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

-- Adjusted EBITDA for fourth quarter 2013 was $86.7 million, a 35% increase year-over-year

-- Distributable Cash Flow for fourth quarter 2013 was $51.7 million, a 28% increase year-over-year

-- Severe winter weather impact of an estimated $5.0 million during the fourth quarter

-- Previously announced distribution of $0.62 per common limited partner unit, a 6.9% increase year-over-year

-- Growth opportunities continue in each core operating area; New facilities expected online in Woodford Shale, Eagle Ford Shale and Permian Basin in 2014

-- Volume from new contracts in South Texas are expected to have Silver Oak I plant fully committed; Silver Oak II plant commitments are underway

-- Management updates financial guidance for 2014, introduces financial guidance for 2015

PHILADELPHIA, Feb. 17, 2014 /PRNewswire/ -- Atlas Pipeline Partners, L.P. (NYSE: APL) ("APL", "Atlas Pipeline", or the "Partnership") today reported adjusted earnings before interest, income taxes, depreciation and amortization ("Adjusted EBITDA"), of $86.7 million for the fourth 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 1,385 million cubic feet per day ("MMCFD"), a 38.3% increase over the fourth quarter of 2012.  Distributable Cash Flow was $51.7 million for the fourth quarter of 2013, or $0.65 per average common limited partner unit, compared to $40.4 million for the prior year's fourth quarter.  The Partnership recognized a net loss of $48.7 million for the fourth quarter of 2013, compared with a net loss of $6.9 million for the prior year's fourth quarter.  The net loss for the current period includes a non-cash impairment charge of $43.9 million.

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 28, 2014, the Partnership declared a cash distribution for the fourth quarter of 2013 of $0.62 per common limited partner unit to holders of record on February 7, 2014, which was paid on February 14, 2014.  This distribution represents Distributable Cash Flow coverage per limited partner unit of 0.92x for the fourth quarter of 2013, however distribution coverage for the fourth quarter would have been approximately 1.02x if not for an estimated $5.0 million impact from severe winter weather conditions in Oklahoma and Texas during the period.

"This past year was another step forward for the Partnership as we continue to grow the business.  We are in more areas serving more producers and adding more infrastructure than at any other point in the history of the company.  As we continue to diversify our operations, add talent, and de-risk the cash flows of the Partnership, we are a stronger enterprise.  Because of this, we are being presented with opportunities that we would not have had a chance to pursue in years prior.  We are excited about signing a number of producers in the Eagle Ford this past quarter, and expect to continue to further our relationships and contract more producers in the year ahead.  I believe 2014 will mark a year of increased focus on execution for the company and, while no ascent is ever completely smooth, we will all benefit as we move forward together," 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 $452.8 million as of December 31, 2013.  Total debt outstanding was $1,707.3 million at December 31, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $527.4 million.  Based upon total debt outstanding at December 31, 2013, total leverage was approximately 4.9x for purposes of calculations under our revolving credit facility, and debt to total capital was 39%.

Risk Management

The Partnership has added further protection to its risk management portfolio for 2014, 2015 and 2016.  As of February 17, 2014, the Partnership had natural gas, natural gas liquids and condensate protection in place for 2014, 2015 and 2016 for approximately 71%, 41%, and 10%, respectively, of associated margin value (exclusive of ethane).  Counterparties to the Partnership's risk management activities consist of investment grade commercial banks that are lenders under the Partnership's credit facility, or affiliates of those banks.  A table summarizing the Partnership's risk management portfolio as of February 17, 2014 is included in this release.

Operating Results

Volumes have continued to increase across the majority of the Partnership's gathering and processing systems since the end of the third quarter, even after factoring in the severe cold weather during the period.  Current gathered volumes are approximately 1.5 BCFD and processed volumes are approximately 1.4 BCFD, an increase of over 13 MMCFD compared to the Partnership's third quarter reported results, inclusive of the cold weather impact to volumes during the fourth quarter.  Growth capital spending was $114.9 million during the fourth quarter and $428.6 million for all of 2013, as organic expansion projects continue across all gathering and processing systems, including expected 2014 processing plant expansions on Arkoma (120 MMCFD Stonewall Plant), SouthTX (200 MMCFD Silver Oak II Plant), and WestTX (200 MMCFD Edward Plant).

Gross margin from operations was $119.6 million for the fourth quarter 2013, compared to $79.5 million for the prior year period, led by increasing producer activity in APL's areas of operations and recent acquisitions.  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 recently acquired Arkoma system and SouthTX system.  The gross margin for the quarter does not include approximately $3.9 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $3.9 million realized derivative settlement gains excluded from gross margin in the fourth quarter of 2012.  

WestTX System

The WestTX system's average natural gas processed volume was 364.0 MMCFD for the fourth quarter 2013, compared to 271.6 MMCFD for the fourth quarter of 2012.  Increased processed volumes are primarily due to significant drilling activity, supported by the completion of the Driver plant in April 2013, which increased processing capacity on the WestTX system to 455 MMCFD.  Average NGL production was 46,660 barrels per day ("BPD") for the fourth quarter 2013, a 33.7% increase over the fourth quarter 2012.  This system continues to operate in ethane rejection due to the value of ethane compared to residue natural gas.  Volume growth was negatively impacted during the quarter by winter weather, which resulted in an estimated $4.0 million of cash flow impact on this system. 

The Partnership expects processed volumes on this system to continue to increase through 2014 and beyond as producers continue to pursue their drilling plans over the coming years in the Permian Basin.  The previously announced Edward plant, which is expected to be complete in late 2014, will support the increased activity in this area. 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. In addition, this extension of the WestTX system is expected to accelerate the Partnership's need to install additional processing capacity in this operating area, potentially by the end of 2015. 

WestOK System

The WestOK system had average natural gas processed volume of 512.6 MMCFD for the fourth quarter, a 24.2% increase from the fourth quarter 2012.  Average NGL production was 23,789 BPD for the fourth quarter 2013, a 43.5% increase from the fourth quarter 2012, due to the increased production on the gathering system and recent modifications to the Waynoka I and II processing facilities.   

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 535 MMCFD. While the current nameplate capacity at WestOK is approximately 458 MMCFD, the Partnership has processed up to approximately 500 MMCFD after completing capacity enhancements in December 2013. Any excess volumes above this level would have been offloaded or bypassed to third parties during the quarter.  Due to the nonrenewal of a low margin commercial agreement, 60-70 MMCFD of capacity will become available during the first half of 2014. This capacity is expected to be filled under more favorable economic terms 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, only approximately 25% of the currently available ethane is being produced on the system.

SouthOK System (Velma/Arkoma)

The Velma system's average natural gas processed volume was 151.9 MMCFD for the fourth quarter 2013, a 42.6% increase from the fourth 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, including the emerging South Central Oklahoma Oil Province ("SCOOP") play in southern Oklahoma.  Average NGL production increased to 17,247 BPD for the fourth quarter 2013, up approximately 38.1% compared to the fourth quarter 2012, due to the increase in overall processed volumes.  Additionally, the Arkoma system had average natural gas processed volumes of 223.8 MMCFD and produced 14,030 BPD of NGLs during the fourth quarter of 2013.  The Arkoma system currently consists of gas gathering, processing and treating facilities in the Arkoma Basin in southeastern Oklahoma and is located approximately 55 miles from the Velma system. 

Drilling activity behind the Velma and Arkoma systems continues to increase and incremental demand for processing capacity, particularly in the vicinity of the SCOOP, has increased as well.  APL has entered into fixed fee arrangements with producers in the area and 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 installing approximately 55 miles of pipeline between the Velma system and the Arkoma system to combine the systems.  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. The Partnership will refer to the combined systems as SouthOK.  The SouthOK system will expand by an additional 120 MMCFD upon installation of the Stonewall plant, expected to be operational by early in second quarter of 2014.  The connection of these systems is expected to accelerate the utilization of the Stonewall plant.  SouthOK will have 500 MMCFD of processing capacity upon completion of the facility, including 220 MMCFD of capacity owned by Centrahoma (a 60% Partnership-owned joint venture with MarkWest Energy Partners, L.P.) and the SouthOK system can be expanded to 580 MMCFD of processing capacity with a minimal capital outlay by Centrahoma at Stonewall. The system will be able to meet the needs of current and future producer customers in the Woodford Shale, Ardmore Basin, SCOOP and Arkoma Basin, providing potentially significant economic and volumetric incentives to those producer customers, including increasing options for residue and NGL takeaway out of these areas.

The Partnership expects certain volumes on the system to continue to be offloaded to a third-party processor until the Stonewall plant is operational.  Cash flows from SouthOK system are largely fee-based; however, the Arkoma portion of the system does currently have additional commodity exposure on certain fixed recovery contracts, primarily related to ethane.  Approximately 70% of the ethane is being rejected back into the residue gas stream at the Arkoma facilities to minimize the negative impact of the current ethane margin, while the Velma plants cannot currently operate in ethane rejection, primarily due to residue pipeline restrictions. 

SouthTX System

The SouthTX system in the Eagle Ford shale 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 early in the second quarter of 2014.  The system had average natural gas processed volumes of 133.2 MMCFD and produced 17,083 BPD of NGLs during the fourth quarter of 2013.  The reported processed volumes includes the impact of interruptible volumes coming off the system during the quarter, which otherwise would have contributed to a higher reported volume figure.

During the fourth quarter of 2013 and early 2014, Atlas Pipeline has contracted nine new producers in the Eagle Ford shale and some other contracts are in final review. These opportunities include producers that are some of the largest and most significant operators in the basin.  Gathering and processing demand is coming from multiple counties on both the east and west sides of our high pressure gathering system.  Management estimates that these recent contracts could result in an incremental 50-65 MMCFD of production once connected to the system, which is anticipated in the second quarter of 2014.  These anticipated volumes, along with those acquired in the acquisition, fully support the processing capacity of Silver Oak I.  Management anticipates volumes under these new contracts could exceed 90 MMCFD by the end of the year.  The commercial opportunity set remains strong in the Eagle Ford, as the Partnership continues to contract Silver Oak II, in anticipation of its' start-up date in the second quarter of 2014. 

Corporate and Other

General and administrative costs, excluding non-cash compensation, for the fourth quarter of 2013 totaled $11.1 million, compared to $10.6 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 December 2012 and the SouthTX system in April 2013.  Additionally, the Partnership recognized a non-cash goodwill impairment charge related to the gas treating business of approximately $43.9 million in the current quarter, as management has determined the growth related to this line of business will be slower than originally forecasted when the assets were acquired.    

Net of deferred financing costs, interest expense increased to $22.2 million for the fourth quarter of 2013, as compared to $12.8 million in the fourth 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.

*    *    *

Forecasted Guidance

The Partnership is forecasting Adjusted EBITDA for 2014 of between $400 million and $425 million, which would represent an approximate 27% increase at the mid-point of the range, over 2013 reported Adjusted EBITDA of approximately $325 million.  This also compares to 2012 reported Adjusted EBITDA of approximately $220 million, an approximate 88% increase in two years at the mid-point of the current guidance.  The forecasted Adjusted EBITDA for 2014 includes commodity price assumptions of $4.375 per MMBTU average for natural gas, a weighted average natural gas liquids price of $1.065 per gallon and an average crude oil price of $92.785 per barrel.  Note that as of the date of this press release, the Partnership has 72% of its 2014 expected commodity-price sensitive gross margin protected, and these positions are factored into the current financial guidance.  The Partnership is also assuming that its WestOK, WestTX and Arkoma facilities will continue to operate in ethane rejection throughout the year.  The Partnership is expecting to exit 2014 with at least 40% of its gross margin tied to fee-based contracts and a run-rate annualized Adjusted EBITDA of between $430 million and $460 million.  The Partnership's forecast assumes volumetric growth across each of its major gathering and processing systems and management is expecting to exit 2014 processing approximately 1.8 BCFD. The Partnership would have upside to this forecasted Adjusted EBITDA should volume growth by producer customers exceed current estimates or if commodity prices increase above the amounts stated above.  Under similar price assumptions and moderate volume growth, the Partnership is forecasting it could generate between $450 million and $500 million in Adjusted EBITDA for 2015, based on current hedges in place.

The Partnership is forecasting growth capital spending between $450 and $500 million for 2014, a reflection of the strong backlog of accretive projects across the Partnership's liquid-rich operating areas.  There are currently significant projects underway at each of the Partnership's major gathering and processing systems, including three new cryogenic processing facilities totaling 520 MMCFD of capacity expected to come online in 2014.  This includes the 120 MMCFD Stonewall Plant at the Arkoma system, the 200 MMCFD Silver Oak II plant at the SouthTX system, and the 200 MMCFD Edward plant at the WestTX system.  Additional major projects include: a gathering expansion at Velma along with the connection of Velma and Arkoma; further development of the WestOK system, including pipeline and compression additions, as volume growth continues in western Oklahoma and southern Kansas; the gathering system expansion into Martin county in west Texas as producers expand drilling operations in the Permian Basin; and extensions and enhancements, including new central delivery points, to the high-pressure gathering and residue pipelines in the Eagle Ford.  Maintenance capital spending is expected to increase to approximately $30 to $35 million for the year, accounting for the larger footprint across the business.

Management remains focused on maintaining adequate liquidity and decreasing leverage through 2014 and beyond.  The Partnership had approximately $448 million available under its revolving credit facility at the beginning of the current year and will continue to fund all of its growth capital with an adequate mix of debt and equity.  Atlas Pipeline remains committed to growing the business, including its limited partner distributions, as it has done for years, in a prudent, fiscally responsible way, while also serving its numerous producer customers in a manner that has given the Partnership a best-in-class reputation.  Management currently anticipates the distribution to remain at its current level for the next quarter and expects to increase the distribution once cash flows from the Partnership's organic growth initiatives are realized.  Management expects to exit 2014 distributing at least $2.60 per limited partner unit on an annualized basis, at least a 5% increase from the current distribution rate of $2.48 per limited partner unit.

Please note that forecasted guidance in this press release is 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 construction and maintenance of new and existing 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.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's fourth quarter 2013 results on Tuesday, February 18, 2014 at 10:00 am ET by going to the Investor Relations section of the Partnership's website at www.atlaspipeline.com.  An audio replay of the conference call will also be available beginning at 2:00 pm ET on Tuesday, February 18, 2014. To access the replay, dial 1-888-286-8010 and enter conference code 91118325.

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 11,200 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.

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


Twelve Months Ended



December 31,


December 31,



2013


2012


2013


2012


Revenue:













Natural gas and liquids sales

$

548,347


$

334,617


$

1,959,144


$

1,137,261


Transportation, processing and other fees(2)


48,421



19,891



165,177



66,722


Derivative gain (loss), net


(19,271)



(4,965)



(28,764)



31,940


Other income, net


2,631



2,509



11,292



10,097


Total revenues


580,128



352,052



2,106,849



1,246,020















Costs and expenses:













Natural gas and liquids cost of sales


477,062



274,960



1,690,382



927,946


Plant operating


22,600



16,819



92,271



60,480


Transportation and compression


492



622



2,256



1,618


General and administrative


11,099



10,595



41,512



35,570


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


5,526



4,098



19,344



11,636


Other


420



15,372



20,005



15,069


Depreciation and amortization


40,696



24,314



168,617



90,029


Interest


24,023



14,091



89,637



41,760


Total costs and expenses


581,918



360,871



2,124,024



1,184,108















Equity income (loss) in joint ventures


(4,422)



2,088



(4,736)



6,323


Goodwill impairment loss


(43,866)





(43,866)




Loss on asset sales and other






(1,519)




Loss on early extinguishment of debt






(26,601)




Income (loss) before income taxes


(50,078)



(6,731)



(93,897)



68,235


Income tax (benefit) expense


(1,406)



176



(2,260)



176















Net income (loss)


(48,672)



(6,907)



(91,637)



68,059















Income attributable to non-controlling interests


(2,282)



(1,902)



(6,975)



(6,010)


Preferred unit imputed dividend effect


(11,378)





(29,485)




Preferred unit dividends in kind


(9,170)





(23,583)




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

$

(71,502)


$

(8,809)


$

(151,680)


$

62,049















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













Basic and diluted:

$

(0.94)


$

(0.22)


$

(2.23)


$

0.95


Weighted average common limited partner units (basic)


79,859



56,288



74,364



54,326


Weighted average common limited partner units (diluted)


79,859



56,288



74,364



55,138




(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)

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, except per unit amounts)



Three Months Ended


Year Ended


December 31,


December 31,


2013


2012


2013


2012

Summary Cash Flow Data:












Cash provided by operating activities

$

65,723


$

48,939


$

210,844


$

174,638

Cash used in investing activities


(104,934)



(727,916)



(1,443,083)



(1,006,641)

Cash provided by financing activities


33,686



682,034



1,233,755



835,233













Capital Expenditure Data:












Maintenance capital expenditures

$

7,800


$

5,780


$

21,919


$

19,021

Expansion capital expenditures


114,889



125,342



428,641



354,512

Contributions in equity method investments


3,553





13,366



Acquisitions


(24,898)



596,921



975,887



633,610













Total

$

101,344


$

728,043


$

1,439,813


$

1,007,143

 

 

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


ASSETS


December 31,

2013


December 31,
2012






Current assets:







Cash and cash equivalents


$

4,914


$

3,398

Other current assets



236,864



216,677








Total current assets



241,778



220,075








Property, plant and equipment, net



2,724,192



2,200,381

Intangible assets, net



1,064,843



518,645

Investment in joint ventures



248,301



86,002

Other assets, net



48,731



40,535










$

4,327,845


$

3,065,638








LIABILITIES AND EQUITY





















Current liabilities


$

320,226


$

253,519

Long-term debt, less current portion



1,706,786



1,169,083

Deferred income taxes, net



33,290



30,258

Other long-term liability



7,638



6,370








Total partners' capital



2,200,645



1,539,177

Non-controlling interest



59,260



67,231








Total equity



2,259,905



1,606,408










$

4,327,845


$

3,065,638

 

 

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



Three Months Ended


Year Ended


December 31,


December 31,


2013


2012


2013


2012













Gross margin calculation:












Natural gas and liquids sales

$

548,347


$

334,617


$

1,959,144


$

1,137,261

Transportation, processing and other fees


48,421



19,891



165,177



66,722

Less: non-cash line fill (gain) loss


83



9



(249)



(2,111)

Less : natural gas and liquids cost of sales


477,062



274,960



1,690,382



927,946

   Gross margin


119,623



79,539



434,188



278,148













Reconciliation of net income to other

non-GAAP measures(1):












Net income (loss)

$

(48,672)


$

(6,907)


$

(91,637)


$

68,059

Depreciation and amortization


40,696



24,314



168,617



90,029

Income tax (benefit) expense


(1,406)



176



(2,260)



176

Interest expense


24,023



14,091



89,637



41,760













EBITDA


14,641



31,674



164,357



200,024

Income attributable to non-controlling interests(2)


(2,282)



(1,902)



(6,975)



(6,010)

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


110





(2,778)



Adjustment for cash flow from investment in joint ventures


6,422



(288)



12,136



877

Loss on asset disposition






1,519



Goodwill impairment loss


43,866





43,866



Non-cash (gain) loss on derivatives


15,374



8,285



28,440



(23,283)

Acquisition costs


420



15,372



20,005



15,395

Premium expense on derivative instruments


5,239



5,168



17,083



17,759

Unrecognized economic impact of acquisitions


(145)



1,698



1,023



1,698

Loss on early termination of debt






26,601



Other non-cash losses(4)


3,006



4,089



19,593



13,747













Adjusted EBITDA


86,651



64,096



324,870



220,207

Interest expense


(24,023)



(14,091)



(89,637)



(41,760)

Amortization of deferred finance costs


1,846



1,316



6,965



4,672

Premium expense on derivative instruments


(5,239)



(5,168)



(17,083)



(17,759)

Other costs








(326)

Maintenance capital expenditures(5)


(7,493)



(5,779)



(21,252)



(19,021)













Distributable Cash Flow

$

51,742


$

40,374


$

203,863


$

146,013

 

(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") 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 $307 thousand and $667 thousand for the three and twelve months ended December 31, 2013, respectively

 

 

 


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



Three Months Ended December 31,


Year Ended December 31,


2013


2012


Percent
Change


2013


2012


Percent
Change

Pricing (unhedged):
























Weighted Average Market Prices:












NGL price per gallon – Conway hub

$

0.89


$

0.80


11.3%


$

0.82


$

0.78


5.1%

NGL price per gallon – Mt. Belvieu hub


0.91



0.86


5.8%



0.85



0.96


(11.5)%













Natural gas sales ($/MCF):












Velma

3.43


3.17


8.2%


3.46


2.60


33.1%

WestOK

3.33


3.21


3.7%


3.42


2.66


28.6%

WestTX

3.35


3.12


7.4%


3.88


2.54


52.8%

Weighted average

3.39


3.18


6.6%


3.44


2.62


31.3%













NGL sales ($/Gallon):












SouthTX

0.86


-


-


0.79


-


-

Velma

0.86


0.75


14.7%


0.79


0.78


1.3%

Arkoma

1.01


-


-


0.78


-


-

WestOK

1.11


0.97


14.4%


1.04


0.89


16.9%

WestTX

0.97


0.92


5.4%


0.92


0.98


(6.1)%

Weighted average

0.99


0.90


10.0%


0.91


0.90


1.1%













Condensate sales ($/barrel):












SouthTX

95.63


-


-


93.75


-


-

Velma

94.53


87.31


8.3%


96.23


94.82


1.5%

Arkoma

88.92


-


-


88.26


-


-

WestOK

84.39


78.08


8.1%


87.17


84.76


1.8%

WestTX

97.27


83.16


17.0%


98.55


89.40


10.2%

Weighted average

88.71


80.75


9.9%


91.90


87.88


4.6%

 

 

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



Three Months Ended December 31,


Year Ended December 31,


2013


2012


Percent
Change


2013


2012


Percent
Change













Volumes:
























SouthTX system:












Gathered gas volume (MCFD)

134,836


-


-


132,826


-


-

Processed gas volume(3) (MCFD)

133,227


-


-


131,745


-


-

Residue gas volume (MCFD)

104,635


-


-


105,207


-


-

Processed NGL volume (BPD)

17,083


-


-


16,711


-


-

Condensate volume (BPD)

61


-


-


77


-


-













SouthOK system:












   Velma:












Gathered gas volume (MCFD)

160,926


111,572


44.2%


147,300


128,548


14.6%

Processed gas volume(3) (MCFD)

151,930


106,577


42.6%


140,571


114,421


22.9%

Residue gas volume (MCFD)

127,278


87,534


45.4%


117,079


100,711


16.3%

Processed NGL volume (BPD)

17,247


12,493


38.1%


16,067


13,850


16.0%

Condensate volume (BPD)

373


356


4.8%


379


409


(7.3)%













   Arkoma(2):












Gathered gas volume (MCFD)

243,595


222,045


9.7%


258,773


222,045


16.5%

Processed gas volume(3) (MCFD)

223,829


211,032


6.1%


238,161


211,032


12.9%

Residue gas volume (MCFD)

200,370


174,604


14.8%


206,946


174,604


18.5%

Processed NGL volume (BPD)

14,030


16,138


(13.1)%


19,021


16,138


17.9%

Condensate volume (BPD)

188


122


54.1%


146


122


19.7%













WestOK system:












Gathered gas volume (MCFD)

537,958


436,694


23.2%


500,756


369,035


35.7%

Processed gas volume(3) (MCFD)

512,560


412,682


24.2%


475,441


348,041


36.6%

Residue gas volume (MCFD)

469,931


383,107


22.7%


438,611


322,751


35.9%

Processed NGL volume (BPD)

23,789


16,576


43.5%


20,971


14,505


44.6%

Condensate volume (BPD)

1,874


1,484


26.3%


1,887


1,360


38.8%













WestTX system(2):












Gathered gas volume (MCFD)

380,165


298,252


27.5%


357,524


275,946


29.6%

Processed gas volume(3) (MCFD)

364,043


271,592


34.0%


328,678


249,221


31.9%

Residue gas volume (MCFD)

270,955


201,549


34.4%


244,294


179,539


36.1%

Processed NGL volume (BPD)

46,660


34,913


33.7%


41,920


32,314


29.7%

Condensate volume (BPD)

994


1,082


(8.1)%


1,657


1,524


8.7%













Other systems:












   Gathered gas volumes (MCFD)

28,716


31,723


(9.5)%


29,656


31,422


(5.6)%

























West Texas LPG Partnership(2)












      Average NGL volumes (BPD)

232,758


255,387


(8.9)%


245,599


249,533


(1.6)%













Consolidated Volumes:












     Gathered gas volume (MCFD)

1,486,196


1,100,286


35.1%


1,426,835


1,026,996


38.9%

     Processed gas volume (MCFD)

1,385,589


1,001,883


38.3%


1,314,596


922,715


42.5%

     Residue gas volume (MCFD)

1,173,169


846,794


38.5%


1,112,137


777,605


43.0%

     Processed NGL volume (BPD)

118,809


80,120


48.3%


114,690


76,807


49.3%

     Condensate volume (BPD)

3,490


3,044


14.7%


4,146


3,415


21.4%









(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 February 17, 2014)


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-K. 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

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

14,868,000

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

12,474,000

0.99

3Q14

Sold

Iso Butane

1,260,000

1.26

3Q14

Sold

Normal Butane

1,260,000

1.50

3Q14

Sold

Natural Gasoline

3,150,000

1.93

4Q14

Sold

Propane

12,852,000

1.00

4Q14

Sold

Iso Butane

1,260,000

1.26

4Q14

Sold

Normal Butane

1,260,000

1.53

4Q14

Sold

Natural Gasoline

3,150,000

1.93

1Q15

Sold

Propane

12,474,000

0.98

1Q15

Sold

Natural Gasoline

2,142,000

1.91

2Q15

Sold

Propane

10,584,000

0.95

2Q15

Sold

Natural Gasoline

630,000

1.97

3Q15

Sold

Propane

6,678,000

1.04

3Q15

Sold

Natural Gasoline

630,000

1.97

4Q15

Sold

Propane

7,308,000

1.00

4Q15

Sold

Natural Gasoline

630,000

1.97

1Q16

Sold

Propane

3,150,000

3.89

2Q16

Sold

Propane

1,890,000

1.02

3Q16

Sold

Propane

630,000

1.07

4Q16

Sold

Propane

630,000

1.07

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of February 17, 2014)


SWAP CONTRACTS


CONDENSATE HEDGES


Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

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

1Q14

Sold

Natural Gas

1,950,000

3.98

2Q14

Sold

Natural Gas

2,890,000

3.91

3Q14

Sold

Natural Gas

4,750,000

4.01

4Q14

Sold

Natural Gas

5,050,000

4.11

1Q15

Sold

Natural Gas

5,065,000

4.35

2Q15

Sold

Natural Gas

4,615,000

4.18

3Q15

Sold

Natural Gas

4,615,000

4.18

4Q15

Sold

Natural Gas

4,315,000

4.26

1Q16

Sold

Natural Gas

2,400,000

4.33

2Q16

Sold

Natural Gas

1,650,000

4.24

3Q16

Sold

Natural Gas

1,650,000

4.24

4Q16

Sold

Natural Gas

1,650,000

4.24

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of February 17, 2014)


OPTION CONTRACTS


NGL OPTIONS


Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

1Q14

Purchased

Put

Iso Butane

1,260,000

1.2225

2Q14

Purchased

Put

Propane

1,890,000

0.9627

2Q14

Sold

Call

Propane

1,260,000

1.3100

3Q14

Purchased

Put

Propane

2,520,000

0.9544

3Q14

Sold

Call

Propane

1,260,000

1.3050

4Q14

Purchased

Put

Propane

2,520,000

0.9644

4Q14

Sold

Call

Propane

1,260,000

1.3400

1Q15

Purchased

Put

Propane

1,890,000

0.9792

1Q15

Sold

Call

Propane

1,260,000

1.2750

3Q15

Purchased

Put

Propane

1,260,000

0.8825


CRUDE OPTIONS


Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

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

SOURCE Atlas Pipeline Partners, L.P.



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