Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Targa Pipeline Partners LP | d767416d8k.htm |
Exhibit 99.1
Contact: Matthew Skelly
VP – Investor Relations
1845 Walnut Street
Philadelphia, PA 19103
(877) 280-2857
(215) 561-5692 (facsimile)
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 2014 RESULTS
| • | Previously announced growth of quarterly distribution to $0.63 per common limited partner unit, at approximately 1.1x coverage |
| • | APL reports processed gas volumes of approximately 1.5 billion cubic feet per day (BCFD) in second quarter 2014 – an all-time Partnership record |
| • | Partnership expands company-wide processing capacity by 21% over past three months with addition of Stonewall and Silver Oak II plants to serve increasing producer activities |
| • | Adjusted EBITDA for second quarter 2014 was $92.9 million, an 8% increase year-over-year |
| • | Distributable Cash Flow for second quarter 2014 was $62.8 million, an 8% increase year-over-year |
| • | Completed the sale of subsidiaries holding a 20% interest in West Texas LPG Pipeline Limited Partnership for net proceeds of $132.7 million |
Philadelphia, PA, August 4, 2014 – 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 $92.9 million for the second quarter of 2014. Processed natural gas volumes averaged 1,503 million cubic feet per day (“MMCFD”), a 20% increase over the second quarter of 2013. Distributable Cash Flow was $62.8 million for the second quarter of 2014, or $0.78 per average common limited partner unit, compared to $58.0 million for the prior year’s second quarter. The Partnership recognized net income of $60.5 million for the second quarter of 2014, compared to net income of $10.1 million for the prior year’s second quarter. Net income was higher for second quarter 2014 compared to the prior year’s second quarter, mainly due to a $48.5 million gain recognized on the sale of the Partnership’s subsidiaries that held a 20% interest in West Texas LPG Pipeline Limited Partnership.
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, 2014, the Partnership declared a cash distribution for the second quarter of 2014 of $0.63 per common limited partner unit to holders of record on August 7, 2014, which will be paid on August 14, 2014. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.1x for the second quarter of 2014.
Eugene Dubay, Chief Executive Officer of the Partnership, commented, “The quarter came in as expected and we were pleased to be able to raise the distribution. The Partnership has progressed on executing its plans for bringing online the expansion projects that we have invested in over the past year, adding additional capacity in Southern
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Oklahoma and South Texas. We expect to complete an additional processing expansion in West Texas this fall and expect to see more organic capital projects and opportunities as we move forward. We look forward to continuing to provide best in class service to our customers and increasing value to all of our stakeholders.”
Capitalization and Liquidity
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $500.9 million as of June 30, 2014. Total debt outstanding was $1,654.3 million at June 30, 2014, compared to $1,706.8 million at December 31, 2013, a decrease of $52.5 million. Based upon total debt outstanding at June 30, 2014, total leverage was approximately 4.7x for purposes of calculations under our revolving credit facility, and debt to total capital was 41%.
Risk Management
The Partnership continues to add further protection to its risk management portfolio for forecasted production in 2014 through 2017. As of August 1, 2014, the Partnership had natural gas, natural gas liquids and condensate protection in place for 2014, 2015 and 2016 for approximately 70%, 50%, and 13%, respectively, of associated margin value (exclusive of ethane). Counterparties to the Partnership’s risk management activities consist of investment grade commercial banks that are lenders under the Partnership’s credit facility, or affiliates of those banks. A table summarizing the Partnership’s risk management portfolio as of August 1, 2014 is included in this release.
Operating Results
Gathered volumes for the three months ended June 30, 2014 were approximately 1.6 BCFD and processed volumes were approximately 1.5 BCFD, an increase of over 12% and 20%, respectively, compared to the Partnership’s second quarter 2013 reported results. Growth capital spending, including contributions to joint ventures, was $146.4 million during the second quarter of 2014, as organic expansion projects continue across all gathering and processing systems, including the processing plant expansions in SouthOK (120 MMCFD Stonewall plant), SouthTX (200 MMCFD Silver Oak II plant), and WestTX (200 MMCFD Edward plant in the southern portion and 200 MMCFD Buffalo plant in the northern portion of the Permian Basin). In addition, construction continues on multiple gathering pipeline projects, including the pipeline connecting the Velma and Arkoma portions of the SouthOK system.
Gross margin from operations was $136.8 million for the second quarter 2014, compared to $108.7 million for the prior year period, a result of increasing producer activity in APL’s areas of operations and the start-up of the Stonewall plant in May 2014. 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 SouthOK, WestOK and WestTX systems. The gross margin for the quarter does not include approximately $6.6 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $2.8 million realized derivative settlement gains excluded from gross margin in the second quarter of 2013.
WestTX System
The WestTX system’s average natural gas processed volume was 439.4 MMCFD for the second quarter of 2014, compared to 313.5 MMCFD for the second quarter of 2013, an increase of 40% over the past year. Increased processed volumes are primarily due to continued significant drilling activity in the Permian Basin. The completion of the Driver Plant in April 2013 increased processing capacity on the WestTX system to 455 MMCFD, supporting the increased gathered volumes. Average natural gas liquids (NGL) production was 56,165 barrels per day (“BPD”) for the second quarter of 2014, a 41% increase over the second quarter of 2013 with the entire system utilizing 97% of its available processing capacity for the quarter. This system continues to operate in partial ethane rejection due to the value of ethane compared to the value of residue natural gas.
Pioneer Natural Resources, Inc. (“Pioneer”), a 27.2% partner in the WestTX system, continues to be the largest producer on this system and the contract between APL and Pioneer was recently extended 10 additional years through 2032 and includes additional acreage dedicated from Pioneer. The Partnership expects processed volumes on this system to continue to increase through 2014 and beyond as Pioneer, and the Partnership’s many other producer customers, continue to pursue their drilling plans over the coming years in the Permian Basin. The previously announced 200 MMCFD Edward plant is expected to be complete in September of 2014 and the previously announced new Buffalo plant, an incremental 200 MMCFD cryogenic processing plant to be located in the northern part of the system, is expected to be complete in the second half of 2015. These two plants will serve the increasing activity in the Permian Basin and will be fully integrated with APL’s WestTX gathering and processing system,
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increasing the processing capacity in the Permian Basin to 855 MMCFD in 2015. Management currently expects to install a new 200 MMCFD cryogenic processing facility in each of the next five years, along with all necessary infrastructure, in support of the current production plans of the Partnership’s producer customers in this area.
WestOK System
The WestOK system had average natural gas processed volume of 530.5 MMCFD for the second quarter of 2014, a 10% increase from the second quarter of 2013. Average NGL production was 23,678 BPD for the second quarter of 2014, a 7% increase from the second quarter of 2013, due to the continued increased production on the gathering system.
Activity continues to be strong by APL’s producer customers, with Atlas Pipeline continuing to connect over a well per day in the Mississippi Lime over the past quarter. During the second quarter, a contract change was implemented with APL’s largest customer at WestOK, SandRidge Energy, Inc. (“SandRidge”). The contract transfers all existing volumes that were under SandRidge’s previous Keep-Whole contract to the current Percent-of-Proceeds (“POP”) contract. As a result, APL’s exposure to Keep-Whole contracts has been reduced to an insignificant portion of its overall contract mix. Included in the contract change was an additional acreage dedication, and, today APL has dedication of a significant portion of the 1.9 million acres SandRidge has in the core of the Mississippi Lime under this long-term POP contract. The Partnership continues to add capital projects to this area to accommodate growing development from SandRidge and others, including (i) adding compression, (ii) looping gathering lines, and (iii) adding off-load capabilities to third party processors. The Partnership continues to evaluate the need for further processing capacity in this area.
SouthOK System
The SouthOK system’s average natural gas processed volume was 408.6 MMCFD for the second quarter 2014, a 22% increase from second quarter 2013. The increase in processed volumes is primarily due to the start-up of the previously announced Stonewall plant, which increased processing capacity by 120 MMCFD. Average NGL production was 29,344 BPD for the second quarter 2014, a decrease of approximately 30% compared to the second quarter 2013. The Partnership has made operational improvements in 2014 that have increased the overall margin received per thousand cubic feet (MCF) of rich gas that is gathered and processed on this system. These improvements result in additional ethane rejection, which reduces the amount of barrels of NGLs produced, however enhances profit.
The Stonewall plant, a new cryogenic processing facility, was brought into operation on May 1, 2014 and is now fully operational. This plant was constructed under the Centrahoma joint venture, which is a joint venture with MarkWest Energy Partners of which APL owns 60%. The Partnership plans to accelerate the timeframe of the scheduled 80 MMCFD expansion at this plant, due to the increased activity in Southern Oklahoma, including production from the Woodford Shale, SCOOP, Arkoma and Ardmore Basins. This expansion will allow the facility to operate at its name-plate 200 MMCFD capacity and bring total gross processing capacity on the SouthOK system to 580 MMCFD by the end of 2014. Additionally, construction is continuing on the project to connect the Velma and Arkoma portions of the SouthOK system, which is expected be complete in September 2014.
SouthTX System
The SouthTX system recognized revenues on average natural gas processed volumes of 124.5 MMCFD for the second quarter 2014, including volumes processed under midstream sharing agreements. Under certain existing contractual agreements, APL receives a share of the economic interest from certain volumes currently processed by a third party midstream provider, as well as shares certain economic interests on volumes processed internally with a third party midstream provider. The volumes reported do not include any deficiencies under minimum volume commitments with producers during the period.
APL continues to make commercial progress in the SouthTX area and has connected newly acquired gas from two prominent operators in the Eagle Ford during the second quarter as previously expected. The first connection was in mid-May and the second connection was completed at the end of June. As a result, actual physical volumes processed by APL during the second quarter 2014 increased approximately 22% compared to first quarter 2014, and preliminary estimates for the month of July have indicated actual physical processed volume were approximately 143.5 MMCFD, which is a 25% increase over second quarter average physical processed volume. The new, 200 MMCFD processing facility, Silver Oak II, recently came on-line and is expected to provide incremental processing capacity for the remainder of 2014 and beyond.
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Corporate and Other
General and administrative costs, excluding non-cash compensation, for the second quarter of 2014 totaled $12.0 million, compared to $9.1 million in the same period in 2013. The increase in G&A is related to the continued expansion of the business, including in South Texas. Net of deferred financing costs, interest expense was $21.2 million for the second quarter of 2014, as compared to $20.8 million in the second quarter of 2013.
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s second quarter 2014 results on Tuesday, August 5, 2014 at 10:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 2:00 pm ET on Tuesday, August 5, 2014. To access the replay, dial 1-888-286-8010 and enter conference code 62895511.
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 16 gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. 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 28% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity prices and local or national economic conditions and other risks detailed from time to time in Atlas Pipeline’s reports filed with the SEC, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K.
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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, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Revenue: |
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| Natural gas and liquids sales |
$ | 667,549 | $ | 491,230 | $ | 1,330,679 | $ | 875,078 | ||||||||
| Transportation, processing and other fees(2) |
50,043 | 40,306 | 93,480 | 73,031 | ||||||||||||
| Derivative gain (loss), net |
(6,367 | ) | 27,107 | (15,038 | ) | 15,024 | ||||||||||
| Other income, net |
2,731 | 2,296 | 4,839 | 5,718 | ||||||||||||
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| Total revenues |
713,956 | 560,939 | 1,413,960 | 968,851 | ||||||||||||
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| Costs and expenses: |
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| Natural gas and liquids cost of sales |
580,885 | 424,216 | 1,156,353 | 749,756 | ||||||||||||
| Operating expenses |
26,983 | 24,770 | 52,111 | 46,629 | ||||||||||||
| General and administrative |
11,973 | 9,110 | 23,474 | 18,524 | ||||||||||||
| General and administrative – non-cash unit-based compensation(3) |
6,443 | 3,436 | 12,882 | 7,820 | ||||||||||||
| Other (revenues) costs |
(20 | ) | 18,370 | 17 | 18,900 | |||||||||||
| Depreciation and amortization |
49,220 | 46,383 | 98,459 | 76,841 | ||||||||||||
| Interest |
23,059 | 22,581 | 46,722 | 41,267 | ||||||||||||
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| Total costs and expenses |
698,543 | 548,866 | 1,390,018 | 959,737 | ||||||||||||
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| Equity income (loss) in joint ventures |
(3,875 | ) | (472 | ) | (5,753 | ) | 1,568 | |||||||||
| Loss on early extinguishment of debt |
— | (19 | ) | — | (26,601 | ) | ||||||||||
| Gain (loss) on asset dispositions |
48,465 | (1,519 | ) | 48,465 | (1,519 | ) | ||||||||||
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| Income (loss) before income taxes |
60,003 | 10,063 | 66,654 | (17,438 | ) | |||||||||||
| Income tax benefit |
(498 | ) | (28 | ) | (896 | ) | (37 | ) | ||||||||
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| Net income (loss) |
60,501 | 10,091 | 67,550 | (17,401 | ) | |||||||||||
| Income attributable to non-controlling interests |
(3,965 | ) | (1,810 | ) | (6,427 | ) | (3,179 | ) | ||||||||
| Preferred unit dividends |
(2,609 | ) | — | (3,015 | ) | — | ||||||||||
| Preferred unit imputed dividend effect |
(11,378 | ) | (6,729 | ) | (22,756 | ) | (6,729 | ) | ||||||||
| Preferred unit dividends in kind |
(10,406 | ) | (5,341 | ) | (20,125 | ) | (5,341 | ) | ||||||||
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| Net income (loss) attributable to common limited partners and the General Partner |
$ | 32,143 | $ | (3,789 | ) | $ | 15,227 | $ | (32,650 | ) | ||||||
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| Net income (loss) attributable to common limited partners per unit: |
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| Basic and diluted |
$ | 0.27 | $ | (0.11 | ) | $ | 0.04 | $ | (0.57 | ) | ||||||
| Weighted average common limited partner units (basic) |
80,979 | 74,340 | 80,788 | 69,520 | ||||||||||||
| Weighted average common limited partner units (diluted) |
96,890 | 74,340 | 96,498 | 69,520 | ||||||||||||
| (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. |
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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, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Summary Cash Flow Data: |
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| Cash provided by operating activities |
$ | 73,741 | $ | 30,465 | $ | 139,909 | $ | 71,721 | ||||||||
| Cash used in investing activities |
(19,728 | ) | (1,107,853 | ) | (150,412 | ) | (1,216,244 | ) | ||||||||
| Cash provided by (used in) financing activities |
(59,695 | ) | 1,090,208 | 9,663 | 1,162,206 | |||||||||||
| Capital Expenditure Data: |
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| Maintenance capital expenditures |
$ | 5,555 | $ | 3,848 | $ | 10,880 | $ | 7,703 | ||||||||
| Expansion capital expenditures |
146,693 | 103,345 | 269,699 | 208,006 | ||||||||||||
| Acquisitions |
— | 1,000,785 | — | 1,000,785 | ||||||||||||
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| Total |
$ | 152,248 | $ | 1,107,978 | $ | 280,579 | $ | 1,216,494 | ||||||||
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited; in thousands)
| June 30, 2014 |
December 31, 2013 |
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| ASSETS | ||||||||
| Current assets: |
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| Cash and cash equivalents |
$ | 4,074 | $ | 4,914 | ||||
| Other current assets |
281,502 | 236,864 | ||||||
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| Total current assets |
285,576 | 241,778 | ||||||
| Property, plant and equipment, net |
2,984,168 | 2,724,192 | ||||||
| Intangible assets, net |
999,849 | 1,064,843 | ||||||
| Equity method investment in joint ventures |
179,054 | 248,301 | ||||||
| Other assets, net |
44,382 | 48,731 | ||||||
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| $ | 4,493,029 | $ | 4,327,845 | |||||
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| LIABILITIES AND EQUITY | ||||||||
| Current liabilities |
$ | 399,549 | $ | 320,226 | ||||
| Long-term debt, less current portion |
1,654,319 | 1,706,786 | ||||||
| Deferred income taxes, net |
32,394 | 33,290 | ||||||
| Other long-term liabilities |
7,227 | 7,638 | ||||||
| Total partners’ capital |
2,327,760 | 2,200,645 | ||||||
| Non-controlling interest |
71,780 | 59,260 | ||||||
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| Total equity |
2,399,540 | 2,259,905 | ||||||
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| $ | 4,493,029 | $ | 4,327,845 | |||||
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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, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Gross margin calculations: |
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| Natural gas and liquids sales |
$ | 667,549 | $ | 491,230 | $ | 1,330,679 | $ | 875,078 | ||||||||
| Transportation, processing, and other fees |
50,043 | 40,306 | 93,480 | 73,031 | ||||||||||||
| Less: non-cash linefill gain (loss) |
(49 | ) | (1,339 | ) | 94 | (1,371 | ) | |||||||||
| Less: natural gas and liquids cost of sales |
580,885 | 424,216 | 1,156,353 | 749,756 | ||||||||||||
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| Gross margin |
$ | 136,756 | $ | 108,659 | $ | 267,712 | $ | 199,724 | ||||||||
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| Reconciliation of net income (loss) to other non-GAAP measures(1): |
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| Net income (loss) |
$ | 60,501 | $ | 10,091 | $ | 67,550 | $ | (17,401 | ) | |||||||
| Depreciation and amortization |
49,220 | 46,383 | 98,459 | 76,841 | ||||||||||||
| Income tax benefit |
(498 | ) | (28 | ) | (896 | ) | (37 | ) | ||||||||
| Interest expense |
23,059 | 22,581 | 46,722 | 41,267 | ||||||||||||
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| EBITDA |
132,282 | 79,027 | 211,835 | 100,670 | ||||||||||||
| Income attributable to non-controlling interests(2) |
(3,965 | ) | (1,810 | ) | (6,427 | ) | (3,179 | ) | ||||||||
| Non-controlling interest depreciation, amortization and interest(3) |
(906 | ) | (1,121 | ) | (1,612 | ) | (1,971 | ) | ||||||||
| Adjustment for cash flow from investment in joint ventures |
6,075 | 2,272 | 9,953 | 2,032 | ||||||||||||
| (Gain) loss on asset disposition |
(48,465 | ) | 1,519 | (48,465 | ) | 1,519 | ||||||||||
| Non-cash gain on derivatives |
(252 | ) | (24,263 | ) | (1,416 | ) | (10,544 | ) | ||||||||
| Other (revenues) costs |
(20 | ) | 18,370 | 17 | 18,900 | |||||||||||
| Premium expense on derivative instruments |
892 | 3,745 | 3,515 | 7,020 | ||||||||||||
| Unrecognized economic impact of acquisitions |
— | 1,126 | — | 1,126 | ||||||||||||
| Loss on early termination of debt |
— | 19 | — | 26,601 | ||||||||||||
| Other non-cash losses(4) |
7,246 | 7,428 | 16,291 | 11,844 | ||||||||||||
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| Adjusted EBITDA |
92,887 | 86,312 | 183,691 | 154,018 | ||||||||||||
| Interest expense |
(23,059 | ) | (22,581 | ) | (46,722 | ) | (41,267 | ) | ||||||||
| Amortization of deferred finance costs |
1,874 | 1,739 | 3,730 | 3,283 | ||||||||||||
| Preferred dividend obligation |
(2,609 | ) | — | (3,015 | ) | — | ||||||||||
| Premium expense on derivative instruments |
(892 | ) | (3,745 | ) | (3,515 | ) | (7,020 | ) | ||||||||
| Maintenance capital expenditures(5) |
(5,405 | ) | (3,713 | ) | (10,538 | ) | (7,527 | ) | ||||||||
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| Distributable Cash Flow |
$ | 62,796 | $ | 58,012 | $ | 123,631 | $ | 101,487 | ||||||||
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| (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 some 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 $150 thousand and $135 thousand for the three months ended June 30, 2014 and 2013, respectively, and $342 thousand and $176 thousand for the six months ended June 30, 2014 and 2013, respectively. |
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2014 | 2013 | Percent Change |
2014 | 2013 | Percent Change |
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| Pricing (unhedged): |
||||||||||||||||||||||||
| Weighted average market prices: |
||||||||||||||||||||||||
| NGL price per gallon – Conway hub |
$ | 0.87 | $ | 0.75 | 16.0 | % | $ | 0.94 | $ | 0.79 | 19.0 | % | ||||||||||||
| NGL price per gallon – Mt. Belvieu hub |
0.87 | 0.80 | 8.7 | % | 0.92 | 0.83 | 10.8 | % | ||||||||||||||||
| Natural gas sales ($/MCF): |
||||||||||||||||||||||||
| SouthOK |
4.29 | 3.88 | 10.6 | % | 4.52 | 3.53 | 28.0 | % | ||||||||||||||||
| WestOK |
4.16 | 3.84 | 8.3 | % | 4.44 | 3.54 | 25.4 | % | ||||||||||||||||
| WestTX |
4.23 | 3.74 | 13.1 | % | 4.46 | 3.45 | 29.3 | % | ||||||||||||||||
| Weighted average |
4.19 | 3.82 | 9.7 | % | 4.45 | 3.59 | 24.0 | % | ||||||||||||||||
| NGL sales ($/gallon): |
||||||||||||||||||||||||
| SouthOK |
1.00 | 0.71 | 40.8 | % | 1.03 | 0.69 | 49.3 | % | ||||||||||||||||
| SouthTX |
0.76 | 0.75 | 1.3 | % | 0.93 | 0.75 | 24.0 | % | ||||||||||||||||
| WestOK |
1.11 | 0.96 | 15.6 | % | 1.15 | 0.97 | 18.6 | % | ||||||||||||||||
| WestTX |
0.93 | 0.86 | 8.1 | % | 0.96 | 0.89 | 7.9 | % | ||||||||||||||||
| Weighted average |
0.98 | 0.84 | 16.7 | % | 1.02 | 0.84 | 21.4 | % | ||||||||||||||||
| Condensate sales ($/barrel): |
||||||||||||||||||||||||
| SouthOK |
96.45 | 91.76 | 5.1 | % | 92.96 | 90.89 | 2.3 | % | ||||||||||||||||
| SouthTX |
87.14 | 92.78 | (6.1 | )% | 86.57 | 92.78 | (6.7 | )% | ||||||||||||||||
| WestOK |
96.71 | 84.53 | 14.4 | % | 91.36 | 84.10 | 8.6 | % | ||||||||||||||||
| WestTX |
95.02 | 93.96 | 1.1 | % | 96.25 | 91.97 | 4.7 | % | ||||||||||||||||
| Weighted average |
95.78 | 89.15 | 7.4 | % | 92.74 | 88.09 | 5.3 | % | ||||||||||||||||
8
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2014 | 2013 | Percent Change |
2014 | 2013 | Percent Change |
|||||||||||||||||||
| Volumes: |
||||||||||||||||||||||||
| SouthOK system(2): |
||||||||||||||||||||||||
| Gathered gas volume (MCFD) |
433,294 | 422,974 | 2.4 | % | 416,590 | 407,323 | 2.3 | % | ||||||||||||||||
| Processed gas volume(3) (MCFD) |
408,615 | 334,812 | 22.0 | % | 390,733 | 330,767 | 18.1 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
378,325 | 319,650 | 18.4 | % | 356,980 | 314,892 | 13.4 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
29,344 | 41,791 | (29.8 | )% | 28,810 | 37,841 | (23.9 | )% | ||||||||||||||||
| Condensate volume (BPD) |
585 | 536 | 9.1 | % | 693 | 550 | 26.0 | % | ||||||||||||||||
| WestOK system: |
||||||||||||||||||||||||
| Gathered gas volume (MCFD) |
554,233 | 506,487 | 9.4 | % | 543,003 | 479,577 | 13.2 | % | ||||||||||||||||
| Processed gas volume(3) (MCFD) |
530,455 | 483,504 | 9.7 | % | 520,364 | 454,628 | 14.5 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
488,224 | 444,670 | 9.8 | % | 477,805 | 420,815 | 13.5 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
23,678 | 22,233 | 6.5 | % | 23,346 | 19,258 | 21.2 | % | ||||||||||||||||
| Condensate volume (BPD) |
2,420 | 1,949 | 24.2 | % | 2,292 | 1,959 | 17.0 | % | ||||||||||||||||
| SouthTX system(4): |
||||||||||||||||||||||||
| Gathered gas volume (MCFD) |
127,979 | 122,245 | 4.7 | % | 122,925 | 122,245 | 0.6 | % | ||||||||||||||||
| Processed gas volume(3) (MCFD) |
124,468 | 121,338 | 2.6 | % | 119,880 | 121,338 | (1.2 | )% | ||||||||||||||||
| Residue gas volume (MCFD) |
94,537 | 96,606 | (2.1 | )% | 85,317 | 96,606 | (11.7 | )% | ||||||||||||||||
| Processed NGL volume (BPD) |
13,805 | 15,041 | (8.2 | )% | 12,843 | 15,041 | (14.6 | )% | ||||||||||||||||
| Condensate volume (BPD) |
171 | 65 | 163.1 | % | 159 | 65 | 144.6 | % | ||||||||||||||||
| WestTX system(2): |
||||||||||||||||||||||||
| Gathered gas volume (MCFD) |
460,410 | 352,865 | 30.5 | % | 434,614 | 332,829 | 30.6 | % | ||||||||||||||||
| Processed gas volume(3) (MCFD) |
439,447 | 313,504 | 40.2 | % | 414,867 | 297,220 | 39.6 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
327,994 | 229,777 | 42.7 | % | 307,577 | 219,889 | 39.9 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
56,165 | 39,901 | 40.8 | % | 53,231 | 36,591 | 45.5 | % | ||||||||||||||||
| Condensate volume (BPD) |
2,219 | 1,993 | 11.3 | % | 1,708 | 1,516 | 12.7 | % | ||||||||||||||||
| Other systems: |
||||||||||||||||||||||||
| Gathered gas volumes (MCFD) |
28,435 | 28,247 | 0.7 | % | 28,637 | 29,563 | (3.1 | )% | ||||||||||||||||
| Consolidated Volumes: |
||||||||||||||||||||||||
| Gathered gas volume (MCFD) |
1,604,351 | 1,432,818 | 12.0 | % | 1,545,769 | 1,371,537 | 12.7 | % | ||||||||||||||||
| Processed gas volume (MCFD) |
1,502,985 | 1,253,158 | 19.9 | % | 1,445,844 | 1,203,953 | 20.1 | % | ||||||||||||||||
| Residue gas volume (MCFD) |
1,289,080 | 1,090,703 | 18.2 | % | 1,227,679 | 1,052,202 | 16.7 | % | ||||||||||||||||
| Processed NGL volume (BPD) |
122,992 | 118,966 | 3.4 | % | 118,230 | 108,731 | 8.7 | % | ||||||||||||||||
| Condensate volume (BPD) |
5,395 | 4,543 | 18.8 | % | 4,852 | 4,090 | 18.6 | % | ||||||||||||||||
| (1) | “MCF” represents thousand cubic feet; “MCFD” represents thousand cubic feet per day; “BPD” represents barrels per day. |
| (2) | Operating data for the SouthOK and WestTX systems 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. |
| (4) | Gathered and processed gas volumes on the SouthTX system include volumes processed by a third-party in which the Partnership receives the economic interest. Actual physical gathered and processed volumes totaled 118,133 MCFD and 114,623 MCFD, respectively, during the three months ended June 30, 2014, and 107,293 MCFD and 104,249 MCFD, respectively, during the six months ended June 30, 2014. |
9
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)
Note: 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 | ||||||||
| 3Q14 | Sold | Propane | 12,474,000 | $ | 0.99 | |||||||
| 3Q14 | Sold | Iso Butane | 1,260,000 | 1.26 | ||||||||
| 3Q14 | Sold | Normal Butane | 1,260,000 | 1.50 | ||||||||
| 3Q14 | Sold | Natural Gasoline | 3,780,000 | 1.97 | ||||||||
| 4Q14 | Sold | Propane | 12,852,000 | 1.00 | ||||||||
| 4Q14 | Sold | Iso Butane | 1,260,000 | 1.26 | ||||||||
| 4Q14 | Sold | Normal Butane | 1,260,000 | 1.53 | ||||||||
| 4Q14 | Sold | Natural Gasoline | 3,906,000 | 1.98 | ||||||||
| 1Q15 | Sold | Propane | 13,734,000 | 0.99 | ||||||||
| 1Q15 | Sold | Natural Gasoline | 4,662,000 | 1.97 | ||||||||
| 2Q15 | Sold | Propane | 15,624,000 | 0.99 | ||||||||
| 2Q15 | Sold | Natural Gasoline | 4,914,000 | 2.02 | ||||||||
| 3Q15 | Sold | Propane | 14,238,000 | 1.05 | ||||||||
| 3Q15 | Sold | Natural Gasoline | 3,780,000 | 2.00 | ||||||||
| 4Q15 | Sold | Propane | 11,088,000 | 1.02 | ||||||||
| 4Q15 | Sold | Natural Gasoline | 1,260,000 | 2.00 | ||||||||
| 1Q16 | Sold | Propane | 6,930,000 | 1.03 | ||||||||
| 2Q16 | Sold | Propane | 5,040,000 | 1.03 | ||||||||
| 3Q16 | Sold | Propane | 6,300,000 | 1.04 | ||||||||
| 4Q16 | Sold | Propane | 3,780,000 | 1.04 | ||||||||
| 1Q17 | Sold | Propane | 2,520,000 | 1.04 | ||||||||
| 2Q17 | Sold | Propane | 2,520,000 | 1.04 | ||||||||
| 3Q17 | Sold | Propane | 2,520,000 | 1.04 | ||||||||
| 4Q17 | Sold | Propane | 2,520,000 | 1.04 | ||||||||
10
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)
SWAP CONTRACTS
CONDENSATE HEDGES
| Production Period |
Purchased /Sold | Commodity | Barrels | Avg. Fixed Price | ||||||||
| 3Q14 | Sold | Crude Oil | 90,000 | 92.39 | ||||||||
| 4Q14 | Sold | Crude Oil | 69,000 | 91.71 | ||||||||
| 1Q15 | Sold | Crude Oil | 75,000 | 92.11 | ||||||||
| 2Q15 | Sold | Crude Oil | 75,000 | 90.45 | ||||||||
| 3Q15 | Sold | Crude Oil | 45,000 | 88.58 | ||||||||
| 4Q15 | Sold | Crude Oil | 15,000 | 85.13 | ||||||||
| 1Q16 | Sold | Crude Oil | 15,000 | 90.00 | ||||||||
| 2Q16 | Sold | Crude Oil | 15,000 | 90.00 | ||||||||
NATURAL GAS HEDGES
| Production Period |
Purchased /Sold | Commodity | MMBTUs | Avg. Fixed Price | ||||||||
| 3Q14 | Sold | Natural Gas | 5,050,000 | 4.06 | ||||||||
| 4Q14 | Sold | Natural Gas | 5,350,000 | 4.15 | ||||||||
| 1Q15 | Sold | Natural Gas | 5,965,000 | 4.41 | ||||||||
| 2Q15 | Sold | Natural Gas | 4,615,000 | 4.18 | ||||||||
| 3Q15 | Sold | Natural Gas | 4,615,000 | 4.18 | ||||||||
| 4Q15 | Sold | Natural Gas | 4,315,000 | 4.26 | ||||||||
| 1Q16 | Sold | Natural Gas | 3,150,000 | 4.34 | ||||||||
| 2Q16 | Sold | Natural Gas | 1,650,000 | 4.24 | ||||||||
| 3Q16 | Sold | Natural Gas | 1,650,000 | 4.24 | ||||||||
| 4Q16 | Sold | Natural Gas | 1,650,000 | 4.24 | ||||||||
| 1Q17 | Sold | Natural Gas | 1,200,000 | 4.47 | ||||||||
11
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of August 1, 2014)
OPTION CONTRACTS
NGL OPTIONS
| Production Period |
Purchased/Sold | Type | Commodity | Gallons | Avg. Strike Price | |||||||||
| 3Q14 | Purchased | Put | Propane | 2,520,000 | 0.95 | |||||||||
| 3Q14 | Sold | Call | Propane | 1,260,000 | 1.31 | |||||||||
| 4Q14 | Purchased | Put | Propane | 2,520,000 | 0.96 | |||||||||
| 4Q14 | Sold | Call | Propane | 1,260,000 | 1.34 | |||||||||
| 1Q15 | Purchased | Put | Propane | 1,890,000 | 0.98 | |||||||||
| 1Q15 | Sold | Call | Propane | 1,260,000 | 1.28 | |||||||||
| 3Q15 | Purchased | Put | Propane | 1,260,000 | 0.88 | |||||||||
CRUDE OPTIONS
| Production Period |
Purchased/Sold | Type | Commodity | Barrels | Avg. Strike Price | |||||||||
| 3Q14 | Purchased | Put | Crude Oil | 90,000 | 89.91 | |||||||||
| 4Q14 | Purchased | Put | Crude Oil | 117,000 | 91.57 | |||||||||
| 1Q15 | Purchased | Put | Crude Oil | 45,000 | 91.33 | |||||||||
| 2Q15 | Purchased | Put | Crude Oil | 75,000 | 89.49 | |||||||||
| 3Q15 | Purchased | Put | Crude Oil | 75,000 | 88.59 | |||||||||
| 4Q15 | Purchased | Put | Crude Oil | 75,000 | 88.15 | |||||||||
NATURAL GAS OPTIONS
| Production Period |
Purchased/Sold | Type | Commodity | MMBTUs | Avg. Strike Price | |||||||||
| 3Q 2014 | Purchased | Put | Natural Gas | 300,000 | 4.15 | |||||||||
12