Atlas Pipeline Partners, L.P. Reports Third Quarter 2013 Results -- Record gathered gas volumes of approximately 1.5 billion cubic feet per day (BCFD) in third quarter 2013

-- Adjusted EBITDA for third quarter 2013 was $84.2 million, a 50.5% increase year-over-year

-- Distributable Cash Flow for third quarter 2013 was $50.6 million, a 34.6% increase year-over-year

-- Previously announced distribution of $0.62 per common limited partner unit, an 8.8% increase year-over-year

-- New growth projects announced in Woodford Shale and Permian Basin; three new processing plants due in 2014

PHILADELPHIA, Nov. 4, 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 $84.2 million for the third quarter of 2013, driven primarily by a continued increase in overall volumes across the Partnership's gathering and processing systems.  Processed natural gas volumes averaged 1,372 million cubic feet per day ("MMCFD"), a 78.4% increase over the third quarter of 2012.  Distributable Cash Flow was $50.6 million for the third quarter of 2013, or $0.65 per average common limited partner unit, compared to $37.6 million for the prior year's third quarter.  The Partnership recognized a net loss of $25.6 million for the third quarter of 2013, compared with a net loss of $6.4 million for the prior year's third 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 October 24, 2013, the Partnership declared a cash distribution for the third quarter of 2013 of $0.62 per common limited partner unit to holders of record on November 7, 2013, which will be paid on November 14, 2013.  This distribution represents Distributable Cash Flow coverage per limited partner unit of slightly less than 1.0x for the third quarter of 2013, however distribution coverage for the second and third quarter combined was approximately 1.0x.

"We are pleased with the continued growth of our Company to date, but we are not yet satisfied.  We have numerous growth opportunities in multiple areas in which we operate and we are working diligently to pursue those opportunities in a prudent manner.  Our expectations are to fully utilize any and all of our processing capacity on our existing infrastructure and look for new opportunities to continue our growth trajectory and service to our customers.   While our distribution did not increase this quarter over last quarter, we remain confident that we have set up the Partnership to continue to grow the distribution over the coming years," remarked 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 $510.0 million as of September 30, 2013.  Total debt outstanding was $1,655.7 million at September 30, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $475.7 million.  Based upon total debt outstanding at September 30, 2013, total leverage was approximately 4.9x for purposes of calculations under our revolving credit facility, and debt to total capital was 42%.

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2014 and 2015.  As of October 16, 2013, the Partnership had natural gas, natural gas liquids and condensate protection in place for the remainder of 2013, 2014, and 2015 for approximately 83%, 72%, and 39%, respectively, of associated margin value (exclusive of ethane).  The Partnership also has a minimal amount of 2016 expected equity volumes protected.  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 October 16, 2013 is included in this release.

Operating Results

Volumes have continued to increase across all five of the Partnership's gathering and processing systems since the end of the second quarter. Current gathered volumes are approximately 1.5 billion cubic feet per day ("BCFD") and processable volumes are in excess of 1.4 BCFD, an increase of over 150 MMCFD compared to the Partnership's second quarter reported results. Growth capital spending continues to track $450 million for 2013, as organic expansion projects continue across all gathering and processing systems, including expected 2014 expansions at Arkoma (120 MMCFD), SouthTX (200 MMCFD), and WestTX (200 MMCFD).

Gross margin from operations was $114.8 million for the third quarter 2013, compared to $68.7 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.  The gross margin for the quarter does not include approximately $0.9 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $4.2 million realized derivative settlement gains excluded from gross margin in the third quarter of 2012.  

WestTX System

The WestTX system's average natural gas processed volume was 355.2 MMCFD for the third quarter 2013, compared to 255.7 MMCFD for the third quarter of 2012.  Increased volumes are primarily due to the completion of the Driver plant in April 2013, which increased processing capacity on the WestTX system by 200 MMCFD.  Average NGL production was 47,663 barrels per day ("BPD") for the third quarter 2013, a 67.2% increase over the third 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.  Incremental volume growth from the northern portion of the Partnership's gathering system, where many of the Partnership's producer customers are active, has resulted in the need for additional gathering infrastructure in that area.  APL's Managing Board of Directors has approved an extension of the WestTX gathering system further into Martin County, Texas through a series of growth projects which will service the anticipated needs of its producer customers.  The Partnership will lay a high pressure gathering line into Martin County as well as add compression to increase utilization of WestTX's existing assets, including the recently announced Edward plant.  In addition, this extension of the WestTX system is expected to accelerate the Partnership's need to install additional processing capacity, potentially by the end of 2015.  The initial high pressure gathering pipeline and associated compression is expected to cost approximately $50 million or approximately $36 million net to the Partnership.  As previously announced, the Edward plant, which will add an incremental 200 MMCFD of capacity is expected to be completed in the second half of 2014. 

WestOK System

The WestOK system had average natural gas processed volume of 479.3 MMCFD for the third quarter, a 26.1% increase from the third quarter 2012.  Average NGL production was 21,522 BPD for the third quarter 2013, a 65.6% increase from the third quarter 2012, due to increased production on the gathering systems.  Producers in the Mississippi Lime play in northwestern Oklahoma and southern Kansas continue to grow volumes behind APL's WestOK system, with current gathered volumes in excess of 525 MMCFD. With current nameplate capacity of 458 MMCFD, excess volumes are being offloaded and bypassed as the Partnership works to add capacity in the coming months. With the addition of refrigeration, compression and other engineering work currently being undertaken, the Waynoka facilities are expected to have an incremental 40-50 MMCFD of processing capacity available in November of this year. Due to the nonrenewal of a low margin commercial agreement, an additional 60-70 MMCFD of capacity will become available in the second quarter of 2014. This capacity is expected to be filled under more favorable economic returns with volumes currently being offloaded to third parties and volume growth associated with increased producer drilling activity. Management is committed to continuing to provide excellent service to our producer customers in the play and remain the preeminent gatherer and processor in the area. Due to the ethane pricing environment, approximately only 25% of the currently available ethane is being produced on the system, which Management expects to continue throughout the remainder of this year.

Velma System

The Velma system's average natural gas processed volume was 151.9 MMCFD for the third quarter 2013, a 14.0% increase from the third quarter of 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 16,780 BPD for the third quarter 2013, up approximately 12.9% compared to the third quarter 2012, due to the increase in overall processed volumes.

Drilling activity behind the Velma system continues to increase with incremental demand for processing capacity in the area has increased, partially the result of the emerging South Central Oklahoma Oil Province (SCOOP) play, which has attracted significant producer interest.  APL has entered into fixed fee arrangements with some of these producers and, as a result, will be adding gathering infrastructure at an expected cost of $40 million to facilitate this anticipated growth.  The Velma system's processing capacity today is almost fully utilized, and the Partnership will provide capacity for the incremental SCOOP production by laying approximately 55 miles of pipeline between the Velma system and the Arkoma system.  The Arkoma system is also nearly fully utilized today, but will expand by an additional 120 MMCFD upon installation of the Stonewall plant, expected in the first quarter of 2014.  This project is expected to accelerate the utilization of the Stonewall plant, which is expandable to 200 MMCFD with minimal capital outlay.  The capital to interconnect the Velma and Arkoma systems is expected to be approximately $80 million with anticipated completion in the third quarter of 2014. 

Arkoma System

The Arkoma system consists of gas gathering, processing and treating facilities in the Arkoma Basin in southeastern Oklahoma and includes a 60% interest in a joint venture with MarkWest Energy Partners, L.P., known as Centrahoma Processing, LLC ("Centrahoma"). The system had average natural gas processed volumes of 245.5 MMCFD and produced 16,171 BPD of NGLs during the third quarter of 2013.  The Arkoma system has total gross name-plate processing capacity of 220 MMCFD, including the 120 MMCFD Tupelo plant, which the Partnership owns 100%.  The remaining processing capacity is owned by Centrahoma. 

Gathered volumes continue to increase and are currently in excess of 260 MMCFD in the Arkoma area.  Upon the recent completion of a gathering system expansion by MarkWest Energy Partners, the current processing facilities are now operating near nameplate capacity of 220 MMCFD. This expansion was originally expected to be completed in July 2013 and the delay had a negative impact on the Partnership's results for the quarter as excess volumes were offloaded to third parties.  The Partnership expects certain volumes to continue to be offloaded until the Stonewall plant is operational at the end of the first quarter of 2014. Cash flows from this system are largely fee-based; however, this system does have commodity exposure on fixed recovery contracts, primarily related to Mont Belvieu priced ethane, which is not currently hedged. Approximately half of the ethane is being rejected back into the residue gas stream at these facilities, which is expected to continue at the current ethane and natural gas prices.

SouthTX System

The Partnership acquired the SouthTX system in May 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 name-plate capacity of 400 MMCFD once the Silver Oak II plant goes into service, which is expected to be late in the first quarter or early in the second quarter of 2014.  The system had average natural gas processed volumes of 140.6 MMCFD and produced 17,990 BPD of NGLs during the third quarter of 2013. 

Volumes on the SouthTX system continue to grow with current processed volumes more than 20% higher than those reported for the second quarter. Although at times during the third quarter the SouthTX system ran at the full name-plate capacity, a portion of those volumes have been interruptible packages of gas, which causes periodic fluctuation in volume figures. The Partnership's management team is committed to getting to full utilization of 200 MMCFD on the current Silver Oak I plant by the end of the year and expects the 200 MMCFD Silver Oak II plant to be fully utilized by the end of 2014.

Corporate and Other

General and administrative costs, excluding non-cash compensation, for the third quarter of 2013 totaled $11.9 million, compared to $8.5 million in the same period in 2012.  This increase was driven primarily by an increase in personnel as a result of the acquisition of the Arkoma system in late 2012 and the SouthTX system in April 2013. 

Net of deferred financing costs, interest expense increased to $22.5 million for the third quarter of 2013, as compared to $8.6 million in the third 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 third quarter 2013 results on Tuesday, November 5, 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 2:00 pm ET on Tuesday, November 5, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 35780875.

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 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 except per unit amounts)

 


Three Months Ended


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012

Revenue:












Natural gas and liquids sales

$

535,719


$

274,618


$

1,410,797


$

802,644

Transportation, processing and other fees(2)


43,725



19,272



116,756



46,831

Derivative gain (loss), net


(24,517)



(18,907)



(9,493)



36,905

Other income, net


2,943



2,585



8,661



7,588

Total revenues


557,870



277,568



1,526,721



893,968













Costs and expenses:












Natural gas and liquids cost of sales


463,564



224,778



1,213,320



652,986

Plant operating


24,253



15,180



69,671



43,661

Transportation and compression


553



520



1,764



996

General and administrative


11,889



8,504



30,413



24,976

General and administrative – non-cash

unit-based compensation(3)


5,998



3,619



13,818



7,537

Other


685



(108)



19,585



(303)

Depreciation and amortization


51,080



23,161



127,921



65,715

Interest


24,347



9,692



65,614



27,669

Total costs and expenses


582,369



285,346



1,542,106



823,237













Equity income (loss) in joint ventures


(1,882)



1,422



(314)



4,235

Loss on asset sales and other






(1,519)



Loss on early extinguishment of debt






(26,601)



Income (loss) before income taxes


(26,381)



(6,356)



(43,819)



74,966

Income tax benefit


(817)





(854)















Net income (loss)


(25,564)



(6,356)



(42,965)



74,966













Income attributable to non-controlling interests


(1,514)



(1,511)



(4,693)



(4,108)

Preferred unit imputed dividend effect


(11,378)





(18,107)



Preferred unit dividends


(9,072)





(14,413)



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

$

(47,528)


$

(7,867)


$

(80,178)


$

70,858



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












Basic and diluted:

$

(0.66)


$

(0.17)


$

(1.25)


$

1.19

Weighted average common limited

partner units (basic)


78,398



53,736



72,512



53,668

Weighted average common limited

partner units (diluted)


78,398



55,736



72,512



54,409




(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


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012

Summary Cash Flow Data:












Cash provided by operating activities

$

79,400


$

60,992


$

145,121


$

125,523

Cash used in investing activities


(121,905)



(95,899)



(1,338,149)



(278,725)

Cash provided by financing activities


31,863



34,814



1,200,069



153,199













Capital Expenditure Data:












Maintenance capital expenditures

$

6,416


$

4,732


$

14,119


$

13,242

Expansion capital expenditures


105,736



91,292



313,742



229,170

Contributions in equity method investments


9,813





9,813



Acquisitions






1,000,785



36,689













Total

$

121,965


$

96,024


$

1,338,459


$

279,101

 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)

 

ASSETS


September 30,

2013


December 31,

2012






Current assets:







Cash and cash equivalents


$

10,439


$

3,398

Other current assets



307,786



216,677








Total current assets



318,225



220,075








Property, plant and equipment, net



2,715,361



2,200,381

Intangible assets, net



1,049,892



518,645

Investment in joint ventures



238,221



86,002

Other assets, net



51,896



40,535










$

4,373,595


$

3,065,638








LIABILITIES AND EQUITY





















Current liabilities


$

361,780


$

253,519

Long-term debt, less current portion



1,655,042



1,169,083

Deferred income taxes, net



34,696



30,258

Other long-term liability



7,409



6,370








Total partners' capital



2,266,506



1,539,177

Non-controlling interest



48,162



67,231








Total equity



2,314,668



1,606,408










$

4,373,595


$

3,065,638


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

 


Three Months Ended


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012













Reconciliation of net income to other

non-GAAP measures(1):












Net income (loss)

$

(25,564)


$

(6,356)


$

(42,965)


$

74,966

Depreciation and amortization


51,080



23,161



127,921



65,715

Income tax benefit


(817)





(854)



Interest expense


24,347



9,692



65,614



27,669













EBITDA


49,046



26,497



149,716



168,350

Income attributable to non-controlling interests(2)


(1,514)



(1,511)



(4,693)



(4,108)

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


(917)





(2,888)



Adjustment for cash flow from investment in joint ventures


3,682



378



5,714



1,165

Loss on asset disposition






1,519



Non-cash (gain) loss on derivatives


23,610



22,477



13,066



(31,568)

Acquisition costs


685





19,585



Premium expense on derivative instruments


4,824



4,855



11,844



12,591

Unrecognized economic impact of acquisitions


42





1,168



Loss on early termination of debt






26,601



Other non-cash losses(4)


4,743



3,245



16,587



9,658













Adjusted EBITDA


84,201



55,941



238,219



156,088

Interest expense


(24,347)



(9,692)



(65,614)



(27,669)

Amortization of deferred finance costs


1,836



1,061



5,119



3,356

Premium expense on derivative instruments


(4,824)



(4,855)



(11,844)



(12,591)

Other costs




(108)





(303)

Maintenance capital expenditures(5)


(6,232)



(4,732)



(13,759)



(13,242)













Distributable Cash Flow

$

50,634


$

37,615


$

152,121


$

105,639



(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 $184 thousand and $360 thousand for the three and nine months ended September 30, 2013, respectively
















 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 


Three Months Ended September 30,


Nine Months Ended September 30,


2013


2012


Percent Change


2013


2012


Percent Change

Pricing (unhedged):
























Weighted Average Market Prices:












NGL price per gallon – Conway hub

$

0.81


$

0.70


15.7 %


$

0.80


$

0.78


2.6 %

NGL price per gallon – Mt. Belvieu hub


0.85



0.86


(1.2)%



0.83



0.99


(16.2)%













Natural gas sales ($/MCF):












Velma

3.37


2.64


27.7%


3.47


2.41


44.0%

WestOK

3.30


2.62


26.0%


3.45


2.43


42.0%

WestTX

3.32


2.54


30.7%


3.40


2.32


46.6%

Weighted average

3.34


2.60


28.5%


3.46


2.39


44.8%













NGL sales ($/Gallon):












Arkoma

0.89


-


-


0.73


-


-

SouthTX

0.75


-


-


0.73


-


-

Velma

0.81


0.73


11.0 %


0.77


0.79


(2.5)%

WestOK

1.08


0.86


25.6 %


1.01


0.86


17.4 %

WestTX

0.92


0.96


(4.2)%


0.90


1.01


(10.9)%

Weighted average

0.92


0.87


5.7 %


0.87


0.90


(3.3)%













Condensate sales ($/barrel):












Arkoma

99.94


-


-


87.94


-


-

SouthTX

92.94


-


-


91.05


-


-

Velma

104.29


91.40


14.1 %


96.80


96.93


(0.1)%

WestOK

96.86


82.06


18.0 %


88.10


87.29


0.9 %

WestTX

106.27


90.41


17.5 %


98.78


90.81


8.8 %

Weighted average

101.48


86.65


17.1 %


92.82


90.07


3.1 %

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 


Three Months Ended September 30,


Nine Months Ended September 30,


2013


2012


Percent Change


2013


2012


Percent Change













Volumes:
























Arkoma system(2):












Gathered gas volume (MCFD)

265,992


-


-


270,007


-


-

Processed gas volume(3) (MCFD)

245,496


-


-


249,111


-


-

Residue gas volume (MCFD)

211,438


-


-


209,162


-


-

Processed NGL volume (BPD)

16,171


-


-


20,756


-


-

Condensate volume (BPD)

85


-


-


131


-


-













SouthTX system:












Gathered gas volume (MCFD)

141,282


-


-


131,815


-


-

Processed gas volume(3) (MCFD)

140,557


-


-


131,000


-


-

Residue gas volume (MCFD)

114,287


-


-


105,495


-


-

Processed NGL volume (BPD)

17,990


-


-


16,524


-


-

Condensate volume (BPD)

108


-


-


85


-


-













Velma system:












Gathered gas volume (MCFD)

157,330


136,939


14.9%


142,708


134,248


6.3%

Processed gas volume(3) (MCFD)

151,862


133,166


14.0%


136,743


128,398


6.5%

Residue gas volume (MCFD)

126,931


108,609


16.9%


113,642


105,135


8.1%

Processed NGL volume (BPD)

16,780


14,866


12.9%


15,669


14,306


9.5%

Condensate volume (BPD)

356


283


25.8%


382


427


(10.5)%













WestOK system:












Gathered gas volume (MCFD)

505,222


403,304


25.3%


488,219


346,318


41.0%

Processed gas volume(3) (MCFD)

479,270


380,113


26.1%


462,932


326,337


41.9%

Residue gas volume (MCFD)

442,304


360,688


22.6%


428,056


302,486


41.5%

Processed NGL volume (BPD)

21,522


12,998


65.6%


20,021


13,810


45.0%

Condensate volume (BPD)

1,759


1,341


31.2%


1,892


1,318


43.6%













WestTX system(2):












Gathered gas volume (MCFD)

383,466


288,607


32.9%


349,894


268,456


30.3%

Processed gas volume(3) (MCFD)

355,203


255,709


38.9%


316,760


241,710


31.0%

Residue gas volume (MCFD)

265,648


189,549


40.1%


235,310


172,150


36.7%

Processed NGL volume (BPD)

47,663


28,499


67.2%


40,322


31,441


28.2%

Condensate volume (BPD)

2,598


2,132


21.9%


1,881


1,672


12.5%













Barnett system:












   Gathered gas volumes (MCFD)

22,727


22,789


(0.3)%


21,408


23,084


(7.3)%













Tennessee system:












   Gathered gas volumes (MCFD)

8,052


8,387


(4.0)%


8,565


8,320


2.9%













West Texas LPG Partnership(2)












      Average NGL volumes (BPD)

247,856


256,579


(3.4)%


248,468


247,568


0.4%













Consolidated Volumes:












     Gathered gas volume (MCFD)

1,484,071


860,026


72.6%


1,412,616


780,426


81.0%

     Processed gas volume (MCFD)

1,372,388


768,988


78.5%


1,247,676


696,445


79.1%

     Residue gas volume (MCFD)

1,160,608


658,846


76.2%


1,091,665


579,771


88.3%

     Processed NGL volume (BPD)

120,126


56,363


113.1%


113,292


59,557


90.2%

     Condensate volume (BPD)

4,906


3,756


30.6%


4,371


3,417


27.9%









(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 November 4, 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

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

16,758,000

0.98

1Q14

Sold

Iso Butane

1,260,000

1.26

1Q14

Sold

Normal Butane

2,520,000

1.37

1Q14

Sold

Natural Gasoline

1,890,000

2.01

2Q14

Sold

Propane

14,490,000

0.95

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

10,836,000

0.98

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

10,836,000

0.99

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

11,844,000

0.97

1Q15

Sold

Natural Gasoline

2,142,000

1.91

2Q15

Sold

Propane

9,993,690

0.94

2Q15

Sold

Natural Gasoline

630,000

1.97

3Q15

Sold

Propane

4,788,000

1.00

3Q15

Sold

Natural Gasoline

630,000

1.97

4Q15

Sold

Propane

6,678,000

0.98

4Q15

Sold

Natural Gasoline

630,000

1.97

1Q16

Sold

Propane

1,260,000

1.02

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of November 4, 2013)

 

SWAP CONTRACTS


CONDENSATE HEDGES



Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price


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


4Q13

Sold

Natural Gas

1,870,000

3.80


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 November 4, 2013)

 

OPTION CONTRACTS


NGL OPTIONS



Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price


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

1,260,000

0.9088


4Q14

Purchased

Put

Propane

1,260,000

0.9288


1Q15

Purchased

Put

Propane

630,000

0.9375


3Q15

Purchased

Put

Propane

1,260,000

0.8825








CRUDE OPTIONS









Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price


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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