Atlas Pipeline Partners, L.P. Reports Second Quarter 2013 Results - Record processed gas volumes exceed 1.25 billion cubic feet per day (BCFD) in second quarter 2013

- Adjusted EBITDA for second quarter 2013 was $86.3 million, a 75.9% increase year-over-year

- Distributable Cash Flow for second quarter 2013 of $58.0 million, a 77.0% increase year-over-year

- Partnership reaffirms 2013-2014 previously stated guidance

- Previously announced distribution of $0.62 per common limited partner unit, a 10.7% increase year-over-year

- WestOK 200 MMCFD expansion full after only 9 months in operation; Another 200 MMCFD expansion announced last month at WestTX

PHILADELPHIA, Aug. 5, 2013 /PRNewswire/ -- 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 $86.3 million for the second quarter of 2013, driven primarily by a continued increase in volumes across the Partnership's gathering and processing systems.  Processed natural gas volumes averaged 1,253 million cubic feet per day ("MMCFD"), an 84.0% increase over the second quarter of 2012.  Distributable Cash Flow was $58.0 million for the second quarter of 2013, or $0.78 per average common limited partner unit, compared to $32.8 million for the prior year's second quarter.  The Partnership recognized net income of $10.1 million for the second quarter of 2013, compared with net income of $74.9 million for the prior year's second quarter.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures in the tables included 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 July 23, 2013, the Partnership declared a distribution for the second quarter of 2013 of $0.62 per common limited partner unit to holders of record on August 7, 2013, which will be paid on August 14, 2013.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.07x on a fully diluted basis for the second quarter of 2013.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, "We reported solid results for the second quarter and were pleased to have raised our quarterly distribution more than 10% versus this period last year.  Contributing to the increase was the much needed increased liquids takeaway capacity at our WestOK and WestTX systems and the start-up of the Driver plant in West Texas.  We are very focused on aggressively pursuing opportunities in the second half of the year in all of our operating areas and, specifically, are excited to continue to integrate the new Arkoma and SouthTX assets that we have recently acquired to achieve their full operating potential."      

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $540.7 million as of June 30, 2013.  Total debt outstanding was $1,635.8 million at June 30, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $455.9 million.  Based upon total debt outstanding at June 30, 2013, total leverage was approximately 4.8x for purposes of calculations under our revolving credit facility, and debt to total capital was 41%.

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2016.  As of July 31, 2013, the Partnership has natural gas, natural gas liquids and condensate protection in place for the full years of 2013, 2014, and 2015 for approximately 71%, 72%, and 38% respectively, of associated margin value (exclusive of ethane).  The Partnership has also begun to add to protection in 2016.  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 the Partnership's risk management portfolio as of July 31, 2013 is included in this release.

*    *    *

Operating Results

The Partnership continues to report record volumes, and with the addition of the SouthTX assets, is now processing, on average, over 1.25 billion cubic feet per day of natural gas per day.  Gross margin from operations was $108.7 million for the second quarter 2013, compared to $60.8 million for the prior year period, led by increasing producer activity in APL's area of operations.  Gross margin, a non-GAAP financial measure, 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 higher gross margin for the quarter was primarily due to the increased volumes and expansions that have been completed on the WestOK, WestTX, and Velma systems, as well as the newly acquired Arkoma system and SouthTX system, and was partially offset by lower natural gas liquids ("NGL") prices.  The gross margin for the quarter does not include approximately $2.8 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $2.0 million realized derivative settlement gains excluded from gross margin in the second quarter of 2012.  

WestTX System

The WestTX system's average natural gas processed volume was 313.5 MMCFD for the second quarter 2013, compared to 236.2 MMCFD for the second quarter of 2012.  Increased volumes are primarily due to the April 12, 2013 completion of the Driver plant, which increased processing capacity on the WestTX system by 200 MMCFD.  Average NGL production volumes were 39,901 barrels per day ("BPD") for the second quarter 2013, a 21.8% increase from second quarter 2012.  This system continues to operate in ethane rejection due to the value of ethane compared to residue natural gas.  The Partnership expects processed volumes on this system to continue to increase as producers continue to pursue their drilling plans over the coming years.   

WestOK System

The WestOK system had average natural gas processed volume of 483.5 MMCFD for the second quarter, a 53.1% increase from second quarter 2012.  Average NGL production was 22,233 BPD for the second quarter 2013, a 54.6% increase from second quarter 2012, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012.  The WestOK system is also operating in ethane rejection for economic reasons.  The Partnership announced during the quarter that incremental NGL take-away from the Waynoka facilities became available on April 2, 2013 with the connection to DCP Midstream Partners, L.P.'s Southern Hills pipeline.     

Velma System

The Velma system's average natural gas processed volume was 132.7 MMCFD for the second quarter 2013, a 2.8% increase from second quarter 2012.  The increase is primarily due to additional production gathered from continued producer activity in the liquids-rich portion of the Woodford Shale and Ardmore Basin.  Average NGL production increased to 16,201 BPD for the second quarter 2013, up approximately 13.9% compared to second quarter 2012, due to the increase in overall processed volumes. 

Arkoma System

The Partnership acquired the Arkoma system in December 2012 through the acquisition of Cardinal Midstream L.L.C.  The assets acquired include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas, including a 60% interest in a joint venture with MarkWest Energy Partners, L.P., known as Centrahoma Processing, LLC ("Centrahoma"). The Arkoma gathering and processing system is located in the Arkoma Basin in southeastern Oklahoma and had average natural gas processed volumes of 202.1 MMCFD and produced 25,590 BPD of NGLs during the second quarter of 2013.  The Arkoma system has total gross name-plate processing capacity of 220 MMCFD, including the 120 MMCFD Tupelo plant, of which the Partnership owns 100%.  The remaining processing capacity is owned by Centrahoma.

SouthTX System

The Partnership acquired the SouthTX system in April 2013 through the acquisition of TEAK Midstream L.L.C.  The assets acquired include gas gathering and processing facilities and a co-generation facility located in south Texas within the Eagle Ford shale region.  The SouthTX system has a total gross name-plate processing capacity of 200 MMCFD with the Silver Oak I plant, and will have a capacity of 400 MMCFD once the Silver Oak II plant goes into service, which is expected to be during first quarter 2014.  The system had average natural gas processed volumes of 121.3 MMCFD and produced 15,041 BPD of NGLs during the second quarter of 2013. 

Corporate and Other

Net of deferred financing costs, interest expense increased to $20.8 million for the second quarter of 2013, up 156.1% as compared with the second quarter of 2012.  This increase was due to financing the Partnership's acquisitions and capital expenditure program during 2012 and 2013, including the issuance of 6.625% senior unsecured notes due 2020 in September and December 2012, the February 2013 issuance of 5.875% senior unsecured notes due 2023, and the May 2013 issuance of 4.750% senior unsecured notes due 2021.  The 5.875% senior unsecured notes due 2023 were issued in connection with the redemption of the Partnership's 8.75% Senior Notes due 2018.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's second quarter 2013 results on Tuesday, August 6, 2013 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 12:00 pm ET on Tuesday, August 6, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 78328957.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry.  In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 14 active gas processing plants, 18 gas treating facilities, as well as approximately 10,600 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 Class A units and incentive distribution rights and an approximate 37% limited partner interest 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 all of the general partner interest, all the incentive distribution rights and an approximate 6% 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 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, 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 except per unit amounts)






Three Months Ended


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012

Revenue:












Natural gas and liquids sales

$

491,230


$

238,801


$

875,078


$

528,026

Transportation, processing and other fees(2)


40,306



14,878



73,031



27,559

Derivative gain, net


27,107



67,847



15,024



55,812

Other income, net


2,296



2,588



5,718



5,003

Total revenues


560,939



324,114



968,851



616,400













Costs and expenses:












Natural gas and liquids cost of sales


424,216



195,103



749,756



428,208

Plant operating


24,147



14,600



45,418



28,481

Transportation and compression


623



212



1,211



476

General and administrative


9,110



7,505



18,524



16,472

General and administrative – non-cash unit-based compensation(3)


3,436



2,940



7,820



3,918

Other


18,370



(161)



18,900



(195)

Depreciation and amortization


46,383



21,712



76,841



42,554

Interest


22,581



9,269



41,267



17,977

Total costs and expenses


548,866



251,180



959,737



537,891













Equity income in joint ventures


(472)



1,917



1,568



2,813

Gain (loss) on asset sales and other


(1,519)



-



(1,519)



-

Loss on early extinguishment of debt


(19)



-



(26,601)



-

Income from continuing operations


10,063



74,851



(17,438)



81,322

Income tax benefit


28






37
















Net income


10,091



74,851



(17,401)



81,322













Income attributable to non-controlling interests


(1,810)



(1,061)



(3,179)



(2,597)

Income unit imputed dividend effect


(6,729)



-



(6,729)



-

Preferred unit dividends


(5,341)



-



(5,341)



-

Net income attributable to common limited partners and the General Partner

$

(3,789)


$

73,790


$

(32,650)


$

78,725



Net income attributable to common limited partners per unit:












Basic and diluted:

$

(0.11)


$

1.30


$

(0.57)


$

1.37

Weighted average common limited partner units (basic)


74,340



53,646



69,520



53,633

Weighted average common limited partner units (diluted)


74,340



54,510



69,520



54,262




(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)     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


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012

Summary Cash Flow Data:












Cash provided by operating activities

$

30,465


$

21,784


$

65,721


$

64,531

Cash provided by (used in) investing activities


(1,107,853)



(84,551)



(1,216,244)



(182,827)

Cash provided by (used in) financing activities


1,090,208



62,856



1,168,206



118,385













Capital Expenditure Data:












Maintenance capital expenditures

$

3,848


$

4,000


$

7,703


$

8,510

Expansion capital expenditures


103,345



61,221



208,006



137,878

Acquisitions


1,000,785



19,454



1,000,785



36,689













Total

$

1,107,978


$

84,675


$

1,216,494


$

183,077

 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)

 


ASSETS


June 30,

2013


December 31,

2012






Current assets:







Cash and cash equivalents


$

21,081


$

3,398

Other current assets



294,940



216,677








Total current assets



316,021



220,075








Property, plant and equipment, net



2,623,078



2,200,381

Intangible assets, net



1,072,164



518,645

Investment in joint ventures



232,090



86,002

Other assets, net



60,821



40,535










$

4,304,174


$

3,065,638








LIABILITIES AND EQUITY





















Current liabilities


$

304,816


$

253,519

Long-term debt, less current portion



1,635,297



1,169,083

Deferred income taxes, net



35,513



30,258

Other long-term liability



6,387



6,370








Total partners' capital



2,277,682



1,539,177

Non-controlling interest



44,479



67,231








Total equity



2,322,161



1,606,408










$

4,304,174


$

3,065,638

 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

 





Three Months Ended


Six Months Ended


June 30,


June 30,


2013


2012


2013


2012













Reconciliation of net income to other

non-GAAP measures(1):












Net income

$

10,091


$

74,851


$

(17,401)


$

81,322













Depreciation and amortization


46,383



21,712



76,841



42,554

Income tax benefit


(28)



-



(37)



-

Interest expense


22,581



9,269



41,267



17,977













EBITDA


79,027



105,832



100,670



141,853

Income attributable to non-controlling interests(2)


(1,810)



(1,061)



(3,179)



(2,597)

Non-controlling interest depreciation, amortization and interest(3)


(1,121)



-



(1,971)



-

Adjustment for cash flow from investment in joint ventures


2,272



(117)



2,032



787

Loss on asset disposition


1,519



-



1,519



-

Non-cash (gain) loss on derivatives


(24,263)



(64,741)



(10,544)



(54,045)

Acquisition costs


18,370



-



18,900



-

Premium expense on derivative instruments


3,745



3,984



7,020



7,736

Unrecognized economic impact of acquisitions


1,126



-



1,126



-

Loss on early termination of debt


19



-



26,601



-

Other non-cash losses(4)


7,428



5,163



11,844



6,413













Adjusted EBITDA


86,312



49,060



154,018



100,147

Interest expense


(22,581)



(9,269)



(41,267)



(17,977)

Amortization of deferred finance costs


1,739



1,130



3,283



2,295

Premium expense on derivative instruments


(3,745)



(3,984)



(7,020)



(7,736)

Other costs


-



(161)



-



(195)

Maintenance capital expenditures(5)


(3,713)



(4,000)



(7,527)



(8,510)













Distributable Cash Flow

$

58,012


$

32,776


$

101,487


$

68,024



(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 unit holders 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 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)  Represents Anadarko Petroleum Corporation's ("Anadarko" – NYSE: APC) non-controlling interest in the operating results of Atlas Pipeline Mid-Continent WestOk, LLC ("WestOK") and Atlas Pipeline Mid-Continent WestTex, LLC ("WestTX"); and MarkWest's non-controlling interest in Centrahoma

(3)  Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest's interest in Centrahoma

(4)  Includes the non-cash impact of commodity price movements on pipeline linefill inventory, non-cash compensation and minimum volume adjustments on certain producer throughput contracts

(5)  Net of non-controlling interest maintenance capital of $135 thousand and $176 thousand for the three and six months ended June 30, 2013, respectively















 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 



Three Months Ended June 30,


Six Months Ended June 30,


2013


2012


Percent

 Change


2013


2012


Percent

 Change

Pricing (unhedged):
























Weighted Average Market Prices:












NGL price per gallon – Conway hub

$

0.75


$

0.70


7.1 %


$

0.79


$

0.82


(3.7)%

NGL price per gallon – Mt. Belvieu hub


0.80



0.94


(14.9)%



0.83



1.06


(21.7)%













Natural gas sales ($/MCF):












Velma

3.88


2.04


90.2%


3.53


2.29


54.1%

WestOK

3.84


2.09


83.7%


3.54


2.30


53.9%

WestTX

3.74


1.85


102.2%


3.45


2.18


58.3%

Weighted average

3.82


2.01


90.0%


3.59


2.26


58.8%













NGL sales ($/Gallon):












Arkoma

0.66


-


-


0.69


-


-

Velma

0.72


0.71


1.4 %


0.75


0.82


(8.5)%

WestOK

0.96


0.79


21.5 %


0.97


0.85


14.1 %

WestTX

0.86


0.88


(2.3)%


0.89


1.03


(13.6)%

Weighted average

0.84


0.80


5.0 %


0.84


0.92


(8.7)%













Condensate sales ($/barrel):












Arkoma

81.18


-


-


84.79


-


-

Velma

93.32


93.69


(0.4)%


93.36


98.52


(5.2)%

WestOK

84.53


85.41


(1.0)%


84.10


90.00


(6.6)%

WestTX

93.96


86.17


9.0 %


91.97


91.11


0.9 %

Weighted average

89.15


87.00


2.5 %


88.09


91.95


(4.2)%

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 



Three Months Ended June 30,


Six Months Ended June 30,


2013


2012


Percent

Change


2013


2012


Percent

 Change













Volumes:
























Arkoma system(2):












Gathered gas volume (MCFD)

283,238


-


-


272,047


-


-

Processed gas volume(3) (MCFD)

202,113


-


-


201,709


-


-

Residue gas volume (MCFD)

208,163


-


-


208,004


-


-

Processed NGL volume (BPD)

25,590


-


-


22,736


-


-

Condensate volume (BPD)

152


-


-


156


-


-













SouthTX system:












Gathered gas volume (MCFD)

122,245


-


-


122,245


-


-

Processed gas volume(3) (MCFD)

121,338


-


-


121,338


-


-

Residue gas volume (MCFD)

96,606


-


-


96,606


-


-

Processed NGL volume (BPD)

15,041


-


-


15,041


-


-

Condensate volume (BPD)

65


-


-


65


-


-













Velma system:












Gathered gas volume (MCFD)

139,736


136,553


2.3%


135,276


132,888


1.8%

Processed gas volume(3) (MCFD)

132,699


129,070


2.8%


129,058


125,987


2.4%

Residue gas volume (MCFD)

111,487


106,424


4.8%


106,888


103,380


3.4%

Processed NGL volume (BPD)

16,201


14,220


13.9%


15,105


13,931


8.4%

Condensate volume (BPD)

384


434


(11.5)%


394


499


(21.0)%













WestOK system:












Gathered gas volume (MCFD)

506,487


336,377


50.6%


479,577


315,787


51.9%

Processed gas volume(3) (MCFD)

483,504


315,753


53.1%


454,628


297,529


52.8%

Residue gas volume (MCFD)

444,670


291,225


52.7%


420,815


271,582


54.9%

Processed NGL volume (BPD)

22,233


14,379


54.6%


19,258


14,220


35.4%

Condensate volume (BPD)

1,949


1,209


61.2%


1,959


1,307


49.9%













WestTX system(2):












Gathered gas volume (MCFD)

352,865


267,395


32.0%


332,829


256,867


29.6%

Processed gas volume(3) (MCFD)

313,504


236,213


32.7%


297,220


233,359


27.4%

Residue gas volume (MCFD)

229,777


164,593


39.6%


219,889


162,308


35.5%

Processed NGL volume (BPD)

39,901


32,755


21.8%


36,591


32,928


11.1%

Condensate volume (BPD)

1,993


1,941


2.7%


1,516


1,440


5.3%













Barnett system:












   Gathered gas volumes (MCFD)

20,081


23,988


(16.3)%


20,737


23,988


(13.6)%













Tennessee system:












   Gathered gas volumes (MCFD)

8,166


8,348


(2.2)%


8,826


8,286


6.5%













West Texas LPG Partnership(2)












      Average NGL volumes (BPD)

252,886


243,708


3.8%


248,779


243,013


2.4%













Consolidated Volumes:












     Gathered gas volume (MCFD)

1,432,818


772,661


85.4%


1,371,537


737,816


85.9%

     Processed gas volume (MCFD)

1,253,158


681,036


84.0%


1,203,953


656,875


83.3%

     Residue gas volume (MCFD)

1,090,703


562,242


94.0%


1,052,202


537,270


95.8%

     Processed NGL volume (BPD)

118,966


61,354


93.9%


108,731


61,079


78.0%

     Condensate volume (BPD)

4,543


3,584


26.8%


4,090


3,246


26.0%









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

(2)  Operating data for the Arkoma and WestTX systems and for West Texas LPG Partnership represents 100% of operating activity

(3)  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 July 31, 2013)


Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2016. 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 LIQUIDS HEDGES






Production Period

Purchased /Sold

Commodity

Gallons

Avg. Fixed Price

3Q13

Sold

Propane

12,726,000

1.25

3Q13

Sold

Propane - Conway

1,260,000

1.06

4Q13

Sold

Propane

16,254,000

1.20

4Q13

Sold

Propane - Conway

1,260,000

1.06

4Q13

Sold

Normal Butane

1,260,000

1.31

1Q14

Sold

Propane

15,624,000

0.98

1Q14

Sold

Iso Butane

1,260,000

1.26

1Q14

Sold

Normal Butane

1,260,000

1.28

1Q14

Sold

Natural Gasoline

1,890,000

2.01

2Q14

Sold

Propane

12,852,000

0.94

2Q14

Sold

Iso Butane

2,520,000

1.25

2Q14

Sold

Normal Butane

2,520,000

1.38

2Q14

Sold

Natural Gasoline

3,780,000

1.93

3Q14

Sold

Propane

8,190,000

0.97

3Q14

Sold

Iso Butane

1,260,000

1.26

3Q14

Sold

Normal Butane

1,260,000

1.50

3Q14

Sold

Natural Gasoline

3,150,000

1.93

4Q14

Sold

Propane

8,190,000

0.98

4Q14

Sold

Iso Butane

1,260,000

1.26

4Q14

Sold

Normal Butane

1,260,000

1.53

4Q14

Sold

Natural Gasoline

3,150,000

1.93

1Q15

Sold

Propane

7,686,000

0.95

1Q15

Sold

Natural Gasoline

2,142,000

1.91

2Q15

Sold

Propane

8,064,000

0.92

2Q15

Sold

Natural Gasoline

630,000

1.97

3Q15

Sold

Propane

378,000

0.93

3Q15

Sold

Natural Gasoline

630,000

1.97

4Q15

Sold

Propane

3,528,000

0.96

4Q15

Sold

Natural Gasoline

630,000

1.97

 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of July 31, 2013)






SWAP CONTRACTS










CONDENSATE HEDGES










Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

3Q13

Sold

Crude Oil

78,000

97.08

4Q13

Sold

Crude Oil

75,000

96.66

1Q14

Sold

Crude Oil

93,000

95.45

2Q14

Sold

Crude Oil

99,000

93.29

3Q14

Sold

Crude Oil

75,000

89.86

4Q14

Sold

Crude Oil

45,000

88.16

1Q15

Sold

Crude Oil

15,000

85.13

2Q15

Sold

Crude Oil

15,000

85.13

3Q15

Sold

Crude Oil

15,000

85.13

4Q15

Sold

Crude Oil

15,000

85.13






NATURAL GAS HEDGES










Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

3Q13

Sold

Natural Gas

1,530,000

3.62

4Q13

Sold

Natural Gas

1,570,000

3.75

1Q14

Sold

Natural Gas

1,650,000

3.97

2Q14

Sold

Natural Gas

2,650,000

3.89

3Q14

Sold

Natural Gas

4,000,000

3.95

4Q14

Sold

Natural Gas

4,300,000

4.08

1Q15

Sold

Natural Gas

3,865,000

4.30

2Q15

Sold

Natural Gas

3,865,000

4.17

3Q15

Sold

Natural Gas

3,865,000

4.20

4Q15

Sold

Natural Gas

3,565,000

4.27

1Q16

Sold

Natural Gas

1,500,000

4.45

2Q16

Sold

Natural Gas

750,000

4.36

3Q16

Sold

Natural Gas

750,000

4.36

4Q16

Sold

Natural Gas

750,000

4.36

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of July 31, 2013)







OPTION CONTRACTS












NGL OPTIONS












Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

3Q13

Purchased

Put

Normal Butane

3,528,000

1.6440

3Q13

Purchased

Put

Iso Butane

1,512,000

1.6637

3Q13

Purchased

Put

Natural Gasoline

6,300,000

2.0901

4Q13

Purchased

Put

Normal Butane

3,780,000

1.6613

4Q13

Purchased

Put

Iso Butane

1,512,000

1.6622

4Q13

Purchased

Put

Natural Gasoline

6,552,000

2.0933

1Q14

Purchased

Put

Iso Butane

1,260,000

1.2225

2Q14

Purchased

Put

Propane

630,000

0.8880

3Q14

Purchased

Put

Propane

630,000

0.8975

4Q14

Purchased

Put

Propane

630,000

0.9200

3Q15

Purchased

Put

Propane

1,260,000

0.8825







CRUDE OPTIONS












Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

3Q13

Purchased

Put

Crude Oil

72,000

100.1000

4Q13

Purchased

Put

Crude Oil

75,000

100.1000

1Q14

Purchased

Put

Crude Oil

181,500

100.9690

2Q14

Purchased

Put

Crude Oil

60,000

88.9100

3Q14

Purchased

Put

Crude Oil

90,000

89.9133

4Q14

Purchased

Put

Crude Oil

117,000

91.5692

1Q15

Purchased

Put

Crude Oil

45,000

91.3333

2Q15

Purchased

Put

Crude Oil

75,000

89.4900

3Q15

Purchased

Put

Crude Oil

75,000

88.5900

4Q15

Purchased

Put

Crude Oil

75,000

88.1500







NATURAL GAS OPTIONS












Production Period

Purchased/Sold

Type

Commodity

MMBTUs

Avg. Strike Price

2Q 2014

Purchased

Put

Natural Gas

300,000

4.10

3Q 2014

Purchased

Put

Natural Gas

300,000

4.15

 


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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