AHD Atlas Energy L P

Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL”, “Atlas Pipeline”, or the “Partnership”) today reported adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), a non-GAAP measure, of $42.9 million in the fourth quarter of 2010, a decrease of 3%, as compared to $44.3 million in the fourth quarter of 2009. Adjusted EBITDA for the fourth quarter of 2009 includes $9.7 million related to Elk City, which was sold in September 2010. Excluding Elk City’s contribution to 2009 fourth quarter results, Adjusted EBITDA increased 24% versus same period last year. Excluding the historical impact of Elk City, Adjusted EBITDA was higher for the quarter and full year 2010 compared to last year’s fourth quarter and 2009 full year primarily due to higher realized natural gas liquids (“NGL”) and condensate prices as well as approximately 12% gathered volume growth across the existing business. Net loss was $10.6 million for the fourth quarter of 2010 compared with a net loss of $35.1 million for the prior year fourth quarter.

For the full year 2010, Adjusted EBITDA was $209.8 million, an increase of 20% over full year 2009 Adjusted EBITDA of $174.8 million. Net income was $280.4 million for the full year 2010, versus net income of $62.7 million for the prior year. Adjusted EBITDA excludes gains and losses from asset sales outside the ordinary course of business, option premium expense and non-cash items that impact net income. The Partnership believes this measure provides a more accurate comparison of the operating results for the periods presented.

Distributable Cash Flow, a non-GAAP measure, was $25.2 million for the fourth quarter, a 175% increase compared to the fourth quarter of 2009 Distributable Cash Flow of $9.2 million. For the full year 2010, Distributable Cash Flow was $106.8 million, an increase of 166% over the full year 2009 Distributable Cash Flow of $40.1 million. The increase was attributed to Adjusted EBITDA discussed above and lower cash interest expense for the fourth quarter and full year of 2010 offset by increased maintenance capital expenditures. Distributable Cash Flow per average common limited partner unit for the quarter was $0.47 and for full year 2010 it was $2.01.

On January 25, 2011, the Partnership declared a distribution for the fourth quarter of 2010 of $0.37 per common limited partner unit to holders of record on February 7, 2011, and payable on February 14, 2011. This distribution represents Distributable Cash Flow coverage of 1.3x for the fourth quarter of 2010. A reconciliation of non-GAAP measures, including Adjusted EBITDA and Distributable Cash Flow, is provided within the financial tables of this release.

On February 17, 2011, the Partnership completed the sale of its 49% interest in Laurel Mountain Midstream, LLC (Laurel Mountain) to Atlas Energy Resources, LLC, a wholly owned subsidiary of Atlas Energy, Inc., for $403 million, excluding post-closing adjustments. Laurel Mountain owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in the northeastern United States. At the time of the sale, the Partnership’s general partner was an indirect subsidiary of Atlas Energy, Inc.

“We are pleased to report a strong finish to 2010. Our successful quarter was categorized by overall volume growth across our business coupled with a better pricing environment for our liquids and condensate products. Additionally, we have executed on activities that are going to materially contribute to our unitholder’s distributions in 2011. First, we have added to our risk management book securing over 70% of our margin for 2011 at attractive commodity price levels. Secondly, last Friday we announced the closing of our sale of the Partnership’s interest in our Laurel Mountain joint venture for $403 million to Atlas Energy, which has since become part of Chevron. Lastly, the proceeds will create additional liquidity and flexibility to a balance sheet that is already one of the strongest in the industry. This flexibility is going to allow the Partnership to utilize its balance sheet and add to an already increasing cash flow stream for our investors; as there is significant opportunity to grow cash flow from strategic assets. The resulting accretion should increase distributions to a level that are considerably higher than currently realized. As we look back on 2010, it was clearly a transformational year for Atlas Pipeline and we intend to keep the momentum going for 2011. We thank all of our stakeholders for their support.” stated Eugene Dubay, Chief Executive Officer of the Partnership.

* * *

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $277.0 million as of December 31, 2010, up $232.1 million from December 31, 2009. The Partnership intends to immediately reduce the amount outstanding on the revolving credit facility to a zero balance, making the full $350 million available, less outstanding letters of credit. Total debt outstanding was reduced to $566.0 million at December 31, 2010, from $1,254.2 million at December 31, 2009, a decrease of $688.2 million. The following table summarizes the Partnership’s total liquidity and debt balance at December 31, 2010 along with the impact of the sale of Laurel Mountain. The Partnership will immediately use a portion of the proceeds to repay existing indebtedness under our revolving credit facility, with the remaining proceeds in cash and cash equivalents (in thousands):

                  Pro Forma December 31, 2010 December 31, 2010 Impact of Laurel Mountain Sale Balance Impact Balance Cash and cash equivalents $ 164 $ 343,486 $ 343,650 Investment in joint venture 153,358 (153,358 ) –   Current portion of long-term debt 210 – 210 Revolving credit facility 70,000 (70,000 ) – 8.125% Senior notes – due 2015 272,181 – 272,181 8.750% Senior notes – due 2018 223,050 – 223,050 Other 533 – 533 Total debt $ 565,974 $ (70,000 ) $ 495,974   Liquidity (defined above) $ 276,947 $ 413,486 $ 690,433 Net debt (Total debt less cash equiv.) $ 565,810   $ 152,324  

* * *

Capital Deployment and Balance Sheet Opportunities

The closing of the Laurel Mountain transaction will give the Partnership substantial flexibility as it relates to its capital structure and operational expansion projects going forward. The Partnership has reviewed its debt structure and as a result, intends to pay down the outstanding balance on its revolving credit facility and to retire some of its Senior Notes pursuant to the terms of the indentures. The Partnership expects to experience interest savings of approximately $24 million annually which, as a positive direct impact to Distributable Cash Flow, would result in a DCF per unit increase of $0.45 annually or $0.11 per quarter, a 23% increase over the fourth quarter of 2010. Additionally, the Partnership is currently evaluating meaningful organic expansion opportunities at all three of its systems as expansion will be required to serve the Partnership’s producing customers as they expand their drilling programs behind the Partnership’s systems in 2011.

* * *

Risk Management

The Partnership continues to enhance its risk management portfolio. As of February 21, 2011, the Partnership has natural gas, natural gas liquids and condensate hedges in place for the remainder of 2011, including hedges in place for approximately 72% of associated margin value for 2011. In addition to this coverage, some protection has also recently been added for 2012. Counterparties to the Partnership’s risk management activities consist primarily of investment grade commercial banks that are lenders under the Partnership’s credit facility, or affiliates of such banks. A table summarizing our risk management portfolio is included in this release.

* * *

Operating Results

Gross margin from continuing operations was $60.5 million for the fourth quarter 2010 and $210.6 million for the full year 2010, compared to $51.2 million and $163.7 million for the prior year periods, respectively. Gross margin includes natural gas and liquids revenues and transportation, compression and other fees, less purchased product costs and non-cash gains (or losses). The increase in gross margin was primarily due to increased commodity prices, along with increased volumes on the Midkiff/Benedum and Velma systems. Year-over-year volume increases on Midkiff/Benedum are a direct result of the completion of the Partnership’s Consolidator Plant to support additional development drilling in the Permian Basin. Volumes on the Velma system increased due to production added on the new Madill to Velma gathering system. Volumes on our Chaney Dell system have increased 9.9% since the first quarter of 2010, primarily related to our expansion into Kansas and increased producer activity in the area.

Midkiff/Benedum

The Midkiff/Benedum system’s average natural gas processed volume was 169.4 million cubic feet per day (“Mmcfd”) and 163.5 Mmcfd for the fourth quarter and full year 2010, respectively, compared with 150.1 Mmcfd and 149.7 Mmcfd for the prior year comparable quarter and prior year, respectively. Average gross NGL production volumes increased to 27,110 barrels per day (“bpd”) and 26,678 bpd for the fourth quarter and full year 2010, respectively, up 23.1% and 25.5% when compared to the fourth quarter and full prior year, respectively. Increased volumes are primarily due to the completion of the new Consolidator Plant, which processes gas in the growing Spraberry and Wolfberry Trends. The plant offers increased capacity and higher ethane and propane recoveries over the legacy facility. The Partnership expects volumes on this system to continue to increase as its partner, Pioneer Natural Resources Company (NYSE: PXD), continues to pursue its drilling plan for 2011 and beyond. The Partnership is also seeing significant growth in natural gas volumes from other producers in the Spraberry and Wolfberry Trends, including COG Operating, LLC, and Endeavor Energy Resources, LP.

Chaney Dell

The Chaney Dell system had average NGL production of 14,204 bpd, which represents a 9.6% increase for the fourth quarter 2010 from the prior year comparable period, and 12,395 bpd, which represents a 7.6% reduction for the full year 2010 from 2009. The Partnership completed the Woolsey expansion of its Chaney Dell system into Kansas during June 2010, on-time and on-budget, and experienced an increase in processed gas volumes due to this project, as well as increased production from other producers on the system, including Chesapeake Energy Marketing, Inc. and Sandridge Exploration and Production, LLC. The Partnership expects volumes to continue to increase in 2011 as volumes from Kansas continue to be added to the system.

Velma

The Velma system’s average natural gas processed volume was 87.7 Mmcfd and 78.6 Mmcfd for the fourth quarter and full year 2010, respectively, an increase of approximately 15.9% and 6.3% compared with the comparable quarter and full year in the prior year, respectively. The increase is primarily due to new production gathered on the Madill to Velma pipeline system. Gathered volumes were up 16.6 Mmcfd, or 21.4% compared to the same quarter last year, and up 8.1 Mmcfd, or 10.6% compared to prior year. Average NGL production increased to 10,608 bpd and 9,218 bpd, for the fourth quarter and full year 2010, respectively, up approximately 25.5% and 12.0 %, compared to 8,450 bpd and 8,232 bpd for the prior year fourth quarter and prior year due to the increased processed volumes.

Appalachia

Volumes on the Laurel Mountain system averaged 124.3 Mmcfd and 109.5 Mmcfd during the fourth quarter 2010 and full year 2010, respectively, up 26.6% and 12.9% compared to the fourth quarter 2009 and full year 2009, respectively.

* * *

Corporate and Other

General and administrative expense, net of non-cash compensation, decreased 14.8% to $9.8 million for the fourth quarter 2010, and decreased 16.5% to $30.5 million for the full year 2010 compared with $11.5 million and $36.6 million for the prior year fourth quarter and prior year, respectively. The decrease is attributable to continued focus in costs and efficiencies reflective of our operating strategy.

Net of deferred financing costs, interest expense decreased to $11.7 million and $81.1 million for the fourth quarter 2010 and full year 2010, respectively, down 55.4% and 15.3%, as compared with $26.3 million and $95.8 million for the fourth quarter 2009 and full year 2009, respectively. This decrease was primarily due to a $688.2 million reduction in debt outstanding since December 31, 2009.

* * *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s fourth quarter and full year 2010 results on Tuesday, February 22, 2011 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 12:00 pm ET on Tuesday, February 22, 2011. To access the replay, dial 1-888-286-8010 and enter conference code 45687751.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates five active gas processing plants as well as approximately 8,600 miles of active intrastate gas gathering pipeline. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: AHD), formerly Atlas Pipeline Holdings, L.P., is a master limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P. (NYSE: APL), through which it owns a 2% general partner interest, all the incentive distribution rights and approximately 5.75 million common limited partner units of APL. Additionally, AHD owns an interest in over 8,500 producing natural gas and oil wells, representing over 185 Bcfe of net proved developed reserves. For more information, please visit our website at http://www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity process and local or national economic conditions and other risks detailed from time to time in Atlas Pipeline’s reports filed with the SEC, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K.

        ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary((1)) (unaudited; in thousands)   Three Months Ended Year Ended December 31, December 31,   2010      

2009(2)

  2010      

2009(2)

Revenue: Natural gas and liquids $ 248,070 $ 201,528 $ 890,048 $ 636,231 Transportation, processing and other fees(3) 11,149 9,277 41,093 59,075 Other income (loss), net   (6,129 )   (8,769 )   4,447     (22,701 )   Total revenue and other income (loss), net   253,090     202,036     935,588     672,605     Costs and expenses: Natural gas and liquids 198,720 159,072 720,215 527,730 Plant operating 12,178 12,501 48,670 45,566 Transportation and compression 340 401 1,061 6,657 General and administrative(4)(5) 9,807 11,507 30,537 36,578 General and administrative – non-cash unit-based

compensation(4)

693 205 3,484 702 Depreciation and amortization 19,250 20,117 74,897 75,684 Goodwill and other asset impairment – 10,325 – 10,325 Interest   13,188     27,843     91,632     103,787     Total costs and expenses   254,176     241,971     970,496     807,029     Equity income in joint venture 783 1,903 4,920 4,043 Gain (loss) on asset sale and other   (10,729 )   –     (10,729 )   108,947     Income from continuing operations   (11,032 )   (38,032 )   (40,717 )   (21,434 )   Discontinued operations:   Gain on sale of discontinued operations 610 – 312,102 53,571 Earnings from discontinued operations   (139 )   2,907     9,053     30,577     Income from discontinued operations 471 2,907 321,155 84,148   Net income (10,561 ) (35,125 ) 280,438 62,714   Income attributable to non-controlling interests (1,400 ) (1,101 ) (4,738 ) (3,176 ) Preferred unit dividends   (540 )   −     (780 )   (900 ) Net income (loss) attributable to common limited partners and the general partner $ (12,501 ) $ (36,226 ) $ 274,920   $ 58,638    

_________________

(1)

 

Based on the GAAP statements of operations to be included in Form 10-K, with additional detail of certain items included.

(2)

Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.

(3)

Includes affiliate revenues related to transportation and processing provided to Atlas Energy Resources, LLC.

(4)

Non-cash costs associated with unit-based compensation, which have been reflected in the general and administrative costs and expenses, the category associated with the direct personnel cash costs in the GAAP statements of operations to be included in Form 10-K, includes approximately $2.2 million associated with the conversion of equity-indexed cash bonus units into phantom units during the year ended December 31, 2010. This conversion resulted in a reduction of general and administrative costs and an increase to general and administrative – non cash unit based compensation during the year ended December 31, 2010.

(5)

Includes compensation reimbursement to affiliates.

        ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary (continued) (unaudited; in thousands, except per unit amounts)   Three Months Ended Year Ended December 31, December 31,   2010      

2009(1)

  2010      

2009(1)

  Net income (loss) attributable to common limited partners per unit: Basic: Continuing operations $ (0.24 ) $ (0.76 ) $ (0.85 ) $ (0.52 ) Discontinued operations   0.01     0.06     5.92     1.71     $ (0.23 ) $ (0.70 ) $ 5.07   $ 1.19   Diluted: Continuing operations $ (0.24 ) $ (0.76 ) $ (0.85 ) $ (0.52 ) Discontinued operations Diluted   0.01     0.06     5.92     1.71     $ (0.23 ) $ (0.70 ) $ 5.07   $ 1.19     Weighted average common limited partner units

outstanding:

Basic   53,317     50,511     53,166     48,299     Diluted   53,317     50,511     53,166     48,299     Summary Cash Flow Data Cash provided by (used in) operating activities $ 5,142 $ 4,371 $ 106,427 $ 55,853 Cash provided by (used in) investing activities (35,135 ) (17,665 ) 594,753 241,123 Cash provided by (used in) financing activities 29,991 9,054 (702,037 ) (297,400 )   Capital Expenditure Data: Maintenance capital expenditures $ 4,443 $ 2,018 $ 10,921 $ 3,750 Expansion capital expenditures 10,115 10,774 35,715 106,524 Cash contributions to Laurel Mountain JV   19,600     1,680     26,514     1,680     Total $ 34,158   $ 14,472   $ 73,150   $ 111,954     _________________ (1)   Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.         ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (unaudited, in thousands)   ASSETS December 31,

2010

December 31,

2009(1)

  Current assets: Cash and cash equivalents $ 164 $ 1,021 Other current assets 114,877 94,377 Current assets of discontinued operations   –     22,746     Total current assets 115,041 118,144   Property, plant and equipment, net 1,341,002 1,327,704 Intangible assets, net 126,379 149,481 Investment in joint venture 153,358 132,990 Long-term portion of derivative asset – 361 Other assets, net 29,068 30,253 Long-term assets of discontinued operations   –     379,030     $ 1,764,848   $ 2,137,963     LIABILITIES AND EQUITY     Current liabilities $ 151,606 $ 148,729   Long-term portion of derivative liability 5,608 11,126 Long-term debt, less current portion 565,764 1,254,183 Other long-term liability 223 398   Commitments and contingencies   Total Partners’ capital 1,074,184 754,452 Non-controlling interest   (32,537 )   (30,925 )   Total Equity   1,041,647     723,527     $ 1,764,848   $ 2,137,963     _________________ (1)   Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems.        

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

 

Three Months Ended

December 31,

Year Ended

December 31,

 

2010

     

2009(1)

 

2010

     

2009(1)

Reconciliation of net income (loss) to other non-GAAP measures(2):

Net income (loss)

$

(10,561

)

$

(35,125

)

$

280,438

$

62,714

Income attributable to non-controlling interests

(1,400

)

(1,101

)

(4,738

)

(3,176

)

Depreciation and amortization

19,250

20,117

74,897

75,684

Interest expense(3)

13,188

28,286

92,236

104,230

Depreciation, amortization and interest of discontinued operations

–

4,720

12,069

 

19,394

 

EBITDA

20,477

16,897

454,902

258,846

Adjust for cash flow from investment in joint venture

2,007

751

6,146

267

Non-cash (gain) loss on derivatives

5,996

11,227

(10,166

)

74,644

Early termination cash derivative expense(4)

–

–

22,401

2,260

Premium expense on derivative instruments

3,592

3,474

21,123

9,693

(Gain) loss on asset sales and other

10,119

–

(301,373

)

(162,518

)

Goodwill and other asset impairment

–

10,325

–

10,325

Other non-cash (gains) losses(5)

661

(357

)

3,138

(3,198

)

Discontinued operations adjustments(6)

 

–

   

2,027

   

13,628

   

(15,511

)

Adjusted EBITDA

42,852

44,344

209,799

174,808

Interest expense, net of ineffective interest rate swaps(3)

(13,188

)

(28,286

)

(92,236

)

(104,230

)

Amortization of deferred financing costs

1,457

1,567

10,545

8,016

Preferred unit dividends

(540

)

−

(780

)

(900

)

Maintenance capital expenditures

(4,443

)

(2,018

)

(10,921

)

(3,750

)

Premiums paid for derivative instruments

(656

)

(5,240

)

(8,428

)

(30,478

)

Discontinued operations adjustments(7)

 

(273

)

 

(1,208

)

 

(1,216

)

 

(3,396

)

Distributable Cash Flow

$

25,209

 

$

9,159

 

$

106,763

 

$

40,070

    ___________________

(1)

 

Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems and modifications to the Partnership’s credit facility Consolidated EBITDA definition and covenant calculations.

(2)

EBITDA, Adjusted EBITDA and Distributable Cash Flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of the Partnership believes that EBITDA, Adjusted EBITDA and Distributable Cash Flow provide additional information for evaluating the Partnership’s ability to make distributions to its common unitholders and the general partner, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. Adjusted EBITDA is also similar to the Consolidated EBITDA calculation that is utilized within the Partnership’s financial covenants under its credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of the Partnership’s Elk City/Sweetwater system; and (ii) other non-cash items specifically excluded under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.

(3)

Includes the cost of interest rate swaps that were previously recognized in interest expense prior to becoming ineffective in June 2009. They were subsequently recorded in other income (loss), net in the Partnership’s income statement.

(4)

During the years ended December 31, 2010 and 2009, the Partnership made net payments of $33.7 million and $5.0 million, respectively, related to the early termination of derivative contracts, including $11.3 million and $2.7 million related to Elk City derivatives included in discontinued operations adjustments. The Partnership’s credit facility definition of Consolidated EBITDA allows for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of equity.

(5)

Includes the non-cash impact of commodity price movements on pipeline linefill inventory and non-cash compensation.

(6)

Discontinued operation adjustments for Adjusted EBITDA include (i) early termination cash derivative expense; (ii) premium expense on derivative instruments; and (iii) non-cash (gain) loss on derivatives.

(7)

Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; and (ii) interest expense.

        ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

  Three Months Ended Year Ended December 31, December 31,   2010     2009   2010     2009

Pricing

Mid-Continent Weighted Average NGL sales ($/gallon):

Conway hub $ 1.00 $ 0.95 $ 0.92 $ 0.68 Mt. Belvieu hub 1.11 1.01 1.03 0.77  

Unhedged natural gas sales ($/Mcf):

Velma 4.10 4.06 4.14 3.24 Chaney Dell 4.07 4.14 4.13 3.25 Midkiff/Benedum 4.09 4.03 4.10 3.35 Weighted Average 4.08 4.09 4.12 3.28  

Unhedged NGL sales ($/gallon):

Velma 1.01 0.93 0.90 0.69 Chaney Dell 1.06 0.94 0.94 0.69 Midkiff/Benedum 1.14 1.06 1.02 0.83 Weighted Average 1.08 0.98 0.97 0.73  

Unhedged Condensate sales ($/barrel):

Velma 88.29 74.73 78.28 59.80 Chaney Dell 80.17 72.57 72.67 55.07 Midkiff/Benedum 83.59 75.53 75.57 60.35 Weighted Average 83.44 74.28 75.08 58.21  

Volumes:(1)

Appalachia

Laurel Mountain system: Average throughput volume – mcfd(2) 124,307 98,163 109,480 96,975 Tennessee system Average throughput volume – mcfd 8,660 9,378 8,740 7,907

Mid-Continent

Velma: Gathered gas volume – mcfd 94,389 77,741 84,455 76,378 Processed gas volume – mcfd 87,732 75,687 78,606 73,940 Residue gas volume – mcfd 71,792 59,510 64,138 58,350 NGL volume – bpd 10,608 8,450 9,218 8,232 Condensate volume – bpd 431 360 416 377 Chaney Dell: Gathered gas volume – mcfd 244,033 234,936 228,684 270,703 Processed gas volume – mcfd 230,717 212,309 214,695 215,374 Residue gas volume – mcfd 207,758 198,866 193,200 228,261 NGL volume – bpd 14,204 12,958 12,395 13,418 Condensate volume – bpd 735 712 697 824 Midkiff/Benedum(2): Gathered gas volume – mcfd 184,418 156,412 178,111 159,568 Processed gas volume – mcfd 169,413 150,071 163,475 149,656 Residue gas volume – mcfd 109,659 97,961 105,982 101,788 NGL volume – bpd 27,110 22,017 26,678 21,261 Condensate volume – bpd 1,100 788 1,289 1,265   ________________ (1)   “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. (2) Includes 100% of the throughput volume of Laurel Mountain and Midkiff/Benedum.  

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions through December 31, 2012

(as of February 21, 2011 )

Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2012, which encompass APL’s price risk management position in its entirety.

NATURAL GAS HEDGES

Swap Contracts

                Production Period Purchased /Sold Commodity MMBTU Avg. Fixed Price 1Q 2011 Sold Natural Gas 800,000 4.54 1Q 2011 Sold Natural Gas Basis 480,000 (0.73 ) 1Q 2011 Purchased Natural Gas Basis 480,000 (0.76 ) 2Q 2011 Sold Natural Gas 900,000 4.41 2Q 2011 Sold Natural Gas Basis 480,000 (0.73 ) 2Q 2011 Purchased Natural Gas Basis 480,000 (0.76 ) 3Q 2011 Sold Natural Gas 1,200,000 4.54 3Q 2011 Sold Natural Gas Basis 480,000 (0.73 ) 3Q 2011 Purchased Natural Gas Basis 480,000 (0.76 ) 4Q 2011 Sold Natural Gas 1,200,000 4.91 4Q 2011 Sold Natural Gas Basis 480,000 (0.73 ) 4Q 2011 Purchased Natural Gas Basis 480,000 (0.76 )  

NATURAL GAS LIQUIDS AND CONDENSATE HEDGES

Swap Contracts - NGLS

Production Period Purchased /Sold Commodity Gallons Avg. Fixed Price 1Q 2011 Sold Ethane 5,418,000 0.49 1Q 2011 Sold Propane 3,906,000 1.19 2Q 2011 Sold Ethane 5,040,000 0.50 2Q 2011 Sold Propane 4,284,000 1.11 3Q 2011 Sold Propane 4,284,000 1.16 3Q 2011 Sold Isobutane 504,000 1.61 3Q 2011 Sold Normal Butane 1,386,000 1.57 3Q 2011 Sold Natural Gasoline 3,276,000 2.04 4Q 2011 Sold Propane 4,284,000 1.19 4Q 2011 Sold Isobutane 504,000 1.63 4Q 2011 Sold Normal Butane 1,386,000 1.59 4Q 2011 Sold Natural Gasoline 3,276,000 2.04 2Q 2012 Sold Propane 1,008,000 1.19 3Q 2012 Sold Propane 1,008,000 1.19  

Swap Contracts - Crude

Production Period Purchased /Sold Commodity Barrels Avg. Fixed Price 1Q 2011 Sold Crude 39,000 $ 92.61 2Q 2011 Sold Crude 39,000 93.13 3Q 2011 Sold Crude 30,000 90.60 4Q 2011 Sold Crude 30,000 90.75 1Q 2012 Sold Crude 21,000 99.50 2Q 2012 Sold Crude 21,000 99.50 3Q 2012 Sold Crude 21,000 99.50 4Q 2012 Sold Crude 21,000 99.50    

Unaudited Current Commodity Risk Management Positions through December 31, 2012

(as of February 21, 2011 )

                 

NATURAL GAS LIQUIDS AND CONDENSATE HEDGES

 

Option Contracts – NGLs

Production Period Purchased/Sold Type Commodity Gallons Avg. Strike Price 2Q 2011 Purchased Put Propane 4,410,000 1.21 3Q 2011 Purchased Put Propane 4,410,000 1.22  

Option Contracts – Crude

Production Period Purchased/Sold Type Commodity Barrels Avg. Strike Price 1Q 2011 Purchased Put Crude Oil 210,000 89.00 1Q 2011 Sold Call Crude Oil 169,500 93.80 1Q 2011 Purchased Call Crude Oil 63,000 123.47 2Q 2011 Purchased Put Crude Oil 210,000 89.00 2Q 2011 Sold Call Crude Oil 169,500 93.35 2Q 2011 Purchased Call Crude Oil 63,000 125.20 3Q 2011 Purchased Put Crude Oil 84,000 95.00 3Q 2011 Sold Call Crude Oil 169,500 93.35 3Q 2011 Purchased Call Crude Oil 63,000 125.20 4Q 2011 Purchased Put Crude Oil 54,000 95.80 4Q 2011 Sold Call Crude Oil 169,500 93.35 4Q 2011 Purchased Call Crude Oil 63,000 125.20 1Q 2012 Purchased Call Crude Oil 45,000 125.20 1Q 2012 Sold Call Crude Oil 124,500 94.69 2Q 2012 Purchased Call Crude Oil 45,000 125.20 2Q 2012 Sold Call Crude Oil 124,500 94.69 3Q 2012 Purchased Call Crude Oil 45,000 125.20 3Q 2012 Sold Call Crude Oil 124,500 94.69 4Q 2012 Purchased Call Crude Oil 45,000 125.20