Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Targa Pipeline Partners LP | d8k.htm |
Exhibit 99.1
| Contact: | Matthew Skelly VP – Investor Relations 1845 Walnut Street Philadelphia, PA 19103 (877) 280-2857 (215) 561-5692 (facsimile) |
ATLAS PIPELINE PARTNERS, L.P.
REPORTS SECOND QUARTER 2011 RESULTS
| • | Adjusted EBITDA for second quarter 2011 was $43.5 million |
| • | Distributable Cash Flow for second quarter 2011 was $29.9 million |
| • | Announced distribution of $0.47 per common limited partner unit, a 17% increase over previous quarter |
| • | Second quarter 2011 processed gas volume was 538 Mmcfd, a 31% year-over-year quarterly increase |
| • | Improved balance sheet through long term debt reduction and $100 million increase in revolver capacity |
| • | Completed strategic acquisition of 20% interest in West Texas LPG Partnership to add low-risk, fixed-fee cash flow |
| • | Previously announced major organic expansions are underway |
Philadelphia, PA, August 1, 2011 – 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 $43.5 million for the second quarter of 2011 as volumes and natural gas liquids (“NGL”) prices increased across all systems. Processed natural gas volumes totaled 538 million cubic feet per day, a 31% increase to the same period last year, and the weighted average NGL price was $1.25/gallon for the quarter, a 42% increase. For the second quarter of 2011, Distributable Cash Flow was $29.9 million, or $0.56 per average common limited partner unit. Net income was $8.8 million for the second quarter of 2011 compared with net income of $0.7 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 26, 2011, the Partnership declared a distribution for the second quarter of 2011 of $0.47 per common limited partner unit to holders of record on August 5, 2011, and payable on August 12, 2011. This represents a sequential quarterly growth rate of 17.5% over the first quarter of 2011. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.2x for the second quarter of 2011.
“We are pleased to have reported strong second quarter results, which would have been even better aside from some extremely hot weather and a short period of maintenance downtime at our WestOK system. Since the first quarter, we achieved 100% capacity on all our systems, which gives us substantial operating leverage as drilling activity continues to be better than expected. During the quarter we have simplified and enhanced our balance sheet, announced significant system wide expansion plans of which we have already begun work, as well as closed on our 20% investment in the West Texas LPG pipeline, a strategic addition for our WestTX System. To finance our growth, we have raised the capacity on our revolving credit facility to $450 million,” stated Eugene Dubay, Chief Executive Officer of the Partnership.
Regarding the recent second quarter distribution, Mr. Dubay added, “We have recently announced a distribution of $0.47 per limited common unit, a 17% increase from the previous quarter, and have achieved publicly stated distribution guidance of $0.45-0.50 per unit a quarter earlier than expected. The Partnership will continue to execute financially and operationally so that we may continue to grow the distribution for our unit holders in the second half of 2011. Thank you for all of your continued support.”
* * *
1
Capitalization and Liquidity
Utilizing proceeds from the sale of its interest in the Laurel Mountain JV, the Partnership redeemed its outstanding 8 1/8% Senior Notes due 2015 on April 8, 2011. In addition, the Partnership repurchased $7.2 million of its 8 3/4% Senior Notes due 2018 through a tender offer which expired on April 7, 2011. The costs and premium associated with the redemption and repurchase of these notes, along with previously capitalized financing costs, totaled $19.6 million and was recognized as a non-recurring expense during the current quarter, which is excluded from Adjusted EBITDA and Distributable Cash Flow. Additionally, the Partnership has exercised the $100 million accordion feature on its revolving credit facility to increase the capacity from $350 million to $450 million, effective July 8, 2011. The other terms of the Partnership’s credit facility remain unchanged.
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $206.0 million as of June 30, 2011, which does not include the $100 million increase in its revolving credit facility announced on July 11, 2011. Total debt outstanding was reduced to $359.0 million at June 30, 2011, from $566.0 million at December 31, 2010, a decrease of $207.0 million. Based upon the total debt outstanding at June 30, 2011, total leverage was 2.3x and debt to capital was 22%, inclusive of a large portion of the purchase of two new cryogenic processing facilities and the strategic investment of a 20% interest in the West Texas LPG Partnership as part of the Partnership’s recently announced expansions.
* * *
Risk Management
The Partnership has continued to enhance its risk management portfolio, recently adding additional protection for the fourth quarter of 2012 as well as in 2013. As of July 29, 2011, the Partnership has natural gas, natural gas liquids and condensate protection in place for the remainder of 2011 for approximately 75% of associated margin value, as well as coverage for 2012 on approximately 47% of associated margin value. 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 such banks. A table summarizing our risk management portfolio is included in this release.
* * *
Operating Results
Gross margin from operations was $67.8 million for the second quarter 2011, compared to $46.0 million for the same period last year. Gross margin includes natural gas and liquids revenues and transportation, compression and other fees, less purchased product costs and non-cash gains (or losses). The increase in gross margin was primarily due to increased NGL prices and volumes across all systems. Volume increases on the WestTX system are a result of additional development for oil drilling in the Permian Basin. Volumes on the Velma system increased due to production added on the Madill to Velma gathering system associated with activity in the Woodford Shale. The increase in volumes on the Partnership’s WestOK system is related to our expansion into Kansas and increased producer activity in the counties along the Oklahoma and Kansas borders, particularly in the Mississippian formations.
WestTX System
The WestTX system’s average natural gas processed volume was 193.7 million cubic feet per day (“Mmcfd”) for the second quarter 2011 compared with 164.1 Mmcfd for the prior year comparable quarter, an increase of 18.0%. Average gross NGL production volumes increased to 29,147 barrels per day (“bpd”) for the second quarter 2011, compared to 26,609 bpd in the prior year second quarter, an increase of 9.5%. Increased volumes are primarily due to increased production from its partner, Pioneer Natural Resources (NYSE: PXD) (“Pioneer”) and significant growth in associated natural gas volumes from other producers in the Spraberry and Wolfberry Trends, including Concho Resources Inc. (NYSE: CXO), and Endeavor Energy Resources. The Partnership expects volumes on this system to continue to increase as Pioneer and other producers continue to aggressively pursue their drilling plans over the coming years. As a result of this increased producer activity, the Partnership is re-commissioning its 60 Mmcfd Midkiff plant, which will increase processing capacity on the WestTX system to 255 Mmcfd, an increase of 31% over the current system. The expansion is expected to be in-service during the third quarter of 2011.
West Texas LPG Pipeline
On May 11, 2011, the Partnership completed the acquisition of a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. WTLPG owns a 2,295 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corp. (NYSE: CVX). The Partnership realized the equity earnings for this investment from May 11, 2011, however it does not include any cash flows from this investment in its Distributable Cash Flow for the period until they are received, which is delayed by one quarter.
2
WestOK System
The WestOK system had average natural gas processed volume of 247.9 Mmcfd, a 43.2% increase, and NGL production of 13,204 bpd, a 38.9% increase, for the second quarter 2011 from the prior year comparable period. The Partnership completed the Woolsey expansion of its WestOK system into Kansas during June 2010 and experienced an increase in processed gas volumes due to this project, as well as increased production from other producers on the system, including Chesapeake Energy Corp. (NYSE: CHK) and SandRidge Energy Inc. (NYSE: SD). The WestOK system is currently operating 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 in 2011 as volumes from 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 has purchased and 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. This expansion would result in total processing capacity of 428 Mmcfd, for an increase of 88%. The expansion is expected to be completed in mid-2012.
Velma System
The Velma system’s average natural gas processed volume was 96.6 Mmcfd for the second quarter 2011, an increase of 33.0% compared with the comparable quarter in the prior year. 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. Gathered volumes were up 23.2 Mmcfd, or 29.3% compared to the same quarter last year. Average NGL production increased to 11,367 bpd for the second quarter 2011, up approximately 38.1% compared to 8,230 bpd for the prior year second quarter, due to the increased processed volumes. The Partnership plans to expand the Velma system by adding a 60 Mmcfd cryogenic plant, thereby increasing processing capacity to 160 Mmcfd, an increase of 60%, as producers look to take advantage of high NGL content gas in the Woodford shale.
* * *
Corporate and Other
Net of deferred financing costs, interest expense decreased to $5.1 million for the second quarter 2011, down 77.8% as compared with $23.0 million for the second quarter 2010. This decrease was primarily due to an $847.7 million reduction in debt outstanding since June 30, 2010 from the proceeds of the Elk City/Sweetwater and Laurel Mountain sales.
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s second quarter 2011 results on Tuesday, August 2, 2011 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 1:00 pm ET on Tuesday, August 2, 2011. To access the replay, dial 1-888-286-8010 and enter conference code 5100899.
Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates five active gas processing plants as well as approximately 8,600 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in the West Texas LPG Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.
Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P., through which it owns a 2% general partner interest, all the incentive distribution rights and approximately 5.75 million common limited partner units of APL. Additionally, ATLS owns an interest in over 8,500 producing natural gas and oil wells, representing over 185 Bcfe of net proved developed reserves. For more information, please visit the Partnership website at http://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, reports on Form 8-K and annual reports on Form 10-K.
3
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary(1)
(unaudited; in thousands)
| Three Months Ended June 30, |
Six Months Ended June 30, |
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| 2011 | 2010(2) | 2011 | 2010(2) | |||||||||||||
| Revenue: |
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| Natural gas and liquids |
$ | 330,168 | $ | 198,162 | $ | 596,477 | $ | 421,500 | ||||||||
| Transportation, processing and other fees(3) |
10,435 | 9,898 | 19,845 | 19,993 | ||||||||||||
| Other income (loss), net |
9,582 | 8,167 | (9,274 | ) | 14,887 | |||||||||||
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| Total revenue and other income (loss), net |
350,185 | 216,227 | 607,048 | 456,380 | ||||||||||||
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| Costs and expenses: |
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| Natural gas and liquids |
274,176 | 162,816 | 492,468 | 342,575 | ||||||||||||
| Plant operating |
13,381 | 11,981 | 26,155 | 23,940 | ||||||||||||
| Transportation and compression |
151 | 232 | 335 | 421 | ||||||||||||
| General and administrative(4) |
8,153 | 4,288 | 15,993 | 13,916 | ||||||||||||
| General and administrative – non-cash unit-based compensation(4) |
502 | 1,904 | 1,679 | 2,027 | ||||||||||||
| Other |
575 | — | 575 | — | ||||||||||||
| Depreciation and amortization |
19,123 | 18,624 | 38,028 | 37,081 | ||||||||||||
| Interest |
6,145 | 24,595 | 18,590 | 50,998 | ||||||||||||
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| Total costs and expenses |
322,206 | 224,440 | 593,823 | 470,958 | ||||||||||||
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| Equity income in joint ventures |
687 | 888 | 1,149 | 2,350 | ||||||||||||
| Gain on asset sale |
(273 | ) | — | 255,674 | — | |||||||||||
| Loss on early extinguishment of debt |
(19,574 | ) | — | (19,574 | ) | — | ||||||||||
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| Income (loss) from continuing operations |
8,819 | (7,325 | ) | 250,474 | (12,228 | ) | ||||||||||
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| Discontinued operations: |
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| Loss on sale of discontinued operations |
— | — | (81 | ) | — | |||||||||||
| Earnings from discontinued operations |
— | 7,976 | — | 14,757 | ||||||||||||
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| Income (loss) from discontinued operations |
— | 7,976 | (81 | ) | 14,757 | |||||||||||
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| Net income |
8,819 | 651 | 250,393 | 2,529 | ||||||||||||
| Income attributable to non-controlling interests |
(1,545 | ) | (945 | ) | (2,732 | ) | (2,262 | ) | ||||||||
| Preferred unit dividends |
(149 | ) | — | (389 | ) | — | ||||||||||
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| Net income (loss) attributable to common limited partners and the General Partner |
$ | 7,125 | $ | (294 | ) | $ | 247,272 | $ | 267 | |||||||
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| (1) | Based on the GAAP statements of operations to be included in Form 10-Q, with additional detail of certain items included. |
| (2) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems. |
| (3) | Includes affiliate revenues related to transportation and processing provided to Atlas Energy, LP. |
| (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. |
4
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary (continued)
(unaudited; in thousands, except per unit amounts)
| Three Months Ended June 30, |
Six Months Ended June 30, |
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| 2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
| Net income (loss) attributable to common limited partners per unit: |
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| Basic: |
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| Continuing operations |
$ | 0.13 | $ | (0.15 | ) | $ | 4.50 | $ | (0.27 | ) | ||||||
| Discontinued operations |
— | 0.14 | — | 0.27 | ||||||||||||
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| $ | 0.13 | $ | (0.01 | ) | $ | 4.50 | $ | — | ||||||||
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| Weighted average common limited partner units (basic) |
53,517 | 53,214 | 53,446 | 53,033 | ||||||||||||
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| Diluted: |
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| Continuing operations |
$ | 0.13 | $ | (0.15 | ) | $ | 4.50 | $ | (0.27 | ) | ||||||
| Discontinued operations |
— | 14 | — | 0.27 | ||||||||||||
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| $ | 0.13 | $ | (0.01 | ) | $ | 4.50 | $ | — | ||||||||
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| Weighted average common limited partner units (diluted) |
53,909 | 53,214 | 53,878 | 53,033 | ||||||||||||
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| Summary Cash Flow Data: |
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| Cash provided by operating activities |
$ | 48,183 | $ | 9,624 | $ | 51,910 | $ | 57,126 | ||||||||
| Cash provided by (used in) investing activities |
(158,843 | ) | (20,979 | ) | 222,562 | (29,377 | ) | |||||||||
| Cash provided by (used in) financing activities |
110,659 | 11,356 | (274,470 | ) | (28,610 | ) | ||||||||||
| Capital Expenditure Data: |
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| Maintenance capital expenditures |
$ | 5,211 | $ | 3,008 | $ | 8,471 | $ | 3,883 | ||||||||
| Expansion capital expenditures |
68,425 | 10,053 | 83,498 | 16,855 | ||||||||||||
| Investments in Joint Ventures |
85,000 | 5,614 | 12,250 | 5,614 | ||||||||||||
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| Total |
$ | 158,636 | $ | 18,675 | $ | 104,219 | $ | 26,352 | ||||||||
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| (1) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems. |
5
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited; in thousands)
| June 30, 2011 |
December 31, 2010 |
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| ASSETS | ||||||||
| Current assets: |
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| Cash and cash equivalents |
$ | 166 | $ | 164 | ||||
| Other current assets |
139,638 | 114,877 | ||||||
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| Total current assets |
139,804 | 115,041 | ||||||
| Property, plant and equipment, net |
1,413,104 | 1,341,002 | ||||||
| Intangible assets, net |
114,827 | 126,379 | ||||||
| Investment in joint venture |
85,687 | 153,358 | ||||||
| Other assets, net |
25,843 | 29,068 | ||||||
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| $ | 1,779,265 | $ | 1,764,848 | |||||
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| LIABILITIES AND EQUITY | ||||||||
| Current liabilities |
$ | 175,053 | $ | 151,606 | ||||
| Long-term portion of derivative liability |
976 | 5,608 | ||||||
| Long-term debt, less current portion |
358,744 | 565,764 | ||||||
| Other long-term liability |
173 | 223 | ||||||
| Commitments and contingencies |
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| Total partners’ capital |
1,275,716 | 1,074,184 | ||||||
| Non-controlling interest |
(31,397 | ) | (32,537 | ) | ||||
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| Total equity |
1,244,319 | 1,041,647 | ||||||
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| $ | 1,779,265 | $ | 1,764,848 | |||||
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6
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Reconciliation of Non-GAAP Measures
(unaudited; in thousands)
| Three Months
Ended June 30, |
Six Months
Ended June 30, |
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| 2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
| Reconciliation of net income (loss) to other non-GAAP measures(2): |
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| Net income (loss) |
$ | 8,819 | $ | 651 | $ | 250,393 | $ | 2,529 | ||||||||
| Income attributable to non-controlling interests |
(1,545 | ) | (945 | ) | (2,732 | ) | (2,262 | ) | ||||||||
| Depreciation and amortization |
19,123 | 18,624 | 38,028 | 37,081 | ||||||||||||
| Interest expense(3) |
6,145 | 24,740 | 18,590 | 51,602 | ||||||||||||
| Depreciation, amortization and interest of discontinued operations |
— | 4,262 | — | 8,579 | ||||||||||||
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| EBITDA |
32,542 | 47,332 | 304,279 | 97,529 | ||||||||||||
| Adjustment for cash flow from investment in joint ventures |
(687 | ) | 1,571 | 615 | 4,100 | |||||||||||
| Non-cash (gain) loss on derivatives |
(13,788 | ) | (9,838 | ) | 4,572 | (22,250 | ) | |||||||||
| Early termination cash derivative expense(4) |
— | 12,785 | — | 22,402 | ||||||||||||
| Premium expense on derivative instruments |
3,710 | 7,163 | 6,715 | 13,817 | ||||||||||||
| (Gain) loss on asset sales and other |
273 | — | (255,593 | ) | — | |||||||||||
| Loss on early extinguishment of debt |
19,574 | — | 19,574 | — | ||||||||||||
| Other non-cash (gains) losses(5) |
1,859 | 2,647 | 1,922 | 2,948 | ||||||||||||
| Discontinued operations adjustments(6) |
— | 1,309 | — | 24 | ||||||||||||
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| Adjusted EBITDA |
43,483 | 62,969 | 82,084 | 118,570 | ||||||||||||
| Interest expense(3) |
(6,145 | ) | (24,740 | ) | (18,590 | ) | (51,602 | ) | ||||||||
| Amortization of deferred financing costs |
1,034 | 1,559 | 2,301 | 3,182 | ||||||||||||
| Preferred unit dividends |
(149 | ) | — | (389 | ) | — | ||||||||||
| Premium expense on derivative instruments |
(3,710 | ) | (7,163 | ) | (6,715 | ) | (13,817 | ) | ||||||||
| Laurel Mountain proceeds remaining(7) |
— | — | 5,850 | — | ||||||||||||
| Other |
575 | — | 575 | — | ||||||||||||
| Maintenance capital expenditures |
(5,211 | ) | (3,008 | ) | (8,471 | ) | (3,883 | ) | ||||||||
| Discontinued operations adjustments(8) |
— | (3,090 | ) | — | (6,547 | ) | ||||||||||
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| Distributable Cash Flow |
$ | 29,877 | $ | 26,527 | $ | 56,645 | $ | 45,903 | ||||||||
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| (1) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems and modifications to the Partnership’s credit facility Consolidated EBITDA definition and covenant calculations. |
| (2) | 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 that 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 that is utilized within the Partnership’s financial covenants under its credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of the Partnership’s Elk City/Sweetwater system; and (ii) other non-cash items specifically excluded under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP. |
| (3) | For the three and six months ended June 30, 2010, includes the cost of interest rate swaps that were previously recognized in interest expense prior to becoming ineffective in June 2009. They were subsequently recorded in other income (loss), net in the Partnership’s income statement. |
| (4) | During the three and six months ended June 30, 2010, the Partnership made net payments of $20.4 million and $33.7 million, respectively, related to the early termination of derivative contracts, including $7.6 million and $11.3 million, respectively, related to Elk City derivatives included in discontinued operations adjustments. The Partnership’s credit facility definition of Consolidated EBITDA allows for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of equity. |
| (5) | Includes the non-cash impact of commodity price movements on pipeline linefill inventory and non-cash compensation. |
| (6) | Discontinued operation adjustments for Adjusted EBITDA include (i) early termination cash derivative expense; (ii) premium expense on derivative instruments; and (iii) non-cash (gain) loss on derivatives. |
| (7) | Net proceeds remaining from the sale of Laurel Mountain after the repayment of the amount outstanding on the Partnership’s revolving credit facility, redemption of its 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018. |
| (8) | Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; (ii) interest expense and (iii) premiums expense on derivative instruments. |
7
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2011 | 2010 | Percent Change |
2011 | 2010 | Percent Change |
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| Pricing (unhedged): |
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| Mid-Continent Weighted Average Prices: |
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| NGL price per gallon – Conway hub |
$ | 1.16 | $ | 0.81 | 43.2 | % | $ | 1.12 | $ | 0.92 | 21.7 | % | ||||||||||||
| NGL price per gallon – Mt. Belvieu hub |
1.34 | 0.97 | 38.1 | % | 1.27 | 1.04 | 22.1 | % | ||||||||||||||||
| Natural gas sales ($/Mcf): |
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| Velma |
4.11 | 3.89 | 5.7 | % | 4.05 | 4.56 | (11.2 | )% | ||||||||||||||||
| WestOK |
4.14 | 3.91 | 5.9 | % | 4.05 | 4.55 | (11.0 | )% | ||||||||||||||||
| WestTX |
4.12 | 3.88 | 6.2 | % | 4.03 | 4.53 | (11.0 | )% | ||||||||||||||||
| Weighted Average |
4.13 | 3.90 | 5.9 | % | 4.05 | 4.45 | (9.0 | )% | ||||||||||||||||
| NGL sales ($/gallon): |
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| Velma |
1.16 | 0.83 | 39.8 | % | 1.10 | 0.92 | 19.6 | % | ||||||||||||||||
| WestOK |
1.17 | 0.82 | 42.7 | % | 1.12 | 0.92 | 21.7 | % | ||||||||||||||||
| WestTX |
1.36 | 0.98 | 38.8 | % | 1.28 | 1.04 | 23.1 | % | ||||||||||||||||
| Weighted Average |
1.25 | 0.88 | 42.0 | % | 1.18 | 0.95 | 24.2 | % | ||||||||||||||||
| Condensate sales ($/barrel): |
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| Velma |
101.57 | 76.21 | 33.3 | % | 96.51 | 76.64 | 25.9 | % | ||||||||||||||||
| WestOK |
93.68 | 70.22 | 33.4 | % | 89.29 | 72.38 | 23.4 | % | ||||||||||||||||
| WestTX |
100.42 | 72.85 | 37.8 | % | 96.66 | 73.54 | 31.4 | % | ||||||||||||||||
| Weighted Average |
98.23 | 72.80 | 34.9 | % | 93.79 | 73.82 | 27.1 | % | ||||||||||||||||
| Volumes: |
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| Velma system: |
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| Gathered gas volume (MCFD) |
102,159 | 79,007 | 29.3 | % | 96,418 | 76,396 | 26.2 | % | ||||||||||||||||
| Processed gas volume (MCFD) |
96,625 | 72,629 | 33.0 | % | 90,923 | 71,096 | 27.9 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
78,381 | 60,043 | 30.5 | % | 74,072 | 57,923 | 27.9 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
11,367 | 8,230 | 38.1 | % | 10,722 | 7,996 | 34.1 | % | ||||||||||||||||
| Condensate volume (BPD) |
442 | 386 | 14.5 | % | 486 | 431 | 12.8 | % | ||||||||||||||||
| WestOK system: |
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| Gathered gas volume (MCFD) |
260,250 | 223,098 | 16.7 | % | 252,257 | 222,554 | 13.3 | % | ||||||||||||||||
| Processed gas volume (MCFD) |
247,868 | 173,096 | 43.2 | % | 238,925 | 189,910 | 25.8 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
230,605 | 156,057 | 47.8 | % | 214,711 | 172,120 | 24.7 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
13,204 | 9,505 | 38.9 | % | 13,397 | 11,022 | 21.5 | % | ||||||||||||||||
| Condensate volume (BPD) |
884 | 625 | 41.4 | % | 871 | 691 | 26.0 | % | ||||||||||||||||
| WestTX system(2): |
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| Gathered gas volume (MCFD) |
204,515 | 180,960 | 13.0 | % | 195,268 | 169,391 | 15.3 | % | ||||||||||||||||
| Processed gas volume (MCFD) |
193,714 | 164,111 | 18.0 | % | 183,323 | 156,639 | 17.0 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
133,012 | 105,315 | 26.3 | % | 124,512 | 102,493 | 21.5 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
29,147 | 26,609 | 9.5 | % | 28,316 | 25,504 | 11.0 | % | ||||||||||||||||
| Condensate volume (BPD) |
1,827 | 1,490 | 22.6 | % | 1,428 | 1,092 | 30.8 | % | ||||||||||||||||
| West Texas LPG Partnership(3) |
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| Average NGL volumes (BPD) |
230,913 | 234,585 | (1.6 | )% | 227,087 | 220,368 | 3.0 | % | ||||||||||||||||
| Consolidated Volumes: |
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| Gathered gas volume (MCFD) |
574,599 | 491,611 | 16.9 | % | 551,819 | 476,918 | 15.7 | % | ||||||||||||||||
| Processed gas volume (MCFD) |
538,207 | 409,836 | 31.3 | % | 513,171 | 417,645 | 22.9 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
441,998 | 321,415 | 37.5 | % | 413,295 | 332,536 | 24.3 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
53,718 | 44,344 | 21.1 | % | 52,435 | 44,522 | 17.8 | % | ||||||||||||||||
| Condensate volume (BPD) |
3,153 | 2,501 | 26.1 | % | 2,785 | 2,214 | 25.8 | % | ||||||||||||||||
| (1) | “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. |
| (2) | Operating data for the WestTX system represents 100% of its operating activity. |
| (3) | Volume data for the West Texas LPG Partnership represents 100% of its operating activity for the calendar year. |
8
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of July 29, 2011)
Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2013. APL’s price risk management position in its entirety will be disclosed in the Partnership’s Form 10-Q.
SWAP CONTRACTS
NATURAL GAS HEDGES
| Production Period |
Purchased /Sold | Commodity | MMBTU | Avg. Fixed Price | ||||||||
| 3Q 2011 |
Sold | Natural Gas | 1,200,000 | $ | 4.54 | |||||||
| 4Q 2011 |
Sold | Natural Gas | 1,200,000 | 4.91 | ||||||||
NATURAL GAS LIQUIDS HEDGES
| Production Period |
Purchased /Sold | Commodity | Gallons | Avg. Fixed Price | ||||||||
| 3Q 2011 |
Sold | Ethane | 1,428,000 | $ | 0.78 | |||||||
| 3Q 2011 |
Sold | Propane | 4,284,000 | 1.16 | ||||||||
| 3Q 2011 |
Sold | Isobutane | 504,000 | 1.61 | ||||||||
| 3Q 2011 |
Sold | Normal Butane | 1,386,000 | 1.57 | ||||||||
| 3Q 2011 |
Sold | Natural Gasoline | 3,276,000 | 2.04 | ||||||||
| 4Q 2011 |
Sold | Ethane | 2,142,000 | 0.78 | ||||||||
| 4Q 2011 |
Sold | Propane | 4,284,000 | 1.19 | ||||||||
| 4Q 2011 |
Sold | Isobutane | 504,000 | 1.63 | ||||||||
| 4Q 2011 |
Sold | Normal Butane | 1,386,000 | 1.59 | ||||||||
| 4Q 2011 |
Sold | Natural Gasoline | 3,276,000 | 2.04 | ||||||||
| 1Q 2012 |
Sold | Propane | 4,410,000 | 1.37 | ||||||||
| 1Q 2012 |
Sold | Normal Butane | 1,386,000 | 1.93 | ||||||||
| 1Q 2012 |
Sold | Natural Gasoline | 1,008,000 | 2.42 | ||||||||
| 2Q 2012 |
Sold | Propane | 4,788,000 | 1.24 | ||||||||
| 2Q 2012 |
Sold | Normal Butane | 630,000 | 1.88 | ||||||||
| 2Q 2012 |
Sold | Natural Gasoline | 1,008,000 | 2.40 | ||||||||
| 3Q 2012 |
Sold | Propane | 5,040,000 | 1.25 | ||||||||
| 3Q 2012 |
Sold | Normal Butane | 630,000 | 1.88 | ||||||||
| 3Q 2012 |
Sold | Natural Gasoline | 1,008,000 | 2.39 | ||||||||
| 4Q 2012 |
Sold | Propane | 5,040,000 | 1.35 | ||||||||
| 4Q 2012 |
Sold | Normal Butane | 630,000 | 1.89 | ||||||||
| 4Q 2012 |
Sold | Natural Gasoline | 1,134,000 | 2.39 | ||||||||
CONDENSATE HEDGES
| Production Period |
Purchased /Sold | Commodity | Barrels | Avg. Fixed Price | ||||||||
| 3Q 2011 |
Sold | Crude | 30,000 | $ | 90.60 | |||||||
| 4Q 2011 |
Sold | Crude | 30,000 | 90.75 | ||||||||
| 1Q 2012 |
Sold | Crude | 45,000 | 104.56 | ||||||||
| 2Q 2012 |
Sold | Crude | 45,000 | 104.05 | ||||||||
| 3Q 2012 |
Sold | Crude | 45,000 | 103.45 | ||||||||
| 4Q 2012 |
Sold | Crude | 45,000 | 103.02 | ||||||||
9
Unaudited Current Commodity Risk Management Positions through December 31, 2013
(as of July 29, 2011)
OPTION CONTRACTS
NATURAL GAS LIQUIDS AND CONDENSATE HEDGES
Option Contracts – NGLs
| Production Period |
Purchased/Sold | Type | Commodity | Gallons | Avg. Strike Price | |||||||||
| 3Q 2011 |
Purchased | Put | Ethane | 1,428,000 | $ | 0.78 | ||||||||
| 3Q 2011 |
Purchased | Put | Propane | 5,166,000 | 1.24 | |||||||||
| 4Q 2011 |
Purchased | Put | Ethane | 2,142,000 | 0.74 | |||||||||
| 4Q 2011 |
Purchased | Put | Propane | 5,040,000 | 1.38 | |||||||||
| 1Q 2012 |
Purchased | Put | Propane | 6,300,000 | 1.47 | |||||||||
| 2Q 2012 |
Purchased | Put | Propane | 6,426,000 | 1.36 | |||||||||
| 3Q 2012 |
Purchased | Put | Propane | 7,560,000 | 1.36 | |||||||||
| 4Q 2012 |
Purchased | Put | Propane | 8,190,000 | 1.36 | |||||||||
Option Contracts – Crude
| Production Period |
Purchased/Sold | Type | Commodity | Barrels | Avg. Strike Price | |||||||||
| 3Q 2011 |
Purchased | Put | Crude Oil | 99,000 | $ | 96.87 | ||||||||
| 3Q 2011 |
Sold | Call | Crude Oil | 169,500 | 93.35 | |||||||||
| 3Q 2011 |
Purchased | Call | Crude Oil | 63,000 | 125.20 | |||||||||
| 4Q 2011 |
Purchased | Put | Crude Oil | 93,000 | 99.45 | |||||||||
| 4Q 2011 |
Sold | Call | Crude Oil | 169,500 | 93.35 | |||||||||
| 4Q 2011 |
Purchased | Call | Crude Oil | 63,000 | 125.20 | |||||||||
| 1Q 2012 |
Purchased | Put | Crude Oil | 63,000 | 106.00 | |||||||||
| 1Q 2012 |
Sold | Call | Crude Oil | 124,500 | 94.69 | |||||||||
| 1Q 2012 |
Purchased | Call | Crude Oil | 45,000 | 125.20 | |||||||||
| 2Q 2012 |
Purchased | Put | Crude Oil | 39,000 | 107.58 | |||||||||
| 2Q 2012 |
Sold | Call | Crude Oil | 124,500 | 94.69 | |||||||||
| 2Q 2012 |
Purchased | Call | Crude Oil | 45,000 | 125.20 | |||||||||
| 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 | |||||||||
10