PR Newswire: news distribution, targeting and monitoring
February 21, 2012 at 17:10 PM EST
Atlas Pipeline Partners, L.P. Reports Fourth Quarter and Full Year 2011 Results

PHILADELPHIA, Feb. 21, 2012 /PRNewswire/ --

  • Distributable Cash Flow for fourth quarter 2011 of $36.0 million, an increase of 62% year-over-year  
  • Previously announced distribution of $0.55 per common limited partner unit, 49% higher year-over-year
  • Adjusted EBITDA for fourth quarter 2011 was $49.2 million, a 15% increase year-over-year
  • Fourth quarter 2011 processed gas volume was 601 MMCFD, a 23% increase year-over-year
  • Risk management program expanded to increase margin protection through 2013
  • Current $600 million organic growth expansion program is ahead of schedule
  • Forecasted 2012 Adjusted EBITDA between $200 - 225 million with further increases in 2013

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"), of $49.2 million for the fourth quarter of 2011 as volumes and natural gas liquids ("NGL") prices increased across all systems versus the same period last year.  Processed natural gas volumes totaled 601 million cubic feet per day, a 23% increase over the fourth quarter of 2010, and the weighted average NGL price was $1.17 per gallon for the quarter, an 8% increase year-over-year.  For the fourth quarter of 2011, Distributable Cash Flow was $36.0 million, or $0.67 per average common limited partner unit.  Net loss was $5.3 million for the fourth quarter of 2011 compared with net loss of $10.6 million for the prior year fourth quarter.    

For the full year 2011, Adjusted EBITDA was $181.0 million, compared to full year 2010 Adjusted EBITDA of $175.0 million, excluding $34.8 million of Adjusted EBITDA related to the Elk City system, which was sold in September 2010.  Net income was $295.4 million for the full year 2011, compared to net income of $280.4 million for the prior year.  For the full year 2011, Distributable Cash Flow was $129.9 million, an increase of approximately 50% over the full year 2010 Distributable Cash Flow of $86.9 million.  Distributable Cash Flow per average common limited partner unit for the full year 2011 was $2.43.  

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures within the tables at the end of this news release.  The Partnership believes these measures provide a more accurate comparison of the operating results for the periods presented.

On January 26, 2012, the Partnership declared a distribution for the fourth quarter of 2011 of $0.55 per common limited partner unit to holders of record on February 7, 2012 and was paid on February 14, 2012.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.14x for the fourth quarter of 2011.  

"We are pleased to end the 2011 year with a solid quarter of results.  During the fourth quarter we successfully transacted on a non-dilutive high-yield bond offering to secure adequate liquidity and funding to execute on our numerous organic growth projects. Additionally during the quarter, we announced a second expansion at our WestTX facility, increasing our backlog of organic projects to $600 million from the previously announced $400 million.  We are making good progress on our current expansion plans, which are coming in ahead of schedule.  Similar to the third quarter, our processing plants are at or near full capacity as we continue to see robust activity by our producer customers.  Our goal over the first half of 2012 will be to execute on installing the two previously announced, new plants in Oklahoma as our producer customers continue to develop the valuable areas in which we operate.  We expect the Partnership will start to benefit from these expansions in the second half of 2012 when those facilities come online and anticipate that benefit to significantly increase in 2013," stated Eugene N. Dubay, Chief Executive Officer of the Partnership.      

*    *    *

2012 Forecasted Guidance

The Partnership is forecasting Adjusted EBITDA for 2012 between $200 million and $225 million based on an average natural gas price of $2.92 per MMbtu, a weighted average NGL price of $1.06 per gallon and an average crude price of $102.84 per barrel, and would be approximately $240 million utilizing the average commodity prices realized in 2011.  The resulting forecasted Distributable Cash Flow for 2012 would range from $130 million to $165 million based on similar assumptions.   The Partnership is currently expecting growth capital expenditures for the year to total approximately $300 million, based on previously announced expansion projects and well connections during the year.  

Under similar commodity pricing scenarios as those used for 2012, there would be even greater upside in 2013 as the result of the organic expansions currently underway.  The Partnership anticipates these expansions could significantly increase cash flows to the company, with total 2013 Adjusted EBITDA for the Partnership ranging between $250 million and $300 million, implying up to an approximately 66% increase in Adjusted EBITDA over 2011 results as the Partnership's expanded facilities begin to add meaningful volumes and additional NGL take-away capacity becomes available.  The Partnership's management team will address the 2012-2013 outlook on the earnings conference call tomorrow morning.  

These forecasted amounts are based on various assumptions, including, among others, the Partnership's expected cost and timing for completion of its announced capital expenditure program, timing of incremental volumes on its gathering and processing systems, known contract structures, scheduled maintenance of facilities including those of third-parties that impact the Partnership's operations, estimated interest rates, and budgeted operating and general administrative costs.  Management does not forecast certain items, including GAAP revenues, depreciation, amortization, and non-cash changes in derivatives, and therefore is unable to provide forecasted Net Income, a comparable GAAP measure, for the periods presented.  The reconciling items between these non-GAAP measures and Net Income are expected to be similar to those for the current periods presented and are not expected to be significant to the Partnership's cash flows.

*    *    *

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $308.1 million as of December 31, 2011.  Total debt outstanding was $524.1 million at December 31, 2011, compared to $566.0 million at December 31, 2010, a decrease of $41.8 million.  On November 21, 2011, the Partnership issued $150.0 million of 8.75% senior unsecured notes due on June 15, 2018, priced at a premium of $155.3 million, in a private placement transaction and used the proceeds to reduce the outstanding balance on its revolving credit facility.  Based upon total debt outstanding at December 31, 2011, total leverage was 2.9x and debt to capital was 30%, inclusive of down-payments on the purchase of three new cryogenic processing facilities and the strategic investment of a 20% interest in the West Texas LPG Pipeline Limited Partnership ("WTLPG").  The Partnership has incurred approximately 50% of the $600 million planned capital expenditure program announced in 2011, including $85 million for the purchase of West Texas LPG, the WestTX re-commissioning of its 60 million cubic feet per day ("MMCFD") Midkiff plant, the WestOK and Velma expansions, and down payment on the WestTX Driver Plant construction.  

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2012 and 2013.  As of February 20, 2012, the Partnership has natural gas, natural gas liquids and condensate protection in place for the 2012 for approximately 76% of associated margin value (exclusive of ethane), as well as coverage for 2013 on approximately 65% of associated margin value (exclusive of ethane).  Counterparties to the Partnership's risk management activities consist 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 operations was $69.6 million for the fourth quarter 2011 and $264.9 million for the full year 2011, compared to $60.5 million and $210.6 million for the prior year periods, respectively.  Gross margin includes natural gas and liquids sales and transportation, processing and other fees, less purchased product costs and non-cash gains (or losses) included in these items.  The increase in gross margin was primarily due to increased NGL prices and volumes.  Volumes on the Velma system increased due to production associated with activity in the Woodford Shale in southern Oklahoma.  The increase in volumes on the Partnership's WestOK system is related to increased producer activity in Oklahoma and Kansas, particularly in the Mississippian formations.  Volume increases on the WestTX system are a result of additional development for oil drilling in the Permian Basin.  

WestTX System

The WestTX system's average natural gas processed volume was 220.5 "MMCFD" and 196.4 MMCFD for the fourth quarter and full year 2011, respectively, compared with 169.4 MMCFD and 163.5 MMCFD for the prior year comparable periods.  NGL production volumes were 32,165 barrels per day ("BPD") and 29,052 BPD for the fourth quarter and full year 2011, respectively, an increase of 18.6% and 8.9% compared with the fourth quarter and full prior year.  Increased volumes are primarily due to increased production in the Spraberry and Wolfberry Trends.  The Partnership expects volumes on this system to continue to increase as producers continue to aggressively pursue their drilling plans over the coming years.  As a result of this increased producer activity, the Partnership re-commissioned its 60 MMCFD Midkiff plant, which increased processing capacity on the WestTX system to 255 MMCFD, an increase of 31% in processing capacity.  In addition, the Partnership has announced plans to construct a new 200 MMCFD cryogenic processing plant to facilitate increased Permian Basin production.  The new plant, to be known as the Driver plant, will be constructed in two phases, with the first phase involving construction of the plant and associated compression to process 100 MMCFD, expected to be in service in the first quarter of 2013.  The second phase, involving placement of additional compression and refrigeration equipment to increase the plant's capacity to 200 MMCFD, is scheduled to be operational by the first quarter of 2015, as capacity is needed.

WestOK System

The WestOK system had average natural gas processed volume of 275.6 MMCFD and 254.4 MMCFD for the fourth quarter and full year 2011, respectively, a 19.4% and 18.5% increase from the prior year comparable periods. NGL production increased to 14,348 BPD and 13,635 BPD for the fourth quarter and full year 2011, respectively, a 1.0% and 10.0% increase from the prior year comparable periods.  The WestOK system is currently operating in excess of capacity with certain volumes being off-loaded to third-parties for processing or by-passing the processing facilities.  The Partnership expects volumes to continue to increase as producers in Oklahoma, along with others in Kansas, continue to add to the system via development in the oil rich Mississippian Limestone formation.  The Partnership has purchased and is currently working to install a new 200 MMCFD cryogenic plant and an expansion of the gathering system in order to meet the drilling plans of its existing producers.  This expansion, along with the recent installation of a 30 MMCFD refrigeration plant, would result in total processing capacity of 458 MMCFD, for an increase of 101%.  The expansion is expected to be completed in mid-2012.

Velma System

The Velma system's average natural gas processed volume was 105.1 MMCFD and 98.1 MMCFD for the fourth quarter and full year 2011, respectively, a 19.8% and 24.8% increase from the prior year comparable periods.  The increase is primarily due to additional production gathered on the Madill to Velma pipeline system from continued producer activity in the liquids-rich portion of the Woodford Shale.  Average NGL production increased to 12,084 BPD and 11,433 BPD for the fourth quarter and full year 2011, respectively, up approximately 13.9% and 24.0% compared to the prior year comparable periods, due to the increased processed volumes.  In December 2011, the Partnership entered into a long-term fee-based agreement with XTO Energy, Inc. ("XTO"), a subsidiary of ExxonMobil, to provide gathering and processing services for up to an incremental 60 MMCFD.  The Partnership has previously announced plans to expand the Velma system by adding a 60 MMCFD cryogenic plant, thereby increasing name-plate processing capacity to 160 MMCFD, an increase of 60%, which supports the additional volumes from XTO and other producers in the area who are looking to take advantage of the high NGL content gas in the Woodford shale.  The expansion is expected to be operational in May 2012.  The Partnership is also currently exploring options to further increase processing capacity on the Velma system as it determines the future demand needs from its producing customers.

West Texas LPG Pipeline

On May 11, 2011, the Partnership completed the acquisition of a 20% interest in WTLPG from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million.  WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation.  WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corp. (NYSE: CVX).  The Partnership received $1.9 million and $2.7 million in distributions during the fourth quarter and full year 2011, respectively, from this investment, which is included in its Distributable Cash Flow.

*    *    *

Corporate and Other

Net of deferred financing costs, interest expense decreased to $6.0 million and $27.1 million for the fourth quarter 2011 and full year 2011, respectively, down 49.3% and 66.8%, as compared with $11.7 million and $81.6 million for the fourth quarter 2010 and full year 2010, respectively. This decrease was primarily due to reduction in debt outstanding during the period from the proceeds of the Elk City and Laurel Mountain sales, offset by the current organic expansion program.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's fourth quarter and full year 2011 results, as well as its projection for 2012 results, on Wednesday, February 22, 2012 at 10:00 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 1:00 pm ET on Wednesday, February 22, 2012. To access the replay, dial 1-888-286-8010 and enter conference code 20057273.

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 seven active gas processing plants as well as approximately 9,000 miles of active intrastate gas gathering pipeline.  APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P., 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, ATLS 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 Atlas Energy's 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 prices 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, current 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


Years Ended


December 31,


December 31,


2011


2010


2011


2010(2)

Revenue:












Natural gas and liquids sales

$

330,220


$

248,070


$

1,268,195


$

890,048

Transportation, processing and other fees(2)


12,263



11,149



43,799



41,093

Derivative loss, net(3)


(29,404)



(9,078)



(20,452)



(5,945)

Other income, net(3)


2,827



2,949



11,192



10,392













Total revenues


315,906



253,090



1,302,734



935,588













Costs and expenses:












Natural gas and liquids cost of sales


272,166



198,720



1,047,025



720,215

Plant operating


14,446



12,178



54,686



48,670

Transportation and compression


230



340



833



1,061

General and administrative(4)


8,769



9,807



33,083



30,537

General and administrative – non-cash unit-based compensation(4)


767



693



3,274



3,484

Other


457





1,040



Depreciation and amortization


19,936



19,250



77,435



74,897

Interest(5)


7,078



13,188



31,603



87,273













Total costs and expenses


323,849



254,176



1,248,979



966,137













Equity income in joint ventures


2,091



783



5,025



4,920

Gain (loss) on asset sale


598



(10,729)



256,272



(10,729)

Loss on early extinguishment of debt(5)






(19,574)



(4,359)













Income (loss) from continuing operations


(5,254)



(11,032)



295,478



(40,717)













Discontinued operations:












Gain (loss) on sale of discontinued operations




610



(81)



312,102

Earnings (loss) from discontinued operations




(139)





9,053













Income (loss) from discontinued operations




471



(81)



321,155













Net income (loss)


(5,254)



(10,561)



295,397



280,438













Income attributable to non-controlling interests


(1,708)



(1,400)



(6,200)



(4,738)

Preferred unit dividends




(540)



(389)



(780)

Net income (loss) attributable to common limited partners

 and the General Partner

$

(6,962)


$

(12,501)


$

288,808


$

274,920






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


(2) Includes affiliate revenues related to transportation and processing provided to Atlas Energy, L.P.


(3) Adjusted to separately present derivative gain (loss) within derivative loss, net instead of combining these amounts in other income, net.


(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.  General and administrative also includes any compensation reimbursement to affiliates.


(5) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.




ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)




Three Months Ended


Years Ended


December 31,


December 31,


2011


2010


2011


2010

Net income (loss) attributable to common limited partners per unit:












Basic:












Continuing operations

$

(0.15)


$

(0.24)


$

5.22


$

(0.85)

Discontinued operations




0.01





5.92


$

(0.15)


$

(0.23)


$

5.22


$

5.07

Weighted average common limited partner units (basic)


53,617



53,317



53,525



53,166













Diluted:












Continuing operations

$

(0.15)


$

(0.24)


$

5.22


$

(0.85)

Discontinued operations




0.01





5.92


$

(0.15)


$

(0.23)


$

5.22


$

5.07

Weighted average common limited partner units (diluted)


53,617



53,317



53,944



53,166













Summary Cash Flow Data:












Net cash provided by (used in):












Operating activities

$

22,209


$

5,142


$

102,867


$

106,427

Investing activities


(98,231)



(35,135)



67,763



594,753

Financing activities


76,023



29,991



(170,626)



(702,037)













Capital Expenditure Data:












Maintenance capital expenditures

$

4,796


$

4,443


$

18,247


$

10,921

Expansion capital expenditures


92,486



10,115



227,179



35,715

Investments in joint ventures




19,600



97,250



26,514













Total

$

97,282


$

34,158


$

342,676


$

73,150






ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)


ASSETS


December 31,

2011


December 31,

2010






Current assets:







Cash and cash equivalents


$

168


$

164

Other current assets



132,698



114,877








Total current assets



132,866



115,041








Property, plant and equipment, net



1,567,828



1,341,002

Intangible assets, net



103,276



126,379

Investment in joint ventures



86,879



153,358

Other assets, net



39,963



29,068










$

1,930,812


$

1,764,848








LIABILITIES AND EQUITY





















Current liabilities


$

172,406


$

151,606

Long-term debt, less current portion



522,055



565,764

Other long-term liability



123



5,831








Commitments and contingencies














Total partners' capital



1,264,629



1,074,184

Non-controlling interest



(28,401)



(32,537)








Total equity



1,236,228



1,041,647










$

1,930,812


$

1,764,848




ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)



Three Months Ended

December 31,


Years Ended

December 31,


2011


2010


2011


2010(1)

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












Net income (loss)

$

(5,254)


$

(10,561)


$

295,397


$

280,438

Income attributable to non-controlling interests


(1,708)



(1,400)



(6,200)



(4,738)

Depreciation and amortization


19,936



19,250



77,435



74,897

Interest expense(1) (3)


7,078



13,188



31,603



87,877

Depreciation, amortization and interest of discontinued operations








12,069

EBITDA


20,052



20,477



398,235



450,543

Adjustment for cash flow from investment in joint ventures


(191)



2,007



(577)



6,146

Non-cash (gain) loss on derivatives


27,015



5,996



4,538



(10,166)

Early termination cash derivative expense(4)








22,401

Premium expense on derivative instruments


2,905



3,592



12,219



21,123

(Gain) loss on asset sales and other


(598)



10,119



(256,191)



(301,373)

Loss on early extinguishment of debt






19,574



4,359

Other non-cash losses(5)


56



661



3,228



3,138

Discontinued operations adjustments(6)








13,628

Adjusted EBITDA


49,239



42,852



181,026



209,799

Interest expense(1)(3)


(7,078)



(13,188)



(31,603)



(87,877)

Amortization of deferred financing costs


1,126



1,457



4,480



6,186

Preferred unit dividends  




(540)



(389)



(780)

Premium expense on derivative instruments


(2,905)



(3,592)



(12,219)



(21,123)

Laurel Mountain proceeds remaining(7)






5,850



Other


457





1,040



Maintenance capital expenditures


(4,796)



(4,443)



(18,247)



(10,921)

Discontinued operations adjustments(8)




(273)





(8,413)

Distributable Cash Flow

$

36,043


$

22,273


$

129,938


$

86,871






(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.


(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 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 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) For the year ended December 31, 2010, includes the cost of interest rate swaps 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 year ended December 31, 2010, the Partnership made net payments of $33.7 million related to the early termination of derivative contracts, including $11.3 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) Net proceeds remaining from the sale of Laurel Mountain after the repayment of the amount outstanding on the Partnership's revolving credit facility, redemption of its 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018.


(8) Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; (ii) interest expense and (iii) premiums expense on derivative instruments.



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)



Three Months Ended December 31,


Years Ended December 31,


2011


2010


Percent Change


2011


2010


Percent Change

Pricing (unhedged):
























Mid-Continent Weighted Average Prices:












NGL price per gallon – Conway hub

$

1.01


$

1.00


1.0%


$

1.08


$

0.92


17.4%

NGL price per gallon – Mt. Belvieu hub


1.35



1.11


21.6%



1.31



1.03


27.2%













Natural gas sales ($/MCF):












Velma

3.36


4.10


(18.0)%


3.86


4.14


(6.8)%

WestOK

3.43


4.07


(15.7)%


3.87


4.13


(6.3)%

WestTX

3.35


4.09


(18.1)%


3.84


4.10


(6.3)%

Weighted Average

3.40


4.08


(16.7)%


3.86


4.12


(6.3)%













NGL sales ($/Gallon):












Velma

1.08


1.01


6.9%


1.11


0.90


23.3%

WestOK

0.99


1.06


(6.6)%


1.10


0.94


17.0%

WestTX

1.35


1.14


18.4%


1.33


1.02


30.4%

Weighted Average

1.17


1.08


8.3%


1.20


0.97


23.7%













Condensate sales ($/Barrel):












Velma

94.21


88.29


6.7%


94.35


78.28


20.5%

WestOK

86.35


80.17


7.7%


86.63


72.67


19.2%

WestTX

93.27


83.59


11.6%


92.84


75.57


22.9%

Weighted Average

89.75


83.44


7.6%


90.65


75.08


20.7%













Volumes:
























Velma system:












Gathered gas volume (MCFD)

108,475


94,389


14.9%


103,328


84,455


22.3%

Processed gas volume(4) (MCFD)

105,115


87,732


19.8%


98,126


78,606


24.8%

Residue gas volume (MCFD)

85,873


71,792


19.6%


80,330


64,138


25.2%

Processed NGL volume (BPD)

12,084


10,608


13.9%


11,433


9,218


24.0%

Condensate volume (BPD)

376


431


(12.8)%


423


416


1.7%













WestOK system:












Gathered gas volume (MCFD)

290,485


244,033


19.0%


268,329


228,684


17.3%

Processed gas volume(4) (MCFD)

275,567


230,717


19.4%


254,394


214,695


18.5%

Residue gas volume (MCFD)

250,933


207,758


20.8%


230,907


193,200


19.5%

Processed NGL volume (BPD)

14,348


14,204


1.0%


13,635


12,395


10.0%

Condensate volume (BPD)

1,063


735


44.6%


898


697


28.8%













WestTX system(2):












Gathered gas volume (MCFD)

235,582


184,418


27.7%


212,775


178,111


19.5%

Processed gas volume(4) (MCFD)

220,506


169,413


30.2%


196,412


163,475


20.1%

Residue gas volume (MCFD)

149,506


109,659


36.3%


133,857


105,982


26.3%

Processed NGL volume (BPD)

32,165


27,110


18.6%


29,052


26,678


8.9%

Condensate volume (BPD)

886


1,100


(19.5)%


1,500


1,289


16.4%













West Texas LPG Partnership(3)












Average NGL volumes (BPD)

236,614


231,695


2.1%


229,673


226,660


1.3%













Consolidated Volumes:












Gathered gas volume (MCFD)

642,093


531,500


20.8%


592,130


499,990


18.4%

Processed gas volume (MCFD)

601,188


487,862


23.2%


548,932


456,776


20.2%

Residue gas volume (MCFD)

486,312


389,209


24.9%


445,094


363,320


22.5%

Processed NGL volume (BPD)

58,597


51,922


12.9%


54,120


48,291


12.1%

Condensate volume (BPD)

2,325


2,266


2.6%


2,821


2,402


17.4%











(1) "MCF" represents thousand cubic feet; "MCFD" represents thousand cubic feet per day; "BPD" represents barrels per day.


(2) Operating data for the WestTX system represents 100% of its operating activity.


(3) Volume data for the West Texas LPG Partnership represents 100% of its operating activity for the calendar year.


(4) Processed gas volumes include volumes offloaded and processed by third parties as well as volumes bypassed and delivered as residue gas.



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of February 20, 2012)


Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2014. APL's price risk management position in its entirety will be disclosed in the Partnership's Form 10-K.



SWAP CONTRACTS


NATURAL GAS LIQUIDS HEDGES


Production Period

Purchased /Sold

Commodity

Gallons

Avg. Fixed Price

1Q 2012

Sold

Ethane

2,898,000

0.74

1Q 2012

Sold

Propane

4,410,000

1.37

1Q 2012

Sold

Isobutane

504,000

1.97

1Q 2012

Sold

Normal Butane

1,386,000

1.93

1Q 2012

Sold

Natural Gasoline

1,008,000

2.42

2Q 2012

Sold

Propane

4,788,000

1.24

2Q 2012

Sold

Isobutane

630,000

1.60

2Q 2012

Sold

Normal Butane

1,260,000

1.72

2Q 2012

Sold

Natural Gasoline

1,008,000

2.40

3Q 2012

Sold

Propane

5,040,000

1.25

3Q 2012

Sold

Isobutane

756,000

1.57

3Q 2012

Sold

Normal Butane

1,260,000

1.71

3Q 2012

Sold

Natural Gasoline

1,008,000

2.39

4Q 2012

Sold

Propane

5,040,000

1.35

4Q 2012

Sold

Isobutane

756,000

1.58

4Q 2012

Sold

Normal Butane

1,386,000

1.71

4Q 2012

Sold

Natural Gasoline

1,134,000

2.39

1Q 2013

Sold

Propane

6,552,000

1.30

1Q 2013

Sold

Isobutane

504,000

1.86

1Q 2013

Sold

Normal Butane

1,134,000

1.66

2Q 2013

Sold

Propane

7,056,000

1.26

2Q 2013

Sold

Isobutane

630,000

1.77

2Q 2013

Sold

Normal Butane

1,260,000

1.66

3Q 2013

Sold

Propane

7,560,000

1.26

4Q 2013

Sold

Propane

12,222,000

1.28




ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of February 20, 2012)


CONDENSATE HEDGES


Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

1Q 2012

Sold

Crude

81,000

95.02

2Q 2012

Sold

Crude

78,000

95.33

3Q 2012

Sold

Crude

69,000

96.65

4Q 2012

Sold

Crude

75,000

95.58

1Q 2013

Sold

Crude

93,000

97.49

2Q 2013

Sold

Crude

99,000

97.33

3Q 2013

Sold

Crude

78,000

97.08

4Q 2013

Sold

Crude

75,000

96.66

1Q 2014

Sold

Crude

30,000

99.00

2Q 2014

Sold

Crude

30,000

97.85




OPTION CONTRACTS


NGL OPTION CONTRACTS


Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

1Q 2012

Purchased

Put

Ethane

1,890,000

0.70

1Q 2012

Purchased

Put

Propane

6,300,000

1.47

1Q 2012

Purchased

Put

Isobutane

756,000

1.75

1Q 2012

Purchased

Put

Natural Gasoline

2,898,000

2.36

2Q 2012

Purchased

Put

Ethane

1,260,000

0.75

2Q 2012

Purchased

Put

Propane

6,426,000

1.36

2Q 2012

Purchased

Put

Isobutane

756,000

1.60

2Q 2012

Purchased

Put

Normal Butane

1,134,000

1.56

2Q 2012

Purchased

Put

Natural Gasoline

2,898,000

2.05

3Q 2012

Purchased

Put

Propane

7,560,000

1.36

3Q 2012

Purchased

Put

Isobutane

1,008,000

1.57

3Q 2012

Purchased

Put

Normal Butane

1,890,000

1.54

3Q 2012

Purchased

Put

Natural Gasoline

3,780,000

2.00

4Q 2012

Purchased

Put

Propane

8,190,000

1.36

4Q 2012

Purchased

Put

Isobutane

1,134,000

1.58

4Q 2012

Purchased

Put

Normal Butane

2,142,000

1.56

4Q 2012

Purchased

Put

Natural Gasoline

4,032,000

2.00

1Q 2013

Purchased

Put

Isobutane

504,000

1.79

1Q 2013

Purchased

Put

Normal Butane

1,512,000

1.74

1Q 2013

Purchased

Put

Natural Gasoline

5,292,000

2.15

2Q 2013

Purchased

Put

Isobutane

630,000

1.72

2Q 2013

Purchased

Put

Normal Butane

1,638,000

1.66

2Q 2013

Purchased

Put

Natural Gasoline

5,796,000

2.10

3Q 2013

Purchased

Put

Isobutane

1,512,000

1.66

3Q 2013

Purchased

Put

Normal Butane

3,528,000

1.64

3Q 2013

Purchased

Put

Natural Gasoline

6,300,000

2.09

4Q 2013

Purchased

Put

Isobutane

1,512,000

1.66

4Q 2013

Purchased

Put

Normal Butane

3,780,000

1.66

4Q 2013

Purchased

Put

Natural Gasoline

6,552,000

2.09




ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of February 20, 2012)


OPTION CONTRACTS


CRUDE OPTION CONTRACTS


Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

1Q 2012

Purchased

Put

Crude Oil

63,000

106.00

1Q 2012

Sold

Call

Crude Oil

124,500

94.69

1Q 2012

Purchased

Call

Crude Oil

45,000

125.20

2Q 2012

Purchased

Put

Crude Oil

39,000

107.58

2Q 2012

Sold

Call

Crude Oil

124,500

94.69

2Q 2012

Purchased

Call

Crude Oil

45,000

125.20

3Q 2012

Purchased

Put

Crude Oil

39,000

106.56

3Q 2012

Sold

Call

Crude Oil

124,500

94.69

3Q 2012

Purchased

Call

Crude Oil

45,000

125.20

4Q 2012

Purchased

Put

Crude Oil

39,000

105.80

4Q 2012

Sold

Call

Crude Oil

124,500

94.69

4Q 2012

Purchased

Call

Crude Oil

45,000

125.20

1Q 2013

Purchased

Put

Crude Oil

66,000

100.10

2Q 2013

Purchased

Put

Crude Oil

69,000

100.10

3Q 2013

Purchased

Put

Crude Oil

72,000

100.10

4Q 2013

Purchased

Put

Crude Oil

75,000

100.10




Contact: Matthew Skelly
VP – Investor Relations
1845 Walnut Street
Philadelphia, PA 19103
(877) 280-2857
(215) 561-5692 (facsimile)

SOURCE Atlas Pipeline Partners, L.P.

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