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Press release from PR Newswire

Atlas Pipeline Partners, L.P. Reports Second Quarter 2013 Results

Monday, August 05, 2013

Atlas Pipeline Partners, L.P. Reports Second Quarter 2013 Results

16:48 EDT Monday, August 05, 2013

- Record processed gas volumes exceed 1.25 billion cubic feet per day (BCFD) in second quarter 2013
- Adjusted EBITDA for second quarter 2013 was $86.3 million, a 75.9% increase year-over-year
- Distributable Cash Flow for second quarter 2013 of $58.0 million, a 77.0% increase year-over-year
- Partnership reaffirms 2013-2014 previously stated guidance
- Previously announced distribution of $0.62 per common limited partner unit, a 10.7% increase year-over-year
- WestOK 200 MMCFD expansion full after only 9 months in operation; Another 200 MMCFD expansion announced last month at WestTX

PHILADELPHIA, Aug. 5, 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 $86.3 million for the second quarter of 2013, driven primarily by a continued increase in volumes across the Partnership's gathering and processing systems.  Processed natural gas volumes averaged 1,253 million cubic feet per day ("MMCFD"), an 84.0% increase over the second quarter of 2012.  Distributable Cash Flow was $58.0 million for the second quarter of 2013, or $0.78 per average common limited partner unit, compared to $32.8 million for the prior year's second quarter.  The Partnership recognized net income of $10.1 million for the second quarter of 2013, compared with net income of $74.9 million for the prior year's second 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 July 23, 2013, the Partnership declared a distribution for the second quarter of 2013 of $0.62 per common limited partner unit to holders of record on August 7, 2013, which will be paid on August 14, 2013.  This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.07x on a fully diluted basis for the second quarter of 2013.

Eugene Dubay, Chief Executive Officer of the Partnership, commented, "We reported solid results for the second quarter and were pleased to have raised our quarterly distribution more than 10% versus this period last year.  Contributing to the increase was the much needed increased liquids takeaway capacity at our WestOK and WestTX systems and the start-up of the Driver plant in West Texas.  We are very focused on aggressively pursuing opportunities in the second half of the year in all of our operating areas and, specifically, are excited to continue to integrate the new Arkoma and SouthTX assets that we have recently acquired to achieve their full operating potential."      

Capitalization and Liquidity

The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $540.7 million as of June 30, 2013.  Total debt outstanding was $1,635.8 million at June 30, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $455.9 million.  Based upon total debt outstanding at June 30, 2013, total leverage was approximately 4.8x for purposes of calculations under our revolving credit facility, and debt to total capital was 41%.

*    *    *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2016.  As of July 31, 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 71%, 72%, and 38% respectively, of associated margin value (exclusive of ethane).  The Partnership has also begun to add to protection in 2016.  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 July 31, 2013 is included in this release.

*    *    *

Operating Results

The Partnership continues to report record volumes, and with the addition of the SouthTX assets, is now processing, on average, over 1.25 billion cubic feet per day of natural gas per day.  Gross margin from operations was $108.7 million for the second quarter 2013, compared to $60.8 million for the prior year period, led by increasing producer activity in APL's area of operations.  Gross margin, a non-GAAP financial measure, includes natural gas and liquids sales and transportation, processing and other fees, less purchased product costs and non-cash gains (or losses) included in these items.  The higher gross margin for the quarter was primarily due to the increased volumes and expansions that have been completed on the WestOK, WestTX, and Velma systems, as well as the newly acquired Arkoma system and SouthTX system, and was partially offset by lower natural gas liquids ("NGL") prices.  The gross margin for the quarter does not include approximately $2.8 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $2.0 million realized derivative settlement gains excluded from gross margin in the second quarter of 2012.  

WestTX System

The WestTX system's average natural gas processed volume was 313.5 MMCFD for the second quarter 2013, compared to 236.2 MMCFD for the second quarter of 2012.  Increased volumes are primarily due to the April 12, 2013 completion of the Driver plant, which increased processing capacity on the WestTX system by 200 MMCFD.  Average NGL production volumes were 39,901 barrels per day ("BPD") for the second quarter 2013, a 21.8% increase from second quarter 2012.  This system continues to operate in ethane rejection due to the value of ethane compared to residue natural gas.  The Partnership expects processed volumes on this system to continue to increase as producers continue to pursue their drilling plans over the coming years.   

WestOK System

The WestOK system had average natural gas processed volume of 483.5 MMCFD for the second quarter, a 53.1% increase from second quarter 2012.  Average NGL production was 22,233 BPD for the second quarter 2013, a 54.6% increase from second quarter 2012, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012.  The WestOK system is also operating in ethane rejection for economic reasons.  The Partnership announced during the quarter 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.     

Velma System

The Velma system's average natural gas processed volume was 132.7 MMCFD for the second quarter 2013, a 2.8% increase from second 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 16,201 BPD for the second quarter 2013, up approximately 13.9% compared to second quarter 2012, due to the increase in overall processed volumes. 

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 202.1 MMCFD and produced 25,590 BPD of NGLs during the second quarter of 2013.  The Arkoma system has total gross name-plate processing capacity of 220 MMCFD, including the 120 MMCFD Tupelo plant, of which the Partnership owns 100%.  The remaining processing capacity is owned by Centrahoma.

SouthTX System

The Partnership acquired the SouthTX system in April 2013 through the acquisition of TEAK Midstream L.L.C.  The assets acquired include gas gathering and processing facilities and a co-generation facility located in south Texas within the Eagle Ford shale region.  The SouthTX system has a total gross name-plate processing capacity of 200 MMCFD with the Silver Oak I plant, and will have a capacity of 400 MMCFD once the Silver Oak II plant goes into service, which is expected to be during first quarter 2014.  The system had average natural gas processed volumes of 121.3 MMCFD and produced 15,041 BPD of NGLs during the second quarter of 2013. 

Corporate and Other

Net of deferred financing costs, interest expense increased to $20.8 million for the second quarter of 2013, up 156.1% as compared with the second quarter of 2012.  This increase was due to financing the Partnership's acquisitions and capital expenditure program during 2012 and 2013, including the issuance of 6.625% senior unsecured notes due 2020 in September and December 2012, the February 2013 issuance of 5.875% senior unsecured notes due 2023, and the May 2013 issuance of 4.750% senior unsecured notes due 2021.  The 5.875% senior unsecured notes due 2023 were issued in connection with the redemption of the Partnership's 8.75% Senior Notes due 2018.

*    *    *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's second quarter 2013 results on Tuesday, August 6, 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, August 6, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 78328957.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry.  In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 14 active gas processing plants, 18 gas treating facilities, as well as approximately 10,600 miles of active intrastate gas gathering pipeline.  APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 37% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity 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

Six Months Ended

June 30,

June 30,

2013

2012

2013

2012

Revenue:

Natural gas and liquids sales

$

491,230

$

238,801

$

875,078

$

528,026

Transportation, processing and other fees(2)

40,306

14,878

73,031

27,559

Derivative gain, net

27,107

67,847

15,024

55,812

Other income, net

2,296

2,588

5,718

5,003

Total revenues

560,939

324,114

968,851

616,400

Costs and expenses:

Natural gas and liquids cost of sales

424,216

195,103

749,756

428,208

Plant operating

24,147

14,600

45,418

28,481

Transportation and compression

623

212

1,211

476

General and administrative

9,110

7,505

18,524

16,472

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

3,436

2,940

7,820

3,918

Other

18,370

(161)

18,900

(195)

Depreciation and amortization

46,383

21,712

76,841

42,554

Interest

22,581

9,269

41,267

17,977

Total costs and expenses

548,866

251,180

959,737

537,891

Equity income in joint ventures

(472)

1,917

1,568

2,813

Gain (loss) on asset sales and other

(1,519)

-

(1,519)

-

Loss on early extinguishment of debt

(19)

-

(26,601)

-

Income from continuing operations

10,063

74,851

(17,438)

81,322

Income tax benefit

28

37

Net income

10,091

74,851

(17,401)

81,322

Income attributable to non-controlling interests

(1,810)

(1,061)

(3,179)

(2,597)

Income unit imputed dividend effect

(6,729)

-

(6,729)

-

Preferred unit dividends

(5,341)

-

(5,341)

-

Net income attributable to common limited partners and the General Partner

$

(3,789)

$

73,790

$

(32,650)

$

78,725

Net income attributable to common limited partners per unit:

Basic and diluted:

$

(0.11)

$

1.30

$

(0.57)

$

1.37

Weighted average common limited partner units (basic)

74,340

53,646

69,520

53,633

Weighted average common limited partner units (diluted)

74,340

54,510

69,520

54,262

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

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

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

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Financial Summary (continued)

(unaudited; in thousands, except per unit amounts)

Three Months Ended

Six Months Ended

June 30,

June 30,

2013

2012

2013

2012

Summary Cash Flow Data:

Cash provided by operating activities

$

30,465

$

21,784

$

65,721

$

64,531

Cash provided by (used in) investing activities

(1,107,853)

(84,551)

(1,216,244)

(182,827)

Cash provided by (used in) financing activities

1,090,208

62,856

1,168,206

118,385

Capital Expenditure Data:

Maintenance capital expenditures

$

3,848

$

4,000

$

7,703

$

8,510

Expansion capital expenditures

103,345

61,221

208,006

137,878

Acquisitions

1,000,785

19,454

1,000,785

36,689

Total

$

1,107,978

$

84,675

$

1,216,494

$

183,077

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(unaudited; in thousands)

 

ASSETS

June 30,

2013

December 31,

2012

Current assets:

Cash and cash equivalents

$

21,081

$

3,398

Other current assets

294,940

216,677

Total current assets

316,021

220,075

Property, plant and equipment, net

2,623,078

2,200,381

Intangible assets, net

1,072,164

518,645

Investment in joint ventures

232,090

86,002

Other assets, net

60,821

40,535

$

4,304,174

$

3,065,638

LIABILITIES AND EQUITY

Current liabilities

$

304,816

$

253,519

Long-term debt, less current portion

1,635,297

1,169,083

Deferred income taxes, net

35,513

30,258

Other long-term liability

6,387

6,370

Total partners' capital

2,277,682

1,539,177

Non-controlling interest

44,479

67,231

Total equity

2,322,161

1,606,408

$

4,304,174

$

3,065,638

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Reconciliation of Non-GAAP Measures

(unaudited; in thousands)

 

Three Months Ended

Six Months Ended

June 30,

June 30,

2013

2012

2013

2012

Reconciliation of net income to other

non-GAAP measures(1):

Net income

$

10,091

$

74,851

$

(17,401)

$

81,322

Depreciation and amortization

46,383

21,712

76,841

42,554

Income tax benefit

(28)

-

(37)

-

Interest expense

22,581

9,269

41,267

17,977

EBITDA

79,027

105,832

100,670

141,853

Income attributable to non-controlling interests(2)

(1,810)

(1,061)

(3,179)

(2,597)

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

(1,121)

-

(1,971)

-

Adjustment for cash flow from investment in joint ventures

2,272

(117)

2,032

787

Loss on asset disposition

1,519

-

1,519

-

Non-cash (gain) loss on derivatives

(24,263)

(64,741)

(10,544)

(54,045)

Acquisition costs

18,370

-

18,900

-

Premium expense on derivative instruments

3,745

3,984

7,020

7,736

Unrecognized economic impact of acquisitions

1,126

-

1,126

-

Loss on early termination of debt

19

-

26,601

-

Other non-cash losses(4)

7,428

5,163

11,844

6,413

Adjusted EBITDA

86,312

49,060

154,018

100,147

Interest expense

(22,581)

(9,269)

(41,267)

(17,977)

Amortization of deferred finance costs

1,739

1,130

3,283

2,295

Premium expense on derivative instruments

(3,745)

(3,984)

(7,020)

(7,736)

Other costs

-

(161)

-

(195)

Maintenance capital expenditures(5)

(3,713)

(4,000)

(7,527)

(8,510)

Distributable Cash Flow

$

58,012

$

32,776

$

101,487

$

68,024

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

(2)  Represents Anadarko Petroleum Corporation's ("Anadarko" ? NYSE: APC) non-controlling interest in the operating results of Atlas Pipeline Mid-Continent WestOk, LLC ("WestOK") and Atlas Pipeline Mid-Continent WestTex, LLC ("WestTX"); and MarkWest's non-controlling interest in Centrahoma

(3)  Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest's interest in Centrahoma

(4)  Includes the non-cash impact of commodity price movements on pipeline linefill inventory, non-cash compensation and minimum volume adjustments on certain producer throughput contracts

(5)  Net of non-controlling interest maintenance capital of $135 thousand and $176 thousand for the three and six months ended June 30, 2013, respectively

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 

Three Months Ended June 30,

Six Months Ended June 30,

2013

2012

Percent

 Change

2013

2012

Percent

 Change

Pricing (unhedged):

Weighted Average Market Prices:

NGL price per gallon ? Conway hub

$

0.75

$

0.70

7.1 %

$

0.79

$

0.82

(3.7)%

NGL price per gallon ? Mt. Belvieu hub

0.80

0.94

(14.9)%

0.83

1.06

(21.7)%

Natural gas sales ($/MCF):

Velma

3.88

2.04

90.2%

3.53

2.29

54.1%

WestOK

3.84

2.09

83.7%

3.54

2.30

53.9%

WestTX

3.74

1.85

102.2%

3.45

2.18

58.3%

Weighted average

3.82

2.01

90.0%

3.59

2.26

58.8%

NGL sales ($/Gallon):

Arkoma

0.66

-

-

0.69

-

-

Velma

0.72

0.71

1.4 %

0.75

0.82

(8.5)%

WestOK

0.96

0.79

21.5 %

0.97

0.85

14.1 %

WestTX

0.86

0.88

(2.3)%

0.89

1.03

(13.6)%

Weighted average

0.84

0.80

5.0 %

0.84

0.92

(8.7)%

Condensate sales ($/barrel):

Arkoma

81.18

-

-

84.79

-

-

Velma

93.32

93.69

(0.4)%

93.36

98.52

(5.2)%

WestOK

84.53

85.41

(1.0)%

84.10

90.00

(6.6)%

WestTX

93.96

86.17

9.0 %

91.97

91.11

0.9 %

Weighted average

89.15

87.00

2.5 %

88.09

91.95

(4.2)%

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Operating Highlights(1)

 

Three Months Ended June 30,

Six Months Ended June 30,

2013

2012

Percent

Change

2013

2012

Percent

 Change

Volumes:

Arkoma system(2):

Gathered gas volume (MCFD)

283,238

-

-

272,047

-

-

Processed gas volume(3) (MCFD)

202,113

-

-

201,709

-

-

Residue gas volume (MCFD)

208,163

-

-

208,004

-

-

Processed NGL volume (BPD)

25,590

-

-

22,736

-

-

Condensate volume (BPD)

152

-

-

156

-

-

SouthTX system:

Gathered gas volume (MCFD)

122,245

-

-

122,245

-

-

Processed gas volume(3) (MCFD)

121,338

-

-

121,338

-

-

Residue gas volume (MCFD)

96,606

-

-

96,606

-

-

Processed NGL volume (BPD)

15,041

-

-

15,041

-

-

Condensate volume (BPD)

65

-

-

65

-

-

Velma system:

Gathered gas volume (MCFD)

139,736

136,553

2.3%

135,276

132,888

1.8%

Processed gas volume(3) (MCFD)

132,699

129,070

2.8%

129,058

125,987

2.4%

Residue gas volume (MCFD)

111,487

106,424

4.8%

106,888

103,380

3.4%

Processed NGL volume (BPD)

16,201

14,220

13.9%

15,105

13,931

8.4%

Condensate volume (BPD)

384

434

(11.5)%

394

499

(21.0)%

WestOK system:

Gathered gas volume (MCFD)

506,487

336,377

50.6%

479,577

315,787

51.9%

Processed gas volume(3) (MCFD)

483,504

315,753

53.1%

454,628

297,529

52.8%

Residue gas volume (MCFD)

444,670

291,225

52.7%

420,815

271,582

54.9%

Processed NGL volume (BPD)

22,233

14,379

54.6%

19,258

14,220

35.4%

Condensate volume (BPD)

1,949

1,209

61.2%

1,959

1,307

49.9%

WestTX system(2):

Gathered gas volume (MCFD)

352,865

267,395

32.0%

332,829

256,867

29.6%

Processed gas volume(3) (MCFD)

313,504

236,213

32.7%

297,220

233,359

27.4%

Residue gas volume (MCFD)

229,777

164,593

39.6%

219,889

162,308

35.5%

Processed NGL volume (BPD)

39,901

32,755

21.8%

36,591

32,928

11.1%

Condensate volume (BPD)

1,993

1,941

2.7%

1,516

1,440

5.3%

Barnett system:

   Gathered gas volumes (MCFD)

20,081

23,988

(16.3)%

20,737

23,988

(13.6)%

Tennessee system:

   Gathered gas volumes (MCFD)

8,166

8,348

(2.2)%

8,826

8,286

6.5%

West Texas LPG Partnership(2)

      Average NGL volumes (BPD)

252,886

243,708

3.8%

248,779

243,013

2.4%

Consolidated Volumes:

     Gathered gas volume (MCFD)

1,432,818

772,661

85.4%

1,371,537

737,816

85.9%

     Processed gas volume (MCFD)

1,253,158

681,036

84.0%

1,203,953

656,875

83.3%

     Residue gas volume (MCFD)

1,090,703

562,242

94.0%

1,052,202

537,270

95.8%

     Processed NGL volume (BPD)

118,966

61,354

93.9%

108,731

61,079

78.0%

     Condensate volume (BPD)

4,543

3,584

26.8%

4,090

3,246

26.0%

(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 July 31, 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

3Q13

Sold

Propane

12,726,000

1.25

3Q13

Sold

Propane - Conway

1,260,000

1.06

4Q13

Sold

Propane

16,254,000

1.20

4Q13

Sold

Propane - Conway

1,260,000

1.06

4Q13

Sold

Normal Butane

1,260,000

1.31

1Q14

Sold

Propane

15,624,000

0.98

1Q14

Sold

Iso Butane

1,260,000

1.26

1Q14

Sold

Normal Butane

1,260,000

1.28

1Q14

Sold

Natural Gasoline

1,890,000

2.01

2Q14

Sold

Propane

12,852,000

0.94

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

8,190,000

0.97

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

8,190,000

0.98

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

7,686,000

0.95

1Q15

Sold

Natural Gasoline

2,142,000

1.91

2Q15

Sold

Propane

8,064,000

0.92

2Q15

Sold

Natural Gasoline

630,000

1.97

3Q15

Sold

Propane

378,000

0.93

3Q15

Sold

Natural Gasoline

630,000

1.97

4Q15

Sold

Propane

3,528,000

0.96

4Q15

Sold

Natural Gasoline

630,000

1.97

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

Unaudited Current Commodity Risk Management Positions

(as of July 31, 2013)

SWAP CONTRACTS

CONDENSATE HEDGES

Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

3Q13

Sold

Crude Oil

78,000

97.08

4Q13

Sold

Crude Oil

75,000

96.66

1Q14

Sold

Crude Oil

93,000

95.45

2Q14

Sold

Crude Oil

99,000

93.29

3Q14

Sold

Crude Oil

75,000

89.86

4Q14

Sold

Crude Oil

45,000

88.16

1Q15

Sold

Crude Oil

15,000

85.13

2Q15

Sold

Crude Oil

15,000

85.13

3Q15

Sold

Crude Oil

15,000

85.13

4Q15

Sold

Crude Oil

15,000

85.13

NATURAL GAS HEDGES

Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

3Q13

Sold

Natural Gas

1,530,000

3.62

4Q13

Sold

Natural Gas

1,570,000

3.75

1Q14

Sold

Natural Gas

1,650,000

3.97

2Q14

Sold

Natural Gas

2,650,000

3.89

3Q14

Sold

Natural Gas

4,000,000

3.95

4Q14

Sold

Natural Gas

4,300,000

4.08

1Q15

Sold

Natural Gas

3,865,000

4.30

2Q15

Sold

Natural Gas

3,865,000

4.17

3Q15

Sold

Natural Gas

3,865,000

4.20

4Q15

Sold

Natural Gas

3,565,000

4.27

1Q16

Sold

Natural Gas

1,500,000

4.45

2Q16

Sold

Natural Gas

750,000

4.36

3Q16

Sold

Natural Gas

750,000

4.36

4Q16

Sold

Natural Gas

750,000

4.36

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIESUnaudited Current Commodity Risk Management Positions (as of July 31, 2013)

OPTION CONTRACTS

NGL OPTIONS

Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

3Q13

Purchased

Put

Normal Butane

3,528,000

1.6440

3Q13

Purchased

Put

Iso Butane

1,512,000

1.6637

3Q13

Purchased

Put

Natural Gasoline

6,300,000

2.0901

4Q13

Purchased

Put

Normal Butane

3,780,000

1.6613

4Q13

Purchased

Put

Iso Butane

1,512,000

1.6622

4Q13

Purchased

Put

Natural Gasoline

6,552,000

2.0933

1Q14

Purchased

Put

Iso Butane

1,260,000

1.2225

2Q14

Purchased

Put

Propane

630,000

0.8880

3Q14

Purchased

Put

Propane

630,000

0.8975

4Q14

Purchased

Put

Propane

630,000

0.9200

3Q15

Purchased

Put

Propane

1,260,000

0.8825

CRUDE OPTIONS

Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

3Q13

Purchased

Put

Crude Oil

72,000

100.1000

4Q13

Purchased

Put

Crude Oil

75,000

100.1000

1Q14

Purchased

Put

Crude Oil

181,500

100.9690

2Q14

Purchased

Put

Crude Oil

60,000

88.9100

3Q14

Purchased

Put

Crude Oil

90,000

89.9133

4Q14

Purchased

Put

Crude Oil

117,000

91.5692

1Q15

Purchased

Put

Crude Oil

45,000

91.3333

2Q15

Purchased

Put

Crude Oil

75,000

89.4900

3Q15

Purchased

Put

Crude Oil

75,000

88.5900

4Q15

Purchased

Put

Crude Oil

75,000

88.1500

NATURAL GAS OPTIONS

Production Period

Purchased/Sold

Type

Commodity

MMBTUs

Avg. Strike Price

2Q 2014

Purchased

Put

Natural Gas

300,000

4.10

3Q 2014

Purchased

Put

Natural Gas

300,000

4.15

 

Contact: Matthew Skelly

VP ? Investor Relations

1845 Walnut Street

Philadelphia, PA 19103

(877) 280-2857

(215) 561-5692 (facsimile)

SOURCE Atlas Pipeline Partners, L.P.

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