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Atlas Pipeline Partners, L.P. Reports Fourth Quarter And Full Year 2012 Results

-- Adjusted EBITDA for fourth quarter 2012 was $64.1 million, a 30% increase year-over-year

PHILADELPHIA, Feb. 18, 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 $64.1 million for the fourth quarter of 2012, driven by a continued increase in volumes across the Partnership's gathering and processing systems.  Processed natural gas volumes averaged 1,002 million cubic feet per day ("MMCFD"), a 67% increase over the fourth quarter of 2011.  Distributable Cash Flow was $40.4 million for the fourth quarter of 2012, or $0.72 per average common limited partner unit, compared to $36.0 million for the prior year fourth quarter.  These results include one month of operations for the Partnership's newly acquired Arkoma assets, which were purchased on December 20, 2012 and have an effective date as of December 1, 2012.  Net loss was $6.9 million for the fourth quarter of 2012, which in accordance with GAAP includes eleven days of earnings from the Arkoma assets, compared with net loss of $5.3 million for the prior year fourth quarter.

For the full year 2012, Adjusted EBITDA was $220.2 million, compared to full year 2011 Adjusted EBITDA of $181.0 million, a 22% increase from prior year.  Net income was $68.1 million for the full year 2012, compared to net income of $295.4 million for the prior year, which included a $256.3 million gain on the sale of the Partnership's remaining interest in the Laurel Mountain joint venture.  For the full year 2012, Distributable Cash Flow was $146.0 million, an increase of approximately 12% over the full year 2011 Distributable Cash Flow of $129.9 million.  Distributable Cash Flow per average common limited partner unit for the full year 2012 was $2.69.

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 January 23, 2013, the Partnership declared a distribution for the fourth quarter of 2012 of $0.58 per common limited partner unit to holders of record on February 7, 2013, which was paid on February 14, 2013.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.0x on a fully diluted basis for the fourth quarter of 2012, however coverage would have been 1.1x pro forma if the operating results for the Arkoma assets had been included for the entire quarter.

"This has been a very successful year for the Partnership.  Even with weaker natural gas and NGL pricing, not having full NGL takeaway at our two largest systems, and various 3rd party disruptions of operations both upstream and downstream, we still managed to increase our distribution three out of four quarters, paying out 16% more in cash flow than we did for 2011.  Additionally, in the face of those headwinds, we managed to expand two out of our three legacy processing systems and purchase a fourth system for $600 million in December, most of which is fixed-fee cash flow, reducing our commodity exposure.  With another legacy expansion coming this spring, coupled with much needed NGL takeaway at our two largest systems, plus the addition of a previously announced expansion at our new Arkoma system, we have plenty of catalysts to take the distribution even higher in 2013 and beyond.  We expect to continue to announce opportunities this year to add to our expanding portfolio of growth and wish to thank all of our supporters in our efforts," stated Eugene Dubay, Chief Executive Officer of the Partnership.

2013 Forecasted Guidance

The Partnership is forecasting Adjusted EBITDA for 2013 between $320 million and $360 million based on current commodity pricing curves for natural gas, natural gas liquids component products, and crude oil.  The resulting forecasted Distributable Cash Flow for 2013 would range from $200 million to $240 million based on the same assumptions.   Based on the Partnership's distribution coverage targets, the forecasted distributions for 2013 would be between $2.50 and $2.60 per limited partner unit.  The Partnership is currently expecting growth capital expenditures for the year to total approximately $350 million, based on previously announced expansion projects, including completion of the Driver and Stonewall facilities, as well as new infrastructure and projected well connections to support further volume growth on our existing systems.  It is important to note that the range of guidance for 2013 is based information that has been publicly announced to date. The Partnership expects to update guidance as future growth projects are announced this year.   The Partnership's management team will address the 2013 outlook on the earnings conference call tomorrow morning. 

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 $310.3 million as of December 31, 2012.  Pro forma for the recently completed senior notes offering and tender offer, total liquidity would have been approximately $551 million at December 31, 2012.  Total debt outstanding was $1,179.9 million at December 31, 2012, compared to $524.1 million at December 31, 2011, an increase of $655.8 million.  Based upon total debt outstanding at December 31, 2012, total leverage was approximately 4.5x, including historical earnings from the Arkoma acquisition, and debt to capital was 43%. Total leverage was approximately 4.0x for purposes of calculations under our revolving credit facility.

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2015.  As of February 15, 2013, the Partnership has natural gas, natural gas liquids and condensate protection in place for the full years of 2013 and 2014 for approximately 78% and 56%, respectively, of associated margin value (exclusive of ethane).  The Partnership has also added protection into 2015 covering approximately 24% of associated margin value (exclusive of ethane).  Counterparties to the Partnership's risk management activities consist of investment grade commercial banks that are lenders under the Partnership's credit facility, or affiliates of those banks.  A table summarizing our risk management portfolio is included in this release.

Operating Results

The Partnership continues to report record volumes, and with the addition of the Arkoma assets, is now processing, on average, over 1.0 BCFD of natural gas. Gross margin from operations was $79.5 million for the fourth quarter 2012 and $278.1 for the full year 2012, compared to $69.6 million and $264.9 million for the prior year periods, respectively.  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, partially offset by decreased NGL prices.  The gross margin for the quarter does not include approximately $3.9 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $1.7 million realized derivative settlement losses excluded from gross margin in the fourth quarter of 2011. 

WestTX System

The WestTX system's average natural gas processed volume was 271.6 MMCFD and 249.2 MMCFD for the fourth quarter and full year 2012, respectively, compared to 220.5 MMCFD and 196.4 MMCFD for prior year comparable periods.  Increased volumes are primarily due to increased production in the Spraberry and Wolfberry Trends of the Permian basin.  Average NGL production volumes were 34,913 barrels per day ("BPD") and 32,314 BPD for the fourth quarter and full year 2012, respectively, an 8.5% and 11.2% increase from prior year comparable periods.  The Partnership expects processed volumes on this system to continue to increase as producers continue to pursue their drilling plans over the coming years.  The construction of the previously announced Driver plant, which will increase processing capacity by 200 MMCFD, is expected to be completed by the end of the first quarter or beginning of the second quarter of 2013. 

WestOK System

The WestOK system had average natural gas processed volume of 412.7 MMCFD and 348.0 MMCFD for the fourth quarter and full year 2012, respectively, a 49.7% and 36.8% increase from the prior year comparable periods.  Average NGL production was 16,576 BPD and 14,505 BPD, respectively, for the fourth quarter and full year 2012, respectively, a 15.5% increase and 6.4% increase from the prior year comparable periods, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012.    The Partnership expects volumes to continue to increase as producers in Oklahoma and Kansas, continue to add to the system via development in the oil-rich Mississippian Limestone formation. 

Velma System

The Velma system's average natural gas processed volume was 106.6 MMCFD and 114.4 MMCFD for the fourth quarter and full year 2012, respectively, a 1.4% and 16.6% increase from the prior year comparable periods.  The increase is primarily due to additional production gathered on the Madill to Velma pipeline system from continued producer activity in the liquids-rich portion of the Woodford Shale.  Average NGL production increased to 12,493 BPD and 13,850 BPD for the fourth quarter and full year 2012, respectively, up approximately 3.4% and 21.1% compared to the prior year comparable periods, 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 lower than the third quarter of 2012 primarily due to XTO diverting gas to a third party during the period.  The Partnership expects these volumes to return in 2013 and has a fee-based commitment from XTO on the V-60 plant that commences in mid-2013. 

Arkoma System

On December 20, 2012, the Partnership acquired 100% of the equity interests held by Cardinal Midstream in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments.  The assets of these companies 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 211.0 MMCFD and produced 16,138 BPD of NGLs during the effective period it was owned by the Partnership. Centrahoma is in the process of constructing a new processing facility, the Stonewall plant, which is expected to be complete in early 2014, with anticipated initial processing capacity of 120 MMCFD. 

Corporate and Other

Net of deferred financing costs, interest expense increased to $14.1 million and $41.8 million for the fourth quarter and full year 2012, respectively, up 135.0% and 54.2% as compared with the fourth quarter and full year 2011.  This increase was due to financing the Partnership's $600 million capital expenditure program during 2011 and 2012, including the issuance of senior unsecured notes in November 2011, as well as the issuance of additional senior unsecured notes in September and December 2012.

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's fourth quarter 2012 results on Tuesday, February 19, 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, February 19, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 61912389.

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 12 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 [email protected].

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 44% 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 [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 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.

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


Year Ended



December 31,


December 31,



2012


2011


2012


2011


Revenue:












Natural gas and liquids sales

$

334,617


$

330,220


$

1,137,261


$

1,268,195


Transportation, processing and other fees(2)


19,891



12,263



66,722



43,799


Derivative gain (loss), net(3)


(4,965)



(29,404)



31,940



(20,452)


Other income, net(3)


2,509



2,827



10,097



11,192


Total revenues


352,052



315,906



1,246,020



1,302,734















Costs and expenses:













Natural gas and liquids cost of sales


274,960



272,166



927,946



1,047,025


Plant operating


16,819



14,446



60,480



54,686


Transportation and compression


622



230



1,618



833


General and administrative(4)


10,595



8,769



35,570



33,083


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


4,098



767



11,636



3,274


Other


15,372



457



15,069



1,040


Depreciation and amortization


24,314



19,936



90,029



77,435


Interest


14,091



7,078



41,760



31,603


Total costs and expenses


360,871



323,849



1,184,108



1,248,979















Equity income in joint ventures


2,088



2,091



6,323



5,025


Gain on asset sales and other




598





256,272


Loss on early extinguishment of debt








(19,574)


Income (loss) from continuing operations, before tax


(6,731)



(5,254)



68,235



295,478















Income tax expense (benefit)


176





176




Income (loss) from continuing operations, after tax


(6,907)



(5,254)



68,059



295,478


Loss on sale of discontinued operations








(81)















Net income


(6,907)



(5,254)



68,059



295,397















Income attributable to non-controlling interests


(1,902)



(1,708)



(6,010)



(6,200)


Preferred unit dividends








(389)


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

$

(8,809)


$

(6,962)


$

62,049


$

288,808



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













Basic and diluted:

$

(0.22)


$

(0.15)


$

0.95


$

5.22


Weighted average common limited partner units (basic)


56,288



53,617



54,326



53,525


         Weighted average common limited partner units (diluted)


56,288



53,617



55,138



53,944



 

(1)

Based on the GAAP statements of operations to be included in Form 10-K, with additional detail of certain items included

(2)

Includes affiliate revenues related to transportation and processing provided to Atlas Resource Partners, L.P

(3)

Adjusted to separately present derivative gain (loss) within derivative gain (loss), net instead of combining these amounts in other income, net

(4)

Non-cash costs associated with unit-based compensation, which have been reflected in the general and administrative costs and expenses, the category associated with the direct personnel cash costs in the GAAP statements of operations to be included in Form 10-K.  General and administrative also includes any compensation reimbursement to affiliates

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary (continued)
(unaudited; in thousands)








Three Months Ended


Year Ended



December 31,


December 31,



2012


2011


2012


2011


Summary Cash Flow Data:













Cash provided by operating activities

$

48,939


$

22,209


$

174,638


$

102,867


Cash provided by (used in) investing activities


(727,916)



(98,231)



(1,006,641)



67,763


Cash provided by (used in) financing activities


682,034



76,023



835,233



(170,626)















Capital Expenditure Data:













Maintenance capital expenditures

$

5,780


$

4,796


$

19,021


$

18,247


Expansion capital expenditures


125,342



92,486



354,512



227,179


Investments in joint ventures and acquisitions


596,921





633,610



97,250















Total

$

728,043


$

97,282


$

1,007,143


$

342,676
















 

 


Condensed Consolidated Balance Sheets
(unaudited; in thousands)






ASSETS


December 31,

2012


December 31,
2011






Current assets:







Cash and cash equivalents


$

3,398


$

168

Other current assets



216,677



132,698








Total current assets



220,075



132,866








Property, plant and equipment, net



2,200,381



1,567,828

Intangible assets, net (including goodwill)



518,645



103,276

Investment in joint ventures



86,002



86,879

Other assets, net



40,535



39,963










$

3,065,638


$

1,930,812








LIABILITIES AND EQUITY





















Current liabilities


$

253,519


$

172,406

Long-term debt, less current portion



1,169,083



522,055

Deferred income taxes, net



30,258



Other long-term liabilities



6,370



123








Commitments and contingencies














Total partners' capital



1,539,177



1,264,629

Non-controlling interest



67,231



(28,401)








Total equity



1,606,408



1,236,228










$

3,065,638


$

1,930,812









 



ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Reconciliation of Non-GAAP Measures(1)
(unaudited; in thousands)






Three Months Ended


Year Ended


December 31,


December 31,


2012


2011


2012


2011













Net income

$

(6,907)


$

(5,254)


$

68,059


$

295,397

Income attributable to non-controlling interests


(1,902)



(1,708)



(6,010)



(6,200)

Income tax expense


176





176



Interest expense


14,091



7,078



41,760



31,603

Depreciation and amortization


24,314



19,936



90,029



77,435













EBITDA


29,772



20,052



194,014



398,235

Adjustment for cash flow from investment in joint ventures


(288)



(191)



877



(577)

Gain on asset sale




(598)





(256,191)

Loss on early extinguishment of debt








19,574

Unrecognized economic impact of acquisition(4)


1,698





1,698



Non-cash (gain) loss on derivatives


8,285



27,015



(23,283)



4,538

Premium expense on derivative instruments


5,168



2,905



17,759



12,219

Acquisition costs


15,372





15,395



Other non-cash losses(2)


4,089



56



13,747



3,228













Adjusted EBITDA


64,096



49,239



220,207



181,026

Interest expense


(14,091)



(7,078)



(41,760)



(31,603)

Amortization of deferred finance costs


1,316



1,126



4,672



4,480

Preferred unit dividends








(389)

Premium expense on derivative instruments


(5,168)



(2,905)



(17,759)



(12,219)

Proceeds remaining from asset sale(3)








5,850

Other costs




457



(326)



1,040

Maintenance capital


(5,779)



(4,796)



(19,021)



(18,247)













Distributable Cash Flow

$

40,374


$

36,043


$

146,013


$

129,938



(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 (i) includes EBITDA from the discontinued operations related to the sale of the Partnership's 49% interest in Laurel Mountain; (ii) includes other non-cash items specifically excluded under the credit facility; and (iii) excludes projected revenues from certain capital expansions allowed by the financial covenants under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP

(2)

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

(3)

Net proceeds remaining from the sale of Laurel Mountain after the repayment of the amount outstanding on our revolving credit facility, redemption of our 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018

(4)

Unrecognized economic impact of acquisition represents the estimated Adjusted EBITDA associated with acquisitions for the period from the effective date to the closing date.  These earnings are recorded as an adjustment to the purchase price in accordance with GAAP

 

 

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






Three Months Ended December 31,


Year Ended December 31,


2012


2011


Percent Change


2012


2011


Percent Change

Pricing (unhedged):












Weighted Average Market Prices:












NGL price per gallon – Conway hub

$

0.80


$

1.01


(20.8)%


$

0.78


$

1.08


(27.8)%

NGL price per gallon – Mt. Belvieu hub


0.86



1.35


(36.3)%



0.96



1.31


(26.7)%

Natural gas sales ($/MCF):












Velma

3.17


3.36


(5.7)%


2.60


3.86


(32.6)%

WestOK

3.21


3.43


(6.4)%


2.66


3.87


(31.3)%

WestTX

3.12


3.35


(6.9)%


2.54


3.84


(33.9)%

Weighted average

3.18


3.40


(6.5)%


2.62


3.86


(32.1)%

NGL sales ($/Gallon):












Velma

0.75


1.08


(30.6)%


0.78


1.11


(29.7)%

WestOK

0.97


0.99


(2.0)%


0.89


1.10


(19.1)%

WestTX

0.92


1.35


(31.9)%


0.98


1.33


(26.3)%

Weighted average

0.90


1.17


(23.1)%


0.90


1.20


(25.0)%

Condensate sales ($/barrel):












Velma

87.31


94.21


(7.3)%


94.82


94.35


0.5%

WestOK

78.08


86.35


(9.6)%


84.76


86.63


(2.2)%

WestTX

83.16


93.27


(10.8)%


89.40


92.84


(3.7)%

Weighted average

80.75


89.75


(10.0)%


87.88


90.65


(3.1)%


Operating data:
























Velma system:












Gathered gas volume (MCFD)

111,572


108,475


2.9%


128,548


103,328


24.4%

Processed gas volume (MCFD)(2)

106,577


105,115


1.4%


114,421


98,126


16.6%

Residue Gas volume (MCFD)

87,534


85,873


1.9%


100,711


80,330


25.4%

NGL volume (BPD)

12,493


12,084


3.4%


13,850


11,433


21.1%

Condensate volume (BPD)

356


376


(5.3)%


409


423


(3.3)%

WestOK system:












Gathered gas volume (MCFD)

436,694


290,485


50.3%


369,035


268,329


37.5%

Processed gas volume (MCFD)(2)

412,682


275,567


49.8%


348,041


254,394


36.8%

Residue Gas volume (MCFD)

383,107


250,933


52.7%


383,107


230,907


65.9%

NGL volume (BPD)

16,576


14,348


15.5%


14,505


13,635


6.4%

Condensate volume (BPD)

1,484


1,063


39.6%


1,360


898


51.4%

WestTX system(3):












Gathered gas volume (MCFD)

298,252


235,582


26.6%


275,946


212,775


29.7%

Processed gas volume (MCFD)

271,592


220,506


23.2%


249,221


196,412


26.9%

Residue Gas volume (MCFD)

201,549


149,506


34.8%


179,539


133,857


34.1%

NGL volume (BPD)

34,913


32,165


8.5%


32,314


29,052


11.2%

Condensate volume (BPD)

1,082


886


22.1%


1,524


1,500


1.6%

Arkoma system(3):












  Gathered gas volume (MCFD)

222,045



100.0%


222,045



100.0%

  Processed gas volume (MCFD)

211,032



100.0%


211,032



100.0%

  Residue Gas volume (MCFD)

174,604



100.0%


174,604



100.0%

  NGL volume (BPD)

16,138



100.0%


16,138



100.0%

  Condensate volume (BPD)

122



100.0%


122



100.0%

Barnett system:












Average gathered volumes (MCFD)

22,739



100.0%


22,935



100.0%

Tennessee system:












Average gathered volumes (MCFD)

8,984


7,551


19.0%


8,487


7,698


10.2%

West Texas LPG(3):












Average NGL volumes (BPD)

255,387


231,695


10.2%


249,533


229,673


8.6%

Consolidated Volumes:












Gathered gas volume (MCFD)

1,100,286


649,644


69.4%


1,026,996


599,828


71.2%

Processed gas volume (MCFD)

1,001,883


601,188


66.7%


922,715


548,932


68.1%

Residue gas volume (MCFD)

846,794


486,312


74.1%


837,961


445,094


88.3%

Processed NGL volume (BPD)

80,120


58,597


36.7%


76,807


54,120


41.9%

Condensate volume (BPD)

3,044


2,325


30.9%


3,415


2,821


21.1%






(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 WestTX, Arkoma and WTLPG represent 100% of the operating activity for the respective systems.  Arkoma gathered gas volumes includes volumes gathered by MarkWest and delivered to our processing facilities. 
















 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of February 15, 2013)

Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2015. APL's price risk management position in its entirety will be disclosed in the Partnership's Form 10-K.  NGL contracts are traded at Mt. Belvieu unless otherwise disclosed.

SWAP CONTRACTS

NATURAL GAS HEDGES

Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

2Q 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

3,700,000

3.95

4Q 2014

Sold

Natural gas

3,700,000

4.04

1Q 2015

Sold

Natural gas

2,800,000

4.30

2Q 2015

Sold

Natural gas

2,800,000

4.12

3Q 2015

Sold

Natural gas

2,800,000

4.16

4Q 2015

Sold

Natural gas

2,500,000

4.26

NATURAL GAS LIQUIDS HEDGES

Production Period

Purchased /Sold

Commodity

Gallons

Avg. Fixed Price

1Q 2013

Sold

Propane - Conway

3,780,000

0.94

1Q 2013

Sold

Propane

9,072,000

1.22

1Q 2013

Sold

Isobutane

504,000

1.86

1Q 2013

Sold

Normal butane

1,134,000

1.66

2Q 2013

Sold

Propane – Conway

1,260,000

1.06

2Q 2013

Sold

Propane

10,836,000

1.27

2Q 2013

Sold

Isobutane

630,000

1.77

2Q 2013

Sold

Normal butane

1,260,000

1.66

3Q 2013

Sold

Propane – Conway

1,260,000

1.06

3Q 2013

Sold

Propane

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

6,930,000

1.02

1Q 2014

Sold

Natural gasoline

1,260,000

2.08

2Q 2014

Sold

Propane

6,930,000

0.98

2Q 2014

Sold

Normal Butane

1,260,000

1.50

2Q 2014

Sold

Natural gasoline

3,150,000

1.94

3Q 2014

Sold

Propane

6,930,000

0.98

3Q 2014

Sold

Normal Butane

1,260,000

1.50

3Q 2014

Sold

Natural gasoline

2,520,000

1.94

4Q 2014

Sold

Propane

6,930,000

0.99

4Q 2014

Sold

Normal Butane

1,260,000

1.53

4Q 2014

Sold

Natural gasoline

2,520,000

1.95

1Q 2015

Sold

Propane

3,528,000

0.97

1Q 2015

Sold

Natural gasoline

1,260,000

1.97

2Q 2015

Sold

Propane

3,528,000

0.93

2Q 2015

Sold

Natural gasoline

1,260,000

1.97

3Q 2015

Sold

Propane

378,000

0.93

3Q 2015

Sold

Natural gasoline

1,260,000

1.97

4Q 2015

Sold

Propane

3,528,000

0.96

4Q 2015

Sold

Natural gasoline

1,260,000

1.97

SWAP CONTRACTS

CONDENSATE HEDGES

Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

1Q 2013

Sold

Crude

93,000

97.49

2Q 2013

Sold

Crude

99,000

97.33

3Q 2013

Sold

Crude

78,000

97.08

4Q 2013

Sold

Crude

75,000

96.66

1Q 2014

Sold

Crude

93,000

95.45

2Q 2014

Sold

Crude

90,000

93.43

3Q 2014

Sold

Crude

75,000

89.86

4Q 2014

Sold

Crude

30,000

88.09

OPTION CONTRACTS

NGL OPTIONS

Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

1Q 2013

Purchased

Put

Isobutane

504,000

1.79

1Q 2013

Purchased

Put

Normal Butane

1,512,000

1.74

1Q 2013

Purchased

Put

Natural Gasoline

5,292,000

2.15

2Q 2013

Purchased

Put

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

1Q 2013

Purchased

Put

Crude Oil

66,000

100.10

2Q 2013

Purchased

Put

Crude Oil

69,000

100.10

3Q 2013

Purchased

Put

Crude Oil

72,000

100.10

4Q 2013

Purchased

Put

Crude Oil

75,000

100.10

1Q 2014

Purchased

Put

Crude Oil

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

45,000

90.48

3Q 2015

Purchased

Put

Crude Oil

45,000

89.92

4Q 2015

Purchased

Put

Crude Oil

45,000

89.38

SOURCE Atlas Pipeline Partners, L.P.

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