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 FIRST QUARTER 2013 RESULTS
| | • | | Adjusted EBITDA for first quarter 2013 was $67.7 million, a 32% increase year-over-year |
| | • | | Average processed gas volumes exceeds 1 billion cubic feet per day (BCFD) in first quarter 2013 |
| | • | | Distributable Cash Flow for first quarter 2013 of $43.5 million, a 23% increase year-over-year |
| | • | | Previously announced distribution of $0.59 per common limited partner unit, a 5% increase year-over-year |
| | • | | Atlas Pipeline recently announces transformative $1 billion acquisition of TEAK to enter Eagle Ford Shale |
Philadelphia, PA, April 29, 2013 – 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 $67.7 million for the first quarter of 2013, driven primarily by a continued increase in volumes across the Partnership’s gathering and processing systems. Processed natural gas volumes averaged 1,033 million cubic feet per day (“MMCFD”), a 63% increase over the first quarter of 2012. Distributable Cash Flow was $43.5 million for the first quarter of 2013, or $0.67 per average common limited partner unit, compared to $35.2 million for the prior year’s first quarter. The Partnership recognized a net loss of $27.5 million for the first quarter of 2013, which included a $26.6 million loss on the early retirement of the Partnership’s 8.75% Senior Notes due 2018, compared with net income of $6.5 million for the prior year first quarter.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures in the tables included at the end of this news release. The Partnership believes these measures provide a more accurate comparison of the operating results for the periods presented.
On April 24, 2013, the Partnership declared a distribution for the first quarter of 2013 of $0.59 per common limited partner unit to holders of record on May 8, 2013, which will be paid on May 15, 2013. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.04x on a fully diluted basis for the first quarter of 2013, excluding the most recent common equity issuance that closed on April 23, 2013.
Eugene Dubay, Chief Executive Officer of the Partnership, commented, “The year has already provided for some very exciting announcements for Atlas Pipeline. It is with great pleasure that, since the end of the quarter, we have announced a major entry into the Eagle Ford with the $1 billion announced purchase of TEAK Midstream. This is a major win for the Partnership, adding tremendous expected future growth while reducing APL cash flow volatility through diversity and significant fixed fee business. Since the end of the quarter, we have also brought the Driver expansion online in West Texas and are receiving NGL takeaway capacity relief on our two largest systems, which will lead to more NGL’s being produced and more future cash flow to the Partnership. Our first quarter of 2013 came in line with expectations, aside from some weather disruptions, which can be a normal occurrence during winter months. More importantly, looking forward, our business and future opportunities have never looked better after all of the recent positive developments we have just announced. I would like to thank our investors who have supported us as we grow, and assure all of us our best days still lay ahead.”
Significant Developments after First Quarter of 2013
Since the end of the reporting period, the Partnership has publicly announced several developments that are expected to have a significant impact on the Distributable Cash Flow of APL for 2013-2014. On April 15, 2013, Atlas Pipeline announced that the 200 MMCFD Driver plant has come online at the WestTX facility, increasing capacity from 255 MMCFD to 455 MMCFD. In addition to the expansion at WestTX, APL also announced the addition of further NGL takeaway capacity to deliver incremental natural gas liquids from its WestOK and WestTX processing systems. These connections will eliminate the near-term constraints on our NGL production at these systems and better utilize the Waynoka II and Driver expansions that were brought in service in September 2012 and April 2013, respectively.
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Additionally, on April 16, 2013, the Partnership announced the acquisition of TEAK Midstream, L.L.C. (“TEAK”), a private midstream company in the prolific Eagle Ford shale. TEAK currently has 200 MMCFD in processing capacity with 200 MMCFD of additional capacity expected in 2014 and potentially an additional 200 MMCFD processing facility to be added in 2015. The cash flow of TEAK is approximately 80% fixed-fee, which will serve to greatly reduce the commodity sensitivity of the Partnership’s overall cash flows upon build-out and utilization of the system. Please refer to the Partnership’s press release from April 16, 2013 (“Atlas Pipeline Partners, L.P. To Acquire Eagle Ford Midstream Business For $1 Billion From TEAK Midstream”) for more information regarding the transaction.
* * *
Updated 2013-2014 Forecasted Guidance
Upon the announcement of the acquisition of TEAK, APL initiated guidance for 2014, including forecasted Adjusted EBITDA of between $450 to $500 million and anticipated distributions of between $2.75 and $2.85 per limited partner unit. The Partnership is now updating Adjusted EBITDA for 2013 to between $360 million and $400 million based on current commodity pricing curves for natural gas, natural gas liquids, and crude oil. The resulting forecasted Distributable Cash Flow for 2013 is expected to range from $230 million to $270 million based on the same assumptions. Based on the Partnership’s distribution coverage targets, the forecasted distributions for 2013 remain between $2.50 and $2.60 per limited partner unit for the calendar year. The Partnership expects growth capital expenditures for the year to total approximately $450 million, based on previously announced expansion projects, including the now completed Driver plant and anticipated phase one of the Stonewall plant, as well as new infrastructure and projected well connections to support further volume growth on our existing and systems, including TEAK. It is important to note that the range of guidance for 2013 is based on information that has been publicly announced to date. Management will address the future outlook of the Partnership on the earnings conference call tomorrow morning as well as discuss recent developments since the end of the first quarter.
These forecasted amounts are based on various assumptions, including, among others, the Partnership’s expected cost and timing for completion of its announced capital expenditure program, timing of incremental volumes on its gathering and processing systems, known contract structures, scheduled maintenance of facilities, including those of third-parties that impact the Partnership’s operations, estimated interest rates, and budgeted operating and general administrative costs. Management does not forecast certain items, including GAAP revenues, depreciation, amortization, and non-cash changes in derivatives, and therefore is unable to provide forecasted Net Income, a comparable GAAP measure, for the periods presented. The reconciling items between these non-GAAP measures and Net Income are expected to be similar to those for the current periods presented and are not expected to be significant to the Partnership’s cash flows.
Capitalization and Liquidity
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $453.7 million as of March 31, 2013. Total debt outstanding was $1,318.9 million at March 31, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $139.0 million. Based upon total debt outstanding at March 31, 2013, total leverage was approximately 4.6x for purposes of calculations under our revolving credit facility, and debt to total capital was 46%. The Partnership recently announced the closing of a follow-on common equity issuance totaling 11,845,000 common limited partner units, resulting in gross proceeds of $402.7 million which will be used to fund the acquisition of TEAK. The Partnership also expects to issue $400 million of mandatorily convertible Class D Preferred Units in connection with the closing of the TEAK acquisition.
* * *
Risk Management
The Partnership continued enhancement of its risk management portfolio, adding further protection for 2013 through 2016. As of April 29, 2013, the Partnership has natural gas, natural gas liquids and condensate protection in place for the full years of 2013, 2014, and 2015 for approximately 75%, 58%, and 33% respectively, of associated margin value (exclusive of ethane). The Partnership has also begun to add to protection in 2016. The percentages do not include the TEAK acquisition, which has not closed as of the date of this press release. Counterparties to the Partnership’s
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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 April 29, 2013 is included in this release.
* * *
Operating Results
The Partnership continues to report record volumes, and with the addition of the Arkoma assets, is now processing, on average, over 1.0 billion cubic feet per day of natural gas per day. Gross margin from operations was $91.1 million for the first quarter 2013, compared to $69.1 million for the prior year period, led by increasing producer activity in APL’s area of operations. Gross margin, a non-GAAP financial measure, includes natural gas and liquids sales and transportation, processing and other fees, less purchased product costs and non-cash gains (or losses) included in these items. The higher gross margin for the quarter was primarily due to the increased volumes and expansions that have been completed on the WestOK and Velma systems, as well as the newly acquired Arkoma system, and was partially offset by lower NGL prices. The gross margin for the quarter does not include approximately $1.6 million of realized derivative settlement gains, which are excluded in the calculation of gross margin, compared to $0.8 million realized derivative settlement losses excluded from gross margin in the first quarter of 2012.
WestTX System
The WestTX system’s average natural gas processed volume was 280.8 MMCFD for the first quarter 2013, compared to 230.5 MMCFD for first quarter of 2012. Increased volumes are primarily due to increased production in the Spraberry and Wolfberry formations of the Permian basin, including an increase in the number of horizontally drilled wells by our producer customers. Average NGL production volumes were 33,245 barrels per day (“BPD”) for the first quarter 2013, a 0.4% increase from first quarter 2012. The Partnership expects processed volumes on this system to continue to increase as residue gas and NGL take-away constraints have been removed and producers continue to pursue their drilling plans over the coming years. The construction of the previously announced Driver plant, which increases processing capacity by 200 MMCFD, was completed and placed into service on April 12, 2013 and will allow for more efficient processing and delivery of natural gas and NGLs going forward.
WestOK System
The WestOK system had average natural gas processed volume of 425.4 MMCFD for the first quarter, a 52.3% increase from first quarter 2012. Average NGL production was 16,251 BPD for the first quarter 2013, a 15.6% increase from first quarter 2012, due to increased production on the gathering systems and the start-up of the Waynoka II plant in September 2012. First quarter 2013 results were negatively impacted by certain weather events in western Oklahoma which caused the loss of power and the shut-in of significant volumes for approximately 10 days in late February and early March. The Partnership estimates that the financial impact for this period was between $2 to $3 million in Adjusted EBITDA. The Partnership recently announced that incremental NGL take-away from the Waynoka facilities became available on April 2, 2013 with the connection to DCP Midstream Partners, L.P.’s Southern Hills pipeline. This pipeline will allow the Partnership to process and deliver incremental NGL volumes from the WestOK system, including full production from the Waynoka I and Waynoka II facilities.
Velma System
The Velma system’s average natural gas processed volume was 125.4 MMCFD for the first quarter 2013, a 2.0% increase from first quarter 2012. The increase is primarily due to additional production gathered from continued producer activity in the liquids-rich portion of the Woodford Shale and Ardmore Basin. Average NGL production increased to 13,997 BPD for the first quarter 2013, up approximately 2.6% compared to first quarter 2012, 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 (the “V-60 plant”), which supports the additional volumes from XTO Energy, Inc (“XTO”). Volumes on the Velma system were greater than the fourth quarter of 2012 primarily due to XTO returning gas to V-60 during the period.
Arkoma System
The Partnership acquired the Arkoma system in December 2012 through the acquisition of Cardinal Midstream L.L.C. The assets acquired include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas, including a 60% interest in a joint venture with MarkWest Energy Partners, L.P., known as Centrahoma Processing, LLC (“Centrahoma”). The Arkoma gathering and processing system is located in the Arkoma Basin in southeastern Oklahoma and had average natural gas processed volumes of 201.3 MMCFD and produced 20,555 BPD
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of NGLs during the first quarter of 2013. The Arkoma system has total gross name-plate processing capacity of 220 MMCFD, including the 120 MMCFD Tupelo plant which the Partnership owns 100%. The remaining processing capacity is owned by Centrahoma.
* * *
Corporate and Other
Net of deferred financing costs, interest expense increased to $17.1 million for the first quarter of 2013, up 34.2% as compared with the first quarter of 2012. This increase was due to financing the Partnership’s capital expenditure program during 2012 and 2013, including the issuance of senior unsecured notes in September and December 2012, as well as the February 2013 issuance of new 5.875% senior unsecured notes due 2023. These new senior unsecured notes were issued in connection with the redemption of the Partnership’s 8.75% Senior Notes due 2018, which resulted in a loss on the early termination of debt totaling $26.6 million in the first quarter 2013.
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s first quarter 2013 results on Tuesday, April 30, 2013 at 10:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 12:00 pm ET on Tuesday, April 30, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 32722721.
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, northern and western Texas, and Tennessee, APL owns and operates 13 active gas processing plants, 18 gas treating facilities, as well as approximately 10,100 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 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 9% limited partner interest. Additionally, Atlas Energy owns all of the general partner Class A units and incentive distribution rights and an approximate 43% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. For more information, please visit the Partnership’s website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity process and local or national economic conditions and other risks detailed from time to time in Atlas Pipeline’s reports filed with the SEC, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K.
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary(1)
(unaudited; in thousands except per unit amounts)
| | | | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | | 2013 | | | 2012 | |
Revenue: | | | | | | | | |
Natural gas and liquids | | $ | 383,848 | | | $ | 289,225 | |
Transportation, processing and other fees(2) | | | 32,725 | | | | 12,681 | |
Derivative loss, net | | | (12,083 | ) | | | (12,035 | ) |
Other income, net | | | 3,422 | | | | 2,415 | |
| | | | | | | | |
| | |
Total revenue and other income, net | | | 407,912 | | | | 292,286 | |
| | | | | | | | |
| | |
Costs and expenses: | | | | | | | | |
Natural gas and liquids | | | 325,540 | | | | 233,105 | |
Plant operating | | | 21,271 | | | | 13,881 | |
Transportation and compression | | | 588 | | | | 264 | |
General and administrative(3) | | | 9,414 | | | | 8,967 | |
General and administrative – non-cash unit-based compensation(3) | | | 4,384 | | | | 978 | |
Other costs | | | 530 | | | | (34 | ) |
Depreciation and amortization | | | 30,458 | | | | 20,842 | |
Interest | | | 18,686 | | | | 8,708 | |
| | | | | | | | |
| | |
Total costs and expenses | | | 410,871 | | | | 286,711 | |
| | | | | | | | |
| | |
Equity income in joint venture | | | 2,040 | | | | 896 | |
Loss on early extermination of debt | | | (26,582 | ) | | | — | |
| | | | | | | | |
| | |
Income (loss) from continuing operations, before tax | | | (27,501 | ) | | | 6,471 | |
| | |
Income tax benefit | | | (9 | ) | | | — | |
| | |
Net income (loss) | | | (27,492 | ) | | | 6,471 | |
| | |
Income attributable to non-controlling interests | | | (1,369 | ) | | | (1,536 | ) |
| | | | | | | | |
Net income attributable to common limited partners and the general partner | | $ | (28,861 | ) | | $ | 4,935 | |
| | | | | | | | |
| | |
Net income (loss) attributable to common limited partners per unit: | | | | | | | | |
Basic and diluted: | | $ | (0.48 | ) | | $ | 0.06 | |
| | | | | | | | |
| | |
Weighted average common limited partner units (basic) | | | 64,646 | | | | 53,620 | |
| | | | | | | | |
| | |
Weighted average common limited partner units (diluted) | | | 64,646 | | | | 54,013 | |
| | | | | | | | |
| (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 | |
| | | March 31, | |
| | | 2013 | | | 2012 | |
| | |
Summary Cash Flow Data: | | | | | | | | |
Net cash provided by (used in): | | | | | | | | |
Operating activities | | $ | 34,856 | | | $ | 42,747 | |
Investing activities | | | (107,990 | ) | | | (98,276 | ) |
Financing activities | | | 77,997 | | | | 55,529 | |
| | |
Capital Expenditure Data: | | | | | | | | |
Maintenance capital expenditures | | $ | 3,855 | | | $ | 4,510 | |
Expansion capital expenditures | | | 104,661 | | | | 76,657 | |
Acquisitions | | | — | | | | 17,235 | |
| | | | | | | | |
Total | | $ | 108,516 | | | $ | 98,402 | |
| | | | | | | | |
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited; in thousands)
| | | | | | | | |
| | | March 31,
2013 | | | December 31,
2012 | |
| ASSETS | | | | | | | | |
| | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 8,261 | | | $ | 3,398 | |
Other current assets | | | 216,853 | | | | 216,677 | |
| | | | | | | | |
Total current assets | | | 225,114 | | | | 220,075 | |
| | |
Property, plant and equipment, net | | | 2,299,967 | | | | 2,200,381 | |
Intangible assets, net | | | 502,071 | | | | 518,645 | |
Investment in joint ventures | | | 86,242 | | | | 86,002 | |
Other assets, net | | | 41,036 | | | | 40,535 | |
| | | | | | | | |
| | $ | 3,154,430 | | | $ | 3,065,638 | |
| | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | |
| | |
Current liabilities | | $ | 252,059 | | | $ | 253,519 | |
Long-term debt, less current portion | | | 1,310,051 | | | | 1,169,083 | |
Deferred income taxes, net | | | 30,249 | | | | 30,258 | |
Other long-term liability | | | 7,283 | | | | 6,370 | |
| | |
Total partners’ capital | | | 1,487,942 | | | | 1,539,177 | |
Non-controlling interest | | | 66,846 | | | | 67,231 | |
| | | | | | | | |
Total equity | | | 1,554,788 | | | | 1,606,408 | |
| | | | | | | | |
| | $ | 3,154,430 | | | $ | 3,065,638 | |
| | | | | | | | |
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Reconciliation of Non-GAAP Measures
(unaudited; in thousands)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2013 | | | 2012 | |
Reconciliation of net income to other non-GAAP measures(1): | | | | | | | | |
Net income | | $ | (27,492 | ) | | $ | 6,471 | |
Income attributable to non-controlling interests(2) | | | (1,369 | ) | | | (1,536 | ) |
Depreciation and amortization | | | 30,458 | | | | 20,842 | |
Income tax benefit | | | (9 | ) | | | — | |
Non-controlling interest depreciation, amortization and interest(3) | | | (850 | ) | | | — | |
Interest expense | | | 18,686 | | | | 8,708 | |
| | | | | | | | |
| | |
EBITDA | | | 19,424 | | | | 34,485 | |
| | |
Adjustment for cash flow from investment in joint ventures | | | (240 | ) | | | 904 | |
Non-cash loss on derivatives | | | 13,719 | | | | 10,696 | |
Successful acquisition costs | | | 530 | | | | — | |
Premium expense on derivative instruments | | | 3,275 | | | | 3,752 | |
Loss on early termination of debt | | | 26,582 | | | | — | |
Other non-cash losses(4) | | | 4,416 | | | | 1,250 | |
| | | | | | | | |
| | |
Adjusted EBITDA | | | 67,706 | | | | 51,087 | |
| | |
Interest expense | | | (18,686 | ) | | | (8,708 | ) |
Amortization of deferred financing costs | | | 1,544 | | | | 1,165 | |
Premium expense on derivative instruments | | | (3,275 | ) | | | (3,752 | ) |
Other costs | | | — | | | | (34 | ) |
Maintenance capital expenditures | | | (3,814 | ) | | | (4,510 | ) |
| | | | | | | | |
| | |
Distributable Cash Flow | | $ | 43,475 | | | $ | 35,248 | |
| | | | | | | | |
| (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 includes (i) EBITDA from the discontinued operations related to the sale of the Partnership’s 49% interest in Laurel Mountain; 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. |
| (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 and non-cash compensation. |
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| | | | | | | | | | | | |
| | | Three Months Ended March 31, | |
| | | 2013 | | | 2012 | | | Percent
Change | |
Pricing (unhedged): | | | | | | | | | | | | |
| | | |
Mid-Continent Weighted Average Prices: | | | | | | | | | | | | |
NGL price per gallon – Conway hub | | $ | 0.83 | | | $ | 0.93 | | | | (10.8 | )% |
NGL price per gallon – Mt. Belvieu hub | | | 0.85 | | | | 1.18 | | | | (28.0 | )% |
| |
Natural gas sales ($/MCF): | | | | |
Velma | | | 3.17 | | | | 2.55 | | | | 24.3 | % |
WestOK | | | 3.20 | | | | 2.56 | | | | 25.0 | % |
WestTX | | | 3.12 | | | | 2.51 | | | | 24.3 | % |
Weighted Average | | | 3.17 | | | | 2.54 | | | | 24.8 | % |
| |
NGL sales ($/Gallon): | | | | |
Arkoma | | | 0.70 | | | | — | | | | — | |
Velma | | | 0.75 | | | | 0.93 | | | | (19.4 | )% |
WestOK | | | 0.98 | | | | 0.91 | | | | 7.7 | % |
WestTX | | | 0.93 | | | | 1.17 | | | | (20.5 | )% |
Weighted Average | | | 0.90 | | | | 1.03 | | | | (12.6 | )% |
| |
Condensate sales ($/Barrel): | | | | |
Arkoma | | | 87.92 | | | | — | | | | — | |
Velma | | | 93.39 | | | | 102.22 | | | | (8.6 | )% |
WestOK | | | 83.67 | | | | 93.95 | | | | (10.9 | )% |
WestTX | | | 88.02 | | | | 101.38 | | | | (13.2 | )% |
Weighted Average | | | 86.00 | | | | 97.44 | | | | (11.7 | )% |
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| | | | | | | | | | | | |
| | | Three Months Ended March 31, | |
| | | 2013 | | | 2012 | | | Percent
Change | |
| | | |
Volumes: | | | | | | | | | | | | |
| | | |
Arkoma system: | | | | | | | | | | | | |
Gathered gas volume (MCFD) | | | 260,732 | | | | — | | | | — | |
Processed gas volume(2) (MCFD) | | | 201,301 | | | | — | | | | — | |
Residue gas volume (MCFD) | | | 207,844 | | | | — | | | | — | |
Processed NGL volume (BPD) | | | 20,555 | | | | — | | | | — | |
Condensate volume (BPD) | | | 158 | | | | — | | | | — | |
| | | |
Velma system: | | | | | | | | | | | | |
Gathered gas volume (MCFD) | | | 130,767 | | | | 129,223 | | | | 1.2 | % |
Processed gas volume(2) (MCFD) | | | 125,377 | | | | 122,904 | | | | 2.0 | % |
Residue gas volume (MCFD) | | | 102,238 | | | | 100,335 | | | | 1.9 | % |
Processed NGL volume (BPD) | | | 13,997 | | | | 13,643 | | | | 2.6 | % |
Condensate volume (BPD) | | | 405 | | | | 564 | | | | (28.2 | )% |
| | | |
WestOK system: | | | | | | | | | | | | |
Gathered gas volume (MCFD) | | | 452,368 | | | | 295,198 | | | | 53.2 | % |
Processed gas volume(2) (MCFD) | | | 425,431 | | | | 279,305 | | | | 52.3 | % |
Residue gas volume (MCFD) | | | 396,694 | | | | 251,940 | | | | 57.5 | % |
Processed NGL volume (BPD) | | | 16,251 | | | | 14,062 | | | | 15.6 | % |
Condensate volume (BPD) | | | 1,969 | | | | 1,405 | | | | 40.1 | % |
| | | |
WestTX system(3): | | | | | | | | | | | | |
Gathered gas volume (MCFD) | | | 312,571 | | | | 246,339 | | | | 26.9 | % |
Processed gas volume(2) (MCFD) | | | 280,756 | | | | 230,504 | | | | 21.8 | % |
Residue gas volume (MCFD) | | | 209,891 | | | | 160,022 | | | | 31.2 | % |
Processed NGL volume (BPD) | | | 33,245 | | | | 33,101 | | | | 0.4 | % |
Condensate volume (BPD) | | | 1,033 | | | | 939 | | | | 10.0 | % |
| | | |
Barnett system: | | | | | | | | | | | | |
Gathered gas volumes (MCFD) | | | 21,401 | | | | — | | | | 100 | % |
| | | |
Tennessee system: | | | | | | | | | | | | |
Gathered gas volumes (MCFD) | | | 9,495 | | | | 8,225 | | | | 15.4 | % |
| | | |
West Texas LPG Partnership(4) | | | | | | | | | | | | |
Average NGL volumes (BPD) | | | 244,626 | | | | 242,318 | | | | 1.0 | % |
| | | |
Consolidated Volumes: | | | | | | | | | | | | |
Gathered gas volume (MCFD) | | | 1,187,334 | | | | 678,985 | | | | 74.9 | % |
Processed gas volume (MCFD) | | | 1,032,865 | | | | 632,713 | | | | 63.2 | % |
Residue gas volume (MCFD) | | | 916,667 | | | | 512,297 | | | | 78.9 | % |
Processed NGL volume (BPD) | | | 84,048 | | | | 60,806 | | | | 38.2 | % |
Condensate volume (BPD) | | | 3,565 | | | | 2,908 | | | | 22.6 | % |
| (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 the WestTX system represents 100% of its operating activity. |
| (4) | Volume data for the West Texas LPG Partnership represents 100% of its operating activity for the calendar year. |
12
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of April 29, 2013)
Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the contracts in place through December 31, 2016. APL’s price risk management position in its entirety will be disclosed in the Partnership’s Form 10-Q. NGL contracts are traded at Mt. Belvieu unless otherwise disclosed.
SWAP CONTRACTS
NATURAL GAS LIQUIDS HEDGES
| | | | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Gallons | | | Avg. Fixed Price | |
| 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 | | | 12,726,000 | | | | 1.25 | |
| 4Q 2013 | | Sold | | Propane – Conway | | | 1,260,000 | | | | 1.06 | |
| 4Q 2013 | | Sold | | Propane | | | 12,222,000 | | | | 1.28 | |
| 1Q 2014 | | Sold | | Propane | | | 8,694,000 | | | | 1.00 | |
| 1Q 2014 | | Sold | | Natural gasoline | | | 1,260,000 | | | | 2.08 | |
| 2Q 2014 | | Sold | | Propane | | | 8,442,000 | | | | 0.96 | |
| 2Q 2014 | | Sold | | Normal Butane | | | 1,260,000 | | | | 1.50 | |
| 2Q 2014 | | Sold | | Natural gasoline | | | 3,150,000 | | | | 1.94 | |
| 3Q 2014 | | Sold | | Propane | | | 8,190,000 | | | | 0.97 | |
| 3Q 2014 | | Sold | | Normal Butane | | | 1,260,000 | | | | 1.50 | |
| 3Q 2014 | | Sold | | Natural gasoline | | | 2,520,000 | | | | 1.94 | |
| 4Q 2014 | | Sold | | Propane | | | 8,190,000 | | | | 0.98 | |
| 4Q 2014 | | Sold | | Normal Butane | | | 1,260,000 | | | | 1.53 | |
| 4Q 2014 | | Sold | | Natural gasoline | | | 2,520,000 | | | | 1.95 | |
| 1Q 2015 | | Sold | | Propane | | | 7,686,000 | | | | 0.95 | |
| 1Q 2015 | | Sold | | Natural gasoline | | | 2,142,000 | | | | 1.91 | |
| 2Q 2015 | | Sold | | Propane | | | 8,064,000 | | | | 0.92 | |
| 2Q 2015 | | Sold | | Natural gasoline | | | 630,000 | | | | 1.97 | |
| 3Q 2015 | | Sold | | Propane | | | 378,000 | | | | 0.93 | |
| 3Q 2015 | | Sold | | Natural gasoline | | | 630,000 | | | | 1.97 | |
| 4Q 2015 | | Sold | | Propane | | | 3,528,000 | | | | 0.96 | |
| 4Q 2015 | | Sold | | Natural gasoline | | | 630,000 | | | | 1.97 | |
13
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of April 24, 2013)
SWAP CONTRACTS
CONDENSATE HEDGES
| | | | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Barrels | | | Avg. Fixed Price | |
| 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 | | | 93,000 | | | | 95.45 | |
| 2Q 2014 | | Sold | | Crude | | | 90,000 | | | | 93.43 | |
| 3Q 2014 | | Sold | | Crude | | | 75,000 | | | | 89.86 | |
| 4Q 2014 | | Sold | | Crude | | | 45,000 | | | | 88.16 | |
| 1Q 2015 | | Sold | | Crude | | | 15,000 | | | | 85.13 | |
| 2Q 2015 | | Sold | | Crude | | | 15,000 | | | | 85.13 | |
| 3Q 2015 | | Sold | | Crude | | | 15,000 | | | | 85.13 | |
| 4Q 2015 | | Sold | | Crude | | | 15,000 | | | | 85.13 | |
NATURAL GAS HEDGES | | | | | | | | | | | | |
| | | | |
Production Period | | Purchased /Sold | | Commodity | | MMBTUs | | | Avg. Fixed Price | |
| 2Q 2013 | | Sold | | Natural gas | | | 600,000 | | | | 3.43 | |
| 3Q 2013 | | Sold | | Natural gas | | | 1,100,000 | | | | 3.60 | |
| 4Q 2013 | | Sold | | Natural gas | | | 1,420,000 | | | | 3.69 | |
| 1Q 2014 | | Sold | | Natural gas | | | 1,500,000 | | | | 3.91 | |
| 2Q 2014 | | Sold | | Natural gas | | | 2,500,000 | | | | 3.87 | |
| 3Q 2014 | | Sold | | Natural gas | | | 4,000,000 | | | | 3.95 | |
| 4Q 2014 | | Sold | | Natural gas | | | 4,000,000 | | | | 4.05 | |
| 1Q 2015 | | Sold | | Natural gas | | | 3,100,000 | | | | 4.29 | |
| 2Q 2015 | | Sold | | Natural gas | | | 3,100,000 | | | | 4.13 | |
| 3Q 2015 | | Sold | | Natural gas | | | 3,100,000 | | | | 4.17 | |
| 4Q 2015 | | Sold | | Natural gas | | | 2,800,000 | | | | 4.26 | |
| 1Q 2016 | | Sold | | Natural gas | | | 300,000 | | | | 4.40 | |
| 2Q 2016 | | Sold | | Natural gas | | | 300,000 | | | | 4.40 | |
| 3Q 2016 | | Sold | | Natural gas | | | 300,000 | | | | 4.40 | |
| 4Q 2016 | | Sold | | Natural gas | | | 300,000 | | | | 4.40 | |
14
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of April 24, 2013)
OPTION CONTRACTS
NGL OPTIONS
| | | | | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Gallons | | | Avg. Strike Price | |
| 2Q 2013 | | Purchased | | Put | | Propane | | | 1,260,000 | | | | 0.87 | |
| 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 | |
CRUDE OPTIONS | | | | | | | | | | | | | | |
| | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Barrels | | | Avg. Strike Price | |
| 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 | | | 75,000 | | | | 89.68 | |
| 4Q 2014 | | Purchased | | Put | | Crude Oil | | | 102,000 | | | | 91.64 | |
| 1Q 2015 | | Purchased | | Put | | Crude Oil | | | 45,000 | | | | 91.33 | |
| 2Q 2015 | | Purchased | | Put | | Crude Oil | | | 75,000 | | | | 89.49 | |
| 3Q 2015 | | Purchased | | Put | | Crude Oil | | | 75,000 | | | | 88.59 | |
| 4Q 2015 | | Purchased | | Put | | Crude Oil | | | 75,000 | | | | 88.15 | |
NATURAL GAS OPTIONS | | | | | | | | | | | | | | |
| | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | MMBTUs | | | Avg. Strike Price | |
| 2Q 2014 | | Purchased | | Put | | Natural Gas | | | 300,000 | | | | 4.10 | |
| 3Q 2014 | | Purchased | | Put | | Natural Gas | | | 300,000 | | | | 4.15 | |
15
