Atlas Pipeline Partners, L.P. Reports First Quarter 2013 Results - Adjusted EBITDA for first quarter 2013 was $67.7 million, a 32% increase year-over-year

- Average processed gas volumes exceeds 1 billion cubic feet per day (BCFD) in first quarter 2013

- Distributable Cash Flow for first quarter 2013 of $43.5 million, a 23% increase year-over-year

- Previously announced distribution of $0.59 per common limited partner unit, a 5% increase year-over-year

- Atlas Pipeline recently announces transformative $1 billion acquisition of TEAK to enter Eagle Ford Shale

PHILADELPHIA, April 29, 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 $67.7 million for the first quarter of 2013, driven primarily by a continued increase in volumes across the Partnership's gathering and processing systems.  Processed natural gas volumes averaged 1,033 million cubic feet per day ("MMCFD"), a 63% increase over the first quarter of 2012.  Distributable Cash Flow was $43.5 million for the first quarter of 2013, or $0.67 per average common limited partner unit, compared to $35.2 million for the prior year's first quarter.  The Partnership recognized a net loss of $27.5 million for the first quarter of 2013, which included a $26.6 million loss on the early retirement of the Partnership's 8.75% Senior Notes due 2018, compared with net income of $6.5 million for the prior year first 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 April 24, 2013, the Partnership declared a distribution for the first quarter of 2013 of $0.59 per common limited partner unit to holders of record on May 8, 2013, which will be paid on May 15, 2013.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.04x on a fully diluted basis for the first quarter of 2013, excluding the most recent common equity issuance that closed on April 23, 2013.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, "The year has already provided for some very exciting announcements for Atlas Pipeline.  It is with great pleasure that, since the end of the quarter, we have announced a major entry into the Eagle Ford with the $1 billion announced purchase of TEAK Midstream.  This is a major win for the Partnership, adding tremendous expected future growth while reducing APL cash flow volatility through diversity and significant fixed fee business. Since the end of the quarter, we have also brought the Driver expansion online in West Texas and are receiving NGL takeaway capacity relief on our two largest systems, which will lead to more NGL's being produced and more future cash flow to the Partnership.  Our first quarter of 2013 came in line with expectations, aside from some weather disruptions, which can be a normal occurrence during winter months.  More importantly, looking forward, our business and future opportunities have never looked better after all of the recent positive developments we have just announced.  I would like to thank our investors who have supported us as we grow, and assure all of us our best days still lay ahead."  

Significant Developments after First Quarter of 2013

Since the end of the reporting period, the Partnership has publicly announced several developments that are expected to have a significant impact on the Distributable Cash Flow of APL for 2013-2014.  On April 15, 2013, Atlas Pipeline announced that the 200 MMCFD Driver plant has come online at the WestTX facility, increasing capacity from 255 MMCFD to 455 MMCFD.  In addition to the expansion at WestTX, APL also announced the addition of further NGL takeaway capacity to deliver incremental natural gas liquids from its WestOK and WestTX processing systems.  These connections will eliminate the near-term constraints on our NGL production at these systems and better utilize the Waynoka II and Driver expansions that were brought in service in September 2012 and April 2013, respectively.

Additionally, on April 16, 2013, the Partnership announced the acquisition of TEAK Midstream, L.L.C. ("TEAK"), a private midstream company in the prolific Eagle Ford shale.  TEAK currently has 200 MMCFD in processing capacity with 200 MMCFD of additional capacity expected in 2014 and potentially an additional 200 MMCFD processing facility to be added in 2015.  The cash flow of TEAK is approximately 80% fixed-fee, which will serve to greatly reduce the commodity sensitivity of the Partnership's overall cash flows upon build-out and utilization of the system.  Please refer to the Partnership's press release from April 16, 2013 ("Atlas Pipeline Partners, L.P. To Acquire Eagle Ford Midstream Business For $1 Billion From TEAK Midstream") for more information regarding the transaction.

*    *    *

Updated 2013-2014 Forecasted Guidance

Upon the announcement of the acquisition of TEAK, APL initiated guidance for 2014, including forecasted Adjusted EBITDA of between $450 to $500 million and anticipated distributions of between $2.75 and $2.85 per limited partner unit.  The Partnership is now updating Adjusted EBITDA for 2013 to between $360 million and $400 million based on current commodity pricing curves for natural gas, natural gas liquids, and crude oil.  The resulting forecasted Distributable Cash Flow for 2013 is expected to range from $230 million to $270 million based on the same assumptions.   Based on the Partnership's distribution coverage targets, the forecasted distributions for 2013 remain between $2.50 and $2.60 per limited partner unit for the calendar year.  The Partnership expects growth capital expenditures for the year to total approximately $450 million, based on previously announced expansion projects, including the now completed Driver plant and anticipated phase one of the Stonewall plant, as well as new infrastructure and projected well connections to support further volume growth on our existing and systems, including TEAK.  It is important to note that the range of guidance for 2013 is based on information that has been publicly announced to date.  Management will address the future outlook of the Partnership on the earnings conference call tomorrow morning as well as discuss recent developments since the end of the first quarter. 

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

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $453.7 million as of March 31, 2013.  Total debt outstanding was $1,318.9 million at March 31, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $139.0 million.  Based upon total debt outstanding at March 31, 2013, total leverage was approximately 4.6x for purposes of calculations under our revolving credit facility, and debt to total capital was 46%. The Partnership recently announced the closing of a follow-on common equity issuance totaling 11,845,000 common limited partner units, resulting in gross proceeds of $402.7 million which will be used to fund the acquisition of TEAK.  The Partnership also expects to issue $400 million of mandatorily convertible Class D Preferred Units in connection with the closing of the TEAK acquisition.

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2016.  As of April 29, 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 75%, 58%, and 33% respectively, of associated margin value (exclusive of ethane).  The Partnership has also begun to add to protection in 2016.  The percentages do not include the TEAK acquisition, which has not closed as of the date of this press release.  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 April 29, 2013 is included in this release.

*    *    *

Operating Results

The Partnership continues to report record volumes, and with the addition of the Arkoma assets, is now processing, on average, over 1.0 billion cubic feet per day of natural gas per day.  Gross margin from operations was $91.1 million for the first quarter 2013, compared to $69.1 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 and Velma systems, as well as the newly acquired Arkoma system, and was partially offset by lower NGL prices.  The gross margin for the quarter does not include approximately $1.6 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $0.8 million realized derivative settlement losses excluded from gross margin in the first quarter of 2012.   

WestTX System

The WestTX system's average natural gas processed volume was 280.8 MMCFD for the first quarter 2013, compared to 230.5 MMCFD for first quarter of 2012.  Increased volumes are primarily due to increased production in the Spraberry and Wolfberry formations of the Permian basin, including an increase in the number of horizontally drilled wells by our producer customers.  Average NGL production volumes were 33,245 barrels per day ("BPD") for the first quarter 2013, a 0.4% increase from first quarter 2012.  The Partnership expects processed volumes on this system to continue to increase as residue gas and NGL take-away constraints have been removed and producers continue to pursue their drilling plans over the coming years.  The construction of the previously announced Driver plant, which increases processing capacity by 200 MMCFD, was completed and placed into service on April 12, 2013 and will allow for more efficient processing and delivery of natural gas and NGLs going forward. 

WestOK System

The WestOK system had average natural gas processed volume of 425.4 MMCFD for the first quarter, a 52.3% increase from first quarter 2012.  Average NGL production was 16,251 BPD for the first quarter 2013, a 15.6% increase from first quarter 2012, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012.  First quarter 2013 results were negatively impacted by certain weather events in western Oklahoma which caused the loss of power and the shut-in of significant volumes for approximately 10 days in late February and early March.  The Partnership estimates that the financial impact for this period was between $2 to $3 million in Adjusted EBITDA.  The Partnership recently announced 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.  This pipeline will allow the Partnership to process and deliver incremental NGL volumes from the WestOK system, including full production from the Waynoka I and Waynoka II facilities.   

Velma System

The Velma system's average natural gas processed volume was 125.4 MMCFD for the first quarter 2013, a 2.0% increase from first 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 13,997 BPD for the first quarter 2013, up approximately 2.6% compared to first quarter 2012, due to the increased processed volumes.  In June 2012, the Partnership completed the previously announced plans to expand the Velma system by adding a 60 MMCFD cryogenic plant (the "V-60 plant"), which supports the additional volumes from XTO Energy, Inc ("XTO").  Volumes on the Velma system were greater than the fourth quarter of 2012 primarily due to XTO returning gas to V-60 during the period.    

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 201.3 MMCFD and produced 20,555 BPD of NGLs during the first 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.

*    *    *

Corporate and Other

Net of deferred financing costs, interest expense increased to $17.1 million for the first quarter of 2013, up 34.2% as compared with the first quarter of 2012.  This increase was due to financing the Partnership's capital expenditure program during 2012 and 2013, including the issuance of senior unsecured notes in September and December 2012, as well as the February 2013 issuance of new 5.875% senior unsecured notes due 2023.  These new senior unsecured notes were issued in connection with the redemption of the Partnership's 8.75% Senior Notes due 2018, which resulted in a loss on the early termination of debt totaling $26.6 million in the first quarter 2013.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's first quarter 2013 results on Tuesday, April 30, 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, April 30, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 32722721.

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, northern and western Texas, and Tennessee, APL owns and operates 13 active gas processing plants, 18 gas treating facilities, as well as approximately 10,100 miles of active intrastate gas gathering pipeline.  APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns and operates the general partner of 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 9% limited partner interest. Additionally, Atlas Energy owns all of the general partner Class A units and incentive distribution rights and an approximate 43% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P.  For more information, please visit the Partnership's 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


March 31,


2013


2012

Revenue:




Natural gas and liquids

$

383,848


$

289,225

Transportation, processing and other fees(2)

32,725


12,681

Derivative loss, net

(12,083)


(12,035)

Other income, net

3,422


2,415





Total revenue and other income, net

407,912


292,286





Costs and expenses:




Natural gas and liquids

325,540


233,105

Plant operating

21,271


13,881

Transportation and compression

588


264

General and administrative(3)

9,414


8,967

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

4,384


978

Other costs

530


(34)

Depreciation and amortization

30,458


20,842

Interest

18,686


8,708





Total costs and expenses

410,871


286,711





Equity income in joint venture

2,040


896

Loss on early extermination of debt

(26,582)






Income (loss) from continuing operations, before tax

(27,501)


6,471





Income tax benefit

(9)






Net income (loss)

(27,492)


6,471





Income attributable to non-controlling interests

(1,369)


(1,536)

Net income attributable to common limited partners and the general partner

$

(28,861)


$

4,935





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





Basic and diluted:

$

(0.48)


$

0.06





Weighted average common limited partner units (basic)

64,646


53,620





Weighted average common limited partner units (diluted)

64,646


54,013



(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



March 31,



2013


2012








Summary Cash Flow Data:







Net cash provided by (used in):







Operating activities


$

34,856


$

42,747

Investing activities



(107,990)



(98,276)

Financing activities



77,997



55,529








Capital Expenditure Data:







Maintenance capital expenditures


$

3,855


$

4,510

Expansion capital expenditures



104,661



76,657

Acquisitions





17,235








Total


$

108,516


$

98,402

 


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)

 


ASSETS


March 31,

2013


December 31,
2012






Current assets:







Cash and cash equivalents


$

8,261


$

3,398

Other current assets



216,853



216,677








Total current assets



225,114



220,075








Property, plant and equipment, net



2,299,967



2,200,381

Intangible assets, net



502,071



518,645

Investment in joint ventures



86,242



86,002

Other assets, net



41,036



40,535










$

3,154,430


$

3,065,638








LIABILITIES AND EQUITY





















Current liabilities


$

252,059


$

253,519

Long-term debt, less current portion



1,310,051



1,169,083

Deferred income taxes, net



30,249



30,258

Other long-term liability



7,283



6,370








Total partners' capital



1,487,942



1,539,177

Non-controlling interest



66,846



67,231








Total equity



1,554,788



1,606,408










$

3,154,430


$

3,065,638


 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

 




Three Months Ended

March 31,



2013


2012

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








Net income


$

(27,492)


$

6,471


Income attributable to non-controlling interests(2)



(1,369)



(1,536)


Depreciation and amortization



30,458



20,842


Income tax benefit



(9)




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



(850)





Interest expense



18,686



8,708










EBITDA



19,424



34,485










Adjustment for cash flow from investment in joint ventures



(240)



904


Non-cash loss on derivatives



13,719



10,696


Successful acquisition costs



530




Premium expense on derivative instruments



3,275



3,752


Loss on early termination of debt



26,582




Other non-cash losses(4)



4,416



1,250










Adjusted EBITDA



67,706



51,087










Interest expense



(18,686)



(8,708)


Amortization of deferred financing costs



1,544



1,165


Premium expense on derivative instruments



(3,275)



(3,752)


Other costs





(34)


Maintenance capital expenditures



(3,814)



(4,510)










Distributable Cash Flow


$

43,475


$

35,248




(1)  EBITDA, Adjusted EBITDA and Distributable Cash Flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission.  Management of the Partnership believes EBITDA, Adjusted EBITDA and Distributable Cash Flow provide additional information for evaluating the Partnership's ability to make distributions to its common unitholders and the general partner, among other things.  These measures are widely-used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards.  Adjusted EBITDA is also similar to the Consolidated EBITDA calculation utilized for the Partnership's financial covenants under its credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of the Partnership's 49% interest in Laurel Mountain; and (ii) other non-cash items specifically excluded under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP

(2)  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 and non-cash compensation












 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 



Three Months Ended March 31,


2013


2012


Percent
Change

Pricing (unhedged):












Mid-Continent Weighted Average Prices:






NGL price per gallon – Conway hub

$

0.83


$

0.93


(10.8)%

NGL price per gallon – Mt. Belvieu hub


0.85



1.18


(28.0)%







Natural gas sales ($/MCF):






Velma

3.17


2.55


24.3%

WestOK

3.20


2.56


25.0%

WestTX

3.12


2.51


24.3%

Weighted Average

3.17


2.54


24.8%







NGL sales ($/Gallon):






Arkoma

0.70


-


-

Velma

0.75


0.93


(19.4)%

WestOK

0.98


0.91


7.7%

WestTX

0.93


1.17


(20.5)%

Weighted Average

0.90


1.03


(12.6)%







Condensate sales ($/Barrel):






Arkoma

87.92


-


-

Velma

93.39


102.22


(8.6)%

WestOK

83.67


93.95


(10.9)%

WestTX

88.02


101.38


(13.2)%

Weighted Average

86.00


97.44


(11.7)%

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 



Three Months Ended March 31,


2013


2012


Percent
Change







Volumes:












Arkoma system:






Gathered gas volume (MCFD)

260,732


-


-

Processed gas volume(2) (MCFD)

201,301


-


-

Residue gas volume (MCFD)

207,844


-


-

Processed NGL volume (BPD)

20,555


-


-

Condensate volume (BPD)

158


-


-







Velma system:






Gathered gas volume (MCFD)

130,767


129,223


1.2%

Processed gas volume(2) (MCFD)

125,377


122,904


2.0%

Residue gas volume (MCFD)

102,238


100,335


1.9%

Processed NGL volume (BPD)

13,997


13,643


2.6%

Condensate volume (BPD)

405


564


(28.2)%







WestOK system:






Gathered gas volume (MCFD)

452,368


295,198


53.2%

Processed gas volume(2) (MCFD)

425,431


279,305


52.3%

Residue gas volume (MCFD)

396,694


251,940


57.5%

Processed NGL volume (BPD)

16,251


14,062


15.6%

Condensate volume (BPD)

1,969


1,405


40.1%







WestTX system(3):






Gathered gas volume (MCFD)

312,571


246,339


26.9%

Processed gas volume(2) (MCFD)

280,756


230,504


21.8%

Residue gas volume (MCFD)

209,891


160,022


31.2%

Processed NGL volume (BPD)

33,245


33,101


0.4%

Condensate volume (BPD)

1,033


939


10.0%







Barnett system:






   Gathered gas volumes (MCFD)

21,401


-


100%







Tennessee system:






   Gathered gas volumes (MCFD)

9,495


8,225


15.4%







West Texas LPG Partnership(4)






      Average NGL volumes (BPD)

244,626


242,318


1.0%







Consolidated Volumes:






     Gathered gas volume (MCFD)

1,187,334


678,985


74.9%

     Processed gas volume (MCFD)

1,032,865


632,713


63.2%

     Residue gas volume (MCFD)

916,667


512,297


78.9%

     Processed NGL volume (BPD)

84,048


60,806


38.2%

     Condensate volume (BPD)

3,565


2,908


22.6%



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

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

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

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









ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of April 29, 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

2Q 2013

Sold

Propane – Conway

1,260,000

1.06

2Q 2013

Sold

Propane

10,836,000

1.27

2Q 2013

Sold

Isobutane

630,000

1.77

2Q 2013

Sold

Normal butane

1,260,000

1.66

3Q 2013

Sold

Propane – Conway

1,260,000

1.06

3Q 2013

Sold

Propane

12,726,000

1.25

4Q 2013

Sold

Propane – Conway

1,260,000

1.06

4Q 2013

Sold

Propane

12,222,000

1.28

1Q 2014

Sold

Propane

8,694,000

1.00

1Q 2014

Sold

Natural gasoline

1,260,000

2.08

2Q 2014

Sold

Propane

8,442,000

0.96

2Q 2014

Sold

Normal Butane

1,260,000

1.50

2Q 2014

Sold

Natural gasoline

3,150,000

1.94

3Q 2014

Sold

Propane

8,190,000

0.97

3Q 2014

Sold

Normal Butane

1,260,000

1.50

3Q 2014

Sold

Natural gasoline

2,520,000

1.94

4Q 2014

Sold

Propane

8,190,000

0.98

4Q 2014

Sold

Normal Butane

1,260,000

1.53

4Q 2014

Sold

Natural gasoline

2,520,000

1.95

1Q 2015

Sold

Propane

7,686,000

0.95

1Q 2015

Sold

Natural gasoline

2,142,000

1.91

2Q 2015

Sold

Propane

8,064,000

0.92

2Q 2015

Sold

Natural gasoline

630,000

1.97

3Q 2015

Sold

Propane

378,000

0.93

3Q 2015

Sold

Natural gasoline

630,000

1.97

4Q 2015

Sold

Propane

3,528,000

0.96

4Q 2015

Sold

Natural gasoline

630,000

1.97

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of April 24, 2013)

 

 

SWAP CONTRACTS

 

 

CONDENSATE HEDGES






Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

2Q 2013

Sold

Crude

99,000

97.33

3Q 2013

Sold

Crude

78,000

97.08

4Q 2013

Sold

Crude

75,000

96.66

1Q 2014

Sold

Crude

93,000

95.45

2Q 2014

Sold

Crude

90,000

93.43

3Q 2014

Sold

Crude

75,000

89.86

4Q 2014

Sold

Crude

45,000

88.16

1Q 2015

Sold

Crude

15,000

85.13

2Q 2015

Sold

Crude

15,000

85.13

3Q 2015

Sold

Crude

15,000

85.13

4Q 2015

Sold

Crude

15,000

85.13

 


NATURAL GAS HEDGES






Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

2Q 2013

Sold

Natural gas

600,000

3.43

3Q 2013

Sold

Natural gas

1,100,000

3.60

4Q 2013

Sold

Natural gas

1,420,000

3.69

1Q 2014

Sold

Natural gas

1,500,000

3.91

2Q 2014

Sold

Natural gas

2,500,000

3.87

3Q 2014

Sold

Natural gas

4,000,000

3.95

4Q 2014

Sold

Natural gas

4,000,000

4.05

1Q 2015

Sold

Natural gas

3,100,000

4.29

2Q 2015

Sold

Natural gas

3,100,000

4.13

3Q 2015

Sold

Natural gas

3,100,000

4.17

4Q 2015

Sold

Natural gas

2,800,000

4.26

1Q 2016

Sold

Natural gas

300,000

4.40

2Q 2016

Sold

Natural gas

300,000

4.40

3Q 2016

Sold

Natural gas

300,000

4.40

4Q 2016

Sold

Natural gas

300,000

4.40

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of April 24, 2013)

 

 

OPTION CONTRACTS

 

 

NGL OPTIONS







Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

2Q 2013

Purchased

Put

Propane

1,260,000

0.87

2Q 2013

Purchased

Put

Isobutane

630,000

1.72

2Q 2013

Purchased

Put

Normal Butane

1,638,000

1.66

2Q 2013

Purchased

Put

Natural Gasoline

5,796,000

2.10

3Q 2013

Purchased

Put

Isobutane

1,512,000

1.66

3Q 2013

Purchased

Put

Normal Butane

3,528,000

1.64

3Q 2013

Purchased

Put

Natural Gasoline

6,300,000

2.09

4Q 2013

Purchased

Put

Isobutane

1,512,000

1.66

4Q 2013

Purchased

Put

Normal Butane

3,780,000

1.66

4Q 2013

Purchased

Put

Natural Gasoline

6,552,000

2.09

 

 

CRUDE OPTIONS







Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

2Q 2013

Purchased

Put

Crude Oil

69,000

100.10

3Q 2013

Purchased

Put

Crude Oil

72,000

100.10

4Q 2013

Purchased

Put

Crude Oil

75,000

100.10

1Q 2014

Purchased

Put

Crude Oil

166,500

101.86

2Q 2014

Purchased

Put

Crude Oil

45,000

88.18

3Q 2014

Purchased

Put

Crude Oil

75,000

89.68

4Q 2014

Purchased

Put

Crude Oil

102,000

91.64

1Q 2015

Purchased

Put

Crude Oil

45,000

91.33

2Q 2015

Purchased

Put

Crude Oil

75,000

89.49

3Q 2015

Purchased

Put

Crude Oil

75,000

88.59

4Q 2015

Purchased

Put

Crude Oil

75,000

88.15

 

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.



RELATED LINKS
http://www.atlaspipeline.com

More by this Source


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

 

PR Newswire Membership

Fill out a PR Newswire membership form or contact us at (888) 776-0942.

Learn about PR Newswire services

Request more information about PR Newswire products and services or call us at (888) 776-0942.