Atlas Pipeline Partners, L.P. Reports Second Quarter 2012 Results

- Partnership reports record volumes at all three gathering and processing systems

- Distributable Cash Flow for second quarter 2012 of $32.8 million, an increase of 10% year-over-year

- Previously announced distribution of $0.56 per common limited partner unit, 19% higher year-over-year

- Adjusted EBITDA for second quarter 2012 was $49.1 million, a 13% increase year-over-year

- Second quarter 2012 processed gas volume was 681 MMCFD, a 27% increase year-over-year

- Risk management program expanded to increase margin protection for 2013 - 2014

- Velma 60 MMCFD expansion completed; WestOK 200 MMCFD expansion scheduled for completion in third quarter 2012

Aug 01, 2012, 16:34 ET from Atlas Pipeline Partners, L.P.

PHILADELPHIA, Aug. 1, 2012 /PRNewswire/ -- Atlas Pipeline Partners, L.P. (NYSE: APL) ("APL", "Atlas Pipeline", or the "Partnership") today reported record volumes at all three of its gathering and processing systems for the second quarter of 2012 as expansion efforts continue across the Partnership. Processed volumes have increased significantly versus the second quarter of 2011 and each operating area is either at full processing capacity or operating at a high utilization rate.

The Partnership recognized adjusted earnings before interest, income taxes, depreciation and amortization ("Adjusted EBITDA"), of $49.1 million for the second quarter of 2012 driven by the increased volumes across each system versus the same period last year. Processed natural gas volumes averaged 681 million cubic feet per day ("MMCFD"), a 27% increase over the second quarter of 2011. Results for the current quarter were negatively impacted by the planned maintenance of a third-party fractionator at Mont Belvieu, resulting in reduced NGL production in May and June at the Partnership's WestTX system, including the rejection of ethane in order to meet reduced allocated NGL volumes. The Partnership's results were also impacted by lower commodity prices as the weighted average NGL price was $0.80 per gallon for the quarter, a 36% decrease year-over-year. For the second quarter of 2012, Distributable Cash Flow was $32.8 million, or $0.61 per average common limited partner unit, or $2.44 annualized. Net income was $74.9 million for the second quarter of 2012 compared with net income of $8.8 million for the prior year second quarter.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures within the tables 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 17, 2012, the Partnership declared a distribution for the second quarter of 2012 of $0.56 per common limited partner unit to holders of record on August 7, 2012, which will be paid on August 14, 2012. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.01x for the second quarter of 2012.

"We were satisfied with the results during the quarter in the face of a severe decline in commodity prices versus a year ago. Despite a 50% drop in gas prices and a 35% drop in NGL prices compared to this time last year, processed volumes have materially increased on all of our systems compared to a year ago. We remain significantly hedged for 2012 and 2013 and continue to build further protection for expected margin through 2014. Our Velma expansion is online, filling up quickly, and adding fixed-fee cash flow that is not directly impacted by commodity prices. We anticipate being within weeks of bringing our new WestOK plant online. Activity continues to increase in our areas regardless of current price levels. We are optimistic about continuing to build our business on fundamental volume growth and executing on expanding our asset base. Thank you for your continued interest in the Partnership", commented 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 $269.7 million as of June 30, 2012. Total debt outstanding was $713.0 million at June 30, 2012, compared to $524.1 million at December 31, 2011, an increase of $188.9 million. Based upon total debt outstanding at June 30, 2012, total leverage was 3.4x and debt to capital was 36%. The Partnership has completed the previously announced Velma expansion, which was placed in service in June 2012. The WestOK expansion is nearing completion and is scheduled to be placed in service during the second half of 2012. The WestTX Driver Plant construction is in process and the first phase is scheduled to be in service in 2013.

* * *

Risk Management

The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 and 2014. As of August 1, 2012, the Partnership has natural gas, natural gas liquids and condensate protection in place for the remainder of 2012 for approximately 78% of associated margin value (exclusive of ethane), as well as coverage for 2013 for approximately 75% of associated margin value (exclusive of ethane). The Partnership has also added similar protection into 2014 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

Gross margin from operations was $60.8 million for the second quarter 2012 compared to $67.8 million for the prior year period. Gross margin 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 decrease in gross margin was primarily due to decreased NGL prices offset by increased volumes. On all systems, an increase in volumes compared to the prior year period was primarily due to increased producer activity, while the reduction in price was offset by approximately $2.0 million of realized derivative settlements, net of option premiums, during the quarter which are not included in the calculation of gross margin.

WestTX System

The WestTX system's average natural gas processed volume was 236.2 MMCFD for the second quarter 2012 compared with 193.7 MMCFD for the prior year comparable period. Average NGL production volumes were 32,755 barrels per day ("BPD") for the second quarter 2012, an increase of 12.4% compared with the second quarter 2011. Increased volumes are primarily due to increased production in the Spraberry and Wolfberry Trends. While gathered and processed volumes were higher for the second quarter 2012 compared to the prior year quarter, the current period NGL volumes were negatively impacted by a third-party fractionator downstream of the Partnership's plants being down during May 2012 for planned maintenance and operating at a reduced capacity in June and through July 2012. The downtime has resulted in the Partnership's plants being placed on a reduced NGL allocation causing the Partnership's facilities to operate in ethane rejection. The Partnership expects the NGL allocation to return to previous levels once the third-party fractionator is fully operational.

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 first phase of construction of the previously announced Driver plant, which will increase processing capacity by 100 MMCFD, is progressing on schedule and is expected to be completed in the first quarter of 2013. The second phase, involving placement of additional compression and refrigeration equipment to increase the plant's capacity to 200 MMCFD, is now scheduled to be operational by the first quarter of 2014, or earlier as capacity is needed. This is more than a full year ahead of the original planned in-service date of first quarter of 2015 that was previously announced.

WestOK System

The WestOK system had average natural gas processed volume of 315.8 MMCFD for the second quarter 2012, a 27.4% increase from the prior year comparable period. NGL production increased to 14,379 BPD for the second quarter 2012, an 8.9% increase from the prior year comparable period. The Partnership began rejecting ethane at its WestOK facilities in June 2012 due to the decline in processing economics which impacted the total NGL volumes produced during the period. The WestOK system is continuing to operate in excess of capacity with certain volumes being off-loaded to third-parties for processing or by-passing the processing facilities. The Partnership expects volumes to continue to increase as producers in Oklahoma, along with others in Kansas, continue to add to the system via development in the oil-rich Mississippian Limestone formation. The Partnership is currently working to install a new 200 MMCFD cryogenic plant and an expansion of the gathering system in order to meet the drilling plans of its existing producers. The expansion is expected to be completed in the third quarter of 2012.

Velma System

The Velma system's average natural gas processed volume was 129.1 MMCFD for the second quarter 2012, a 33.6% increase from the prior year comparable period. 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 14,220 BPD for the second quarter 2012, up approximately 25.1% compared to the prior year comparable period, 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, which supports the additional volumes from XTO Energy, Inc. and other producers in the area who are looking to take advantage of the high NGL content gas in the Woodford shale. The plants are currently processing at approximately 88% of the newly expanded 160 MMCFD capacity.

* * *

Corporate and Other

Net of deferred financing costs, interest expense increased to $8.1 million for the second quarter 2012 up 59.2% as compared with $5.1 million for the second quarter 2011. This increase was due to an increase in the outstanding balance on the revolving credit facility and the November 2011 issuance of additional senior notes as a result of financing the current organic expansion program.

* * *

Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's second quarter 2012 results on Thursday, August 2, 2012 at 9:00 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 Thursday, August 2, 2012. To access the replay, dial 1-888-286-8010 and enter conference code 15057488.

Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the midcontinent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates seven active gas processing plants as well as approximately 9,100 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner interest and approximately 52% of the limited partner interests 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 which it owns a 2% general partner interest, all the incentive distribution rights and an approximate 11% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.

Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity prices and local or national economic conditions and other risks detailed from time to time in Atlas Pipeline's reports filed with the SEC, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary(1) (unaudited; in thousands except per unit amounts)

Three Months Ended

Six Months Ended

June 30,

June 30,

2012

2011

2012

2011

Revenue:

Natural gas and liquids sales

$

238,801

$

330,168

$

528,026

$

596,477

Transportation, processing and other fees(2)

14,878

10,435

27,559

19,845

Derivative gain (loss), net(3)

67,847

6,837

55,812

(14,808)

Other income, net(3)

2,588

2,745

5,003

5,534

Total revenues

324,114

350,185

616,400

607,048

Costs and expenses:

Natural gas and liquids cost of sales

195,103

274,176

428,208

492,468

Plant operating

14,600

13,381

28,481

26,155

Transportation and compression

212

151

476

335

General and administrative(4)

7,505

8,153

16,472

15,993

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

2,940

502

3,918

1,679

Other

(161)

575

(195)

575

Depreciation and amortization

21,712

19,123

42,554

38,028

Interest

9,269

6,145

17,977

18,590

Total costs and expenses

251,180

322,206

537,891

593,823

Equity income in joint ventures

1,917

687

2,813

1,149

Gain (loss) on asset sales and other

-

(273)

-

255,674

Loss on early extinguishment of debt

-

(19,574)

-

(19,574)

Income from continuing operations

74,851

8,819

81,322

250,474

Loss on sale of discontinued operations

-

-

-

(81)

Net income

74,851

8,819

81,322

250,393

Income attributable to non-controlling interests

(1,061)

(1,545)

(2,597)

(2,732)

Preferred unit dividends

-

(149)

-

(389)

Net income attributable to common limited partners and the General Partner

$

73,790

$

7,125

$

78,725

$

247,272

Net income attributable to common limited partners per unit:

Basic and diluted:

$

1.30

$

0.13

$

1.37

$

4.50

Weighted average common limited partner units (basic)

53,646

53,517

53,633

53,446

Weighted average common limited partner units (diluted)

54,510

53,909

54,262

53,878

(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) Adjusted to separately present derivative gain (loss) within derivative 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-Q. 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

Six Months Ended

June 30,

June 30,

2012

2011

2012

2011

Summary Cash Flow Data:

Cash provided by operating activities

$

21,784

$

48,183

$

64,531

$

51,910

Cash provided by (used in) investing activities

(84,551)

(158,843)

(182,827)

222,562

Cash provided by (used in) financing activities

62,856

110,659

118,385

(274,470)

Capital Expenditure Data:

Maintenance capital expenditures

$

4,000

$

5,211

$

8,510

$

8,471

Expansion capital expenditures

61,221

68,425

137,878

83,498

Investments in joint ventures and acquisitions

19,454

85,000

36,689

12,250

Total

$

84,675

$

158,636

$

183,077

$

104,219

Condensed Consolidated Balance Sheets (unaudited; in thousands)

ASSETS

June 30,

2012

December 31, 2011

Current assets:

Cash and cash equivalents

$

257

$

168

Other current assets

143,476

132,698

Total current assets

143,733

132,866

Property, plant and equipment, net

1,705,034

1,567,828

Intangible assets, net

111,702

103,276

Investment in joint ventures

86,092

86,879

Other assets, net

53,841

39,963

$

2,100,402

$

1,930,812

LIABILITIES AND EQUITY

Current liabilities

$

126,657

$

172,406

Long-term debt, less current portion

709,065

522,055

Other long-term liability

6,129

123

Commitments and contingencies

Total partners' capital

1,284,236

1,264,629

Non-controlling interest

(25,685)

(28,401)

Total equity

1,258,551

1,236,228

$

2,100,402

$

1,930,812

 

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

Three Months Ended

Six Months Ended

June 30,

June 30,

2012

2011

2012

2011

Net income

$

74,851

$

8,819

$

81,322

$

250,393

Income attributable to non-controlling interests

(1,061)

(1,545)

(2,597)

(2,732)

Interest expense

9,269

6,145

17,977

18,590

Depreciation and amortization

21,712

19,123

42,554

38,028

EBITDA

104,771

32,542

139,256

304,279

Adjustment for cash flow from investment in joint ventures

(117)

(687)

787

615

(Gain) loss on asset sale

-

273

-

(255,593)

Loss on early extinguishment of debt

-

19,574

-

19,574

Non-cash (gain) loss on derivatives

(64,741)

(13,788)

(54,045)

4,572

Premium expense on derivative instruments

3,984

3,710

7,736

6,715

Other non-cash losses(2)

5,163

1,859

6,413

1,922

Adjusted EBITDA

49,060

43,483

100,147

82,084

Interest expense

(9,269)

(6,145)

(17,977)

(18,590)

Amortization of deferred finance costs

1,130

1,034

2,295

2,301

Preferred unit dividends

-

(149)

-

(389)

Premium expense on derivative instruments

(3,984)

(3,710)

(7,736)

(6,715)

Proceeds remaining from asset sale(3)

-

-

-

5,850

Other costs

(161)

575

(195)

575

Maintenance capital

(4,000)

(5,211)

(8,510)

(8,471)

Distributable Cash Flow

$

32,776

$

29,877

$

68,024

$

56,645

(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

 

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

Three Months Ended June 30,

Six Months Ended June 30,

2012

2011

Percent Change

2012

2011

Percent Change

Pricing (unhedged):

Weighted Average Market Prices:

NGL price per gallon - Conway hub

$  0.70

$   1.16

(39.7)%

$   0.82

$  1.12

(26.8)%

NGL price per gallon - Mt. Belvieu hub

0.94

1.34

(29.9)%

1.06

1.27

(16.5)%

Natural gas sales ($/MCF):

Velma

2.04

4.11

(50.4)%

2.29

4.05

(43.5)%

WestOK

2.09

4.14

(49.5)%

2.30

4.05

(43.2)%

WestTX

1.85

4.12

(55.1)%

2.18

4.03

(45.9)%

Weighted average

2.01

4.13

(51.3)%

2.26

4.05

(44.2)%

NGL sales ($/Gallon):

Velma

0.71

1.16

(38.8)%

0.82

1.10

(25.5)%

WestOK

0.79

1.17

(32.5)%

0.85

1.12

(24.1)%

WestTX

0.88

1.36

(35.3)%

1.03

1.28

(19.5)%

Weighted average

0.80

1.25

(36.0)%

0.92

1.18

(22.0)%

Condensate sales ($/barrel):

Velma

93.69

101.57

(7.8)%

98.52

96.51

2.1%

WestOK

85.41

93.68

(8.8)%

90.00

89.29

0.8%

WestTX

86.17

100.42

(14.2)%

91.11

96.66

(5.7)%

Weighted average

87.00

98.23

(11.4)%

91.95

93.79

(2.0)%

Operating data:

Velma system:

Gathered gas volume (MCFD)

136,553

102,159

33.7%

132,888

96,418

37.8%

Processed gas volume (MCFD)(2)     

129,070

96,625

33.6%

125,987

90,923

38.6%

Residue Gas volume (MCFD)

106,424

78,381

35.8%

103,380

74,072

39.6%

NGL volume (BPD)

14,220

11,367

25.1%

13,931

10,722

29.9%

Condensate volume (BPD)

434

442

(1.8)%

499

486

2.7%

WestOK system:

Gathered gas volume (MCFD)

336,377

260,250

29.3%

315,787

252,257

25.2%

Processed gas volume (MCFD)(2)

315,753

247,868

27.4%

297,529

238,925

24.5%

Residue Gas volume (MCFD)

291,225

230,605

26.3%

271,582

214,711

26.5%

NGL volume (BPD)

14,379

13,204

8.9%

14,220

13,397

6.1%

Condensate volume (BPD)

1,209

884

36.8%

1,307

871

50.1%

WestTX system(3):

Gathered gas volume (MCFD)

267,395

204,515

30.7%

256,867

195,268

31.5%

Processed gas volume (MCFD)

236,213

193,714

21.9%

233,359

183,323

27.3%

Residue Gas volume (MCFD)

164,593

133,012

23.7%

162,308

124,512

30.4%

NGL volume (BPD)

32,755

29,147

12.4%

32,928

28,316

16.3%

Condensate volume (BPD)

1,941

1,827

6.2%

1,440

1,428

0.8%

Tennessee system:

Average throughput volumes (MCFD)

8,348

7,675

8.8%

8,286

7,876

5.2%

West Texas LPG(3):

Average NGL volumes (BPD)

243,708

230,913

5.5%

243,013

227,087

7.0%

Consolidated Volumes:

Gathered gas volume (MCFD)

748,673

574,599

30.3%

713,828

551,819

29.4%

Processed gas volume (MCFD)

681,036

538,207

26.5%

656,875

513,171

28.0%

Residue gas volume (MCFD)

562,242

441,998

27.2%

537,270

413,295

30.0%

Processed NGL volume (BPD)

61,354

53,718

14.2%

61,079

52,435

16.5%

Condensate volume (BPD)

3,584

3,153

13.7%

3,246

2,785

16.6%

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

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

(3) Operating data for WestTX and WTLPG represent 100% of the operating activity for the respective systems

 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of July 31, 2012)

Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2014. 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 HEDGES

Production Period

Purchased /Sold

Commodity

MMBTUs

Avg. Fixed Price

3Q 2012

Sold

Natural gas

1,320,000

2.98

4Q 2012

Sold

Natural gas

1,140,000

3.28

2Q 2013

Sold

Natural gas

600,000

3.43

3Q 2013

Sold

Natural gas

600,000

3.52

1Q 2014

Sold

Natural gas

1,350,000

3.90

2Q 2014

Sold

Natural gas

1,350,000

3.90

3Q 2014

Sold

Natural gas

1,350,000

3.90

4Q 2014

Sold

Natural gas

1,350,000

3.90

NATURAL GAS LIQUIDS HEDGES

Production Period

Purchased /Sold

Commodity

Gallons

Avg. Fixed Price

3Q 2012

Sold

Propane

5,040,000

1.25

3Q 2012

Sold

Isobutane

756,000

1.57

3Q 2012

Sold

Normal butane

1,260,000

1.71

3Q 2012

Sold

Natural gasoline

1,008,000

2.39

4Q 2012

Sold

Propane

5,040,000

1.35

4Q 2012

Sold

Isobutane

756,000

1.58

4Q 2012

Sold

Normal butane

1,386,000

1.71

4Q 2012

Sold

Natural gasoline

1,134,000

2.39

1Q 2013

Sold

Propane - Conway

1,260,000

1.06

1Q 2013

Sold

Propane

6,552,000

1.30

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

11,718,000

1.28

4Q 2013

Sold

Propane - Conway

1,260,000

1.06

4Q 2013

Sold

Propane

12,222,000

1.28

1Q 2014

Sold

Propane

630,000

1.27

2Q 2014

Sold

Natural gasoline

1,260,000

1.86

3Q 2014

Sold

Natural gasoline

1,260,000

1.86

4Q 2014

Sold

Natural gasoline

1,260,000

1.87

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of July 31, 2012)

SWAP CONTRACTS

CONDENSATE HEDGES

Production Period

Purchased /Sold

Commodity

Barrels

Avg. Fixed Price

3Q 2012

Sold

Crude

69,000

96.65

4Q 2012

Sold

Crude

75,000

95.58

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

30,000

99.00

2Q 2014

Sold

Crude

60,000

93.58

3Q 2014

Sold

Crude

30,000

88.65

4Q 2014

Sold

Crude

30,000

88.09

OPTION CONTRACTS

NGL OPTIONS

Production Period

Purchased/Sold

Type

Commodity

Gallons

Avg. Strike Price

3Q 2012

Purchased

Put

Propane

7,560,000

1.36

3Q 2012

Purchased

Put

Isobutane

1,008,000

1.57

3Q 2012

Purchased

Put

Normal Butane

1,890,000

1.54

3Q 2012

Purchased

Put

Natural Gasoline

3,780,000

2.00

4Q 2012

Purchased

Put

Propane

8,190,000

1.36

4Q 2012

Purchased

Put

Isobutane

1,134,000

1.58

4Q 2012

Purchased

Put

Normal Butane

2,142,000

1.56

4Q 2012

Purchased

Put

Natural Gasoline

4,032,000

2.00

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

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

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of July 31, 2012)

OPTION CONTRACTS

CRUDE OPTIONS

Production Period

Purchased/Sold

Type

Commodity

Barrels

Avg. Strike Price

3Q 2012

Purchased

Put

Crude Oil

39,000

106.56

3Q 2012

Sold

Call

Crude Oil

124,500

94.69

3Q 2012

Purchased

Call

Crude Oil

45,000

125.20

4Q 2012

Purchased

Put

Crude Oil

39,000

105.80

4Q 2012

Sold

Call

Crude Oil

124,500

94.69

4Q 2012

Purchased

Call

Crude Oil

45,000

125.20

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

45,000

87.71

4Q 2014

Purchased

Put

Crude Oil

45,000

87.43

 

Contact: Matthew Skelly                   VP – Investor Relations                                                             1845 Walnut Street Philadelphia, PA 19103 (877) 280-2857 (215) 561-5692 (facsimile)  

 

 

 

 

SOURCE Atlas Pipeline Partners, L.P.



RELATED LINKS

http://www.atlaspipeline.com