Atlas Pipeline Partners, L.P. Reports First Quarter 2012 Results

PHILADELPHIA, May 1, 2012 /PRNewswire/ --

  • Distributable Cash Flow for first quarter 2012 of $35.2 million, an increase of 32% year-over-year
  • Previously announced distribution of $0.56 per common limited partner unit, 40% higher year-over-year
  • Adjusted EBITDA for first quarter 2012 was $51.1 million, a 32% increase year-over-year
  • First quarter 2012 processed gas volume was 633 MMCFD, a 31% increase year-over-year
  • Risk management program expanded to increase margin protection for 2012 – 2013 and into 2014
  • Current $600 million organic growth expansion program is ahead of schedule

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 $51.1 million for the first quarter of 2012 as volumes increased across all systems versus the same period last year.  Processed natural gas volumes averaged 633 million cubic feet per day ("MMCFD"), a 31% increase over the first quarter of 2011, while the weighted average NGL price was $1.03 per gallon for the quarter, a 6% decrease year-over-year.  For the first quarter of 2012, Distributable Cash Flow was $35.2 million, or $0.66 per average common limited partner unit, or $2.64 annualized.  Net income was $6.5 million for the first quarter of 2012 compared with net income of $241.6 million for the prior year first quarter, which included a gain of $255.9 million from the sale of the Partnership's 49% non-controlling interest in Laurel Mountain Midstream, LLC ("Laurel Mountain sale").   

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 April 25, 2012, the Partnership declared a distribution for the first quarter of 2012 of $0.56 per common limited partner unit to holders of record on May 8, 2012, which will be paid on May 15, 2012.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.1x for the first quarter of 2012 and has remained within the Partnership's target of 1.15x on an annualized basis.   

"We are pleased to report a strong quarter of results for the start of 2012.  While the mild winter weather over the first quarter provided for a weaker pricing environment on natural gas and propane, the same conditions have provided for greater volume growth during the period and have had a positive effect on the progress of the installation of our two new Oklahoma processing plants, which are scheduled to be in service over the next two months.  We look forward to executing on these organic projects, so that our systems can process more volumes in the second half of 2012 to the benefit of the Partnership and our unit holders," commented 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 $220.1 million as of March 31, 2012.  Total debt outstanding was $613.3 million at March 31, 2012, compared to $524.1 million at December 31, 2011, an increase of $89.2 million.  Based upon total debt outstanding at March 31, 2012, total leverage was 3.2x and debt to capital was 34%.  The Partnership has incurred approximately 60% of the $600 million planned capital expenditure program announced in 2011, including the WestOK and Velma expansions and the WestTX Driver Plant construction.  The projects continue to be on time and within budget. 

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2012.  As of May 1, 2012, the Partnership has natural gas, natural gas liquids and condensate protection in place for the remainder of 2012 for approximately 79% of associated margin value (exclusive of ethane), as well as coverage for 2013 for approximately 73% 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 those banks.  A table summarizing our risk management portfolio is included in this release.

*    *    *

Operating Results

Gross margin from operations was $69.1 million for the first quarter 2012 compared to $56.3 million for the prior year period.  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 volumes.  On all systems, an increase in volumes compared to the prior year period was partially due to the absence of the negative impact of colder weather in the current year.  In addition, volumes on the Velma system increased due to production associated with producer 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 230.5 MMCFD for the first quarter 2012 compared with 172.8 MMCFD for the prior year comparable period.  NGL production volumes were 33,101 barrels per day ("BPD") for the first quarter 2012, an increase of 20.5% compared with the first quarter 2011.  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  pursue their drilling plans over the coming years.  The first phase of construction of the previously announced Driver plant, which will increase processing capacity by 100 MMCFD, is progressing on schedule and is 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 now scheduled to be operational by the first quarter of 2014, as capacity is needed.  This is a full year ahead of the original planned in-service date of first quarter of 2015 that was previously announced.

WestOK System

The WestOK system had average natural gas processed volume of 279.3 MMCFD for the first quarter 2012, a 22.0% increase from the prior year comparable period. NGL production increased to 14,062 BPD for the first quarter 2012, a 3.5% increase from the prior year comparable period.  NGL production volume was impacted due to the fractionator downstream of the plant being down for a week during the current period.  The WestOK system is continuing to operate 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 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.  The expansion is expected to be completed in mid-2012.

Velma System

The Velma system's average natural gas processed volume was 122.9 MMCFD for the first quarter 2012, a 44.3% increase from the prior year comparable period.  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 13,643 BPD for the first quarter 2012, up approximately 35.5% compared to the prior year comparable period, 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. 

*    *    *

Corporate and Other

Net of deferred financing costs, interest expense decreased to $7.5 million for the first quarter 2012 down 32.5% as compared with $11.2 million for the first quarter 2011. This decrease was primarily due to reduction in 8.125% senior notes outstanding in the prior  year from the proceeds of the Laurel Mountain sale, 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 first quarter 2012 results on Wednesday, May 2, 2012 at 11:00 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, May 2, 2012. To access the replay, dial 1-888-286-8010 and enter conference code 41059015.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry.  In the midcontinent 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 all of the general partner interest and approximately 78% of the limited partner interests in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through which it owns a 2% general partner interest, all the incentive distribution rights and an approximate 11% limited partner interest. For more information, please visit our website at 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


March 31,


2012


2011

Revenue:




Natural gas and liquids ..............................................................................

$

289,225


$

266,309

Transportation, processing and other fees(2)................................................

12,681


9,410

Derivative loss, net(3)..................................................................................

(12,035)


(21,645)

Other income, net(3)....................................................................................

2,415


2,789

Total revenue and other income (loss), net..............................................

292,286


256,863





Costs and expenses:




Natural gas and liquids...............................................................................

233,105


218,292

Plant operating............................................................................................

13,811


12,774

Transportation and compression.................................................................

264


184

General and administrative(4)......................................................................

8,967


7,840

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

978


1,177

Other costs.................................................................................................

(34)


Depreciation and amortization....................................................................

20,842


18,905

Interest.......................................................................................................

8,708


12,445





Total costs and expenses..........................................................................

286,711


271,617





Equity income in joint venture........................................................................

896


462

Gain on asset sale and other............................................................................


255,947





Income (loss) from continuing operations.......................................................

6,471


241,655





Income (loss) from discontinued operations...................................................


(81)





Net income.....................................................................................................

6,471


241,574





Income attributable to non-controlling interests...............................................

(1,536)


(1,187)

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


(240)

Net income attributable to common limited partners and the general partner..

$

4,935


$

240,147





Net income attributable to common limited partners per unit:





Basic and diluted:...................................................................................

$

0.06


$

4.37





Weighted average common limited partner units (basic).............................

53,620


53,375





Weighted average common limited partner units (diluted)..........................

54,013


53,846



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

(2)     Includes affiliate revenues related to transportation and processing provided to Atlas Resource Partners, 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-Q.  General and administrative also includes any compensation reimbursement to affiliates.










 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)






Three Months Ended



March 31,



2012


2011








Summary Cash Flow Data:







Net cash provided by (used in):







Operating activities......................................................................


$

42,747


$

3,727

Investing activities.......................................................................



(98,276)



381,405

Financing activities......................................................................



55,529



(385,129)








Capital Expenditure Data:







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


$

4,510


$

3,260

Expansion capital expenditures......................................................



76,657



15,073

Acquisitions...................................................................................



17,235



Investments in joint ventures.........................................................





12,250








Total............................................................................................


$

98,402


$

30,583

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)






ASSETS


March 31,

2012


December 31,

2011






Current assets:







Cash and cash equivalents.......................................................


$

168


$

168

Other current assets..................................................................



117,464



132,698








Total current assets................................................................



117,632



132,866








Property, plant and equipment, net..........................................



1,642,350



1,567,828

Intangible assets, net.................................................................



108,070



103,276

Investment in joint ventures.....................................................



85,975



86,879

Other assets, net........................................................................



26,891



39,963










$

1,980,918


$

1,930,812








LIABILITIES AND EQUITY





















Current liabilities......................................................................


$

152,325


$

172,406

Long-term debt, less current portion.......................................



609,314



522,055

Other long-term liability...........................................................



6,128



123








Commitments and contingencies














Total partners' capital..............................................................



1,239,978



1,264,629

Non-controlling interest............................................................



(26,827)



(28,401)








Total equity...............................................................................



1,213,151



1,236,228










$

1,980,918


$

1,930,812


ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

 (unaudited; in thousands)






Three Months Ended

March 31,



2012


2011

Reconciliation of net income to other non-GAAP measures(1):








Net income....................................................................................................................


$

6,471


$

241,574


Income attributable to non-controlling interests....................................................



(1,536)



(1,187)


Depreciation and amortization..................................................................................



20,842



18,905


Interest expense ...........................................................................................................



8,708



12,445










EBITDA.....................................................................................................................



34,485



271,737










Adjustment for cash flow from investment in joint ventures..............................



904



1,302


Non-cash loss on derivatives......................................................................................



10,696



18,360


Premium expense on derivative instruments..........................................................



3,752



3,005


Gain on asset sales and other.....................................................................................





(255,866)


Other non-cash losses(2)...............................................................................................



1,250



63










Adjusted EBITDA....................................................................................................



51,087



38,601










Interest expense............................................................................................................



(8,708)



(12,445)


Amortization of deferred financing costs................................................................



1,165



1,267


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





(240)


Premium expense on derivative instruments..........................................................



(3,752)



(3,005)


Laurel Mountain proceeds remaining and other costs(3).......................................



(34)



5,850


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



(4,510)



(3,260)










Distributable Cash Flow.........................................................................................


$

35,248


$

26,768




(1)  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 for 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 49% interest in Laurel Mountain; 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.

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

(3)  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.












 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)




Three Months Ended March 31,


2012


2011


Percent

Change

Pricing (unhedged):












Mid-Continent Weighted Average Prices:






NGL price per gallon – Conway hub.............................................................................

$

0.93


$

1.08


(13.9)%

NGL price per gallon – Mt. Belvieu hub.......................................................................


1.18



1.21


(2.5)%







Natural gas sales ($/MCF):






Velma.................................................................................................................................

2.55


3.98


(35.9)%

WestOK..............................................................................................................................

2.56


3.94


(35.0)%

WestTX...............................................................................................................................

2.51


3.92


(36.0)%

Weighted Average............................................................................................................

2.54


3.94


(35.5)%







NGL sales ($/Gallon):






Velma.................................................................................................................................

0.93


1.03


(9.7)%

WestOK..............................................................................................................................

0.91


1.06


(14.2)%

WestTX...............................................................................................................................

1.17


1.18


(0.8)%

Weighted Average............................................................................................................

1.03


1.10


(6.4)%







Condensate sales ($/Barrel):






Velma.................................................................................................................................

102.22


92.24


10.8%

WestOK..............................................................................................................................

93.95


84.72


10.9%

WestTX...............................................................................................................................

101.38


89.80


12.9%

Weighted Average............................................................................................................

97.44


88.29


10.4%







Volumes:












Velma system:






Gathered gas volume (MCFD).......................................................................................

129,223


90,614


42.6%

Processed gas volume(2) (MCFD)...................................................................................

122,904


85,158


44.3%

Residue gas volume (MCFD).........................................................................................

100,335


69,714


43.9%

Processed NGL volume (BPD).......................................................................................

13,643


10,071


35.5%

Condensate volume (BPD).............................................................................................

564


530


6.4%







WestOK system:






Gathered gas volume (MCFD).......................................................................................

295,198


242,965


21.5%

Processed gas volume(2) (MCFD)...................................................................................

279,305


228,865


22.0%

Residue gas volume (MCFD).........................................................................................

251,940


198,640


26.8%

Processed NGL volume (BPD).......................................................................................

14,062


13,591


3.5%

Condensate volume (BPD).............................................................................................

1,405


859


63.6%







WestTX system(3):






Gathered gas volume (MCFD).......................................................................................

246,339


185,918


32.5%

Processed gas volume(2) (MCFD)...................................................................................

230,504


172,817


33.4%

Residue gas volume (MCFD).........................................................................................

160,022


115,917


38.0%

Processed NGL volume (BPD).......................................................................................

33,101


27,476


20.5%

Condensate volume (BPD).............................................................................................

939


1,024


(8.3)%







Tennessee system:






Average throughput volumes (MCFD)............................................................................

8,225


8,079


1.8%







West Texas LPG Partnership(4)






Average NGL volumes (BPD).......................................................................................

242,318


223,217


8.6%







Consolidated Volumes:






Gathered gas volume (MCFD)......................................................................................

678,985


527,576


28.7%

Processed gas volume (MCFD).....................................................................................

632,713


486,840


30.0%

Residue gas volume (MCFD)........................................................................................

512,297


384,271


33.3%

Processed NGL volume (BPD)......................................................................................

60,806


51,138


18.9%

Condensate volume (BPD)............................................................................................

2,908


2,413


20.5%



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

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

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

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











 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of May 1, 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-Q. NGL contracts are traded at Mt. Belvieu unless otherwise disclosed.






SWAP CONTRACTS






NATURAL GAS HEDGES






Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

2Q 2012

Sold

Natural gas

960,000

2.77

3Q 2012

Sold

Natural gas

1,320,000

2.98

4Q 2012

Sold

Natural gas

1,140,000

3.28






NATURAL GAS LIQUIDS HEDGES






Production Period

Purchased /Sold

Commodity

Gallons

Avg. Fixed Price

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 - Conway

1,260,000

1.06

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 - Conway

1,260,000

1.06

2Q 2013

Sold

Propane

10,836,000

1.27

2Q 2013

Sold

Isobutane

630,000

1.77

2Q 2013

Sold

Normal butane

1,260,000

1.66

3Q 2013

Sold

Propane - Conway

1,260,000

1.06

3Q 2013

Sold

Propane

11,718,000

1.28

4Q 2013

Sold

Propane - Conway

1,260,000

1.06

4Q 2013

Sold

Propane

12,222,000

1.28

1Q 2014

Sold

Propane

630,000

1.27

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of May 1, 2012)






SWAP CONTRACTS










CONDENSATE HEDGES










Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

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 OPTIONS







Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

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 May 1, 2012)







OPTION CONTRACTS












CRUDE OPTIONS












Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

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

1Q 2014

Purchased

Put

Crude Oil

136,500

104.75

 

 

Contact: Matthew Skelly
VP – Investor Relations
1845 Walnut Street
Philadelphia, PA 19103
(877) 950-7473
(215) 561-5692 (facsimile)

 

 

SOURCE Atlas Pipeline Partners, L.P.



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