units outstanding.  At December 31, 2008, Atlas America owns 49.4% of
the Company.
 
 NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 Principles
of Combination and Consolidation
 
 The
consolidated financial statements subsequent to the Company’s initial public
offering on December 18, 2006 include the accounts of the Company and its
subsidiaries.  Prior to the Company’s initial public offering, at
which date Atlas America contributed its ownership interests in its natural gas
and oil development and production assets to the Company, the combined financial
statements have been prepared from the separate records maintained by Atlas
America and may not necessarily be indicative of the conditions that would have
existed or the results of operations if the Company had been operated as an
unaffiliated entity. Because a direct ownership relationship did not exist among
all the various entities that comprised the assets contributed by Atlas America
to the Company, Atlas America’s net investment in these entities was shown as
combined equity in the combined financial statements. Transactions between the
Company and other Atlas America operations have been identified in the combined
and consolidated financial statements as transactions between affiliates (see
Note 6).
 
 In
accordance with established practice in the oil and gas industry, the Company
includes its pro-rata share of assets, liabilities, income and lease operating
and general and administrative costs and expenses of the investment partnerships
in which it has an interest.  Such interests typically range from 15%
to 35%. The Company’s financial statements do not include proportional
consolidation of the depletion or impairment expenses of the Partnerships.
Rather, the Company calculates these items specific to its own economics as
further explained under the heading “Oil and Gas Properties”
below.  All material intercompany transactions have been
eliminated.
 
 Use
of Estimates
 
 Preparation
of the combined and consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
The Company’s consolidated financial statements are based on a number of
significant estimates, including the revenue and expense accruals, depletion,
depreciation and amortization, fair value of derivative instruments, the
probability of forecasted transactions, and the allocation of purchase price to
the fair value of assets acquired.  Actual results could differ from
these estimates.
  75
  Reclassifications
 
 Certain amounts in the prior year’s
combined and consolidated financial statements have been reclassified to conform
to the current year presentation.
 
 Cash
Equivalents
 
 The Company considers all highly liquid
investments with a remaining maturity of three months or less at the time of
purchase to be cash equivalents.  These cash equivalents consist
principally of temporary investments of cash in short-term money market
instruments.
 
 Stock-Based
Compensation
 
 The Company applies the provisions of
SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), to its
share-based payments.  Generally, the approach to accounting for SFAS
No. 123(R) requires all unit-based payments to employees, including grants of
employee stock options, to be recognized in the financial statements based on
their fair values.
 
 Net
Income Per Common Unit
 
 Basic net
income per unit for Class B common units is computed by dividing net income
attributable to the Class B members, which is determined after the deduction of
the Class A member’s interests, by the weighted average number of Class B common
units outstanding during the period.  The Class A management incentive
interests (“MIIs” – see Note 13) in net income is calculated on a quarterly
basis based upon its 2% ownership interest, represented by its 1,293,486 Class A
units, and its member’s incentive interests, with a priority allocation of net
income to the Class A member’s MIIs in accordance with the Company’s limited
liability agreement, and the remaining net income or loss allocated with respect
to the Class A’s and Class B’s ownership interests.  Diluted net
income per unit for Class B common units is calculated by dividing net income or
loss attributable to the Class B members by the sum of the weighted average
number of Class B common units outstanding and the dilutive effect, if any, of
the Company’s restricted unit and unit option awards, as calculated by the
treasury stock method.  Restricted units and unit options consist of
Class B common units issuable under the terms of the Company’s long-term
incentive plan (See Note 11).
 
 Prior to the closing of the Company’s
initial public offering on December 18, 2006, there were no common units
outstanding.  As such, the Company’s net income attributable to Class
B common units is only presented for the years ended December 31, 2008 and 2007
and the period from December 18, 2006 to December 31, 2006.
 
 In March 2004, the FASB ratified the
Emerging Issue Task Force (“EITF”) consensus on EITF Issue No. 03-6,
“Participating Securities and the Two-Class Method under FASB Statement No. 128”
(“EITF No. 03-6”), which addresses the computation of earnings per share by
entities that have issued securities other than common stock that contractually
entitles the holder of those securities to participate in dividends and earnings
of the entity when, and if, the entity declares dividends on its common
stock.  In quarterly accounting periods where net income does not
exceed the Company’s aggregate cash distributions to its members, EITF No. 03-6
does not have any impact on the Company’s net income per Class B common unit
calculation as net income is allocated to its members with a priority allocation
to actual MIIs paid to the Class A member for the quarterly period, with the
remaining net income allocated with respect to relative ownership
interests.  However, EITF No. 03-6 provides that if the Company has
net income which exceeds the aggregate cash distributions to its members during
a quarterly period, it is required to present net income per Class B common unit
as if all of the earnings for the quarterly period were distributed in a manner
consistent with the Company’s limited liability agreement, regardless of whether
those earnings would actually be distributed during a quarterly period from an
economic probability standpoint.  The allocation of net income for net
income per Class B common unit purposes under EITF No. 3-06 will result in an
increased allocation of net income to the Class A member’s MIIs and a reduction
of net income allocated to Class B members.   On January 1, 2009,
the Company will adopt EITF No. 07-4, “Application of the Two-Class Method Under
FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships” (see
“Recently Issued Accounting Standards”).
  76
  The
following table sets forth the reconciliation of the Company’s weighted average
number of Class B common units used to compute basic net income attributable to
Class B members’ interests per unit with those used to compute diluted net
income attributable to Class B members’ per unit (in thousands):
 
 Period
      fromDecember 18, 2006Years
      Ended December 31,
                    
                    
                    to
      December 31,2008
                    
                    
                    2007
                    
                    
                    2006Weighted
      average number of Class B units – basic
                    
                    
                    62,409
                    
                    
                    
                    48,909
                    
                    
                    
                    36,627Add
      effect of dilutive unit incentive awards
                    
                    
                    614
                    
                    
                    
                    540
                    
                    
                    
                    11Weighted
      average number of Class B units – diluted
                    
                    
                    63,023
                    
                    
                    
                    49,449
                    
                    
                    
                    36,638
 
 Comprehensive
Income (Loss)
 
 Comprehensive
income (loss) includes net income (loss) and all other changes in the equity of
a business during a period from transactions and other events and circumstances
from non-owner sources that, under accounting principles generally accepted in
the United States, have not been recognized in the calculation of net
income.  These changes, other than net income, are referred to as
“other comprehensive income (loss)” and for the Company include only changes in
the fair value of unsettled derivative contracts accounted for as cash flow
hedges.
 
 Components
of Accumulated other comprehensive income (loss) at the dates indicated are as
follows (in thousands):
 
 December
      31,2008
                      
                      
                      2007Unrealized
      gain (loss) on commodity derivatives
                      
                      $
                      106,117
                      
                      
                      $
                      (5,102
                      )Unrealized
      loss on interest rate derivatives
                      
                      
                      (5,842
                      )
                      
                      
                      —$
                      100,275
                      
                      
                      $
                      (5,102
                      )
 
 Accounts
Receivable and Allowance for Possible Losses
 
 In
evaluating its allowance for possible losses, the Company performs ongoing
credit evaluations of its customers and adjusts credit limits based upon payment
history and the customer’s current creditworthiness, as determined by the
Company’s review of its customer’s credit information. The Company extends
credit on an unsecured basis to many of its customers. At December 31, 2008 and
2007, the Company’s credit evaluation indicated that it had no need for an
allowance for possible losses.
 
 Property,
Plant and Equipment
 
 Property,
plant and equipment are stated at cost. Depreciation, depletion and amortization
are based on cost less estimated salvage value primarily using the
units-of-production or straight line method over the assets estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are
capitalized.
 
 The
estimated service lives of property, plant and equipment excluding natural gas
and oil properties are as follows:
 
 Pipelines,
      processing and compression facilities
                15-40
      yearsRights-of-way
      – Appalachia
                20-40
      yearsBuildings
      and improvements
                10-40
      yearsFurniture
      and equipment
                3-7
      yearsOther
                3-10
      years
  77
  Property,
plant and equipment consists of the following at the dates indicated (in
thousands):
 
 December
      31,2008
                    
                    
                    2007Natural
      gas and oil properties:Proved
      properties:Leasehold
      interests
                    
                    $
                    1,214,991
                    
                    
                    $
                    1,043,687Wells
      and related equipment
                    
                    
                    872,128
                    
                    
                    
                    752,1842,087,119
                    
                    
                    
                    1,795,871Unproved
      properties
                    
                    
                    43,749
                    
                    
                    
                    16,380Support
      equipment
                    
                    
                    9,527
                    
                    
                    
                    6,9362,140,395
                    
                    
                    
                    1,819,187Pipelines,
      processing and compression facilities
                    
                    
                    22,541
                    
                    
                    
                    —Rights-of-way
                    
                    
                    149
                    
                    
                    
                    —Land,
      buildings and improvements
                    
                    
                    6,484
                    
                    
                    
                    5,881Other
                    
                    
                    7,827
                    
                    
                    
                    9,6532,177,396
                    
                    
                    
                    1,834,721Accumulated
      depreciation, depletion and amortization:
                    
                    
                    (232,277
                    )
                    
                    
                    (141,254
                    )$
                    1,945,119
                    
                    
                    $
                    1,693,467
 
 Oil
and Gas Properties
 
 The
Company follows the successful efforts method of accounting for oil and gas
producing activities. Acquisition costs of leases and development activities are
capitalized.  Exploratory drilling costs are capitalized pending
determination of whether a well is successful. Exploratory wells subsequently
determined to be dry holes are charged to expense. Costs resulting in
exploratory discoveries and all development costs, whether successful or not,
are capitalized. Geological and geophysical costs and delay rentals are
expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one
barrel equals 6 Mcf. Depletion is provided on the units-of-production
method.
 
 Depletion
depreciation and amortization expense is determined on a field-by-field basis
using the units-of-production method, with depletion, depreciation and
amortization rates for leasehold acquisition costs based on estimated proved
reserves and depletion, depreciation and amortization rates for well and related
equipment costs based on proved developed reserves associated with each
field.    Depletion rates are determined based on reserve
quantity estimates and the capitalized costs of undeveloped and developed
producing properties.  Capitalized costs of developed producing
properties in each field are aggregated to include the Company’s costs of
property interests in uncontrolled but proportionately consolidated from
investment partnerships, wells drilled solely by the Company, properties
purchased and working interests with other outside operators.
 
 Upon the
sale or retirement of a complete field of a proved property, the cost is
eliminated from the property accounts, and the resultant gain or loss is
reclassified to income. Upon the sale of an individual well, the proceeds are
credited to accumulated depreciation and depletion. Upon the sale of an entire
interest in an unproved property where the property had been assessed for
impairment individually, a gain or loss is recognized in the statements of
income. If a partial interest in an unproved property is sold, any funds
received are accounted for as a reduction of the cost in the interest
retained.
 
 Goodwill
 
 The
Company has  recorded goodwill of $35.2 million in connection with
several acquisitions of assets.  Goodwill and intangibles with
infinite lives must be tested for impairment annually or more frequently if
events or changes in circumstances indicate that the related asset might be
impaired. Under the principles of SFAS No. 142, an impairment loss should be
recognized if the carrying value of an entity’s reporting units exceeds its
estimated fair value.  Because quoted market prices for the Company’s
reporting units are not available, the Company must apply judgment in
determining the estimated fair value of these reporting units.  The
Company uses all available information to make these fair value determinations,
including the present values of expected future cash flows using discount rates
commensurate with the risks involved in the assets.  A key component
of these fair value determinations is a reconciliation of the sum of the fair
value calculations to our market capitalization.  The principles of
SFAS No. 142 and its interpretations acknowledge that the observed market prices
of individual trades of an entity’s equity securities (and thus its computed
market capitalization) may not be representative of the fair value of the entity
as a whole.  Substantial value may arise from the ability to take
advantage of synergies and other benefits that flow from control over another
entity.  Consequently, measuring the fair value of a collection of
assets and liabilities that operate together in a controlled entity is different
from measuring the fair value of that entity’s individual equity
securities.  In most industries, including the Company’s, an acquiring
entity typically is willing to pay more for equity securities that give it a
controlling interest than an investor would pay for a number of equity
securities representing less than a controlling interest.  Therefore,
once the above fair value calculations have been determined, the Company also
considers a control premium to the calculations.  This control premium
is judgmental and is based on, among other items, observed acquisitions in our
industry.  The resultant fair values calculated for the reporting
units are then compared to observable metrics on large mergers and acquisitions
in the Company’s industry to determine whether those valuations appear
reasonable in the Company’s judgment.  The Company’s evaluation of
goodwill at December 31, 2008, 2007 and 2006, respectively, indicated there was
no impairment loss.
  78
 
 Impairment
of Oil and Gas Properties and Long-Lived Assets
 
 The
Company’s oil and gas properties and long-lived assets are reviewed annually or
whenever events or changes in circumstances indicate that their carrying amounts
may not be recoverable. Long-lived assets are reviewed for potential impairments
at the lowest levels for which there are identifiable cash flows that are
largely independent of other groups of assets.
 
 The
review of the Company’s oil and gas properties is done on a field-by-field basis
by determining if the historical cost of proved properties less the applicable
accumulated depletion, depreciation and amortization and abandonment is less
than the estimated expected undiscounted future cash flows. The expected future
cash flows are estimated based on the Company’s plans to continue to produce and
develop proved reserves. Expected future cash flow from the sale of production
of reserves is calculated based on estimated future prices. The Company
estimates prices based upon current contracts in place at December 31, 2008,
adjusted for basis differentials and market related information including
published futures prices. The estimated future level of production is based on
assumptions surrounding future levels of prices and costs, field decline rates,
market demand and supply, and the economic and regulatory climates. If the
carrying value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair market value, (as determined by discounted
future cash flows) and the carrying value of the assets.
 
 The
determination of oil and natural gas reserve estimates is a subjective process,
and the accuracy of any reserve estimate depends on the quality of available
data and the application of engineering and geological interpretation and
judgment. Estimates of economically recoverable reserves and future net cash
flows depend on a number of variable factors and assumptions that are difficult
to predict and may vary considerably from actual results.  In
particular, the Company’s reserve estimates for its investment in its limited
partnerships are based on its own assumptions rather than its proportionate
share of the limited partnership’s reserves.  These assumptions
include the Company’s actual capital contributions, an additional carried
interest (generally 7% to 10%), a disproportionate share of salvage value upon
plugging of the wells and lower operating and administrative costs.
 
 The
Company’s lower operating and administrative costs result from the limited
partners paying to the Company their proportionate share of these expenses plus
a profit margin. These assumptions could result in the Company’s calculation of
depletion and impairment being different than its proportionate share of the
limited partnership calculations for these items. In addition, reserve estimates
for wells with limited or no production history are less reliable than those
based on actual production.   Estimated reserves are often subject to
future revisions, which could be substantial, based on the availability of
additional information which could cause the assumptions to be
modified.  The Company cannot predict what reserve revisions may be
required in future periods.
 
 The
Company’s method of calculating its reserves may result in reserve quantities
and values which are greater than those which would be calculated by the
investment partnerships which the Company sponsors and owns an interest in but
does not control. The Company’s reserve quantities include reserves in excess of
its proportionate share of reserves in a partnership which the Company may be
unable to recover due to the partnership legal structure. The Company may have
to pay additional consideration in the future as a well or investment
partnership becomes uneconomic under the terms of the partnership agreement in
order for the Company to recover these excess reserves and to acquire any
additional residual interests in the wells held by other partnership investors.
The acquisition of any well interest from the partnership by the Company is
governed under the partnership agreement and must be at fair market value
supported by an appraisal of an independent expert selected by the
Company.
 
 Unproved
properties are reviewed annually for impairment or whenever events or
circumstances indicate that the carrying amount of an asset may not be
recoverable. Impairment charges are recorded if conditions indicate the Company
will not explore the acreage prior to expiration of the applicable leases or if
it is determined that the carrying value of the properties is above their fair
value.  There were no impairments of oil and gas properties or
unproved properties recorded by the Company for the years ended December 31,
2008, 2007, or 2006, respectively.
  79
  Capitalized
Interest
 
 The Company capitalizes interest on
borrowed funds related to its share of costs associated with the drilling and
completion of new oil and gas wells and other capital
projects.  Interest is capitalized only during the periods in which
these assets are brought to their intended use. The weighted average interest
rate used to capitalize interest was 7.3% and 6.7% for the years ended December
31, 2008 and 2007, respectively, which resulted in interest capitalized of $5.0
million and $2.7 million, respectively.  There was no interest
capitalized for the year ended December 31, 2006.
 
 Asset
Retirement Obligations
 
 The
Company accounts for asset retirement obligations as required under SFAS
No. 143, “Accounting for Retirement Asset Obligations” (“SFAS No. 143”).
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, with the
associated asset retirement costs being capitalized as a part of the carrying
amount of the long-lived asset. The Company has asset retirement obligations
related to the plugging and abandonment of its oil and gas wells. SFAS No. 143
requires the Company to consider estimated salvage value in the calculation of
depreciation, depletion and amortization.
 
 In March
2005, the Financial Accounting Standards Board (“FASB”) issued FIN 47. FIN 47
clarified that the term “conditional asset retirement obligation” as used in
SFAS No. 143 refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional on a
future event that may or may not be within the control of the entity. Since the
obligation to perform the asset retirement activity is unconditional, FIN 47
provides that a liability for the fair value of a conditional asset obligation
should be recognized if that fair value can be reasonably estimated, even though
uncertainty exists about the timing and/or method of settlement. FIN 47 also
clarifies when an entity would have sufficient information to reasonably
estimate the fair value of a conditional asset retirement obligation under FAS
No. 143.
 
 Under
SFAS No.143, the Company had recorded its asset retirement obligation based on a
probability factor which considered the Company’s history of selling its wells
or otherwise disposing of them without incurring a disposal cost.
 
 FIN 47
requires the Company to record its retirement obligation without regard to its
prior practice and accrue for obligations for all wells owned by the Company
without regard to their probability of being sold or otherwise disposed of
without incurring a disposal cost. Accordingly, the Company adopted FIN 47 as of
December 31, 2006 and recognized a $6.4 million cumulative effect of an
accounting change during the year ended December 31, 2006 and a $8.0 million
increase in its asset retirement obligation and a $14.4 million increase in
property, plant and equipment as of December 31, 2006.
 
 Had the
Company implemented FIN 47 retroactively to October 1, 2002, the following
pro forma information summarizes the impact for the periods presented (in
thousands):
 
 December
      31,2006Net
      income as reported
                    
                    $
                    51,827Proforma
      asset retirement obligation adjustment
                    
                    
                    1,414Proforma
      net income as adjusted
                    
                    
                    53,241Proforma
      asset retirement obligation
                    
                    $
                    26,726
 
 Fair
Value of Financial Instruments
 
 The
carrying amount of the Company’s financial instruments, including cash and cash
equivalents, accounts receivables and accounts payables approximate fair values
because of their short maturities and are represented in the Company’s
consolidated balance sheets.  For further information with regard to
the Company’s financial instruments, see “Recently Adopted Accounting Standards”
and Note 7, “Fair Value of Financial Instruments” and Note 9 “Long-Term
Debt”.
  80
 
 Derivative
Instruments
 
 The
Company enters into certain financial contracts to manage its exposure to
movement in commodity prices and interest rate movements.  The Company
applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments
and Hedging Activities” (“SFAS No.133”). SFAS No. 133 requires each derivative
instrument to be recorded in the balance sheet as either an asset or liability
measured at fair value.  Changes in a derivative instrument’s fair
value are recognized currently in the Company’s consolidated statements of
income unless specific hedge accounting criteria are met (see Note
7).
 
 Concentration
of Credit Risk
 
 Financial
instruments, which potentially subject the Company to concentrations of credit
risk, consist principally of periodic temporary investments of cash and cash
equivalents. The Company places its temporary cash investments in high-quality
short-term money market instruments and deposits with high-quality financial
institutions and brokerage firms. At December 31, 2008 and 2007, the Company had
$25.1 million and $41.8 million, respectively, in deposits at various banks, of
which $23.6 million and $40.9 million, respectively, was over the insurance
limit of the Federal Deposit Insurance Corporation. No losses have been
experienced on such investments to date.
 
 Environmental
Matters
 
 The
Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the ongoing evaluation of its operations, to identify potential
environmental exposures and to comply with regulatory policies and procedures.
The Company accounts for environmental contingencies in accordance with SFAS
No. 5 “Accounting for Contingencies.” Environmental expenditures that
relate to current operations are expensed as appropriate. Expenditures that
relate to an existing condition caused by past operations, and do not contribute
to current or future revenue generation, are also expensed. Liabilities for
environmental contingencies are recorded when environmental assessments and/or
clean-ups are probable and the costs can be reasonably estimated. The Company
maintains insurance which may cover in whole or in part certain types of
environmental contingencies. At December 31, 2008 and 2007, the Company had no
environmental contingencies requiring specific disclosure or the recording of a
liability.
 
 Revenue
Recognition
 
 The
Company conducts certain energy activities through, and a portion of its
revenues are attributable to  sponsored investment partnerships. The
Company contracts with the investment partnerships to drill partnership wells.
The contracts require that the investment partnerships pay the Company the full
contract price upon execution. The income from a drilling contract is recognized
as the services are performed using the percentage of completion method. The
contracts are typically completed in less than 60 days. On an uncompleted
contract, the Company classifies the difference between the contract payments it
has received and the revenue earned as a current liability titled “Liabilities
Associated with Drilling Contracts” on its consolidated balance sheets. The
Company recognizes gathering revenues at the time the natural gas is delivered,
and. recognizes well services revenues at the time the services are performed.
The Company is also entitled to receive administration and oversight fees
according to the respective partnership agreements. The Company recognizes such
fees as income when services are performed.
 
 The
Company generally sells natural gas and crude oil at prevailing market
prices.  Revenue is recognized when produced quantities are delivered
to a custody transfer point, persuasive evidence of a sales arrangement exists,
the rights and responsibility of ownership pass to the purchaser upon delivery,
collection of revenue from the sale is reasonably assured and the sales price is
fixed or determinable.  Revenues from the production of natural gas
and crude oil in which the Company has  an interest with other
producers are recognized on the basis of the Company’s percentage ownership of
working interest  or overriding royalty. Generally, the Company’s
sales contracts are based on pricing provisions that are tied to a market index,
with certain adjustments based on proximity to gathering and transmission lines
and the quality of its natural gas.
 
  81
  Because
there are timing differences between the delivery of natural gas and oil and the
Company’s receipt of a delivery statement, the Company has unbilled revenues.
These revenues are accrued based upon volumetric data from the
Company’s records and the Company’s estimates of the related transportation and
compression fees which are, in turn, based upon applicable product prices. The
Company had unbilled trade receivables at December 31, 2008 and 2007 of $43.7
million and $44.9 million, respectively, which are included in accounts
receivable on its consolidated balance sheets.
 
 Income
Taxes
 
 The
Company is a limited liability company and has elected to be treated as a
partnership for income tax purposes.  As a result, the Company is not
subject to U.S. federal and most state income taxes.  The unit holders
of the Company are liable for income taxes in regards to their distributive
share of the Company’s taxable income.  Such taxable income may vary
substantially from net income reported in the accompanying combined and
consolidated financial statements.   Certain corporate subsidiaries of
the Company are subject to federal and state income tax.  The federal and
state income taxes related to the Company and these corporate subsidiaries
were immaterial to the combined and consolidated financial statements and are
recorded in pre-tax income on a current basis only.  Accordingly, no
federal or state deferred income tax has been provided for in the accompanying
combined and consolidated financial statements.
  In June
2006, the FASB released FASB Interpretation No. 48 “Accounting for
Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109
(“FIN 48”). FIN 48 provides guidance for how uncertain tax positions
should be recognized, measured, presented and disclosed in the financial
statements. FIN 48 requires the evaluation of tax positions taken or
expected to be taken in the course of preparing the Company’s tax returns to
determine whether the tax positions have met a “more-likely-than-not” threshold
of being sustained by the applicable tax authority. Tax benefits related to tax
positions not deemed to meet the more-likely-than-not threshold are not
permitted to be recognized in the financial statements.  The provisions of
FIN 48 were adopted by the Company effective January 1, 2007. 
Implementation of FIN 48 had no impact on the combined and consolidated
financial statements of the Company for the years ended December 31, 2008 and
2007.  The Company’s policy is to reflect interest and penalties
related to uncertain tax positions as part of income tax expense, when and if
they become applicable.
  The
Company files income tax returns in the U.S. federal and various state
jurisdictions. With limited exceptions, the Company is no longer subject to
income tax examinations by major tax authorities for years before
2006.
 
 Recently
Issued Financial Accounting Standards
  The
Financial Accounting Standards Board, (“FASB”) recently issued the following
standards which were reviewed by the Company to determine the potential impact
on its financial statements upon adoption.
 
 In June
2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating
Securities” (“FSP EITF 03-6-1”).  FSP EITF 03-6-1 applies to the
calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of
FASB Statement No. 128, “Earnings per Share” for share-based payment awards with
rights to dividends or dividend equivalents.   It states that
unvested share-based payment awards that contain nonforfeitable rights to
dividends or dividend equivalents (whether paid or unpaid) are participating
securities and shall be included in the computation of EPS pursuant to the
two-class method. FSP EITF 03-6-1 is effective for financial statements issued
for fiscal years beginning after December 15, 2008, and interim periods within
those fiscal years. Early adoption is prohibited.  All prior-period
EPS data presented should be adjusted retrospectively to conform to the
provisions of this FSP.  The Company will apply the requirements of
FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it does not believe the
adoption of FSP EITF 03-6-1 will have a material impact on its financial
position or results of operations.
 
 In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Policies” (“SFAS No. 162”).  SFAS No. 162 identifies
sources of accounting principles and the framework for selecting such principles
used in the preparation of financial statements of nongovernmental entities
presented in conformity with U.S. generally accepted accounting
principles.  SFAS No. 162 is effective beginning November 15,
2008.  The Company adopted the provisions of SFAS No. 162 on November
15, 2008 and it had no impact on its financial position and results of
operations.
  82
 
 In April
2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of
Intangible Assets” (“FSP FAS 142-3”).  FSP FAS 142-3 amends the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible asset under FASB
Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The
intent of this FSP is to improve the consistency between the useful life of a
recognized intangible asset under SFAS No. 142 and the period of expected cash
flows used to measure the fair value of the asset under SFAS No. 141(R),
“Business Combinations” (“SFAS No. 141(R)”).  FSP FAS 142-3 is
effective for financial statements issued for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal years. Early adoption
is prohibited. The guidance for determining the useful life of a recognized
intangible asset should be applied prospectively to intangible assets acquired
after the effective date.   The disclosure requirements should be
applied prospectively to all intangible assets recognized as of, and subsequent
to, the effective date. The Company will apply the requirements of FSP FAS 142-3
upon its adoption on January 1, 2009 and it does not believe the adoption of FSP
FAS 142-3 will have a material impact on its financial position or results of
operations.
 
 In March
2008, the FASB ratified the Emerging Issues Task Force (“EITF”) reached
consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under
FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”
(“EITF No. 07-4”), an update of EITF No. 03-6 “Participating Securities and the
Two-Class Method under FASB Statement No. 128".  EITF No. 07-4
requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings
per limited partner unit for each period presented according to distributions
declared and participation rights in undistributed earnings as if all of the
earnings for that period had been distributed.  In periods with
undistributed earnings above specified levels, the calculation per the two-class
method results in an increased allocation of such undistributed earnings to the
general partner and a dilution of earnings to the limited
partners.  EITF No. 07-4 is effective for fiscal periods beginning on
of after December 15, 2008.  The Company does not expect the
application of EITF 07-4 to have a material effect on its earnings per unit
calculation.  The Company’s net earnings per unit of the Class B unit
holders calculated under the requirements of EITF No. 03-6 would not have
materially differed under the requirements of EITF No. 07-04.
 
 In March
2008, the FASB issued Statement of Financial Accounting Standards No. 161,
“Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No.
161”), an amendment of FASB Statement No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS No. 133”). SFAS No. 161 requires
entities to provide qualitative disclosures about the objectives and strategies
for using derivatives, quantitative data about the fair value of and gains and
losses on derivative contracts, and details of credit-risk-related contingent
features in their hedged positions. The standard is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with early application encouraged but not required. SFAS No. 161 also
requires entities to disclose more information about the location and amounts of
derivative instruments in financial statements; how derivatives and related
hedges are accounted for under SFAS No. 133, and how the hedges affect the
entity’s financial position, financial performance, and cash flows. The Company
will apply the requirements of SFAS No. 161 on its adoption on January 1, 2009
and does not expect it to have an impact on its financial position or results of
operations.
 
 In
January 2008, the FASB issued Statement 133 Implementation Issue No. E23,
“Hedging – General Issues Involving the Application of the Shortcut Method under
Paragraph 68” (“Implementation Issue E23”).  Implementation Issue E23
is effective for hedging relationships designated on or after January 1, 2008,
and amends SFAS No. 133 to explicitly permit use of the “shortcut” method for
those hedging relationships in which:  the interest rate swap has a
nonzero fair value at the inception of the hedging relationship attributable
solely to differing prices within the bid-ask spread; or the hedged item has a
trade date that differs from its settlement date because of generally
established conventions in the marketplace in which the transaction to acquire
or issue the hedging item is executed.  The Company uses the
“long-haul” method by applying the change in variable cash flow method (See Note
7) to measure ineffectiveness on its interest rate swaps under SFAS No. 133 and
therefore Implementation Issue E23 did not have a significant impact on its
financial position or results of operations.
  83
 
 In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No.
160”). This statement amends Accounting Research Bulletin 51, “Consolidated
Financial Statements”, to establish accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity
in the consolidated financial statements. This statement is effective for fiscal
periods beginning on or after December 15, 2008. The Company does not expect the
adoption of SFAS No. 160 to have a significant impact on its financial position
and results of operations.
 
 In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces
SFAS No. 141, “Business Combinations”; however it retains the fundamental
requirements that the acquisition method of accounting be used for all business
combinations and for an acquirer to be identified for each business
combination.  SFAS No. 141(R) requires an acquirer to recognize the
assets acquired, liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date, be measured at their fair values as of that
date, with specified limited exceptions.  Changes subsequent to that
date are to be recognized in earnings, not goodwill.  Additionally,
SFAS No. 141 (R) requires costs incurred in connection with an acquisition be
expensed as incurred.  Restructuring costs, if any, are to be
recognized separately from the acquisition. The acquirer in a business
combination achieved in stages must also recognize the identifiable assets and
liabilities, as well as the noncontrolling interests in the acquiree, at the
full amounts of their fair values. SFAS No. 141(R) is effective for business
combinations occurring in fiscal years beginning on or after December 15,
2008.  Early adoption is not permitted. The Company will apply the
requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and is
currently evaluating whether SFAS No. 141(R) does not expect the adoption to
have a significant impact on its financial position and results of
operations.
 
 In
February 2007, the FASB issued Statement of Financial Accounting Standards
No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to
measure eligible financial instruments and certain other items at fair value.
The objective is to improve financial reporting by providing entities with the
opportunity to mitigate volatility in reported earnings caused by measuring
related assets and liabilities differently without having to apply complex hedge
accounting provisions. By electing the fair value option in conjunction with a
derivative, an entity can achieve an accounting result similar to a fair value
hedge without having to comply with complex hedge accounting rules. The
statement was effective for the Company as of January 1, 2008. The Company
adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair
value option to any of its financial instruments not already carried at fair
value in accordance with other accounting standards, and therefore the adoption
of SFAS No. 159 did not impact the Company’s consolidated financial statements
for the year ended December 31, 2008.
 
 In
September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157, “Fair Value Measurement” (“SFAS No. 157”). SFAS No. 157 addresses
the need for increased consistency in fair value measurements, defining fair
value as the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date. It also establishes a framework for measuring fair value and
expands disclosure requirements. In February 2008, the FASB issued FSP FAS
157-2, “Effective Date of FASB Statement No. 157”, (“FSP FAS
157-2”).  FSP FAS 157-2, which was effective upon issuance, delays the
effective date of SFAS No. 157 for nonfinancial assets and nonfinancial
liabilities, except for items that are recognized or disclosed at fair value at
least once a year, to fiscal years beginning after November 15, 2008. On January
1, 2009, the Company will adopt SFAS No. 157 for nonfinancial assets and
liabilities that are not measured at fair value on a recurring
basis.  For the Company, the nonfinancial assets and liabilities will
be limited to the initial recognition of asset retirement obligations. FSP FAS
157-2 also covers interim periods within the fiscal years for items within its
scope. The delay is intended to allow the FASB and its constituents the time to
consider the various implementation issues associated with SFAS No. 157. The
Company adopted SFAS No. 157 as of January 1, 2008 with respect to its
commodity and interest rate swap derivative instruments which are measured at
fair value within its consolidated financial statements.  See Note 7
and Note 9 for disclosures pertaining to the provisions of SFAS No. 157 with
regard to the Company’s fair value measurements.
 
 NOTE
3 —- ACQUISITION OF DTE GAS & OIL COMPANY
 
 In June
2007, the Company acquired all of the outstanding equity interests of DTE Gas
& Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy
Enterprises for $1.273 billion, including adjustments for working capital of
$15.0 million and current year capital expenditures of $19.0
million.  Subsequently, the Company changed DGO’s name to Atlas Gas
and Oil Company, LLC (“AGO”).
  84
 
 To fund the acquisition, the Company
borrowed $713.9 million on its credit facility (see Note 9) and received net
proceeds of $597.5 million from a private placement of its Class B common and
new Class D units (see Note 12) of which $52.5 million was used to pay the
outstanding balance of the Company’s then existing credit
facility.  The acquisition was accounted for using the purchase method
of accounting under SFAS No. 141, Business Combinations (“SFAS No.
141”).  The table on the following page presents the purchase price
allocation, including professional fees and other related acquisition costs, to
the assets acquired and liabilities assumed based on their estimated fair market
value at the date of acquisition (in thousands):
 
 Non-CashInvesting TransactionAccounts
      receivable
                        
                        $
                        33,764Prepaid
      expenses
                        
                        
                        515Other
      assets
                        
                        
                        890Leaseholds,
      wells and related equipment
                        
                        
                        1,267,901Total
      assets acquired
                        
                        
                        1,303,070Accounts
      payable and accrued liabilities
                        
                        
                        (19,233
                        )Other
      liabilities
                        
                        
                        (210
                        )Asset
      retirement obligations
                        
                        
                        (11,109
                        )(30,552
                        )Net
      assets acquired
                        
                        $
                        1,272,518
 
 AGO’s
operations are included within the Company’s combined and consolidated financial
statements from the date of the acquisition.
 
 The
following data presents pro forma revenues, net income and basic and diluted net
income per unit for the Company as if the AGO acquisition, Class B common unit
and Class D unit equity offerings (see Note 12) and new revolving credit
facility (see Note 9) had occurred on January 1, 2006.  The Company
has prepared these unaudited pro forma financial results for comparative
purposes only; they may not be indicative of the results that would have
occurred if the Company had completed the acquisition at January 1, 2006 or the
results that will be attained in the future.  Net income for the year
ended December 31, 2006 includes periods prior to the Company’s initial public
offering on December 18, 2006, and therefore, no earnings per unit has been
presented (in thousands, except per unit amounts):
 
 Year
      Ended December 31, 2007As
                    Reported
                  
                  
                  Pro
      Forma
                    Adjustments
                  
                  
                  Pro
                    FormaRevenues
                  
                  $
                  577,897
                  
                  
                  $
                  15,888
                  
                  
                  $
                  593,785Net
      income
                  
                  $
                  117,504
                  
                  
                  $
                  (57,877
                  )
                  
                  $
                  59,627Net
      income attributable to Class B unit holders
                  
                  $
                  113,405
                  
                  
                  $
                  (54,971
                  )
                  
                  $
                  58,434Net
      income per Class B common unit outstanding – basic
                  
                  $
                  2.32
                  
                  
                  $
                  (1.36
                  )
                  
                  $
                  0.96Weighted
      average Class B common units outstanding – basic
                  
                  
                  48,909
                  
                  
                  
                  11,801
                  
                  
                  
                  60,710Net
      income per Class B common unit – diluted
                  
                  $
                  2.29
                  
                  
                  $
                  (1.34
                  )
                  
                  $
                  0.95Weighted
      average Class B common units outstanding – diluted
                  
                  
                  49,449
                  
                  
                  
                  11,740
                  
                  
                  
                  61,189
 
 Year
      Ended December 31, 2006As
                    Reported
                  
                  
                  Pro
      Forma
                    Adjustments
                  
                  
                  Pro
                    FormaRevenues
                  
                  $
                  320,982
                  
                  
                  $
                  291,346
                  
                  
                  $
                  612,328Net
      income before cumulative effect of accounting change
                  
                  
                  51,827
                  
                  
                  
                  145,923
                  
                  
                  
                  197,750Net
      income
                  
                  
                  58,182
                  
                  
                  
                  145,923
                  
                  
                  
                  204,105
 
 Pro forma
adjustments to revenues include substantial losses and gains on derivatives
realized by AGO of $54.1 million and $149.5 million in fiscal 2007 and 2006,
respectively.  All existing derivatives were canceled upon the
acquisition of AGO by the Company and the Company entered into new derivative
contracts covering future AGO production.   Pro forma adjustments
include financial hedges between AGO and its affiliate. In addition, pro forma
adjustments include depreciation, depletion and amortization related to assets
acquired and interest expense associated with debt entered into to acquire such
assets.
  85
  NOTE
4 – OTHER ASSETS AND INTANGIBLE ASSETS
 
 Other
Assets
 
 The
following is a summary of other assets (in thousands):
 
 At
      December 31,2008
                  
                  
                  2007Long-term
      derivative receivable from partnerships
                  
                  $
                  2,719
                  
                  
                  $
                  13,542Deferred
      finance costs, net of accumulated amortization of $5,531 and $2,708 at
      December 31, 2008 and 2007, respectively
                  
                  
                  15,018
                  
                  
                  
                  7,650Other
                  
                  
                  666
                  
                  
                  
                  238$
                  18,403
                  
                  
                  $
                  21,430
 
 Long-term
hedge receivable from Partnerships represents the portion of the long-term
unrealized derivative liability on contracts that has been allocated to them
based on their share of total production volumes sold.  Deferred
finance costs related to the Company’s credit facility and senior unsecured
notes (see Note 9) are recorded at cost and amortized over their respective
lives (5 to 10 years).
 
 Intangible
Assets
 
 Included
in intangible assets are partnership management and operating contracts acquired
through previous acquisitions which were recorded at fair value on their
acquisition dates. In addition, the Company entered into a two-year non-compete
agreement in connection with the acquisition of AGO during the year ended
December 31, 2007.  The Company amortizes these contracts on the
declining balance and straight-line methods, over their respective estimated
lives, ranging from two to thirteen years. Amortization expense for these
contracts for the years ended December 31, 2008, 2007, and 2006 was $1.2
million, $1.0 million and $1.0 million, respectively.  The aggregate
estimated annual amortization expense of partnership management and operating
contracts and the non-compete agreement for the next five years ending December
31 is as follows: 2009—$964,000; 2010—$710,000; 2011─$664,000; 2012—$180,000 and
2013—$158,000.
 
 The
following table provides information about intangible assets at the dates
indicated (in thousands):
 
 At
      December 31,2008
                  
                  
                  2007Management
      and operating contracts
                  
                  $
                  14,343
                  
                  
                  $
                  14,343Non-compete
      agreement
                  
                  
                  890
                  
                  
                  
                  890Total
      costs
                  
                  
                  15,233
                  
                  
                  
                  15,233Accumulated
      amortization
                  
                  
                  (11,395
                  )
                  
                  
                  (10,172
                  )$
                  3,838
                  
                  
                  $
                  5,061
 
 NOTE
5—ASSET RETIREMENT OBLIGATIONS
 
 The
Company follows SFAS No. 143 and FIN 47 “Accounting for Conditional Asset
Retirement Obligations,” which require the Company to recognize an estimated
liability for the plugging and abandonment of its oil and gas wells and related
facilities. Under SFAS No. 143, the Company must currently recognize a liability
for future asset retirement obligations if a reasonable estimate of the fair
value of that liability can be made. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143
requires the Company to consider estimated salvage value in the calculation of
depreciation, depletion and amortization.
  86
 
 The
estimated liability is based on historical experience in plugging and abandoning
wells, estimated remaining lives of those wells based on reserve estimates,
external estimates as to the cost to plug and abandon the wells in the future,
and federal and state regulatory requirements. The liability is discounted using
an assumed credit-adjusted risk-free
interest rate. Revisions to the liability could occur due to changes in
estimates of plugging and abandonment costs or remaining lives of the wells, or
if federal or state regulators enact new plugging and abandonment
requirements.
 
 The
Company has no assets legally restricted for purposes of settling asset
retirement obligations. Except for the item previously referenced, the Company
has determined that there are no other material retirement obligations
associated with tangible long-lived assets.
 
 A
reconciliation of the Company’s liability for well plugging and abandonment
costs for the periods indicated is as follows (in thousands):
 
 Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006Asset
      retirement obligations, beginning of period
                    
                    $
                    42,358
                    
                    
                    $
                    26,726
                    
                    
                    $
                    18,499Cumulative
      effect of adoption of FIN 47
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    8,042Liabilities
      acquired
                    
                    
                    —
                    
                    
                    
                    11,109
                    
                    
                    
                    ─Liabilities
      incurred
                    
                    
                    3,305
                    
                    
                    
                    2,582
                    
                    
                    
                    1,570Liabilities
      settled
                    
                    
                    (253
                    )
                    
                    
                    (91
                    )
                    
                    
                    (194
                    )Revision
      in estimates
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    (2,411
                    )Accretion
      expense
                    
                    
                    2,726
                    
                    
                    
                    2,032
                    
                    
                    
                    1,220Asset
      retirement obligations, end of period
                    
                    $
                    48,136
                    
                    
                    $
                    42,358
                    
                    
                    $
                    26,726
 
 The
accretion expense is included in depreciation, depletion and amortization in the
Company’s combined and consolidated statements of income.
 
 NOTE
6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
 
 In the
ordinary course of its business operations, the Company has ongoing
relationships with several related entities:
 
 Relationship with Atlas
America.  Atlas America provides centralized corporate
functions on behalf of the Company, including legal, accounting, treasury,
insurance administration and claims processing, risk management, health, safety
and environmental, information technology, human resources, credit, payroll,
internal audit, taxes and engineering.  These costs  are
reflected in general and administrative expense in the Company’s combined
and consolidated statements of income. The employees supporting these Company
operations are employees of Atlas America.  The compensation costs of
these employees, and rent for the offices out of which they operate, are
allocated to the Company based on estimates of the time spent by such employees
in performing services for the Company.  This allocation of costs may
fluctuate from period to period based upon the level of activity by the Company
of any acquisitions, equity or debt offerings, or other non-recurring
transactions, which requires additional management time.  Management
believes the method used to allocate these expenses is reasonable.
 
 The
Company participates in Atlas America’s cash management program. Any cash
activity performed by Atlas America on behalf of the Company has been recorded
as a long-term liability as parent advances and included in advances from
affiliates on the Company’s consolidated balance sheets.
 
 Relationship with Company Sponsored
Investment Partnerships.  The Company conducts certain
activities through, and a substantial portion of its revenues are attributable
to, the Partnerships. The Company serves as managing general partner of the
Partnerships and assumes customary rights and obligations for the Partnerships.
As a general partner, the Company is liable for Partnership liabilities and can
be liable to limited partners if it breaches its responsibilities with respect
to the operations of the Partnerships. The Company is entitled to receive
management fees, reimbursement for administrative costs incurred, and to share
in the Partnerships’ revenue, and costs and expenses according to the respective
Partnership agreements.
  87
 
 Relationship with Atlas
Pipeline.  The Company has a master gas gathering agreement
with Atlas Pipeline which governs the transportation of substantially all of the
natural gas the Company produces from the wells it operates. This agreement
generally provides for the Company to pay Atlas Pipeline 16% of the sales price
received for natural gas produced from wells located on Atlas Pipeline’s
gathering systems. These fees are shown as Gathering fee—Atlas Pipeline on the
Company’s combined and consolidated statements of income.  Atlas
America agreed to assume the Company’s obligation to pay gathering fees to Atlas
Pipeline after the Company’s initial public offering.
 
 The
Company charges rates to wells connected to these gathering systems,
substantially all of which are owned by the Partnerships, generally ranging from
$.35 per Mcf to 13% of the sales price received for the natural gas transported.
Under the terms of its contribution agreement with Atlas America, the Company
remits this amount to Atlas America.  Therefore, after the closing of
its initial public offering, the gathering revenues and costs within the
partnership management segment net to $0.
 
 NOTE
7—DERIVATIVE AND FINANCIAL INSTRUMENTS
 
 Commodity
Risk Hedging Program
 
 From time
to time, the Company enters into natural gas and crude oil future option
contracts and collar contracts to achieve more predictable cash flows by hedging
its exposure to changes in natural gas prices and oil prices. At any point in
time, such contracts may include regulated New York Mercantile Exchange
(“NYMEX”) futures
and options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. NYMEX contracts are generally settled with offsetting
positions, but may be settled by the delivery of natural gas. Crude oil
contracts are based on a West Texas Intermediate (“WTI”) index. These contracts
have qualified and been designated as cash flow hedges and recorded at their
fair values.
 
 The
Company has a $106.1 million unrealized net asset related to financial
derivatives on its gas and oil production shown as a component of accumulated
other comprehensive loss at December 31, 2008, compared to a net unrealized
liability of $5.1 million at December 31, 2007. If the fair values of the
instruments remain at current market values, the Company will reclassify $63.7
million of unrealized gains to its consolidated statements of income over the
next twelve-month period as these contracts settle and $42.4 million of
unrealized gains will be reclassified in later periods.
 
 The
Company recognized a loss of $25.1 million and gains of $17.6 million and $7.1
million on settled contracts covering natural gas production for the years ended
December 31, 2008, 2007 and 2006, respectively. The Company recognized a loss of
$312,000 on settled oil production for the year ended December 31, 2008, and
there were no gains or (losses) on oil settlements for the years ended December
31, 2007 and 2006. These gains and losses are included with gas and oil
production in the Company’s combined and consolidated statements of
income.  As the underlying prices and terms in the Company’s
derivative contracts were consistent with the indices used to sell its natural
gas and oil, there were no gains or losses recognized during the years ended
December 31, 2008, 2007 and 2006 for derivative ineffectiveness or as a result
of the discontinuance of any cash flow hedges.
 
 On May
18, 2007, the Company signed a definitive agreement to acquire AGO (see Note 3).
In connection with the financing of this transaction, the Company agreed as a
condition precedent to closing that it would hedge 80% of its projected natural
gas volumes for no less than three years from the closing date of the
transaction. During May 2007, the Company entered into derivative instruments to
hedge 80% of the projected production of the assets to be acquired as required
under the financing agreement. The production volume of the assets to be
acquired was not considered to be “probable forecasted production” under SFAS
No. 133 at the date these derivatives were entered into because the acquisition
of the assets had not yet been completed. Accordingly, the Company recognized
the instruments as non-qualifying for hedge accounting at inception with
subsequent changes in the derivative value recorded within revenues in its
consolidated statements of income. The Company recognized a non-cash gain on
mark-to-market derivatives of $26.3 million related to the change in value of
these derivatives from May 22, 2007 through June 28, 2007. Upon closing of the
acquisition on June 29, 2007, the production volume of the assets acquired was
considered “probable forecasted production” under SFAS No. 133 and the Company
evaluated these derivatives under the cash flow hedge criteria in accordance
with SFAS No. 133.
  88
  As of
December 31, 2008, the Company had the following natural gas volumes
hedged:
 
 Natural
Gas Fixed Price Swaps
 
 Twelve MonthPeriod Ending
                          
                          
                          
                          
                          
                          
                          Average
                          
                          
                          Fair ValueDecember 31,
                          
                          
                          
                          Volumes
                          
                          
                          Fixed Price
                          
                          
                          Asset(MMBtu)
                          
                          
                          (per MMBtu)
                          
                          
                          (in thousands)(1)2009
                          
                          
                          
                          
                          38,120,000
                          
                          
                          $
                          8.55
                          
                          
                          $
                          93,2462010
                          
                          
                          
                          
                          26,360,000
                          
                          
                          $
                          8.11
                          
                          
                          
                          25,5372011
                          
                          
                          
                          
                          18,680,000
                          
                          
                          $
                          7.84
                          
                          
                          
                          9,6702012
                          
                          
                          
                          
                          13,800,000
                          
                          
                          $
                          8.05
                          
                          
                          
                          10,8512013
                          
                          
                          
                          
                          1,500,000
                          
                          
                          $
                          8.73
                          
                          
                          
                          2,098$
                          141,402
 
 Natural
Gas Costless Collars
 
 Twelve MonthPeriod Ending
                            
                            
                            
                            
                            
                            
                            Average
                            
                            
                            Fair ValueDecember 31,
                            
                            Option Type
                            
                            Volumes
                            
                            
                            Floor and Cap
                            
                            
                            Asset(MMBtu)
                            
                            
                            (per MMBtu)
                            
                            
                            (in thousands)(1)2009
                            
                            Puts
      purchased
                            
                            
                            240,000
                            
                            
                            $
                            11.00
                            
                            
                            $
                            1,1822009
                            
                            Calls
      sold
                            
                            
                            240,000
                            
                            
                            $
                            15.35
                            
                            
                            
                            —2010
                            
                            Puts
      purchased
                            
                            
                            3,360,000
                            
                            
                            $
                            7.84
                            
                            
                            
                            3,3402010
                            
                            Calls
      sold
                            
                            
                            3,360,000
                            
                            
                            $
                            9.01
                            
                            
                            
                            —2011
                            
                            Puts
      purchased
                            
                            
                            7,500,000
                            
                            
                            $
                            7.48
                            
                            
                            
                            3,7082011
                            
                            Calls
      sold
                            
                            
                            7,500,000
                            
                            
                            $
                            8.44
                            
                            
                            
                            —2012
                            
                            Puts
      purchased
                            
                            
                            1,020,000
                            
                            
                            $
                            7.00
                            
                            
                            
                            2232012
                            
                            Calls
      sold
                            
                            
                            1,020,000
                            
                            
                            $
                            8.32
                            
                            
                            
                            —2013
                            
                            Puts
      purchased
                            
                            
                            300,000
                            
                            
                            $
                            7.00
                            
                            
                            
                            722013
                            
                            Calls
      sold
                            
                            
                            300,000
                            
                            
                            $
                            8.25
                            
                            
                            
                            —$
                            8,525
 
 Crude
Oil Fixed Price Swaps
 
 Twelve MonthPeriod Ending
                          
                          
                          
                          
                          
                          
                          Average
                          
                          
                          Fair ValueDecember 31,
                          
                          
                          
                          Volumes
                          
                          
                          Fixed Price
                          
                          
                          Asset(Bbl)
                          
                          
                          (per Bbl)
                          
                          
                          (in thousands)(2)2009
                          
                          
                          
                          
                          59,900
                          
                          
                          $
                          100.14
                          
                          
                          $
                          2,7902010
                          
                          
                          
                          
                          48,900
                          
                          
                          $
                          97.40
                          
                          
                          
                          1,6242011
                          
                          
                          
                          
                          42,600
                          
                          
                          $
                          96.44
                          
                          
                          
                          1,1412012
                          
                          
                          
                          
                          33,500
                          
                          
                          $
                          96.00
                          
                          
                          
                          7852013
                          
                          
                          
                          
                          10,000
                          
                          
                          $
                          96.06
                          
                          
                          
                          221$
                          6,561
  89
  Crude
Oil Costless Collars
 
 Twelve MonthPeriod Ending
                        
                        
                        
                        
                        
                        
                        Average
                        
                        
                        Fair ValueDecember 31,
                        
                        Option Type
                        
                        Volumes
                        
                        
                        Floor and Cap
                        
                        
                        Asset(Bbl)
                        
                        
                        (per Bbl)
                        
                        
                        (in thousands)(2)2009
                        
                        Puts
      purchased
                        
                        
                        36,500
                        
                        
                        $
                        85.00
                        
                        
                        $
                        1,2002009
                        
                        Calls
      sold
                        
                        
                        36,500
                        
                        
                        $
                        118.63
                        
                        
                        
                        —2010
                        
                        Puts
      purchased
                        
                        
                        31,000
                        
                        
                        $
                        85.00
                        
                        
                        
                        7542010
                        
                        Calls
      sold
                        
                        
                        31,000
                        
                        
                        $
                        112.92
                        
                        
                        
                        —2011
                        
                        Puts
      purchased
                        
                        
                        27,000
                        
                        
                        $
                        85.00
                        
                        
                        
                        5382011
                        
                        Calls
      sold
                        
                        
                        27,000
                        
                        
                        $
                        110.81
                        
                        
                        
                        —2012
                        
                        Puts
      purchased
                        
                        
                        21,500
                        
                        
                        $
                        85.00
                        
                        
                        
                        3792012
                        
                        Calls
      sold
                        
                        
                        21,500
                        
                        
                        $
                        110.06
                        
                        
                        
                        —2013
                        
                        Puts
      purchased
                        
                        
                        6,000
                        
                        
                        $
                        85.00
                        
                        
                        
                        1002013
                        
                        Calls
      sold
                        
                        
                        6,000
                        
                        
                        $
                        110.09
                        
                        
                        
                        —2,971Total
      Net Asset
                        
                        
                        $
                        159,459
 
 (1)
                Fair
      value based on forward NYMEX natural gas prices, as
      applicable.
 (2)
                Fair
      value based on forward WTI crude oil prices, as
  applicable.
 
 The fair value of the derivatives
related to commodities included in the consolidated balance sheets are as
follows (in thousands):
 
 December
      31,2008
                  
                  
                  2007Current
      portion of derivative asset
                  
                  $
                  107,766
                  
                  
                  $
                  38,181Long-term
      derivative asset
                  
                  
                  69,451
                  
                  
                  
                  6,882Current
      portion of derivative liability
                  
                  
                  (9,348
                  )
                  
                  
                  (356
                  )Long-term
      derivative liability
                  
                  
                  (8,410
                  )
                  
                  
                  (39,204
                  )$
                  159,459
                  
                  
                  $
                  5,503
 
 In
addition, an unrealized derivative liability of $(51.8) million and an
unrealized derivative asset of $3.4 million have been allocated to the limited
partners in the Partnerships at December 31, 2008 and 2007, respectively, based
on the Partnerships’ share of estimated future gas and oil production related to
the hedges not yet settled and are included in the consolidated balance sheets
as follows (in thousands):
 
 December
      31,2008
                    
                    
                    2007Unrealized
      derivative loss – short-term
                    
                    $
                    3,022
                    
                    
                    $
                    213Other
      assets – long-term
                    
                    
                    2,719
                    
                    
                    
                    13,542Accrued
      liabilities – short-term
                    
                    
                    (34,932
                    )
                    
                    
                    (9,013
                    )Unrealized
      derivative gain – long-term
                    
                    
                    (22,581
                    )
                    
                    
                    (1,348
                    )$
                    (51,772
                    )
                    
                    $
                    3,394
 
 Interest
Rate Risk Hedging Program
  At
December 31, 2008, the Company had debt outstanding of $467.0 million under its
revolving credit facility. During the year ended December 31, 2008, the Company
entered into derivative contracts in the form of interest rate swaps to reduce
the impact of volatility of changes in the London interbank offered rate
(“LIBOR”).  The Company has LIBOR interest rate swaps at a three-year fixed
swap rate of 3.11% on $150.0 million of outstanding debt through January 2011.
The swaps have been designated as cash flow hedges to minimize the risk
associated with changes in the designated benchmark interest rate (in this case,
LIBOR) related to forecasted payments associated with interest on the credit
facility. The Company has accounted for the interest rate swaps under the
“long-haul” method to measure ineffectiveness under SFAS No. 133. Using the
change in variable cash flow method, no hedge ineffectiveness was identified.
The value of the Company’s cash flow derivatives related to interest rate swaps
included in accumulated other comprehensive income was a net unrecognized loss
of approximately $5.8 million at December 31, 2008. The Company recognized a
loss on settled swaps of $520,000 for the year ended December 31, 2008. The fair
value of the derivatives related to interest rate swaps are included in the
consolidated balance sheet as follows:
  90
  December
      31,2008
                    
                    
                    2007Current
      portion of derivative liability
                    
                    $
                    (3,481
                    )
                    
                    $
                    —Long-term
      derivative liability
                    
                    
                    (2,361
                    )
                    
                    
                    —$
                    (5,842
                    )
                    
                    $
                    —
 
 Fair
Value of Financial Instruments
 
 Derivative
Instruments
 
 The
Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157
establishes a fair value hierarchy which requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be
used to measure fair value:
 
 Level 1–Quoted prices in
active markets for identical assets and liabilities that the reporting entity
has the ability to access at the measurement date.
 
 Level 2 –Inputs other than
quoted prices included within Level 1 that are observable for the asset and
liability or can be corroborated with observable market data for substantially
the entire contractual term of the asset or liability.
 
 Level 3 –Unobservable inputs
that reflect the entity’s own assumptions about the assumptions that market
participants would use in the pricing of the asset or liability and are
consequently not based on market activity, but rather through particular
valuation techniques.
 
 The
Company uses the fair value methodology outlined in SFAS No. 157 to value the
assets and liabilities for its outstanding derivative contracts. All of the
Company’s derivative contracts are defined as Level 2. The Company’s natural gas
and crude oil derivative contracts are valued based on prices quoted on the
NYMEX or WTI and adjusted by the respective counterparty using various
assumptions including quoted forward prices, time value, volatility factors, and
contractual prices for the underlying instruments. The Company’s interest rate
derivative contracts are valued using a LIBOR rate-based forward price curve
model.  In accordance with SFAS No. 157, the following table represents the
Company’s fair value hierarchy for its financial instruments at December 31,
2008 (in thousands):
 
 Level 2
                      
                      
                      TotalCommodity-based
      derivatives
                      
                      $
                      159,459
                      
                      
                      $
                      159,459Interest
      rate swap-based derivatives
                      
                      
                      (5,842
                      )
                      
                      
                      (5,842
                      )Total
                      
                      $
                      153,617
                      
                      
                      $
                      153,617
 
 Other
Financial Instruments
 
 The
estimated fair value of the Company’s other financial instruments has been
determined based upon its assessment of available market information and
valuation methodologies.  However, these estimates may not necessarily
be indicative of the amounts that the Company could realize upon the sale or
refinancing of such financial instruments.  The Company’s other
current assets and liabilities on its consolidated balance sheets are financial
instruments and their estimated fair values  approximate their
carrying amounts due to their short-term nature.   The estimated
fair values of the Company’s long-term debt at December 31, 2008 and 2007, which
consists principally of the Company’s senior unsecured notes and borrowings
under its credit facilities, were $712.2 million and $740.0 million,
respectively, compared with the carrying amounts of $873.7 million and $740.0
million, respectively.  The senior unsecured notes were valued based
upon recent trading activity.  The carrying value of outstanding
borrowings under the credit facility, which bears interest at a variable
interest rate, approximates their estimated fair value.
  91
  NOTE
8—COMMITMENTS AND CONTINGENCIES
 
 General
Commitments
 
 The
Company leases office space and equipment under leases with varying expiration
dates through 2014. Rental expense was approximately $1.6 million, $1.0 million
and $670,000, for the years ended December 31, 2008, 2007 and 2006,
respectively. Future minimum rental commitments for the next five annual periods
are as follows (in thousands):
 
 Years
      Ended December 31,2009
                    
                    $
                    3,1782010
                    
                    
                    2,7702011
                    
                    
                    2,0712012
                    
                    
                    1,4272013
                    
                    
                    1,069Thereafter
                    
                    
                    3,853$
                    14,368
 
 The
Company is the managing general partner of the Partnerships, and has agreed to
indemnify each investor partner from any liability that exceeds such partner’s
share of Partnership assets. Subject to certain conditions, investor partners in
certain Partnerships have the right to present their interests for purchase by
the Company, as managing general partner. The Company is not obligated to
purchase more than 5% to 10% of the units in any calendar year. Based on past
experience, the Company believes that any liability incurred would not be
material.  The Company may be required to subordinate a part of its
net partnership revenues from the Partnerships to the receipt by investor
partners of cash distributions from the investment partnerships equal to at
least 10% of their subscriptions determined on a cumulative basis, in accordance
with the terms of the partnership agreements.
 
 Atlas
America is party to employment agreements with certain executives that provide
compensation, severance and certain other benefits. Some of these obligations
may be allocable to the Company.
 
 Legal
Proceedings
 
 On June
20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named
as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”)
v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell
County, Tennessee).   In its complaint, CNX alleged that Miller
breached a contract to assign to CNX certain leasehold rights (“Leases”)
representing approximately 30,000 acres in Campbell County, Tennessee and that
the Company and another defendant, Wind City Oil & Gas, LLC, interfered with
the closing of this assignment on June 6, 2008.  The Company purchased
the Leases from Miller for approximately $19.1 million.  On December
15, 2008, the Chancery Court dismissed the matter in its entirety, holding that
there had been no breach of the contract by Miller and, therefore, that Atlas
America could not have tortuously interfered with the contract.  The
Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has
appealed this decision.
 
 One of the Company’s subsidiaries,
Resource Energy, LLC, together with Resource America, Inc., (the former parent
of Atlas America), was a defendant in a class action originally filed in
February 2000 in the New York Supreme Court, Chautauqua County, by individuals,
putatively on their own behalf and on behalf of similarly situated individuals,
who leased property to the Company.  The complaint alleged that the
Company was not paying landowners the proper amount of royalty revenues with
respect to natural gas produced from the leased properties.  The
complaint was seeking damages in an unspecified amount for the alleged
difference between the amount of royalties actually paid and the amount of
royalties that allegedly should have been paid.  In April 2007, a
settlement of this lawsuit was approved by the court. Pursuant to the settlement
terms, the Company paid $300,000 in May 2007, upgraded certain gathering systems
and capped certain transportation expenses chargeable to the
landowners.  The Company was indemnified by Atlas America for this
matter.
 
 Atlas Gas
& Oil Company LLC, as successor to DTE Gas & Oil Company, was one of
four defendants in a personal injury action filed in Antrim County Circuit Court
in northern Michigan in August 2006.  The complaint alleged that plaintiff
suffered serious personal injuries as a result of the defendants’
negligence.  The Company paid $125,000 to the plaintiff in October
2007 in full settlement of this action.
 
 92
  The
Company is also a party to various routine legal proceedings arising in of the
ordinary course of its business. Management believes that none of these actions,
individually or in the aggregate, will have a material adverse effect on the
Company’s financial condition or results of operations.
 
 NOTE
9—LONG-TERM DEBT
 
 Total debt consists of the following at
the dates indicated (in thousands):
 
 December
      31,2008
                  
                  
                  2007Revolving
      credit
      facility
                  
                  $
                  467,000
                  
                  
                  $
                  740,00010.75%
      senior unsecured notes – due 2018
                  
                  
                  400,000
                  
                  
                  
                  —Unamortized
      notes premium
                  
                  
                  6,655
                  
                  
                  
                  —Other
      debt
                  
                  
                  —
                  
                  
                  
                  30$
                  873,655
                  
                  
                  $
                  740,030Less
      current maturities
                  
                  
                  —
                  
                  
                  
                  (30
                  )$
                  873,655
                  
                  
                  $
                  740,000
 
 Revolving Credit
Facility.  At December 31, 2008, the Company had a credit
facility with a syndicate of banks with a borrowing base of $697.5 million that
matures in June 2012.  The borrowing base will be redetermined
semiannually on April 1 and October 1 subject to changes in the Company’s oil
and gas reserves.  Up to $50.0 million of the facility may be in the
form of standby letters of credit, of which $1.2 million was outstanding at
December 31, 2008, which are not reflected as borrowings on the Company’s
consolidated balance sheets.   The facility is secured by
substantially all of the Company’s assets and is guaranteed by each of the
company’s subsidiaries and bears interest at either the base rate plus the
applicable margin or at adjusted LIBOR plus the applicable margin, elected at
the Company’s option.  At December 31, 2008 and 2007, the weighted
average interest rate on outstanding borrowings was 2.8% and 7.2%,
respectively.  The base rate for any day equals the higher of the
federal funds rate plus 0.50% or the J.P. Morgan prime rate.  Adjusted
LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal
Reserve Board for  determining the reserve requirement for
Eurocurrency liabilities.  The applicable margin ranges from 0.0% to
0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.
 
 The
events which constitute an event of default for the Company’s credit facility
are also customary for loans of this size, including payment defaults, breaches
of representations or covenants contained in the credit agreement, adverse
judgments against the Company in excess of a specified amount, and a change of
control.  In addition, the agreement limits sales, leases or transfers
of assets and the incurrence of additional indebtedness.  The
agreement limits the distributions payable by the Company if an event of default
has occurred and is continuing or would occur as a result of such
distribution.  The Company was in compliance with these covenants as
of December 31, 2008 and 2007.  The credit facility also requires the
Company to maintain ratios of current assets (as defined in the credit facility)
to current liabilities (as defined in the credit facility) of not less than 1.0
to 1.0 and a ratio of total debt (as defined in the credit facility) to earnings
before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as
defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0
commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1,
2010 and thereafter.  According to the definitions contained in the
Company’s credit facility,  the Company’s ratio of current assets to
current liabilities was 1.60 to 1.0 and its ratio of total debt to EBITDA was
2.89 to 1.0 at December 31, 2008.
 
 93
  Senior Unsecured
Notes.  In January 2008, the Company completed a private
placement of $250.0 million of its 10.75% senior unsecured notes (“Senior
Notes”) due 2018 to institutional buyers pursuant to rule 144A under the
Securities Act of 1933. In May 2008, the Company issued an additional $150.0
million of Senior Notes at 104.75% to par to yield 9.85% to the par call on
February 1, 2016.  The Company intends to treat these issuances as a
single class of debt securities which were subsequently registered for resale on
September 19, 2008.  The Company received proceeds of approximately
$398.0 million from these offerings, including a $7.1 million premium and net of
$9.2 million in underwriting fees.  In addition, the Company received
approximately $4.7 million related to accrued interest.  The Company
used the net proceeds to reduce the balance outstanding on its revolving credit
facility.  Interest on the Senior Notes is payable semi-annually in
arrears on February 1 and August 1 of each year.  The Senior Notes are
redeemable at any time at specified redemption prices, together with accrued and
unpaid interest to the date of redemption.  In addition, before
February 1, 2011, the Company may redeem up to 35% of the aggregate principal
amount of the Senior Notes with the proceeds of equity offerings at a stated
redemption price.  The Senior Notes are also subject to repurchase by
the Company at a price equal to 101% of their principal amount, plus accrued and
unpaid interest, upon a change of control or upon certain asset sales if the
Company does not reinvest the net proceeds within 360 days.  The
Senior Notes are junior in right of payment to the Company’s secured debt,
including its obligations under its credit facility.  The indenture
governing the Senior Notes contains covenants, including limitations of the
Company’s ability to: incur certain liens; engage in sale/leaseback
transactions; 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 its assets.  The Company is in compliance
with the covenants as of December 31, 2008.
 
 Annual
principal debt payments over the next five years ending December 31 are as
follows (in thousands)
 
 2009
                    
                    $
                    —2010
                    
                    
                    —2011
                    
                    
                    —2012
                    
                    
                    467,0002013
                    
                    
                    —Thereafter
                    
                    
                    406,655$
                    873,655
 
 Cash
payments for interest related to debt were $42.4 million and $23.2 million for
the years ended December 31, 2008 and 2007, respectively.  There were
no cash payments for interest related to debt for the year ended December 31,
2006.
 
 NOTE
10—OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS
 
 The
Company’s operations include three reportable operating segments. These
operating segments reflect the way the Company manages its operations and makes
business decisions.  The Company organizes its oil and gas production
segments by geographic location.  The Appalachia segment represents
the Company’s well interests in the states of Pennsylvania, Ohio, New York, West
Virginia and Tennessee.  The Michigan/Indiana segment represents the
Company’s well interests in the Antrim Shale, located in Michigan’s northern,
lower peninsula and the New Albany shale located in southwestern
Indiana.
 
 Operating
segment data (in thousands):
 
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Gas
      and oil productionAppalachia:Revenues
                  
                  $
                  127,935
                  
                  
                  $
                  99,015
                  
                  
                  $
                  88,449Costs
      and expenses
                  
                  
                  25,176
                  
                  
                  
                  17,638
                  
                  
                  
                  13,881Segment
      profit
                  
                  $
                  102,759
                  
                  
                  $
                  81,377
                  
                  
                  $
                  74,568Michigan/Indiana:Revenues(1)
                  
                  $
                  183,915
                  
                  
                  $
                  107,367
                  
                  
                  $
                  —Costs
      and expenses
                  
                  
                  34,403
                  
                  
                  
                  14,555
                  
                  
                  
                  —Segment
      profit
                  
                  $
                  149,512
                  
                  
                  $
                  92,812
                  
                  
                  $
                  —Partnership
      management:Revenues
                  
                  $
                  472,008
                  
                  
                  $
                  370,053
                  
                  
                  $
                  232,533Costs
      and expenses
                  
                  
                  389,361
                  
                  
                  
                  302,382
                  
                  
                  
                  209,548Segment
      profit
                  
                  $
                  82,647
                  
                  
                  $
                  67,671
                  
                  
                  $
                  22,985
  94
  Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Reconciliation
      of segment profit to net incomeSegment
      profitGas
      and oil production-Appalachia
                  
                  $
                  102,759
                  
                  
                  $
                  81,377
                  
                  
                  $
                  74,568Gas
      and oil production-Michigan/Indiana
                  
                  
                  149,512
                  
                  
                  
                  92,812
                  
                  
                  
                  —Partnership
      management
                  
                  
                  82,647
                  
                  
                  
                  67,671
                  
                  
                  
                  22,985Total
      segment profit
                  
                  
                  334,918
                  
                  
                  
                  241,860
                  
                  
                  
                  97,553General
      and administrative expense
                  
                  
                  (44,659
                  )
                  
                  
                  (39,414
                  )
                  
                  
                  (23,367
                  )Compensation
      reimbursement – affiliate
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  (1,237
                  )Depreciation,
      depletion and amortization
                  
                  
                  (95,434
                  )
                  
                  
                  (56,942
                  )
                  
                  
                  (22,491
                  )Interest
      expense
                  
                  
                  (56,306
                  )
                  
                  
                  (30,096
                  )
                  
                  
                  —Other
      − net (2)
                  
                  
                  4,260
                  
                  
                  
                  2,096
                  
                  
                  
                  1,369Net
      income before cumulative effect of accounting change
                  
                  $
                  142,779
                  
                  
                  $
                  117,504
                  
                  
                  $
                  51,827
 
 Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006Capital
      expendituresGas
      and oil productionAppalachia
                    
                    $
                    258,941
                    
                    
                    $
                    146,605
                    
                    
                    $
                    74,075Michigan/Indiana
                    
                    
                    77,884
                    
                    
                    
                    40,878
                    
                    
                    
                    —Partnership
      management
                    
                    
                    2,890
                    
                    
                    
                    4,499
                    
                    
                    
                    1,042Corporate
                    
                    
                    1,260
                    
                    
                    
                    4,753
                    
                    
                    
                    518$
                    340,975
                    
                    
                    $
                    196,735
                    
                    
                    $
                    75,635
 
 (1)
                Revenues
      for the twelve months ended December 31, 2007 include non-cash gains of
      $26.3 million related to non-qualifying hedges associated with the
      acquisition of AGO.
 (2)
                Includes
      revenues of $3.5 million and $1.5 million and expenses of $441,000 and
      $214,000 for the years ended December 31, 2008 and 2007, respectively for
      AGO well services and transportation.  These amounts do not meet
      the quantitative threshold for reporting segment
      information.  The following table reconciles revenue shown for
      each operating segment to total revenues shown on the combined and
      consolidated statements of
income:
 
 Years
      Ended December 31,2008
                        
                        
                        2007
                        
                        
                        2006Revenues:Gas
      and oil production – Appalachia
                        
                        $
                        127,935
                        
                        
                        $
                        99,015
                        
                        
                        $
                        88,449Gas
      and oil production – Michigan/Indiana
                        
                        
                        183,915
                        
                        
                        
                        107,367
                        
                        
                        
                        —Partnership
      Management
                        
                        
                        472,008
                        
                        
                        
                        370,053
                        
                        
                        
                        232,533Other
                        
                        
                        3,542
                        
                        
                        
                        1,462
                        
                        
                        
                        —$
                        787,400
                        
                        
                        $
                        577,897
                        
                        
                        $
                        320,982
  December
      31,2008
                      
                      
                      2007Balance
      sheetsGoodwillGas
      and oil production - Appalachia
                      
                      $
                      21,527
                      
                      
                      $
                      21,527Partnership
      management
                      
                      
                      13,639
                      
                      
                      
                      13,639$
                      35,166
                      
                      
                      $
                      35,166Total
      assetsGas
      and oil productionAppalachia
                      
                      $
                      773,889
                      
                      
                      $
                      491,199Michigan/Indiana
                      
                      
                      1,416,042
                      
                      
                      
                      1,330,432Partnership
      management
                      
                      
                      53,031
                      
                      
                      
                      30,359Corporate
                      
                      
                      27,723
                      
                      
                      
                      39,244$
                      2,270,685
                      
                      
                      $
                      1,891,234
  95
  Segment
profit per segment represents total revenues less costs and expenses
attributable thereto.  Amounts for interest, provision for possible
losses and depreciation, depletion and amortization and general corporate
expenses are shown in the aggregate because these measures are not significant
drivers in deciding how to allocate resources and assessing performance of each
defined segment.
 
 Major
Customer Information:
 
 For the
year ended December 31, 2008, gas sales to DTE Gas & Oil Company accounted
for 12% of total revenues.  No other fiscal period or operating
segment had revenues from a single customer which exceeded 10% of total
revenues.
 
 NOTE
11 - BENEFIT PLANS
 
 Unit Incentive Plan.In December 2006, the
Company adopted a Long-Term Incentive Plan (“LTIP”), which provides performance
incentive awards to officers, employees and board members and employees of its
affiliates, consultants and joint-venture partners.  The LTIP is
administered by the Company’s compensation committee, which may grant awards of
either restricted stock units, phantom units or unit options for an aggregate of
3,742,000 common units. Awards granted in 2008 and 2007 vest 25% after three
years and 100% upon the four year anniversary of grant, except for awards of
1,500 units to board members which vest 25% per year over four years. Awards
granted in 2006 vest 25% per year over four years. Upon termination of service
by a grantee, all unvested awards are forfeited. A restricted stock or phantom
unit entitles a grantee to receive a common unit of the Company upon vesting of
the unit or, at the discretion of the Company’s compensation committee, cash
equivalent to the then fair market value of a common unit of the
Company.  In tandem with phantom unit grants, the Company’s
compensation committee may grant a distribution equivalent right (“DER”), which
is the right to receive cash per phantom unit in an amount equal to, and at the
same time as, the cash distributions the Company makes on a common unit during
the period such phantom unit is outstanding.
 
 Restricted Stock and Phantom
Units.  Under the LTIP, 156,793, 590,950 and 47,619 units of
restricted stock and phantom units were awarded in 2008, 2007 and 2006,
respectively. The fair value of the grants is based on the closing stock price
on the grant date, and is being charged to operations over the requisite service
periods using a straight-line attribution method.
 
 The following table summarizes the
activity of restricted stock and phantom units for the periods
indicated:
 
 WeightedAverageGrant
      DateUnits
                    
                    
                    Fair
      ValueNon-vested
      shares outstanding at December 31, 2005
                    
                    
                    —
                    
                    
                    $
                    —Granted
                    
                    
                    47,619
                    
                    
                    $
                    21.00Non-vested
      shares outstanding at December 31, 2006
                    
                    
                    47,619
                    
                    
                    $
                    21.00Granted
                    
                    
                    590,950
                    
                    
                    $
                    24.63Vested
                    
                    
                    (11,904
                    )
                    
                    $
                    21.00Forfeited
                    
                    
                    (2,000
                    )
                    
                    $
                    23.06Non-vested
      shares outstanding at December 31, 2007
                    
                    
                    624,665
                    
                    
                    $
                    24.42Granted
                    
                    
                    156,793
                    
                    
                    $
                    21.43Vested
                    
                    
                    (12,279
                    )
                    
                    $
                    21.06Forfeited
                    
                    
                    (350
                    )
                    
                    $
                    26.47Non-vested
      shares outstanding at December 31, 2008
                    
                    
                    768,829
                    
                    
                    $
                    23.86
 
 Unit Options.  For
the years ended December 31, 2008, 2007 and 2006, 14,000, 1,532,000 and 373,752
unit options, respectively, were awarded under the LTIP. Option awards expire 10
years from the date of grant and are generally granted with an exercise price
equal to the market price of the Company’s stock at the date of grant. The
Company uses the Black-Scholes option pricing model to estimate the weighted
average fair value per option granted with the following
assumptions:
  96
  Years
      Ended December 31,2008
                    
                    
                    2007
                    
                    
                    2006Expected
      life (years)
                    
                    
                    6.25
                    
                    
                    
                    6.25
                    
                    
                    
                    6.25Expected
      volatility
                    
                    
                    27-34
                    %
                    
                    
                    25
                    %
                    
                    
                    25
                    %Risk-free
      interest rate
                    
                    
                    2.8-4.0
                    %
                    
                    
                    4.7
                    %
                    
                    
                    4.4
                    %Expected
      dividend yield
                    
                    
                    6.2-7.0
                    %
                    
                    
                    5.1-8.0
                    %
                    
                    
                    8.0
                    %Weighted
      average fair value of stock options granted
                    
                    $
                    5.69
                    
                    
                    $
                    2.96
                    
                    
                    $
                    2.14
 
 The
following table sets forth option activity for the periods
indicated:
 WeightedAverageWeighted
                                                                  
                                                                  
                                                                  Remaining
                                                                  
                                                                  
                                                                  AggregateAverage
                                                                  
                                                                  
                                                                  Contractual
                                                                  
                                                                  
                                                                  IntrinsicExercise
                                                                  
                                                                  
                                                                  Term
                                                                  
                                                                  
                                                                  ValueShares
                                                                  
                                                                  
                                                                  Price
                                                                  
                                                                  
                                                                  (in
      years)
                                                                  
                                                                  
                                                                  (in
      thousands)Outstanding
      at December 31, 2005
                                                                  
                                                                  
                                                                  —
                                                                  
                                                                  
                                                                  $
                                                                  —Granted
                                                                  
                                                                  
                                                                  373,752
                                                                  
                                                                  
                                                                  $
                                                                  21.00Outstanding
      at December 31, 2006
                                                                  
                                                                  
                                                                  373,752
                                                                  
                                                                  
                                                                  $
                                                                  21.00Granted
                                                                  
                                                                  
                                                                  1,532,000
                                                                  
                                                                  
                                                                  $
                                                                  24.84Exercised
                                                                  
                                                                  
                                                                  —
                                                                  
                                                                  
                                                                  
                                                                  —Forfeited
      or expired
                                                                  
                                                                  
                                                                  (10,700
                                                                  )
                                                                  
                                                                  $
                                                                  23.06Outstanding
      at December 31, 2007
                                                                  
                                                                  
                                                                  1,895,052
                                                                  
                                                                  
                                                                  $
                                                                  24.09Granted
                                                                  
                                                                  
                                                                  14,000
                                                                  
                                                                  
                                                                  $
                                                                  35.36Exercised
                                                                  
                                                                  
                                                                  —
                                                                  
                                                                  
                                                                  
                                                                  —Forfeited
      or expired
                                                                  
                                                                  
                                                                  (6,150
                                                                  )
                                                                  
                                                                  $
                                                                  25.97Outstanding
      at December 31, 2008
                                                                  
                                                                  
                                                                  1,902,902
                                                                  
                                                                  
                                                                  $
                                                                  24.17
                                                                  
                                                                  
                                                                  
                                                                  7.9
                                                                  
                                                                  
                                                                  $
                                                                  —Options
      exercisable at December 31, 2008
                                                                  
                                                                  
                                                                  186,876
                                                                  
                                                                  
                                                                  $
                                                                  21.00
                                                                  
                                                                  
                                                                  
                                                                  7.25Available
      for grant at December 31, 2008
                                                                  
                                                                  
                                                                  1,046,086
  The
following tables summarize information about stock options outstanding and
exercisable at December 31, 2008:
 Options Outstanding
                                            
                                            
                                            Options ExercisableRange of
                                              Exercise Prices
                                            
                                            
                                            Number of
                                              Shares
                                              Outstanding
                                            
                                            
                                            Weighted
                                              Average
                                              Remaining
                                              Contractual
                                              Life in Years
                                            
                                            
                                            Weighted
                                              Average
                                              Exercise Price
                                            
                                            
                                            Number of
                                              Shares
                                              Exercisable
                                            
                                            
                                            Weighted
                                              Average
                                              Exercise
                                              Price$21.00
      – 23.06
                                            
                                            
                                            
                                            1,654,802
                                            
                                            
                                            
                                            7.9
                                            
                                            
                                            $
                                            22.59
                                            
                                            
                                            
                                            186,876
                                            
                                            
                                            $
                                            21.00$30.24
      - 35.00
                                            
                                            
                                            
                                            240,600
                                            
                                            
                                            
                                            8.5
                                            
                                            
                                            $
                                            34.53
                                            
                                            
                                            
                                            —
                                            
                                            
                                            
                                            —$39.00
      & above
                                            
                                            
                                            
                                            7,500
                                            
                                            
                                            
                                            9.0
                                            
                                            
                                            $
                                            39.79
                                            
                                            
                                            
                                            —
                                            
                                            
                                            
                                            —1,902,902
                                            
                                            
                                            
                                            7.9
                                            
                                            
                                            $
                                            24.17
                                            
                                            
                                            
                                            186,876
                                            
                                            
                                            $
                                            21.00
 
 The Company recognized $5.5 million,
$4.7 million and $337,000 in compensation expense related to restricted stock
units, phantom units and unit options for the years ended December 31, 2008,
2007 and 2006, respectively.  The Company paid $1.4 million with
respect to its LTIP DERs for the year ended December 31, 2008.  This
amount was recorded as a reduction of members’ equity on the Company’s
consolidated balance sheet.   At December 31, 2008, the Company
had approximately $13.7 million of unrecognized compensation expense related to
the unvested portion of the restricted stock units, phantom units and
options.
  97
  NOTE
12 – COMMON EQUITY OFFERINGS
 
 Public
Common Unit Purchase
 
 On May
16, 2008, the Company sold 2,070,000 of its Class B common units in a public
offering at $41.50 per common unit with UBS Investment Bank and Wachovia
Securities acting as joint book-running managers and
underwriters.  The net proceeds of approximately $82.5 million (after
underwriting expenses of $3.4 million) were used to repay a portion of the
Company’s outstanding balance under its revolving credit facility.
 
 Atlas
America Common Unit Purchase
 
 On May 7,
2008, the Company sold 600,000 of its Class B common units to Atlas America in a
private placement at $42.00 per common unit, increasing Atlas America’s
ownership of ATN’s common units to 29,952,996 common units.  The
proceeds of $25.2 million were used to repay a portion of the Company’s
outstanding balance under its revolving credit facility.
 
 Private
Placement of Class B Common and Class D Units
 
 To
partially fund the acquisition of AGO in June 2007, the Company completed a
private placement of 7,298,181 Class B common units and 16,702,828 Class D units
at a weighted average price of $25.00 per unit for net proceeds of $597.5
million.  The private placement of the Class B common and Class D
units was exempt from registration under Section 4(2) of the Securities Act of
1933, as amended.  The Class D units were a new class of equity
security, which automatically converted to common units on a one-to-one basis
upon the receipt of the consent of the Company’s unit holders, which the Company
obtained in November 2007. The Company entered into a registration rights
agreement in connection with the sale of the units.  The agreement
required the Company to prepare and file a registration statement covering the
resale of such units by January 31, 2008 and have such registration statement
declared effective by May 30, 2008.  The Company filed this
registration statement, which was declared effective on February 20,
2008.
 
 NOTE
13 – CASH DISTRIBUTIONS
 
 The
Company is required to distribute, within 45 days after the end of each quarter,
all of its available cash (as defined in its limited liability company
agreement) for that quarter in accordance with their respective percentage
interests.  If Class A and Class B common unit distributions in any
quarter exceed specified target levels, the Managing Member will receive MIIs
between 15% and 50% of such distributions in excess of the specified target
levels as defined in our limited liability company
agreement.  Distributions declared by the Company from inception are
as follows:
 
 CashDistribution
                          
                          
                          Total Cash
                          
                          
                          Total
                          
                          
                          ManagerDate Cash
                          
                          
                          
                          Per
                          
                          
                          Distribution
                          
                          
                          Cash
                          
                          
                          IncentiveDistribution
                          
                          
                          
                          Common
                          
                          
                          to Common
                          
                          
                          Distribution
                          
                          
                          DistributionPaid or Payable
                          
                          For Quarter Ended
                          
                          Unit
                          
                          
                          Unit holders
                          
                          
                          to the Manager
                          
                          
                          Payable(in thousands)
                          
                          
                          (in thousands)
                          
                          
                          (in thousands)February
      14, 2007
                          
                          December
      31, 2006
                          
                          $
                          0.06
                          (1)
                          
                          $
                          2,198
                          
                          
                          $
                          45May
      15, 2007
                          
                          March
      31, 2007
                          
                          $
                          0.43
                          
                          
                          $
                          15,770
                          
                          
                          $
                          322August
      14, 2007
                          
                          June
      30, 2007
                          
                          $
                          0.43
                          
                          
                          $
                          15,770
                          
                          
                          $
                          322November
      14, 2007
                          
                          September
      30, 2007
                          
                          $
                          0.55
                          
                          
                          $
                          33,391
                          
                          
                          $
                          681
                          
                          
                          $
                          784February
      14 , 2008
                          
                          December
      31, 2007
                          
                          $
                          0.57
                          
                          
                          $
                          34,605
                          
                          
                          $
                          706
                          
                          
                          $
                          965May
      15, 2008
                          
                          March
      31, 2008
                          
                          $
                          0.59
                          
                          
                          $
                          36,173
                          
                          
                          $
                          738
                          
                          
                          $
                          1,214August
      14, 2008
                          
                          June
      30, 2008
                          
                          $
                          0.61
                          
                          
                          $
                          38,663
                          
                          
                          $
                          789
                          
                          
                          $
                          1,687November
      14, 2008
                          
                          September
      30, 2008
                          
                          $
                          0.61
                          
                          
                          $
                          38,663
                          
                          
                          $
                          789
                          
                          
                          $
                          1,687February
      13, 2009(2)
                          
                          December
      31, 2008
                          
                          $
                          0.61
                          (2)
                          
                          $
                          38,663
                          
                          
                          $
                          789
                          
                          
                          $
                          1,687
 
 (1)
              Represents
      a prorated distribution of $0.42 per unit for the period from December 18,
      2006, the date of the Company’s initial public offering through December
      31, 2006.
  98
  (2)
              On
      January 28, 2009, the Company declared a quarterly cash distribution for
      the quarter ended December 31, 2008, of $0.61 per common
      unit.  The distribution is payable February 13, 2009 to holders
      of record as of February 9, 2009.
 
 NOTE
14 – SUBSEQUENT EVENTS
 
 On
January 29, 2009, the Company declared a quarterly cash distribution for the
quarter ended December 31, 2008, of $0.61 per common unit.  The
distribution was paid on February 13, 2009 to unit holders of record as of
February 9, 2009.
 
 NOTE
15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
 
 Results
of operations from oil and gas producing activities for the periods indicated
are as follows (in thousands):
 
 Years
      Ended December 31,2008
                      
                      
                      2007
                      
                      
                      2006Revenues
                      
                      $
                      311,850
                      
                      
                      $
                      206,382
                      (1)
                      
                      $
                      88,449Production
      costs
                      
                      
                      (59,579
                      )
                      
                      
                      (32,193
                      )
                      
                      
                      (13,881
                      )Exploration
      expenses (2)
                      
                      
                      (6,029
                      )
                      
                      
                      (4,065
                      )
                      
                      
                      (3,016
                      )Depreciation,
      depletion and amortization
                      
                      
                      (91,991
                      )
                      
                      
                      (54,383
                      )
                      
                      
                      (20,600
                      )Results
      of operations from oil and gas producing activities
                      
                      
                      154,251
                      
                      
                      $
                      115,741
                      
                      
                      $
                      50,952
 
 (1)
              Includes
      unrealized gains from mark-to-market derivatives of $26.3 million.
 (2)
              Represents
      the Company’s land and leasing
activities.
 
 Capitalized Costs Related to Oil and
Gas Producing Activities.The components of capitalized costs
related to the Company’s oil and gas producing activities at the dates indicated
are as follows (in thousands):
 
 At
      December 31,2008
                    
                    
                    2007Natural
      gas and oil properties:Proved
      properties
                    
                    $
                    2,087,119
                    
                    
                    $
                    1,795,871Unproved
      properties
                    
                    
                    43,749
                    
                    
                    
                    16,380Support
      equipment
                    
                    
                    9,527
                    
                    
                    
                    6,9362,140,395
                    
                    
                    
                    1,819,187Accumulated
      depreciation, depletion and amortization(1)
                    
                    
                    (221,356
                    )
                    
                    
                    (136,603
                    )Net
      capitalized costs
                    
                    $
                    1,919,039
                    
                    
                    $
                    1,682,584
 
 (1)
              Costs
      related to unproved properties are excluded from amortization as they are
      assessed for impairment.
 
 Costs Incurred in Oil and Gas
Producing Activities. The costs incurred by the Company in its oil and
gas activities for the periods indicated are as follows (in
thousands):
 
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Property
      acquisition costs:Proved
      properties
                  
                  $
                  63,146
                  
                  
                  $
                  1,243,877
                  
                  
                  $
                  5,153Unproved
      properties
                  
                  
                  27,064
                  
                  
                  
                  50,100
                  
                  
                  
                  —Exploration
      costs
                  
                  
                  6,029
                  
                  
                  
                  4,065
                  
                  
                  
                  3,016Development
      costs
                  
                  
                  229,687
                  
                  
                  
                  168,253
                  
                  
                  
                  76,687$
                  325,926
                  
                  
                  $
                  1,466,295
                  
                  
                  $
                  84,856
 
 (1)
              Represents
      the Company’s land and leasing
activities.
 
 99
  The
development costs above were substantially all incurred for the development of
proved undeveloped properties.
 
 Oil and Gas Reserve
Information.  The estimates of the Company’s proved and
unproved gas and oil reserves are based upon evaluations made by management and
verified by an independent petroleum engineering firm. All reserves are
generally located in the Appalachian Basin in Michigan’s Lower Peninsula and in
southwestern Indiana. Reserves are estimated in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board which require that reserve estimates be prepared
under existing economic and operating conditions with no provisions for price
and cost escalation except by contractual arrangements.
 
 Proved
oil and gas reserves are the estimated quantities of natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e. prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
 
 ·
              Reservoirs
      are considered proved if economic producibility is supported by either
      actual production or conclusive formation tests. The area of a reservoir
      considered proved includes (a) that portion delineated by drilling
      and defined by gas-oil and/or oil-water contacts, if any; and (b) the
      immediately adjoining portions not yet drilled, but which can be
      reasonably judged as economically productive on the basis of available
      geological and engineering data. In the absence of information on fluid
      contacts, the lowest known structural occurrence of hydrocarbons controls
      the lower proved limit of the
reservoir.
 ·
              Reserves
      which can be produced economically through application of improved
      recovery techniques (such as fluid injection) are included in the “proved”
      classification when successful testing by a pilot project, or the
      operation of an installed program in the reservoir, provides support for
      the engineering analysis on which the project or program was
      based.
 
 ·
              Estimates
      of proved reserves do not include the following: (a) oil that may
      become available from known reservoirs but is classified separately as
      “indicated additional reservoirs”; (b) crude oil and natural gas, the
      recovery of which is subject to reasonable doubt because of uncertainty as
      to geology, reservoir characteristics or economic factors; (c) crude
      oil and natural gas, that may occur in undrilled prospects; and natural
      gas, that may be recovered from oil shales, coal, gilsonite and other such
      sources.
 
 Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operation methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as “proved developed reserves”
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
 
 There are
numerous uncertainties inherent in estimating quantities of proven reserves and
in projecting future net revenues and the timing of development expenditures.
The reserve data presented represents estimates only and should not be construed
as being exact. Additionally, the standardized measure of discounted future net
cash flows may not represent the fair market value of the Company’s oil and gas
reserves or the present value of future cash flows of equivalent reserves, due
to anticipated future changes in oil and gas prices and in production and
development costs and other factors for effects have not been proved. The
increase in the Company’s reserves for the year ended December 31, 2007, is
primarily due to the purchase of reserves in place as a result of the
acquisition of DTE Gas & Oil Company on June 29, 2007.
  100
 
 The
Company’s reconciliation of changes in proved reserve quantities is as
follows:
 
 Gas
                  
                  
                  Oil(Mcf)
                  
                  
                  (Bbls)Balance
      December 31, 2005
                  
                  
                  157,924,350
                  
                  
                  
                  2,257,211Extensions,
      discoveries and other additions
                  
                  
                  46,205,382
                  
                  
                  
                  12,920Sales
      of reserves in-place
                  
                  
                  (127,472
                  )
                  
                  
                  (703
                  )Purchase
      of reserves in-place
                  
                  
                  305,433
                  
                  
                  
                  1,675Transfers
      to limited partnerships
                  
                  
                  (6,671,754
                  )
                  
                  
                  (19,235
                  )Revisions
                  
                  
                  (20,147,989
                  )(3)
                  
                  
                  (33,594
                  )Production
                  
                  
                  (8,946,376
                  )
                  
                  
                  (150,628
                  )Balance
      December 31, 2006
                  
                  
                  168,541,574
                  
                  
                  
                  2,067,646Extensions,
      discoveries and other additions
                  
                  
                  126,613,549
                  (1)
                  
                  
                  23,358Sales
      of reserves in-place
                  
                  
                  (62,699
                  )
                  
                  
                  (625
                  )Purchase
      of reserves in-place
                  
                  
                  622,851,730
                  (2)
                  
                  
                  48,634Transfers
      to limited partnerships
                  
                  
                  (11,507,307
                  )
                  
                  
                  —Revisions
                  
                  
                  (714,501
                  )
                  
                  
                  (2,517
                  )Production
                  
                  
                  (20,963,436
                  )
                  
                  
                  (153,465
                  )Balance
      December 31, 2007
                  
                  
                  884,758,910
                  
                  
                  
                  1,983,031Extensions,
      discoveries and other additions
                  
                  
                  210,824,798
                  (1)
                  
                  
                  111,972Sales
      of reserves in-place
                  
                  
                  (34,924
                  )
                  
                  
                  (161
                  )Purchase
      of reserves in-place
                  
                  
                  3,461,987
                  
                  
                  
                  794Transfers
      to limited partnerships
                  
                  
                  (6,026,785
                  )
                  
                  
                  —Revisions
                  
                  
                  (68,276,626
                  )(3)
                  
                  
                  (203,166
                  )Production
                  
                  
                  (33,901,975
                  )
                  
                  
                  (158,529
                  )Balance
      December 31, 2008
                  
                  
                  990,805,385
                  
                  
                  
                  1,733,941Proved
      developed reserves at:December
      31, 2005
                  
                  
                  108,674,675
                  
                  
                  
                  2,122,568December
      31, 2006
                  
                  
                  107,683,343
                  
                  
                  
                  2,064,276December
      31, 2007
                  
                  
                  594,708,965
                  
                  
                  
                  1,977,446December
      31, 2008
                  
                  
                  586,655,301
                  
                  
                  
                  1,685,771
 
 (1)
                Includes
      a significant increase in proved undeveloped reserves due to the addition
      of proved undeveloped reserves for Marcellus
  wells.
 (2)
                Represents
      the reserves purchased from the acquisition of AGO on June 29,
      2007.
 (3)
                Represents
      a decrease of the year-end price of natural gas and oil compared to
      the price of natural gas and oil at the beginning of the
    year.
 
 The
following schedule presents the standardized measure of estimated discounted
future net cash flows relating to proved oil and gas reserves. The estimated
future production is priced at year-end prices, adjusted only for fixed and
determinable increases in natural gas and oil prices provided by contractual
agreements. The resulting estimated future cash inflows are reduced by estimated
future costs to develop and produce the proved reserves based on year-end cost
levels and includes the effect on cash flows of settlement of asset retirement
obligations on gas and oil properties. The future net cash flows are reduced to
present value amounts by applying a 10% discount factor. The standardized
measure of future cash flows was prepared using the prevailing economic
conditions existing at December 31, 2006, 2007 and 2008 and such conditions
continually change. Accordingly, such information should not serve as a basis in
making any judgment on the potential value of recoverable reserves or in
estimating future results of operations.  Since the Company is a
limited liability company that allocates taxable income to the individual unit
holders, no provisions for federal or state income taxes have been included in
the calculation of standardized measure.
  101
   
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006(in
      thousands)Future
      cash inflows
                  
                  $
                  6,333,935
                  
                  
                  $
                  6,408,367
                  
                  
                  $
                  1,262,161Future
      production costs
                  
                  
                  (2,297,091
                  )
                  
                  
                  (1,804,199
                  )
                  
                  
                  (334,062
                  )Future
      development costs
                  
                  
                  (618,604
                  )
                  
                  
                  (388,111
                  )
                  
                  
                  (149,610
                  )Future
      income tax expense
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Future
      net cash flows
                  
                  
                  3,418,240
                  
                  
                  
                  4,216,057
                  
                  
                  
                  778,489Less
      10% annual discount for estimating timing of cash flows
                  
                  
                  (2,286,299
                  )
                  
                  
                  (2,734,879
                  )
                  
                  
                  (495,048
                  )Standardized
      measure of discounted future net cash flows
                  
                  $
                  1,131,941
                  
                  
                  $
                  1,481,178
                  
                  
                  $
                  283,441
 
 The
future cash flows estimated to be spent to develop proved undeveloped properties
in the years ended December 31, 2009, 2010, 2011 and 2012 are $200.7 million,
$192.5 million, $192.0 million and $33.5 million, respectively.
 
 The
following table (in thousands) summarizes the changes in the standardized
measure of discounted future net cash flows from estimated production of proved
oil and gas reserves for the years ended December 31, 2006, 2007 and
2008.  Since the Company allocates taxable income to unit holders, no
recognition has been given to income taxes.
 
 Years
      Ended December 31,2008
                  
                  
                  2007
                  
                  2006Balance,
      beginning of year
                  
                  $
                  1,481,178
                  
                  
                  $
                  283,441
                  
                  
                  $
                  597,137Increase
      (decrease) in discounted future net cash flows:Sales
      and transfers of oil and gas, net of related costs
                  
                  
                  (252,270
                  )
                  
                  
                  (147,982
                  )
                  
                  
                  (74,567
                  )Net
      changes in prices and production costs
                  
                  
                  (316,970
                  )
                  
                  
                  45,261
                  
                  
                  
                  (273,631
                  )Revisions
      of previous quantity estimates
                  
                  
                  (46,767
                  )
                  
                  
                  (1,208
                  )
                  
                  
                  (30,058
                  )Development
      costs incurred
                  
                  
                  48,092
                  
                  
                  
                  98,424
                  
                  
                  
                  3,426Changes
      in future development costs
                  
                  
                  (35,662
                  )
                  
                  
                  (14,128
                  )
                  
                  
                  (8,505
                  )Transfers
      to limited partnerships
                  
                  
                  (615
                  )
                  
                  
                  (13,998
                  )
                  
                  
                  (8,449
                  )Extensions,
      discoveries, and improved recovery less related costs
                  
                  
                  41,020
                  
                  
                  
                  170,349
                  
                  
                  
                  44,820Purchases
      of reserves in place
                  
                  
                  5,170
                  
                  
                  
                  957,137
                  
                  
                  
                  660Sales
      of reserves in place, net of tax effect
                  
                  
                  (97
                  )
                  
                  
                  (105
                  )
                  
                  
                  (572
                  )Accretion
      of discount
                  
                  
                  147,781
                  
                  
                  
                  74,685
                  
                  
                  
                  59,714Net
      changes in future income taxes
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Estimated
      settlement of asset retirement obligations
                  
                  
                  (5,778
                  )
                  
                  
                  (4,523
                  )
                  
                  
                  (8,226
                  )Estimated
      proceeds on disposals of well equipment
                  
                  
                  6,329
                  
                  
                  
                  5,168
                  
                  
                  
                  10,007Changes
      in production rates (timing) and other
                  
                  
                  60,530
                  
                  
                  
                  28,657
                  
                  
                  
                  (28,315
                  )Balance,
      end of year
                  
                  $
                  1,131,941
                  
                  
                  $
                  1,481,178
                  
                  
                  $
                  283,441
  102
  NOTE
16 – QUARTERLY RESULTS (UNAUDITED)
  March 31,
                                              
                                              
                                              June 30,
                                              
                                              
                                              September 30,
                                              
                                              
                                              December 31,(in thousands, except unit data)Year
      ended December 31, 2008Revenues
                                              
                                              $
                                              194,589
                                              
                                              
                                              $
                                              217,556
                                              
                                              
                                              $
                                              213,621
                                              
                                              
                                              $
                                              161,634Net
      income
                                              
                                              $
                                              37,543
                                              
                                              
                                              $
                                              38,359
                                              
                                              
                                              $
                                              38,180
                                              
                                              
                                              $
                                              28,697Net
      income per Class B common unit:Basic
                                              
                                              $
                                              0.59
                                              
                                              
                                              $
                                              0.58
                                              
                                              
                                              $
                                              0.56
                                              
                                              
                                              $
                                              0.42Diluted
                                              
                                              
                                              0.58
                                              
                                              
                                              $
                                              0.57
                                              
                                              
                                              $
                                              0.56
                                              
                                              
                                              $
                                              0.42Year
      ended December 31, 2007Revenues
                                              
                                              $
                                              105,191
                                              
                                              
                                              $
                                              128,055
                                              
                                              
                                              $
                                              180,269
                                              
                                              
                                              $
                                              164,382Net
      income
                                              
                                              $
                                              19,941
                                              
                                              
                                              $
                                              41,665
                                              
                                              
                                              $
                                              31,612
                                              
                                              
                                              $
                                              24,286Net
      income per Class B common unit:Basic
                                              
                                              $
                                              0.53
                                              
                                              
                                              $
                                              1.10
                                              
                                              
                                              $
                                              0.50
                                              
                                              
                                              $
                                              0.38Diluted
                                              
                                              
                                              0.53
                                              
                                              
                                              $
                                              1.08
                                              
                                              
                                              $
                                              0.49
                                              
                                              
                                              $
                                              0.37Year
      ended December 31, 2006Revenues
                                              
                                              $
                                              82,111
                                              
                                              
                                              $
                                              63,608
                                              
                                              
                                              $
                                              81,193
                                              
                                              
                                              $
                                              94,070Income
      from continuing operations before cumulative effect of accounting
      change:Portion
      applicable to owner’s interest
                                              
                                              $
                                              12,469
                                              
                                              
                                              $
                                              12,599
                                              
                                              
                                              $
                                              11,466
                                              
                                              
                                              $
                                              12,486Portion
      applicable to Class B members
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              2,751Portion
      applicable to Class A members
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              56Net
      income before cumulative effect of accounting change
                                              
                                              $
                                              12,469
                                              
                                              
                                              $
                                              12,599
                                              
                                              
                                              $
                                              11,466
                                              
                                              
                                              $
                                              15,293Net
      income before cumulative effect of accounting change per Class B common
      unit – basic and diluted
                                              
                                              $
                                              —
                                              
                                              
                                              $
                                              —
                                              
                                              
                                              $
                                              —
                                              
                                              
                                              $
                                              0.08Cumulative
      effect of accounting change
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              —
                                              
                                              
                                              
                                              6,355Net
      income
                                              
                                              $
                                              12,469
                                              
                                              
                                              $
                                              12,599
                                              
                                              
                                              $
                                              11,466
                                              
                                              
                                              $
                                              21,648
 
 ITEM
      9.
              CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
  None.
 
 ITEM
9A. CONTROLS AND PROCEDURES
 
 Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
 
 We
maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in our Securities Exchange Act of 1934
reports is recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms, and that such information is accumulated
and communicated to our management, including our Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.  In designing and evaluating the disclosure
controls and procedures, our management recognized that any controls and
procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and our
management necessarily was required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
  Under the
supervision of our Chief Executive Officer and Chief Financial Officer, we have
carried out an evaluation of the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this report.  Based
upon that evaluation, our Chief Executive Officer and Chief Financial Officer
concluded that, as of December 31, 2008, our disclosure controls and procedures
were effective at the reasonable assurance level.
  103
 Management’s
Report on Internal Control over Financial Reporting
 
 Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f).  Under the supervision and with the participation of
management, including our Chief Executive Officer and Chief Financial Officer,
we conducted an evaluation of the effectiveness of internal control over
financial reporting based upon criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control - Integrated
Framework (COSO framework).
 
 An
effective internal control system, no matter how well designed, has inherent
limitations, including the possibility of human error and circumvention or
overriding of controls and therefore can provide only reasonable assurance with
respect to reliable financial reporting.  Furthermore, effectiveness
of an internal control system in future periods cannot be guaranteed because the
design of any system of internal controls is based in part upon assumptions
about the likelihood of future events.  There can be no assurance that
any control design will succeed in achieving its stated goals under all
potential future conditions.  Over time certain controls may become
inadequate because of changes in business conditions, or the degree of
compliance with policies and procedures may deteriorate.  As such,
misstatements due to error or fraud may occur and not be detected.
 
 Based on
our evaluation under the COSO framework, management concluded that our internal
control over financial reporting was effective at the reasonable assurance level
as of December 31, 2008.  Grant Thornton, LLP, an independent
registered public accounting firm and auditors of our consolidated financial
statements, has issued an attestation report on the effectiveness of our
internal control over financial reporting as of December 31, 2008, which is
included herein.
 
 There
have been no changes in our internal control over financial reporting during the
fourth quarter of 2008 that have materially affected, or are reasonably likely
to materially affect, our internal control over financial
reporting.
  104
 
 REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 Board of
Directors and Unitholders
 Atlas
Energy Resources, LLC
 
 We have
audited Atlas Energy Resources, LLC (a Delaware limited liability company) and
subsidiaries internal control over financial reporting as of December 31, 2008,
based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Atlas Energy Resources, LLC’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal
Control over Financial Reporting. Our responsibility is to express an
opinion on Atlas Energy Resources, LLC’s internal control over financial
reporting based on our audit.
 
 We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
 
 A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
 
 In our
opinion, Atlas Energy Resources, LLC maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2008,
based on criteria established in Internal Control—Integrated
Framework issued by COSO.
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the accompanying consolidated balance sheets of
Atlas Energy Resources, LLC, (a Delaware limited liability company) and
subsidiaries, as of December 31, 2008 and 2007, and the related combined and
consolidated statements of income, comprehensive income, members' equity, and
cash flows for each of the three years in the period ended December 31,
2008and our
report dated March 2, 2009expressed an
unqualified opinion.
 
 /s/ GRANT
THORNTON LLP
 
 Cleveland,
Ohio
 March 2,
2009
  105
 
 ITEM
9B. OTHER
INFORMATION
 
 None.
 
 PART
III
 
 ITEM
10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
 
 The
information required by this item will be set forth in our definitive proxy
statement with respect to our 2009 annual meeting of unitholders.
  ITEM
11.  EXECUTIVE COMPENSATION
 
 The
information required by this item will be set forth in our definitive proxy
statement with respect to our 2009 annual meeting of unitholders.
  ITEM
12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
 
 The
information required by this item will be set forth in our definitive proxy
statement with respect to our 2009 annual meeting of unitholders.
 
 ITEM
13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTORINDEPENDENCE
  The
information required by this item will be set forth in our definitive proxy
statement with respect to our 2009 annual meeting of unitholders.
 
 ITEM
14.  PRINCIPAL ACCOUNTING FEES AND SERVICES
  The
information required by this item will be set forth in our definitive proxy
statement with respect to our 2009 annual meeting of
unitholders.
  106





PART IV





ITEM
      15.
            EXHIBITS
      AND FINANCIAL STATEMENT SCHEDULES





(a)The following
documents are filed as part of this report:





(1)
  Financial Statements





The
financial statements required by this Item 15 (a)(1) are set forth in Item
8.





(2)  Financial Statement
Schedules





No schedules are required to be
presented.





(3)   Exhibits:





Exhibit No.
                      
                      Description3.1
                      
                      Amended
      and Restated Limited Liability Company Agreement of Atlas Energy
      Resources, LLC(1)3.2
                      
                      Amendment
      No. 1 to Amended and Restated Operating Agreement of Atlas Energy
      Resources, LLC(2)3.3
                      
                      Certificate
      of Formation of Atlas Energy Resources, LLC(3)4.1
                      
                      Form
      of common unit certificate (included as Exhibit A to the Amended and
      Restated Limited Liability Company Agreement of Atlas Energy Resources,
      LLC)(1)10.1(a)
                      
                      Revolving
      Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating
      Company, LLC, its subsidiaries, J.P. Morgan Chase Bank, N.A., as
      Administrative Agent and the other lenders signatory thereto(2)10.1(b)
                      
                      First
      Amendment to Credit Agreement, dated as of October 25, 2007(4)10.2
                      
                      Contribution,
      Conveyance and Assumption Agreement, dated as of December 18, 2006, among
      Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy
      Operating company, LLC)(1)10.3
                      
                      Omnibus
      Agreement, dated as of December 18, 2006, between Atlas America, Inc. and
      Atlas Energy Resources, LLC(1)10.4
                      
                      Management
      Agreement, dated as of December 18, 2006, among Atlas Energy Resources,
      LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management,
      Inc(1)




107




10.5(a)
                  
                  Master
      Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas
      Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas
      America, Inc., Resource Energy, Inc. and Viking Resources Corporation(3)10.5(b)
                  
                  Natural
      Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline
      Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas
      Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corporation,
      Resource Energy, Inc. and Viking Resources Corporation(3)10.5(c)
                  
                  Amendment
      to Master Natural Gas Gathering Agreement and Natural Gas Gathering
      Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P.,
      Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource
      Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas
      Resources, Inc.(3)10.5(d)
                  
                  Amendment
      and Joinder to Gas Gathering Agreements, dated as of December 18, 2006,
      among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership,
      L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC,
      Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy
      Resources, LLC and Atlas Energy Operating Company, LLC(1)10.6(a)
                  
                  Omnibus Agreement, dated February
      2, 2000, among Atlas America, Inc., Resource Energy, Inc., Viking
      Resources Corporation, Atlas Pipeline Partnership, L.P., and Atlas
      Pipeline Partners, L.P.(3)10.6(b)
                  
                  Amendment
      and Joinder to Omnibus Agreement, dated as of December 18, 2006 among
      Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources,
      LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company,
      LLC(1)10.7
                  
                  Agreement
      for Services among Atlas America, Inc. and Richard Weber, dated April 5,
      2006(3)10.8
                  
                  Amended
      and Restated Long-Term Incentive Plan12.1
                  
                  Computation
      of Ratio of Earnings to Fixed Charges21.1
                  
                  Subsidiaries
      of Atlas Energy Resources, LLC23.1
                  
                  Consent
      of Independent Registered Accounting Firm23.2
                  
                  Consent
      of Independent Petroleum Consultants31.1
                  
                  Rule
      13(a)-14(a)/15d-14(a) Certification31.2
                  
                  Rule
      13(a)-14(a)/15d-14(a) Certification32.1
                  
                  Section
      1350 Certification32.2
                  
                  Section
      1350
Certification





(1)
                                Previously
      filed as an exhibit to our Form 8-K filed December 22,
      2006.(2)
                                Previously
      filed as an exhibit to our Form 8-K filed June 29,
2007.(3)
                                Previously
      filed as an exhibit to our registration statement on Form S-1 (Reg. No.
      333-136094).(4)
                                Previously
      filed as an exhibit to our Form 8-K filed October 26,
      2007.




108




SIGNATURES





Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.





ATLAS
      ENERGY RESOURCES, LLC(Registrant)Date:
      March 2, 2009
                  By:
                  /s/
      Edward E. CohenEdward
      E. CohenChairman
      and Chief Executive
Officer





Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant in the
capacities indicated as of March 2, 2009.





/s/ Edward E. Cohen
                
                Chairman
      and Chief Executive OfficerEdward
      E. Cohen/s/ Richard D. Weber
                
                President
      and Chief Operating OfficerRichard
      D. Weber/s/ Matthew A. Jones
                
                Chief
      Financial OfficerMatthew
      A. Jones/s/ Sean P. McGrath
                
                Chief
      Accounting OfficerSean
      P. McGrath/s/ Jonathan Z. Cohen
                
                DirectorJonathan
      Z. Cohen/s/ Walter C. Jones
                
                DirectorWalter
      C. Jones/s/ Ellen F. Warren
                
                DirectorEllen
      F. Warren/s/ Bruce M. Wolf
                
                DirectorBruce
      M. Wolf




109