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Atlas Pipeline Partners, L.P. Reports Second Quarter 2014 Results

-- Previously announced growth of quarterly distribution to $0.63 per common limited partner unit, at approximately 1.1x coverage

PHILADELPHIA, Aug. 4, 2014 /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 $92.9 million for the second quarter of 2014.  Processed natural gas volumes averaged 1,503 million cubic feet per day ("MMCFD"), a 20% increase over the second quarter of 2013.  Distributable Cash Flow was $62.8 million for the second quarter of 2014, or $0.78 per average common limited partner unit, compared to $58.0 million for the prior year's second quarter.  The Partnership recognized net income of $60.5 million for the second quarter of 2014, compared to net income of $10.1 million for the prior year's second quarter.  Net income was higher for second quarter 2014 compared to the prior year's second quarter, mainly due to a $48.5 million gain recognized on the sale of the Partnership's subsidiaries that held a 20% interest in West Texas LPG Pipeline Limited Partnership.

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, 2014, the Partnership declared a cash distribution for the second quarter of 2014 of $0.63 per common limited partner unit to holders of record on August 7, 2014, which will be paid on August 14, 2014.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.1x for the second quarter of 2014.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, "The quarter came in as expected and we were pleased to be able to raise the distribution.  The Partnership has progressed on executing its plans for bringing online the expansion projects that we have invested in over the past year, adding additional capacity in Southern Oklahoma and South Texas.  We expect to complete an additional processing expansion in West Texas this fall and expect to see more organic capital projects and opportunities as we move forward.  We look forward to continuing to provide best in class service to our customers and increasing value to all of our stakeholders."

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $500.9 million as of June 30, 2014.  Total debt outstanding was $1,654.3 million at June 30, 2014, compared to $1,706.8 million at December 31, 2013, a decrease of $52.5 million.  Based upon total debt outstanding at June 30, 2014, total leverage was approximately 4.7x for purposes of calculations under our revolving credit facility, and debt to total capital was 41%.

Risk Management

The Partnership continues to add further protection to its risk management portfolio for forecasted production in 2014 through 2017.  As of August 1, 2014, the Partnership had natural gas, natural gas liquids and condensate protection in place for 2014, 2015 and 2016 for approximately 70%, 50%, and 13%, respectively, 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 the Partnership's risk management portfolio as of August 1, 2014 is included in this release.

Operating Results

Gathered volumes for the three months ended June 30, 2014 were approximately 1.6 BCFD and processed volumes were approximately 1.5 BCFD, an increase of over 12% and 20%, respectively, compared to the Partnership's second quarter 2013 reported results.  Growth capital spending, including contributions to joint ventures, was $146.4 million during the second quarter of 2014, as organic expansion projects continue across all gathering and processing systems, including the processing plant expansions in SouthOK (120 MMCFD Stonewall plant), SouthTX (200 MMCFD Silver Oak II plant), and WestTX (200 MMCFD Edward plant in the southern portion and 200 MMCFD Buffalo plant in the northern portion of the Permian Basin).  In addition, construction continues on multiple gathering pipeline projects, including the pipeline connecting the Velma and Arkoma portions of the SouthOK system.

Gross margin from operations was $136.8 million for the second quarter 2014, compared to $108.7 million for the prior year period, a result of increasing producer activity in APL's areas of operations and the start-up of the Stonewall plant in May 2014.  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 SouthOK, WestOK and WestTX systems.  The gross margin for the quarter does not include approximately $6.6 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $2.8 million realized derivative settlement gains excluded from gross margin in the second quarter of 2013.  

WestTX System

The WestTX system's average natural gas processed volume was 439.4 MMCFD for the second quarter of 2014, compared to 313.5 MMCFD for the second quarter of 2013, an increase of 40% over the past year.  Increased processed volumes are primarily due to continued significant drilling activity in the Permian Basin.  The completion of the Driver Plant in April 2013 increased processing capacity on the WestTX system to 455 MMCFD, supporting the increased gathered volumes.  Average natural gas liquids (NGL) production was 56,165 barrels per day ("BPD") for the second quarter of 2014, a 41% increase over the second quarter of 2013 with the entire system utilizing 97% of its available processing capacity for the quarter.  This system continues to operate in partial ethane rejection due to the value of ethane compared to the value of residue natural gas.  

Pioneer Natural Resources, Inc. ("Pioneer"), a 27.2% partner in the WestTX system, continues to be the largest producer on this system and the contract between APL and Pioneer was recently extended 10 additional years through 2032 and includes additional acreage dedicated from Pioneer. The Partnership expects processed volumes on this system to continue to increase through 2014 and beyond as Pioneer, and the Partnership's many other producer customers, continue to pursue their drilling plans over the coming years in the Permian Basin.  The previously announced 200 MMCFD Edward plant is expected to be complete in September of 2014 and the previously announced new Buffalo plant, an incremental 200 MMCFD cryogenic processing plant to be located in the northern part of the system, is expected to be complete in the second half of 2015.  These two plants will serve the increasing activity in the Permian Basin and will be fully integrated with APL's WestTX gathering and processing system, increasing the processing capacity in the Permian Basin to 855 MMCFD in 2015.  Management currently expects to install a new 200 MMCFD cryogenic processing facility in each of the next five years, along with all necessary infrastructure, in support of the current production plans of the Partnership's producer customers in this area.               

WestOK System

The WestOK system had average natural gas processed volume of 530.5 MMCFD for the second quarter of 2014, a 10% increase from the second quarter of 2013.  Average NGL production was 23,678 BPD for the second quarter of 2014, a 7% increase from the second quarter of 2013, due to the continued increased production on the gathering system. 

Activity continues to be strong by APL's producer customers, with Atlas Pipeline continuing to connect over a well per day in the Mississippi Lime over the past quarter.  During the second quarter, a contract change was implemented with APL's largest customer at WestOK, SandRidge Energy, Inc. ("SandRidge"). The contract transfers all existing volumes that were under SandRidge's previous Keep-Whole contract to the current Percent-of-Proceeds ("POP") contract.  As a result, APL's exposure to Keep-Whole contracts has been reduced to an insignificant portion of its overall contract mix.  Included in the contract change was an additional acreage dedication, and, today APL has dedication of a significant portion of the 1.9 million acres SandRidge has in the core of the Mississippi Lime under this long-term POP contract.  The Partnership continues to add capital projects to this area to accommodate growing development from SandRidge and others, including (i) adding compression, (ii) looping gathering lines, and (iii) adding off-load capabilities to third party processors.  The Partnership continues to evaluate the need for further processing capacity in this area.    

SouthOK System

The SouthOK system's average natural gas processed volume was 408.6 MMCFD for the second quarter 2014, a 22% increase from second quarter 2013.  The increase in processed volumes is primarily due to the start-up of the previously announced Stonewall plant, which increased processing capacity by 120 MMCFD.  Average NGL production was 29,344 BPD for the second quarter 2014, a decrease of approximately 30% compared to the second quarter 2013.  The Partnership has made operational improvements in 2014 that have increased the overall margin received per thousand cubic feet (MCF) of rich gas that is gathered and processed on this system.  These improvements result in additional ethane rejection, which reduces the amount of barrels of NGLs produced, however enhances profit.  

The Stonewall plant, a new cryogenic processing facility, was brought into operation on May 1, 2014 and is now fully operational.  This plant was constructed under the Centrahoma joint venture, which is a joint venture with MarkWest Energy Partners of which APL owns 60%.  The Partnership plans to accelerate the timeframe of the scheduled 80 MMCFD expansion at this plant, due to the increased activity in Southern Oklahoma, including production from the Woodford Shale, SCOOP, Arkoma and Ardmore Basins.  This expansion will allow the facility to operate at its name-plate 200 MMCFD capacity and bring total gross processing capacity on the SouthOK system to 580 MMCFD by the end of 2014.  Additionally, construction is continuing on the project to connect the Velma and Arkoma portions of the SouthOK system, which is expected be complete in September 2014. 

SouthTX System

The SouthTX system recognized revenues on average natural gas processed volumes of 124.5 MMCFD for the second quarter 2014, including volumes processed under midstream sharing agreements.  Under certain existing contractual agreements, APL receives a share of the economic interest from certain volumes currently processed by a third party midstream provider, as well as shares certain economic interests on volumes processed internally with a third party midstream provider.  The volumes reported do not include any deficiencies under minimum volume commitments with producers during the period.

APL continues to make commercial progress in the SouthTX area and has connected newly acquired gas from two prominent operators in the Eagle Ford during the second quarter as previously expected.  The first connection was in mid-May and the second connection was completed at the end of June.  As a result, actual physical volumes processed by APL during the second quarter 2014 increased approximately 22% compared to first quarter 2014, and preliminary estimates for the month of July have indicated actual physical processed volume were approximately 143.5 MMCFD, which is a 25% increase over second quarter average physical processed volume.  The new, 200 MMCFD processing facility, Silver Oak II, recently came on-line and is expected to provide incremental processing capacity for the remainder of 2014 and beyond. 

Corporate and Other

General and administrative costs, excluding non-cash compensation, for the second quarter of 2014 totaled $12.0 million, compared to $9.1 million in the same period in 2013.  The increase in G&A is related to the continued expansion of the business, including in South Texas.  Net of deferred financing costs, interest expense was $21.2 million for the second quarter of 2014, as compared to $20.8 million in the second quarter of 2013. 

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's second quarter 2014 results on Tuesday, August 5, 2014 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 2:00 pm ET on Tuesday, August 5, 2014. To access the replay, dial 1-888-286-8010 and enter conference code 62895511.

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 16 gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline.  For more information, visit the Partnership's website at www.atlaspipeline.com or contact [email protected].

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 28% 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 [email protected].

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.

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

 


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,


2014


2013


2014


2013

Revenue:












Natural gas and liquids sales

$

667,549


$

491,230


$

1,330,679


$

875,078

Transportation, processing and other fees(2)


50,043



40,306



93,480



73,031

Derivative gain (loss), net


(6,367)



27,107



(15,038)



15,024

Other income, net


2,731



2,296



4,839



5,718

   Total revenues


713,956



560,939



1,413,960



968,851













Costs and expenses:












Natural gas and liquids cost of sales


580,885



424,216



1,156,353



749,756

Operating expenses


26,983



24,770



52,111



46,629

General and administrative


11,973



9,110



23,474



18,524

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


6,443



3,436



12,882



7,820

Other (revenues) costs


(20)



18,370



17



18,900

Depreciation and amortization


49,220



46,383



98,459



76,841

Interest


23,059



22,581



46,722



41,267

   Total costs and expenses


698,543



548,866



1,390,018



959,737













Equity income (loss) in joint ventures


(3,875)



(472)



(5,753)



1,568

Loss on early extinguishment of debt




(19)





(26,601)

Gain (loss) on asset dispositions


48,465



(1,519)



48,465



(1,519)

Income (loss) before income taxes


60,003



10,063



66,654



(17,438)

Income tax benefit


(498)



(28)



(896)



(37)













Net income (loss)


60,501



10,091



67,550



(17,401)













Income attributable to non-controlling interests


(3,965)



(1,810)



(6,427)



(3,179)

Preferred unit dividends


(2,609)





(3,015)



Preferred unit imputed dividend effect


(11,378)



(6,729)



(22,756)



(6,729)

Preferred unit dividends in kind


(10,406)



(5,341)



(20,125)



(5,341)

Net income (loss) attributable to common limited partners and the General Partner

$

32,143


$

(3,789)


$

15,227


$

(32,650)













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












Basic and diluted

$

0.27


$

(0.11)


$

0.04


$

(0.57)

Weighted average common limited partner units (basic)


80,979



74,340



80,788



69,520

Weighted average common limited partner units (diluted)


96,890



74,340



96,498



69,520


(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,


2014


2013


2014


2013

Summary Cash Flow Data:












Cash provided by operating activities

$

73,741


$

30,465


$

139,909


$

71,721

Cash used in investing activities


(19,728)



(1,107,853)



(150,412)



(1,216,244)

Cash provided by (used in) financing activities


(59,695)



1,090,208



9,663



1,162,206













Capital Expenditure Data:












Maintenance capital expenditures

$

5,555


$

3,848


$

10,880


$

7,703

Expansion capital expenditures


146,693



103,345



269,699



208,006

Acquisitions




1,000,785





1,000,785













   Total

$

152,248


$

1,107,978


$

280,579


$

1,216,494

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheet
(unaudited; in thousands)

 

ASSETS


June 30,
2014


December 31,
2013






Current assets:







Cash and cash equivalents


$

4,074


$

4,914

Other current assets



281,502



236,864








   Total current assets



285,576



241,778








Property, plant and equipment, net



2,984,168



2,724,192

Intangible assets, net



999,849



1,064,843

Equity method investment in joint ventures



179,054



248,301

Other assets, net



44,382



48,731










$

4,493,029


$

4,327,845








LIABILITIES AND EQUITY





















Current liabilities


$

399,549


$

320,226

Long-term debt, less current portion



1,654,319



1,706,786

Deferred income taxes, net



32,394



33,290

Other long-term liabilities



7,227



7,638








Total partners' capital



2,327,760



2,200,645

Non-controlling interest



71,780



59,260








Total equity



2,399,540



2,259,905










$

4,493,029


$

4,327,845

 

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,


2014


2013


2014


2013













Gross margin calculations:












Natural gas and liquids sales

$

667,549


$

491,230


$

1,330,679


$

875,078

Transportation, processing, and other fees


50,043



40,306



93,480



73,031

Less: non-cash linefill gain (loss)


(49)



(1,339)



94



(1,371)

Less: natural gas and liquids cost of sales


580,885



424,216



1,156,353



749,756

Gross margin

$

136,756


$

108,659


$

267,712


$

199,724













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












Net income (loss)

$

60,501


$

10,091


$

67,550


$

(17,401)

Depreciation and amortization


49,220



46,383



98,459



76,841

Income tax benefit


(498)



(28)



(896)



(37)

Interest expense


23,059



22,581



46,722



41,267













EBITDA


132,282



79,027



211,835



100,670

Income attributable to non-controlling interests(2)


(3,965)



(1,810)



(6,427)



(3,179)

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


(906)



(1,121)



(1,612)



(1,971)

Adjustment for cash flow from investment in joint ventures


6,075



2,272



9,953



2,032

(Gain) loss on asset disposition


(48,465)



1,519



(48,465)



1,519

Non-cash gain on derivatives


(252)



(24,263)



(1,416)



(10,544)

Other (revenues) costs


(20)



18,370



17



18,900

Premium expense on derivative instruments


892



3,745



3,515



7,020

Unrecognized economic impact of acquisitions




1,126





1,126

Loss on early termination of debt




19





26,601

Other non-cash losses(4)


7,246



7,428



16,291



11,844













Adjusted EBITDA


92,887



86,312



183,691



154,018

Interest expense


(23,059)



(22,581)



(46,722)



(41,267)

Amortization of deferred finance costs


1,874



1,739



3,730



3,283

Preferred dividend obligation


(2,609)





(3,015)



Premium expense on derivative instruments


(892)



(3,745)



(3,515)



(7,020)

Maintenance capital expenditures(5)


(5,405)



(3,713)



(10,538)



(7,527)













Distributable Cash Flow

$

62,796


$

58,012


$

123,631


$

101,487




(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 some 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 $150 thousand and $135 thousand for the three months ended June 30, 2014 and 2013, respectively, and $342 thousand and $176 thousand for the six months ended June 30, 2014 and 2013, respectively.

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)

 


Three Months Ended June 30,


Six Months Ended June 30,


2014


2013


Percent Change


2014


2013


Percent Change

Pricing (unhedged):
























Weighted average market prices:












NGL price per gallon – Conway hub

$

0.87


$

0.75


16.0%


$

0.94


$

0.79


19.0%

NGL price per gallon – Mt. Belvieu hub


0.87



0.80


8.7%



0.92



0.83


10.8%













Natural gas sales ($/MCF):












SouthOK

4.29


3.88


10.6%


4.52


3.53


28.0%

WestOK

4.16


3.84


8.3%


4.44


3.54


25.4%

WestTX

4.23


3.74


13.1%


4.46


3.45


29.3%

Weighted average

4.19


3.82


9.7%


4.45


3.59


24.0%













NGL sales ($/gallon):












SouthOK

1.00


0.71


40.8%


1.03


0.69


49.3%

SouthTX

0.76


0.75


1.3%


0.93


0.75


24.0%

WestOK

1.11


0.96


15.6%


1.15


0.97


18.6%

WestTX

0.93


0.86


8.1%


0.96


0.89


7.9%

Weighted average

0.98


0.84


16.7%


1.02


0.84


21.4%













Condensate sales ($/barrel):












SouthOK

96.45


91.76


5.1%


92.96


90.89


2.3%

SouthTX

87.14


92.78


(6.1)%


86.57


92.78


(6.7)%

WestOK

96.71


84.53


14.4%


91.36


84.10


8.6%

WestTX

95.02


93.96


1.1%


96.25


91.97


4.7%

Weighted average

95.78


89.15


7.4%


92.74


88.09


5.3%

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)

 


Three Months Ended June 30,


Six Months Ended June 30,


2014


2013


Percent Change


2014


2013


Percent Change













Volumes:
























SouthOK system(2):












Gathered gas volume (MCFD)

433,294


422,974


2.4%


416,590


407,323


2.3%

Processed gas volume(3) (MCFD)

408,615


334,812


22.0%


390,733


330,767


18.1%

Residue gas volume (MCFD)

378,325


319,650


18.4%


356,980


314,892


13.4%

Processed NGL volume (BPD)

29,344


41,791


(29.8)%


28,810


37,841


(23.9)%

Condensate volume (BPD)

585


536


9.1%


693


550


26.0%













WestOK system:












Gathered gas volume (MCFD)

554,233


506,487


9.4%


543,003


479,577


13.2%

Processed gas volume(3) (MCFD)

530,455


483,504


9.7%


520,364


454,628


14.5%

Residue gas volume (MCFD)

488,224


444,670


9.8%


477,805


420,815


13.5%

Processed NGL volume (BPD)

23,678


22,233


6.5%


23,346


19,258


21.2%

Condensate volume (BPD)

2,420


1,949


24.2%


2,292


1,959


17.0%













SouthTX system(4):












Gathered gas volume (MCFD)

127,979


122,245


4.7%


122,925


122,245


0.6%

Processed gas volume(3) (MCFD)

124,468


121,338


2.6%


119,880


121,338


(1.2)%

Residue gas volume (MCFD)

94,537


96,606


(2.1)%


85,317


96,606


(11.7)%

Processed NGL volume (BPD)

13,805


15,041


(8.2)%


12,843


15,041


(14.6)%

Condensate volume (BPD)

171


65


163.1%


159


65


144.6%













WestTX system(2)












Gathered gas volume (MCFD)

460,410


352,865


30.5%


434,614


332,829


30.6%

Processed gas volume(3) (MCFD)

439,447


313,504


40.2%


414,867


297,220


39.6%

Residue gas volume (MCFD)

327,994


229,777


42.7%


307,577


219,889


39.9%

Processed NGL volume (BPD)

56,165


39,901


40.8%


53,231


36,591


45.5%

Condensate volume (BPD)

2,219


1,993


11.3%


1,708


1,516


12.7%













Other systems:












Gathered gas volumes (MCFD)

28,435


28,247


0.7%


28,637


29,563


(3.1)%













Consolidated Volumes:












Gathered gas volume (MCFD)

1,604,351


1,432,818


12.0%


1,545,769


1,371,537


12.7%

Processed gas volume (MCFD)

1,502,985


1,253,158


19.9%


1,445,844


1,203,953


20.1%

Residue gas volume (MCFD)

1,289,080


1,090,703


18.2%


1,227,679


1,052,202


16.7%

Processed NGL volume (BPD)

122,992


118,966


3.4%


118,230


108,731


8.7%

Condensate volume (BPD)

5,395


4,543


18.8%


4,852


4,090


18.6%









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

(2)  Operating data for the SouthOK and WestTX systems 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

(4)  Gathered and processed gas volumes on the SouthTX system include volumes processed by a third-party in which the Partnership receives the economic interest. Actual physical gathered and processed volumes totaled 118,133 MCFD and 114,623 MCFD, respectively, during the three months ended June 30, 2014, and 107,293 MCFD and 104,249 MCFD, respectively, during the six months ended June 30, 2014














 


ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)


Note: 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

3Q14

Sold

Propane

12,474,000

$ 0.99

3Q14

Sold

Iso Butane

1,260,000

1.26

3Q14

Sold

Normal Butane

1,260,000

1.50

3Q14

Sold

Natural Gasoline

3,780,000

1.97

4Q14

Sold

Propane

12,852,000

1.00

4Q14

Sold

Iso Butane

1,260,000

1.26

4Q14

Sold

Normal Butane

1,260,000

1.53

4Q14

Sold

Natural Gasoline

3,906,000

1.98

1Q15

Sold

Propane

13,734,000

0.99

1Q15

Sold

Natural Gasoline

4,662,000

1.97

2Q15

Sold

Propane

15,624,000

0.99

2Q15

Sold

Natural Gasoline

4,914,000

2.02

3Q15

Sold

Propane

14,238,000

1.05

3Q15

Sold

Natural Gasoline

3,780,000

2.00

4Q15

Sold

Propane

11,088,000

1.02

4Q15

Sold

Natural Gasoline

1,260,000

2.00

1Q16

Sold

Propane

6,930,000

1.03

2Q16

Sold

Propane

5,040,000

1.03

3Q16

Sold

Propane

6,300,000

1.04

4Q16

Sold

Propane

3,780,000

1.04

1Q17

Sold

Propane

2,520,000

1.04

2Q17

Sold

Propane

2,520,000

1.04

3Q17

Sold

Propane

2,520,000

1.04

4Q17

Sold

Propane

2,520,000

1.04

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)


SWAP CONTRACTS


CONDENSATE HEDGES


Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

3Q14

Sold

Crude Oil

90,000

92.39

4Q14

Sold

Crude Oil

69,000

91.71

1Q15

Sold

Crude Oil

75,000

92.11

2Q15

Sold

Crude Oil

75,000

90.45

3Q15

Sold

Crude Oil

45,000

88.58

4Q15

Sold

Crude Oil

15,000

85.13

1Q16

Sold

Crude Oil

15,000

90.00

2Q16

Sold

Crude Oil

15,000

90.00

 


NATURAL GAS HEDGES


Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

3Q14

Sold

Natural Gas

5,050,000

4.06

4Q14

Sold

Natural Gas

5,350,000

4.15

1Q15

Sold

Natural Gas

5,965,000

4.41

2Q15

Sold

Natural Gas

4,615,000

4.18

3Q15

Sold

Natural Gas

4,615,000

4.18

4Q15

Sold

Natural Gas

4,315,000

4.26

1Q16

Sold

Natural Gas

3,150,000

4.34

2Q16

Sold

Natural Gas

1,650,000

4.24

3Q16

Sold

Natural Gas

1,650,000

4.24

4Q16

Sold

Natural Gas

1,650,000

4.24

1Q17

Sold

Natural Gas

1,200,000

4.47

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)


OPTION CONTRACTS


NGL OPTIONS


Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

3Q14

Purchased

Put

Propane

2,520,000

0.95

3Q14

Sold

Call

Propane

1,260,000

1.31

4Q14

Purchased

Put

Propane

2,520,000

0.96

4Q14

Sold

Call

Propane

1,260,000

1.34

1Q15

Purchased

Put

Propane

1,890,000

0.98

1Q15

Sold

Call

Propane

1,260,000

1.28

3Q15

Purchased

Put

Propane

1,260,000

0.88

 

CRUDE OPTIONS


Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

3Q14

Purchased

Put

Crude Oil

90,000

89.91

4Q14

Purchased

Put

Crude Oil

117,000

91.57

1Q15

Purchased

Put

Crude Oil

45,000

91.33

2Q15

Purchased

Put

Crude Oil

75,000

89.49

3Q15

Purchased

Put

Crude Oil

75,000

88.59

4Q15

Purchased

Put

Crude Oil

75,000

88.15

NATURAL GAS OPTIONS


Production Period

Purchased/Sold

Type

Commodity

MMBTUs

Avg. Strike Price

3Q 2014

Purchased

Put

Natural Gas

300,000

4.15

 

SOURCE Atlas Pipeline Partners, L.P.

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