Atlas Pipeline Partners 8-K Regulation FD Disclosure

Atlas Pipeline Partners, L.P.

September 2008 Investor Presentation

Exhibit 99.1

1

Forward Looking Statement

THE WORDS “BELIEVES, ANTICIPATES, EXPECTS”

AND SIMILAR EXPRESSIONS ARE

INTENDED TO IDENTIFY FORWARD LOOKING STATEMENTS.  

SUCH STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES, WHICH

COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED IN

THE FORWARD LOOKING STATEMENTS.

THE RISKS AND UNCERTAINTIES ARE DISCUSSED IN OUR ANNUAL REPORT ON FORM

10-K AND OUR QUARTERLY REPORT ON FORM 10-Q; PARTICULARLY THE SECTION

TITLED RISK FACTORS. READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE

ON THESE FORWARD LOOKING STATEMENTS, WHICH SPEAK ONLY AS OF THE DATE

HEREOF.

THE PARTNERSHIP UNDERTAKES NO OBLIGATIONS TO PUBLICLY RELEASE THE

RESULTS OF ANY REVISIONS TO FORWARD LOOKING STATEMENTS, WHICH MAY BE

MADE

TO

REFLECT

EVENTS

OR

CIRCUMSTANCES

AFTER

THE

DATE

HEREOF

OR

TO

REFLECT THE OCCURRENCE OF UNANTICIPATED EVENTS.

2

Management Presenters

Edward Cohen

Chairman & Chief Executive Officer

Robert Firth

President, Atlas Pipeline Mid-Continent

Matthew Jones

Chief Financial Officer

Glenn Powell

Chief Operating Officer, Atlas Pipeline Mid-Continent

Michael Staines

President

David Hall

Chief Financial Officer, Atlas Pipeline Mid-Continent

3

Appalachian Gathering System

Located in Appalachia Basin of

eastern Ohio, western New York,

western Pennsylvania and

northeastern Tennessee

Over 1,600 mi. of active gathering

pipeline; 6,900+ wells serviced

New York

West

Virginia

Pennsylvania

New York

West

Virginia

Pennsylvania

Elk City/Sweetwater

Gathering &

Processing System

Located in Anadarko Basin of

Oklahoma

Over 560 receipt points serviced

2 processing facilities/1 treating

facility

450 MMcfd

inlet capacity

Prentiss

Treating

Facility

Elk City Plant

NOARK Pipeline System

Ozark Gas Transmission –

565-

mile FERC-regulated pipeline

running from Oklahoma to

Missouri

Ozark Gas Gathering –

365-mile

non-FERC-regulated natural gas

gathering system

Increasing capacity to 500

MMcfd

by adding compression

Chaney Dell Gathering &

Processing System

Located in Anadarko Basin

260 MMcfd

processing capacity

~ 3,500 miles of gathering pipeline

Expected drilling of 250-300 wells

annually into the system

Midkiff/Benedum

Gathering

& Processing System

Located in Spraberry

Trend of

Permian Basin

140 MMcfd

processing capacity

2,500 miles of gathering pipeline

APL Asset Portfolio –

Diversified Strategy

Velma Gathering

& Processing System

1,080 mi. of active gathering

pipeline

Approx. 700 receipt points

serviced

100 MMcfd

capacity processing

facility

Velma Plant

Sweetwater

Plant

4

565 miles of FERC-regulated interstate pipeline

Over 9,500 miles of active natural gas gathering

pipelines

7,900 miles of gathering lines in Mid-

Continent

1,600 miles of gathering lines in Appalachia

Approx. 750 MMcfd

of processing plant capacity

200 MMcfd

in treating facility capacity

LQA Adjusted EBITDA of $304 million

Average Daily System Volumes

APL Operations Overview

Atlas Pipeline Operates:

-

200

,000

400

,000

600

,000

800,000

1,000,000

1,200,000

1,400,000

2004

2005

2006

2007

Q208

Velma

Appalachia

Elk City

NOARK

Chaney Dell

Midkiff/Benedum

5

Anadarko Acquisition –

A Year Later

Atlas Pipeline completed the acquisition of control of the Chaney Dell and

Midkiff/Benedum

systems in July 2007

Transformative transaction nearly tripled operating cash flow for the Partnership

As a result, APL has become the primary competitor and service provider of choice in

each of its basins in which it operates

WestOK

system (Chaney Dell) is now connected to the Elk City/Sweetwater system

via a 110 mile pipeline to provide best in class optionality

to producers in those

regions

WestTX

system (Midkiff/Benedum) continues to be a formidable gathering and

processing service provider in the Permian Basin

Increased scale of overall operations has provided for growth opportunities in other

business units

Elk City/Sweetwater system now benefits from production in Anadarko Basin

(WestOK); increased market share due to scale allows for future expansion

Enhanced service reputation with producers has led to expansion projects at Velma

system (Madill pipeline) and NOARK interstate pipeline (compression expansion;

proposed extension projects)

6

Highlighted Organic Growth Investments

Expected Completion

Reactivation of Chaney Dell 30 MMcfd

cryogenic facility

Now active

105 mile, 16”

Pipeline connecting Chaney Dell system to Elk

City/Sweetwater system

Completed

Expansion of capacity on Sweetwater processing facility

from 120 MMcfd

to 180 MMcfd

Completed

Expand throughput capacity on NOARK pipeline via added

compression from 400 MMcfd

to 500 MMcfd

October 2008

120 MMcfd

“9 mile”

processing facility to be constructed along

Chaney Dell to Elk City/Sweetwater pipeline

December 2008

70 mile, 16”

pipeline from Madill, OK to Velma facility to gather and

produce gas from the Ardmore Basin

March 2009

Midkiff

consolidator plant–

150 MMcfd

cryogenic facility

(replaces

existing

100

MMcfd

legacy

plant)

Mid -

2009

Solid Growth from Organic Initiatives

Targeted EBITDA Multiple of 4.5x -

5.5x

Mid-Continent Update

*

*

*

*

*

8

Chaney Dell System –

Strong Competitive Position

Two gathering systems with approximately

3,470 miles of gathering pipeline located in

north central Oklahoma’s Anadarko Basin

System acts as a primary choice for takeaway

and processing service for producers in the

region

Three processing plants with total processing

capacity of 260 Mmcf/d; systems currently

running near full capacity

Well-established customer base provides strong

growth potential

Long-term contracts with largest producers on

system: Cheaspeake (5 years) and SandRidge

(10 years)

Connecting pipeline to the Elk City/Sweetwater

system allows for further processing capacity

out of the Anadarko Basin and gives optionality

to producers

Primary producers on system:

•

Chesapeake, SandRidge, GAW

Oil, Jack Exploration, Altex

Resources

Competing processors in region:

•

DCP, Mustang, Hiland, OneOK

9

Largest gas processor in the Spraberry

Trend of the Permian Basin in west

Texas; total processing capacity of ~ 150

MMcf/d

Long-term commitment from Pioneer

through 2022

Allows clear sight to growth     

through stable production

APL

will

replace

the

existing

Midkiff

facility with a new 150 MMcf/d

cryogenic

consolidator plant by mid-2009

Midkiff/Benedum

–

Solid Presence in New Region   

Primary producers on system:

•

Pioneer,  Endeavor Energy,

Henry Petroleum, Mariner Energy

Competing processors in region:

•

Southern Union, DCP, Targa, JL

Davis

10

Midkiff/Benedum

–

New Consolidator Facility

Benedum

PlantPlant

WestTX

Gas Gathering

& Processing System

Midkiff

Plant

Benedum

The

Current

Midkiff

Facility

Proposed Form of The

Midkiff

Facility

(Sweetwater plant

shown)

APL will construct a 150 MMcf/d

consolidation

plant

at

the

Midkiff

processing facility

The new plant will be a cryogenic

facility

that

will:

o

Expand the existing capacity of the

Midkiff

facility by 40 MMcf/d

o

Greatly improve efficiencies and liquid

recoveries, notably ethane

o

Reduced O&M and maintenance capital

expense

Approximate  gross cost of $45 million;

Pioneer will share their appropriate

portion of the cost based on ownership

11

Elk City/Sweetwater Systems –

Established Presence in a Growing Market

Primary producers on system:

•

Chesapeake, TX Southwest,

ConocoPhillips, Sanguine,

Newfield

Competing processors in region:

•

Enbridge, Enogex, Penn Virginia,

MarkWest

Newly expanded gathering and

processing system servicing

western OK and the TX panhandle

Total processing capacity is now at

310 MMcf/d

following Sweetwater

expansion

Gaining market share from

surrounding competition due to

APL’s high quality of service and

options

provided

to

producers

to

process their gas

Constructing new, cryogenic facility

along 110 mile connecting pipeline

to Chaney Dell

12

Elk City/Sweetwater –

9-Mile Plant Project

APL is constructing a new 120 Mmcf/d

cryogenic gas processing facility (“9-Mile plant”) in Dewey

County, OK; plant will be an asset in the Elk City/Sweetwater business unit

9-Mile

plant

will

further

expand

the

optionality

amongst

the

Elk

City/Sweetwater

&

Chaney

Dell

systems; total processing capacity between both systems will be ~ 700 Mmcf/d

once plant is completed

New facility will be constructed along the recently completed 110 mile connecting pipeline; APL will now

have access to production in fairway between the two existing systems in western OK

Specifications and efficiencies should resemble original Sweetwater facility

13

Elk City/Sweetwater –

9-Mile Plant Project (cont.)

New 9-Mile facility will access

production between the Elk

City/Sweetwater & Chaney Dell

systems

9-Mile will also handle overflow gas

from either adjoining system

Once completed, the infrastructure

across western and northwestern OK

is expected to continue to win new

business from existing and new

customers

Breadth of expanded OK operations

has made APL the service provider of

choice in the region

APL is well-positioned to take

advantage of production growth in

surrounding areas

Elk City/Sweetwater

system

Chaney Dell system

9-Mile facility

14

Velma System –

Poised for Future Growth

Primary producers on system:

•

Chesapeake, Mack Energy,

Chevron, Noble

Competing processors in region:

•

DCP, Enogex, OneOK, Carrera

100 Mmcf/d processing facility

Planned 70 mile, 16”

pipeline to be

built from Madill, OK to Velma;

pipeline will gather gas from the

Ardmore Shale region

15

Velma System –

Madill Pipeline Project

Proposed Pipeline Route & Placement of  Compressor

Stations

16

Map Legend:

OGT Interstate

Pipeline

OGG Gathering

System

Oklahoma

Arkansas

Ozark Gas Gathering (OGG)

365-mile natural gas gathering

system

13 compressor stations

Gathering assets out of FERC

jurisdiction, allowing for

negotiated rates

Ozark Gas Transmission (OGT)

565-mile FERC-regulated natural

gas interstate pipeline

Total throughput capacity of 400

MMcfd

Approximately 30 supply and

delivery interconnections

2 compressor stations

Accesses prolific Arkoma Basin

and developing Fayetteville Shale

Missouri

NOARK Pipeline System –

Servicing the Growing Fayetteville Shale

17

Hedging Policy

Commodity

Specifics

Year 1

Year 2

Year 3

Natural Gas Liquids

- Long Position

- Ethane Swaps, Collars and/or Puts

- Value Hedged

- Propane Swaps, Collars and/or Puts

- Butane+ Swaps, Collars and/or Puts on Butane+ or Crude Oil

Condensate

- Long Position

- Crude Oil Swaps, Collars and/or Puts

- Volumes Hedged

Natural Gas

- Short and Long Position

- Volumes Hedged

- Natural Gas Swaps, Collars and/or Puts and Calls

(1)

Based on equity volumes of long natural gas associated with percentage of proceeds contracts.

70%

(1)

50%

(1)

25%

(1)

- Hedge short position on a Btu basis equivalent to the

  Company's hedged NGL position to lock in a frac spread

15%

60%

40%

20%

50%

33%

The following chart shows APL’s minimum hedging objectives on a rolling 36-month basis.

APL plans to opportunistically layer on additional hedges under favorable market conditions

(2)

The

2010

hedge

positions

for

natural

gas

liquids

and

condensate

represent

sold

crude

oil

call

options.

A

detail

of

APL’s

current hedge position is shown in the Appendix to this presentation

Current Hedge Percentages (on value basis)

BAL08

2009

2010

Natural Gas (net)

77%

77%

50%

Natural Gas Liquids

61%

58%

56%

(2)

Condensate

80%

53%

63%

(2)

Appalachian Update

*

*

*

*

*

*

*

*

*

*

*

19

APL owns and operates approximately

1,600 miles of natural gas gathering

pipelines in western PA, western NY,

eastern OH and northeastern TN

Over 6,900 producing wells delivering

natural gas into Appalachian system

Q2 2008 throughput volumes of ~ 84

MMcfd (~38 MMcfd at IPO in 2000)

874 wells connected in 2007; connected

711 wells in 2006

Atlas Energy Resources, LLC (“ATN”) is

among the top 10 most active drillers for

natural gas in U.S.

ATN controls ~ 500 Bcfe of natural gas

reserves in Appalachia as of 12/31/07

Appalachian System

Operational Footprint

Corporate Offices

District Offices & Satellite Offices

Gathering System

WV

PA

OH

Pittsburgh

Fayette

Jackson

Center

Uniontown

New

Philadelphia

Cumberland

Deerfield

Mayville

NY

VA

Corporate Offices

District Offices & Satellite Offices

Gathering System

Corporate Offices

District Offices & Satellite Offices

Gathering System

WV

PA

OH

Pittsburgh

Fayette

Jackson

Center

Uniontown

New

Philadelphia

Cumberland

Deerfield

Mayville

NY

VA

WV

PA

OH

Pittsburgh

Fayette

Jackson

Center

Uniontown

New

Philadelphia

Cumberland

Deerfield

Mayville

NY

VA

Appalachian Operations –

Well-Established System Allows for Significant Growth 

20

Substantially all of APL’s throughput in the

Appalachian Basin is owned and/or controlled by

Atlas Energy

ATN currently has over 550,000 acres in its

Marcellus Shale leasehold position, including

280,000 acres in the “core”

development area in

SW Pennsylvania

ATN has drilled 79 wells and completed 69 wells in

the emerging Marcellus Shale of Western

Pennsylvania (as of 8/5/08); current unrisked

reserve potential of 4-6 Tcf

Results from ATN’s vertical wells have been the best

in the play by a significant margin due to the

favorable geology and high-pressured gas in its

position

Vertical results yield encouraging potential for

horizontal drilling development in ATN’s Marcellus

acreage

Atlas Pipeline will fully benefit from all of ATN’s

production growth in the years to come

Atlas Energy’s Marcellus Shale Position Creates Unique Opportunity for APL

LEWIS

RUN

WEST VIRGINIA

21

21

APL has Already Built out a Gathering System in SW PA with Significant

Takeaway Capacity to Handle ATN’s Future Marcellus Production

Major Interstate Pipelines in SW PA

Highlights

APL owns approximately 1,600 miles of gathering

systems in Southwestern Pennsylvania

All of Atlas’s production in SW PA is delivered into

interstate pipelines and has never been subject to

curtailment

APL currently has 100 MMcf/d of capacity in this

gathering system, of which 50 MMcf/d is currently being

utilized; plans are to double available capacity by the

end of 2008, and then double the capacity again by the

end of 2009; APL will provide capex funding for

infrastructure expansion

Between Texas Eastern (Spectra), Dominion

Transmission, Equitable Transmission, and Columbia

Transmission, approximately 2 Bcf of incremental

takeaway capacity exists on interstate pipelines within

Atlas’s SW PA acreage 

Financial Overview

*

*

*

*

*

*

23

APL Capitalization

At

the

end

of

the

second

quarter

2008,

APL

had

$20

million

drawn

against

its

$380

million

revolving

credit

facility

% of

($ millions)

June 30, 2008

Capitalization

Cash and Cash Equivalents

161.4

$                     

Senior Secured Revolving Credit Facility

20.0

$                       

0.8%

Senior Secured Term Loan

707.2

$                     

28.8%

Senior Unsecured Notes

544.3

$                     

22.1%

Total Debt

1,271.5

$                  

51.7%

Total Partners' Capital

1,051.5

$                  

42.8%

Addback: Other Comprehensive Loss balance

135.2

$                     

5.5%

Total Adjusted Partners' Capital

1,186.7

$                  

48.3%

Total Adjusted Capitalization

2,458.2

$                  

100.0%

Credit Metrics

Total Debt / Book Adjusted Capitalization

51.7%

Total Debt / Adjusted EBITDA (max 5.25x)

4.2x

Adjusted EBITDA / Cash Interest Expense (min 2.75x)

4.2x

Statistics

Adjusted EBITDA

(1)

304.0

$                     

Cash Interest Expense

(2)

72.4

$                       

(1) Represents 2nd quarter 2008 annualized Adjusted EBITDA of $76 million

(2) Represents 2nd quarter 2008 annualized Interest Expense of $18.1 million excluding deferred financing cost amortization

24

$2.39

$2.67

$3.16

$3.40

$3.57

$4.00

$4.37

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

2003

2004

2005

2006

2007

1H08 +

2H08

guidance

mid point

2009E

midpoint

$118

$177

$215

$256

$304

$0.0

$65.0

$130.0

$195.0

$260.0

$325.0

2004

2005

2006

2007

LQA

6/30/08

Pro Forma Adjusted EBITDA Contribution & Distribution Growth

($ in millions)

Pro Forma Adjusted EBITDA

(1)

(1) Assumes pro forma ownership of Anadarko as of 1/1/04.

Distribution History

25

($ millions)

Q208 Adjusted EBITDA

$76.0

Less:

Q208 Cash interest expense   

(18.1)

Q208 maintenance capital expenditures

(2.0)

Q208 Distributable Cash Flow

$55.9

Q208 Cash Distributions (1)

$45.1

Coverage Ratio (1)

Annualized Q208 Distribution per Common Unit

1.2x

$3.84

Distributable cash flow per unit estimate for 2H08 after 1.3x coverage

$2.00 - $2.20

Distributable cash flow per unit estimate for FY09 after 1.3x coverage

$4.25 - $4.50

Cash Flow Generation

2008 Cash Flow Enhancements

Increased throughput:

Sweetwater expansion

(incremental 60MMcf/d)

Connected Chaney Dell system to Elk City / Sweetwater system

Throughput expansion from NOARK

Cash flow benefit from termination of crude oil costless collars

associated with ethane and propane

Beneficiary of increased drilling programs in prolific basins

Increased efficiency from compression improvement and application of best practices at Chaney Dell and

Midkiff/Benedum

assets

Increased capacity utilization

(1) Excludes impact from equity issuance of 7.1 million APL common units in late June 2008

26

Commodity Price Sensitivity

Based on average recent commodity prices (and holding all other variables constant), APL estimates the generation

of 2009 distributions per LP unit of approximately $4.25 with a distribution coverage ratio of 1.3x

Based on

15%

increase

of

average

recent

commodity

prices

(and

holding

all

other

variables

constant),

APL

estimates

the generation of 2009 distributions per LP unit of approximately $4.58 with a distribution coverage ratio of 1.3x

Based on

15%

reduction

of

average

recent

commodity

prices

(and

holding

all

other

variables

constant),

APL

estimates the generation of 2009 distributions per LP unit of approximately $4.25 with a distribution coverage ratio of 1.1x

Based on

30%

reduction

of

average

recent

commodity

prices

(and

holding

all

other

variables

constant),

APL

estimates the generation of 2009 distributions per LP unit of approximately $4.04 with a distribution coverage ratio of 1.0x

Based on

45%

reduction

of

average

recent

commodity

prices

(and

holding

all

other

variables

constant),

APL

estimates the generation of 2009 distributions per LP unit of approximately $3.35 with a distribution coverage ratio of 1.0x

If the correlation between the price of crude oil and natural gas liquids were to return to 60%, FY09 distributions per unit 

would be approximately $4.56

with a distribution coverage ratio of 1.3x assuming the “15% price decrease”

scenario above

(1)  Average commodity prices from July 1, 2008 to September 10, 2008 (prior to price effects from Hurricane Ike).

Recent

15%

15%

30%

45%

Average

Price

Price

Price

Price

Prices

(1)

Increase

Decrease

Decrease

Decrease

Commodity

Price

Assumptions

Natural Gas Liquids (per gallon)

1.53

$          

1.76

$          

1.30

$          

1.07

$        

0.84

$         

Crude Oil (per barrel)

122.65

$      

141.05

$      

104.25

$      

85.86

$      

67.46

$       

Natural Gas (per mcf)

9.39

$          

10.80

$        

7.98

$          

6.57

$        

5.17

$         

NGL to Crude Oil Price Correlation

52%

52%

52%

52%

52%

Estimated 2009 APL Distribution per common unit

4.25

$          

4.58

$          

4.25

$          

4.04

$        

3.35

$         

Estimated Distribution coverage ratio

1.3x

1.3x

1.1x

1.0x

1.0x

Questions and Answers

*

*

*

*

*

*

Appendix

*

*

*

*

*

*

29

Reconciliation to Adjusted EBITDA & Distributable Cash Flow

Three Months Ended

June 30,

2008

2007

Reconciliation of net loss

to other non-GAAP measures:

Net loss................................................................................................................

$   

(278,671)

$     (20,816)

Depreciation and amortization

...............................................................................

26,196

6,671

Interest expense

...................................................................................................

19,385

7,327

EBITDA

........................................................................................................

(233,090)

(6,818)

Non-cash derivative expense

..............................................................................

181,147

28,549

Non-recurring cash derivative early termination expense

....................................

116,125

–

Non-recurring crude oil to natural gas liquids price

correlation impact

...............................................................................................

10,653

–

Non-cash compensation expense (income).............................................................

1,195

2,481

Adjusted EBITDA

...........................................................................................

76,030

24,212

Interest expense

....................................................................................................

(19,385)

(7,327)

Amortization of deferred

financing costs

............................................................

1,929

534

Preferred unit dividends.........................................................................................

(650)

–

Maintenance capital expenditures..........................................................................

(2,045)

(700)

Distributable cash flow

....................................................................................

$     

55,879

$      16,719

30

Reconciliation to Adjusted EBITDA & Distributable Cash Flow (cont.)

2004

2005

2006

2007

Reconciliation of net income to non-GAAP measures

Net income (loss)

110,721

$       

146,221

$       

162,757

$       

(138,879)

$      

Effect of prior period items

(1,090)

1,090

Interest expense

2,301

14,175

24,572

99,628

Depreciation and amortization

4,471

13,954

22,994

78,019

Unrecognized economic impact of Chaney Dell and

    Midkiff/Benedum acquisition

-

-

-

10,423

EBITDA

117,493

173,260

211,413

49,191

Adjustments to reflect cash impact of derivatives

(210)

(954)

(2,316)

169,424

Non-cash compensation expense (income)

700

4,672

6,315

36,320

Other non-cash items

-

-

-

1,414

Adjusted EBITDA

117,983

$       

176,978

$       

215,412

$       

256,349

$       

Pro Forma years ended December 31,

31

Current APL Hedge Positions

Ethane

Sales Options

Production Period

Average

Ended December 31,

Volumes

Strike Price

Option Type

(gallons)

(per gallon)

2008 (4

th

quarter)

180,000

$

1.79

Puts purchased

2009

387,000

$

0.68

Puts purchased

Propane

Sales Options

Production Period

Average

Ended December 31,

Volumes

Strike Price

Option Type

(gallons)

(per gallon)

2008 (4

th

quarter)

213,000

$

1.48

Puts purchased

2009

555,000

$

1.40

Puts purchased

Natural Gas Liquids Sales –

Fixed Price Swaps

Production Period

Average

Ended December 31,

Volumes

Fixed Price

(gallons)

(per gallon)

2008

(2

nd

half)

14,868,000

$

0.697

2009

8,568,000

$

0.746

32

Current APL Hedge Positions (cont.)

Crude Oil Sales Options (associated with NGL volume)

Production Period

Associated

Average

Ended

Crude

NGL

Crude

December 31,

Volume

(barrels)

Volume

(gallons)

Strike Price

(per barrel)

Option Type

2008 (2

nd

half)

812,400

46,513,740

$

66.71

Puts purchased

2008 (2

nd

half)

(126,000)

11,219,040

$    127.55

Puts sold

(1)

2008 (2

nd

half)

(126,000)

(11,219,040)

$    140.00

Calls purchased

(1)

2008 (2

nd

half)

946,800

51,529,968

$

80.13

Calls sold

2009

1,584,000

85,038,534

$      80.00

Puts purchased

2009

(304,200)

27,085,968

$    126.05

Puts sold

(1)

2009

(304,200)

(27,085,968)

$    143.00

Calls purchased

(1)

2009

2,121,593

114,071,990

$

81.01

Calls sold

2010

3,127,500

202,370,490

$

81.09

Calls sold

2010

(360,000)

(24,116,400)

$    120.00

Calls purchased

(1)

2011

606,000

32,578,560

$

95.56

Calls sold

2011

(132,000)

(7,595,280)

$    120.00

Calls purchased

(1)

2012

450,000

24,192,000

$

97.10

Calls sold

2012

(96,000)

(5,523,840)

$    120.00

Calls purchased

(1)

Natural Gas Sales –

Fixed Price Swaps

Natural Gas Basis Sales

Production

Period

Average

Ended December 31,

Volumes

Fixed Price

(mmbtu)

(2)

(per mmbtu)

(2)

2008

(2nd

half)

2,742,000

$

(0.744)

2009

5,724,000

$

(0.558)

2010

4,560,000

$

(0.622)

2011

2,160,000

$

(0.664)

2012

1,560,000

$

(0.601)

Production Period

Average

Ended

December 31,

Volumes

Fixed Price

(mmbtu)

(2)

(per mmbtu)

(2)

2008

(2

nd

half)

2,742,000

$

8.823

2009

5,724,000

$

8.611

2010

4,560,000

$

8.526

2011

2,160,000

$

8.270

2012

1,560,000

$

8.250

33

Current APL Hedge Positions (cont.)

Natural Gas Purchases –

Fixed Price Swaps

Production Period

Average

Ended December 31,

Volumes

Fixed Price

(mmbtu)

(2)

(per mmbtu)

(2)

2008

(2

nd

half)

8,130,000

$

9.001

(3)

2009

15,564,000

$

8.680

2010

8,940,000

$

8.580

2011

2,160,000

$

8.270

2012

1,560,000

$

8.250

Natural Gas Basis Purchases

Production Period

Average

Ended December 31,

Volumes

Fixed Price

(mmbtu)

(2)

(per mmbtu)

(2

)

2008

(2

nd

half)

8,130,000

$

(1.114)

2009

15,564,000

$

(0.654)

2010

8,940,000

$

(0.600)

2011

2,160,000

$

(0.700)

2012

1,560,000

$

(0.610)

Crude Oil Sales

Production Period

Average

Ended December 31,

Volumes

Fixed Price

(barrels)

(per barrel)

2008

(2

nd

half)

25,200

$

60.427

2009

33,000

$

62.700

Crude Oil Participating Swaps for NGLs

Production Period

Associated

Average

Ended

Crude

NGL

Crude

December 31,

Volume

(barrels)

Volume

(gallons)

Strike Price

(per barrel)

Option Type

2008 (2nd

half)

126,000

11,219,040

$     137.00

Participating swaps

34

Current APL Hedge Positions (cont.)

Crude Oil Sales Options

Production Period

Average

Ended December 31,

Volumes

Strike Price

Option Type

(barrels)

(per barrel)

2008 (2

nd

half)

98,400

$65.610

Puts purchased

2008 (2

nd

half)

138,000

$78.055

Calls

sold

2009

168,000

$90.000

Puts purchased

2009

306,000

$80.017

Calls sold

2010

234,000

$83.027

Calls sold

2011

72,000

$87.296

Calls sold

2012

48,000

$83.944

Calls sold

___________________________

(1)

Puts sold and calls purchased in 2008 through 2012

represent options

entered into by the

Partnership as offsetting positions for the calls sold related to ethane and propane production.

These offsetting positions were entered into to limit the loss which could be inc

urred

if crude oil

prices continued to rise.

(2)

Mmbtu

represents million British Thermal Units.

(3)

Includes the Partnership’s premium received from its sale of an option for it to sell 468,000 mmbtu

of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.