Atlas Pipeline Partners, L.P. Reports Third Quarter 2013 Results -- Record gathered gas volumes of approximately 1.5 billion cubic feet per day (BCFD) in third quarter 2013 -- Adjusted EBITDA for third quarter 2013 was $84.2 million, a 50.5% increase year-over-year -- Distributable Cash Flow for third quarter 2013 was $50.6 million, a 34.6% increase year-over-year -- Previously announced distribution of $0.62 per common limited partner unit, an 8.8% increase year-over-year -- New growth projects announced in Woodford Shale and Permian Basin; three new processing plants due in 2014 PR Newswire PHILADELPHIA, Nov. 4, 2013 PHILADELPHIA, Nov. 4, 2013 /PRNewswire/ --Atlas Pipeline Partners, L.P. (NYSE: APL) ("APL", "Atlas Pipeline", or the "Partnership") today reported adjusted earnings before interest, income taxes, depreciation and amortization ("Adjusted EBITDA"), of $84.2 million for the third quarter of 2013, driven primarily by a continued increase in overall volumes across the Partnership's gathering and processing systems. Processed natural gas volumes averaged 1,372 million cubic feet per day ("MMCFD"), a 78.4% increase over the third quarter of 2012. Distributable Cash Flow was $50.6 million for the third quarter of 2013, or $0.65 per average common limited partner unit, compared to $37.6 million for the prior year's third quarter. The Partnership recognized a net loss of $25.6 million for the third quarter of 2013, compared with a net loss of $6.4 million for the prior year's third 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 October 24, 2013, the Partnership declared a cash distribution for the third quarter of 2013 of $0.62 per common limited partner unit to holders of record on November 7, 2013, which will be paid on November 14, 2013. This distribution represents Distributable Cash Flow coverage per limited partner unit of slightly less than 1.0x for the third quarter of 2013, however distribution coverage for the second and third quarter combined was approximately 1.0x. "We are pleased with the continued growth of our Company to date, but we are not yet satisfied. We have numerous growth opportunities in multiple areas in which we operate and we are working diligently to pursue those opportunities in a prudent manner. Our expectations are to fully utilize any and all of our processing capacity on our existing infrastructure and look for new opportunities to continue our growth trajectory and service to our customers. While our distribution did not increase this quarter over last quarter, we remain confident that we have set up the Partnership to continue to grow the distribution over the coming years," remarked Eugene Dubay, Chief Executive Officer of the Partnership. Capitalization and Liquidity The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $510.0 million as of September 30, 2013. Total debt outstanding was $1,655.7 million at September 30, 2013, compared to $1,179.9 million at December 31, 2012, an increase of $475.7 million. Based upon total debt outstanding at September 30, 2013, total leverage was approximately 4.9x for purposes of calculations under our revolving credit facility, and debt to total capital was 42%. Risk Management The Partnership continued enhancement of its risk management portfolio, adding further protection for 2014 and 2015. As of October 16, 2013, the Partnership had natural gas, natural gas liquids and condensate protection in place for the remainder of 2013, 2014, and 2015 for approximately 83%, 72%, and 39%, respectively, of associated margin value (exclusive of ethane). The Partnership also has a minimal amount of 2016 expected equity volumes protected. 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 October 16, 2013 is included in this release. Operating Results Volumes have continued to increase across all five of the Partnership's gathering and processing systems since the end of the second quarter. Current gathered volumes are approximately 1.5 billion cubic feet per day ("BCFD") and processable volumes are in excess of 1.4 BCFD, an increase of over 150 MMCFD compared to the Partnership's second quarter reported results. Growth capital spending continues to track $450 million for 2013, as organic expansion projects continue across all gathering and processing systems, including expected 2014 expansions at Arkoma (120 MMCFD), SouthTX (200 MMCFD), and WestTX (200 MMCFD). Gross margin from operations was $114.8 million for the third quarter 2013, compared to $68.7 million for the prior year period, led by increasing producer activity in APL's area of operations. Gross margin, a non-GAAP financial measure, includes natural gas and liquids sales and transportation, processing and other fees, less purchased product costs and non-cash gains (or losses) included in these items. The higher gross margin for the quarter was primarily due to the increased volumes and expansions that have been completed on the WestOK, WestTX, and Velma systems, as well as the newly acquired Arkoma system and SouthTX system. The gross margin for the quarter does not include approximately $0.9 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $4.2 million realized derivative settlement gains excluded from gross margin in the third quarter of 2012. WestTX System The WestTX system's average natural gas processed volume was 355.2 MMCFD for the third quarter 2013, compared to 255.7 MMCFD for the third quarter of 2012. Increased volumes are primarily due to the completion of the Driver plant in April 2013, which increased processing capacity on the WestTX system by 200 MMCFD. Average NGL production was 47,663 barrels per day ("BPD") for the third quarter 2013, a 67.2% increase over the third quarter 2012. This system continues to operate in ethane rejection due to the value of ethane compared to residue natural gas. The Partnership expects processed volumes on this system to continue to increase as producers continue to pursue their drilling plans over the coming years. Incremental volume growth from the northern portion of the Partnership's gathering system, where many of the Partnership's producer customers are active, has resulted in the need for additional gathering infrastructure in that area. APL's Managing Board of Directors has approved an extension of the WestTX gathering system further into Martin County, Texas through a series of growth projects which will service the anticipated needs of its producer customers. The Partnership will lay a high pressure gathering line into Martin County as well as add compression to increase utilization of WestTX's existing assets, including the recently announced Edward plant. In addition, this extension of the WestTX system is expected to accelerate the Partnership's need to install additional processing capacity, potentially by the end of 2015. The initial high pressure gathering pipeline and associated compression is expected to cost approximately $50 million or approximately $36 million net to the Partnership. As previously announced, the Edward plant, which will add an incremental 200 MMCFD of capacity is expected to be completed in the second half of 2014. WestOK System The WestOK system had average natural gas processed volume of 479.3 MMCFD for the third quarter, a 26.1% increase from the third quarter 2012. Average NGL production was 21,522 BPD for the third quarter 2013, a 65.6% increase from the third quarter 2012, due to increased production on the gathering systems. Producers in the Mississippi Lime play in northwestern Oklahoma and southern Kansas continue to grow volumes behind APL's WestOK system, with current gathered volumes in excess of 525 MMCFD. With current nameplate capacity of 458 MMCFD, excess volumes are being offloaded and bypassed as the Partnership works to add capacity in the coming months. With the addition of refrigeration, compression and other engineering work currently being undertaken, the Waynoka facilities are expected to have an incremental 40-50 MMCFD of processing capacity available in November of this year. Due to the nonrenewal of a low margin commercial agreement, an additional 60-70 MMCFD of capacity will become available in the second quarter of 2014. This capacity is expected to be filled under more favorable economic returns with volumes currently being offloaded to third parties and volume growth associated with increased producer drilling activity. Management is committed to continuing to provide excellent service to our producer customers in the play and remain the preeminent gatherer and processor in the area. Due to the ethane pricing environment, approximately only 25% of the currently available ethane is being produced on the system, which Management expects to continue throughout the remainder of this year. Velma System The Velma system's average natural gas processed volume was 151.9 MMCFD for the third quarter 2013, a 14.0% increase from the third quarter of 2012. The increase is primarily due to additional production gathered from continued producer activity in the liquids-rich portion of the Woodford Shale and Ardmore Basin. Average NGL production increased to 16,780 BPD for the third quarter 2013, up approximately 12.9% compared to the third quarter 2012, due to the increase in overall processed volumes. Drilling activity behind the Velma system continues to increase with incremental demand for processing capacity in the area has increased, partially the result of the emerging South Central Oklahoma Oil Province (SCOOP) play, which has attracted significant producer interest. APL has entered into fixed fee arrangements with some of these producers and, as a result, will be adding gathering infrastructure at an expected cost of $40 million to facilitate this anticipated growth. The Velma system's processing capacity today is almost fully utilized, and the Partnership will provide capacity for the incremental SCOOP production by laying approximately 55 miles of pipeline between the Velma system and the Arkoma system. The Arkoma system is also nearly fully utilized today, but will expand by an additional 120 MMCFD upon installation of the Stonewall plant, expected in the first quarter of 2014. This project is expected to accelerate the utilization of the Stonewall plant, which is expandable to 200 MMCFD with minimal capital outlay. The capital to interconnect the Velma and Arkoma systems is expected to be approximately $80 million with anticipated completion in the third quarter of 2014. Arkoma System The Arkoma system consists of gas gathering, processing and treating facilities in the Arkoma Basin in southeastern Oklahoma and includes a 60% interest in a joint venture with MarkWest Energy Partners, L.P., known as Centrahoma Processing, LLC ("Centrahoma"). The system had average natural gas processed volumes of 245.5 MMCFD and produced 16,171 BPD of NGLs during the third 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. Gathered volumes continue to increase and are currently in excess of 260 MMCFD in the Arkoma area. Upon the recent completion of a gathering system expansion by MarkWest Energy Partners, the current processing facilities are now operating near nameplate capacity of 220 MMCFD. This expansion was originally expected to be completed in July 2013 and the delay had a negative impact on the Partnership's results for the quarter as excess volumes were offloaded to third parties. The Partnership expects certain volumes to continue to be offloaded until the Stonewall plant is operational at the end of the first quarter of 2014. Cash flows from this system are largely fee-based; however, this system does have commodity exposure on fixed recovery contracts, primarily related to Mont Belvieu priced ethane, which is not currently hedged. Approximately half of the ethane is being rejected back into the residue gas stream at these facilities, which is expected to continue at the current ethane and natural gas prices. SouthTX System The Partnership acquired the SouthTX system in May 2013 through the acquisition of TEAK Midstream L.L.C. The assets acquired include gas gathering and processing facilities and a co-generation facility located in south Texas within the Eagle Ford shale region. The SouthTX system has a total gross name-plate processing capacity of 200 MMCFD with the Silver Oak I plant, and will have name-plate capacity of 400 MMCFD once the Silver Oak II plant goes into service, which is expected to be late in the first quarter or early in the second quarter of 2014. The system had average natural gas processed volumes of 140.6 MMCFD and produced 17,990 BPD of NGLs during the third quarter of 2013. Volumes on the SouthTX system continue to grow with current processed volumes more than 20% higher than those reported for the second quarter. Although at times during the third quarter the SouthTX system ran at the full name-plate capacity, a portion of those volumes have been interruptible packages of gas, which causes periodic fluctuation in volume figures. The Partnership's management team is committed to getting to full utilization of 200 MMCFD on the current Silver Oak I plant by the end of the year and expects the 200 MMCFD Silver Oak II plant to be fully utilized by the end of 2014. Corporate and Other General and administrative costs, excluding non-cash compensation, for the third quarter of 2013 totaled $11.9 million, compared to $8.5 million in the same period in 2012. This increase was driven primarily by an increase in personnel as a result of the acquisition of the Arkoma system in late 2012 and the SouthTX system in April 2013. Net of deferred financing costs, interest expense increased to $22.5 million for the third quarter of 2013, as compared to $8.6 million in the third quarter of 2012. This increase was due to financing the Partnership's acquisitions and capital expenditure program during 2012 and 2013, including the issuance of 6.625% senior unsecured notes due 2020 in September and December 2012, the February 2013 issuance of 5.875% senior unsecured notes due 2023, and the May 2013 issuance of 4.750% senior unsecured notes due 2021. The 5.875% senior unsecured notes due 2023 were issued in connection with the redemption of the Partnership's 8.75% Senior Notes due 2018. * * * Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's third quarter 2013 results on Tuesday, November 5, 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 2:00 pm ET on Tuesday, November 5, 2013. To access the replay, dial 1-888-286-8010 and enter conference code 35780875. Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 14 active gas processing plants, 18 gas treating facilities, as well as approximately 10,600 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com. Atlas Energy, L.P. (NYSE: ATLS)is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 37% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com. Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Atlas Pipeline does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity prices and local or national economic conditions and other risks detailed from time to time in Atlas Pipeline's reports filed with the SEC, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K. ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary^(1) (unaudited; in thousands except per unit amounts) Three Months Ended Nine Months Ended September 30, September 30, 2013 2012 2013 2012 Revenue: Natural gas and liquids $ 535,719 $ 274,618 $ 1,410,797 $ 802,644 sales Transportation, processing and other 43,725 19,272 116,756 46,831 fees^(2) Derivative gain (loss), (24,517) (18,907) (9,493) 36,905 net Other income, net 2,943 2,585 8,661 7,588 Total revenues 557,870 277,568 1,526,721 893,968 Costs and expenses: Natural gas and liquids 463,564 224,778 1,213,320 652,986 cost of sales Plant operating 24,253 15,180 69,671 43,661 Transportation and 553 520 1,764 996 compression General and 11,889 8,504 30,413 24,976 administrative General and administrative – non-cash 5,998 3,619 13,818 7,537 unit-based compensation^(3) Other 685 (108) 19,585 (303) Depreciation and 51,080 23,161 127,921 65,715 amortization Interest 24,347 9,692 65,614 27,669 Total costs and expenses 582,369 285,346 1,542,106 823,237 Equity income (loss) in (1,882) 1,422 (314) 4,235 joint ventures Loss on asset sales and ‒ ‒ (1,519) ‒ other Loss on early ‒ ‒ (26,601) ‒ extinguishment of debt Income (loss) before (26,381) (6,356) (43,819) 74,966 income taxes Income tax benefit (817) ‒ (854) ‒ Net income (loss) (25,564) (6,356) (42,965) 74,966 Income attributable to non-controlling (1,514) (1,511) (4,693) (4,108) interests Preferred unit imputed (11,378) ‒ (18,107) ‒ dividend effect Preferred unit dividends (9,072) ‒ (14,413) ‒ Net income (loss) attributable to common $ (47,528) $ (7,867) $ (80,178) $ 70,858 limited partners and the General Partner Net income (loss) attributable to common limited partners per unit: Basic and diluted: $ (0.66) $ (0.17) $ (1.25) $ 1.19 Weighted average common limited 78,398 53,736 72,512 53,668 partner units (basic) Weighted average common limited 78,398 55,736 72,512 54,409 partner units (diluted) (1) Based on the GAAP statements of operations to be included in Form 10-Q, with additional detail of certain items included (2) Includes affiliate revenues related to transportation and processing provided to Atlas Resource Partners, L.P (3) Non-cash costs associated with unit-based compensation, which have been reflected in the general and administrative costs and expenses, the category associated with the direct personnel cash costs in the GAAP statements of operations to be included in Form 10-Q. General and administrative also includes any compensation reimbursement to affiliates ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary (continued) (unaudited; in thousands, except per unit amounts) Three Months Ended Nine Months Ended September 30, September 30, 2013 2012 2013 2012 Summary Cash Flow Data: Cash provided by operating $ 79,400 $ 60,992 $ 145,121 $ 125,523 activities Cash used in investing (121,905) (95,899) (1,338,149) (278,725) activities Cash provided by financing 31,863 34,814 1,200,069 153,199 activities Capital Expenditure Data: Maintenance capital $ 6,416 $ 4,732 $ 14,119 $ 13,242 expenditures Expansion capital 105,736 91,292 313,742 229,170 expenditures Contributions in equity 9,813 ‒ 9,813 ‒ method investments Acquisitions ‒ ‒ 1,000,785 36,689 Total $ 121,965 $ 96,024 $ 1,338,459 $ 279,101 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (unaudited; in thousands) September 30, December 31, ASSETS 2013 2012 Current assets: Cash and cash equivalents $ 10,439 $ 3,398 Other current assets 307,786 216,677 Total current assets 318,225 220,075 Property, plant and equipment, net 2,715,361 2,200,381 Intangible assets, net 1,049,892 518,645 Investment in joint ventures 238,221 86,002 Other assets, net 51,896 40,535 $ 4,373,595 $ 3,065,638 LIABILITIES AND EQUITY Current liabilities $ 361,780 $ 253,519 Long-term debt, less current portion 1,655,042 1,169,083 Deferred income taxes, net 34,696 30,258 Other long-term liability 7,409 6,370 Total partners' capital 2,266,506 1,539,177 Non-controlling interest 48,162 67,231 Total equity 2,314,668 1,606,408 $ 4,373,595 $ 3,065,638 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Reconciliation of Non-GAAP Measures (unaudited; in thousands) Three Months Ended Nine Months Ended September 30, September 30, 2013 2012 2013 2012 Reconciliation of net income to other non-GAAP measures^(1): Net income (loss) $ (25,564) $ (6,356) $ (42,965) $ 74,966 Depreciation and 51,080 23,161 127,921 65,715 amortization Income tax benefit (817) ‒ (854) ‒ Interest expense 24,347 9,692 65,614 27,669 EBITDA 49,046 26,497 149,716 168,350 Income attributable to non-controlling (1,514) (1,511) (4,693) (4,108) interests^(2) Non-controlling interest depreciation, (917) ‒ (2,888) ‒ amortization and interest^(3) Adjustment for cash flow from investment in joint 3,682 378 5,714 1,165 ventures Loss on asset ‒ ‒ 1,519 ‒ disposition Non-cash (gain) loss on 23,610 22,477 13,066 (31,568) derivatives Acquisition costs 685 ‒ 19,585 ‒ Premium expense on 4,824 4,855 11,844 12,591 derivative instruments Unrecognized economic 42 ‒ 1,168 ‒ impact of acquisitions Loss on early ‒ ‒ 26,601 ‒ termination of debt Other non-cash 4,743 3,245 16,587 9,658 losses^(4) Adjusted EBITDA 84,201 55,941 238,219 156,088 Interest expense (24,347) (9,692) (65,614) (27,669) Amortization of deferred 1,836 1,061 5,119 3,356 finance costs Premium expense on (4,824) (4,855) (11,844) (12,591) derivative instruments Other costs ‒ (108) ‒ (303) Maintenance capital (6,232) (4,732) (13,759) (13,242) expenditures^(5) Distributable Cash Flow $ 50,634 $ 37,615 $ 152,121 $ 105,639 (1) EBITDA, Adjusted EBITDA and Distributable Cash Flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of the Partnership believes EBITDA, Adjusted EBITDA and Distributable Cash Flow provide additional information for evaluating the Partnership's ability to make distributions to its common unit holders and the general partner, among other things. These measures are widely-used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. Adjusted EBITDA is also similar to the Consolidated EBITDA calculation utilized for the Partnership's financial covenants under its credit facility, with the exception that Adjusted EBITDA includes non-cash items specifically excluded under the credit facility. EBITDA, Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP (2) Represents Anadarko Petroleum Corporation's ("Anadarko" – NYSE: APC) non-controlling interest in the operating results of Atlas Pipeline Mid-Continent WestOk, LLC ("WestOK") and Atlas Pipeline Mid-Continent WestTex, LLC ("WestTX"); and MarkWest's non-controlling interest in Centrahoma (3) Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest's interest in Centrahoma (4) Includes the non-cash impact of commodity price movements on pipeline linefill inventory, non-cash compensation and minimum volume adjustments on certain producer throughput contracts (5) Net of non-controlling interest maintenance capital of $184 thousand and $360 thousand for the three and nine months ended September 30, 2013, respectively ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Operating Highlights^(1) Three Months Ended September Nine Months Ended September 30, 30, 2013 2012 Percent 2013 2012 Percent Change Change Pricing (unhedged): Weighted Average Market Prices: NGL price per gallon $ 0.81 $ 0.70 15.7 % $ 0.80 $ 0.78 2.6 % – Conway hub NGL price per gallon 0.85 0.86 (1.2)% 0.83 0.99 (16.2)% – Mt. Belvieu hub Natural gas sales ($/MCF): Velma 3.37 2.64 27.7% 3.47 2.41 44.0% WestOK 3.30 2.62 26.0% 3.45 2.43 42.0% WestTX 3.32 2.54 30.7% 3.40 2.32 46.6% Weighted average 3.34 2.60 28.5% 3.46 2.39 44.8% NGL sales ($/Gallon): Arkoma 0.89 - - 0.73 - - SouthTX 0.75 - - 0.73 - - Velma 0.81 0.73 11.0 % 0.77 0.79 (2.5)% WestOK 1.08 0.86 25.6 % 1.01 0.86 17.4 % WestTX 0.92 0.96 (4.2)% 0.90 1.01 (10.9)% Weighted average 0.92 0.87 5.7 % 0.87 0.90 (3.3)% Condensate sales ($/barrel): Arkoma 99.94 - - 87.94 - - SouthTX 92.94 - - 91.05 - - Velma 104.29 91.40 14.1 % 96.80 96.93 (0.1)% WestOK 96.86 82.06 18.0 % 88.10 87.29 0.9 % WestTX 106.27 90.41 17.5 % 98.78 90.81 8.8 % Weighted average 101.48 86.65 17.1 % 92.82 90.07 3.1 % ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Operating Highlights^(1) Three Months Ended September Nine Months Ended September 30, 30, 2013 2012 Percent 2013 2012 Percent Change Change Volumes: Arkoma system^(2): Gathered gas volume 265,992 - - 270,007 - - (MCFD) Processed gas 245,496 - - 249,111 - - volume^(3) (MCFD) Residue gas volume 211,438 - - 209,162 - - (MCFD) Processed NGL volume 16,171 - - 20,756 - - (BPD) Condensate volume 85 - - 131 - - (BPD) SouthTX system: Gathered gas volume 141,282 - - 131,815 - - (MCFD) Processed gas 140,557 - - 131,000 - - volume^(3) (MCFD) Residue gas volume 114,287 - - 105,495 - - (MCFD) Processed NGL volume 17,990 - - 16,524 - - (BPD) Condensate volume 108 - - 85 - - (BPD) Velma system: Gathered gas volume 157,330 136,939 14.9% 142,708 134,248 6.3% (MCFD) Processed gas 151,862 133,166 14.0% 136,743 128,398 6.5% volume^(3) (MCFD) Residue gas volume 126,931 108,609 16.9% 113,642 105,135 8.1% (MCFD) Processed NGL volume 16,780 14,866 12.9% 15,669 14,306 9.5% (BPD) Condensate volume 356 283 25.8% 382 427 (10.5)% (BPD) WestOK system: Gathered gas volume 505,222 403,304 25.3% 488,219 346,318 41.0% (MCFD) Processed gas 479,270 380,113 26.1% 462,932 326,337 41.9% volume^(3) (MCFD) Residue gas volume 442,304 360,688 22.6% 428,056 302,486 41.5% (MCFD) Processed NGL volume 21,522 12,998 65.6% 20,021 13,810 45.0% (BPD) Condensate volume 1,759 1,341 31.2% 1,892 1,318 43.6% (BPD) WestTX system^(2): Gathered gas volume 383,466 288,607 32.9% 349,894 268,456 30.3% (MCFD) Processed gas 355,203 255,709 38.9% 316,760 241,710 31.0% volume^(3) (MCFD) Residue gas volume 265,648 189,549 40.1% 235,310 172,150 36.7% (MCFD) Processed NGL volume 47,663 28,499 67.2% 40,322 31,441 28.2% (BPD) Condensate volume 2,598 2,132 21.9% 1,881 1,672 12.5% (BPD) Barnett system: Gathered gas 22,727 22,789 (0.3)% 21,408 23,084 (7.3)% volumes (MCFD) Tennessee system: Gathered gas 8,052 8,387 (4.0)% 8,565 8,320 2.9% volumes (MCFD) West Texas LPG Partnership^(2) Average NGL 247,856 256,579 (3.4)% 248,468 247,568 0.4% volumes (BPD) Consolidated Volumes: Gathered gas 1,484,071 860,026 72.6% 1,412,616 780,426 81.0% volume (MCFD) Processed gas 1,372,388 768,988 78.5% 1,247,676 696,445 79.1% volume (MCFD) Residue gas 1,160,608 658,846 76.2% 1,091,665 579,771 88.3% volume (MCFD) Processed NGL 120,126 56,363 113.1% 113,292 59,557 90.2% volume (BPD) Condensate 4,906 3,756 30.6% 4,371 3,417 27.9% volume (BPD) (1) "MCF" represents thousand cubic feet; "MCFD" represents thousand cubic feet per day; "BPD" represents barrels per day (2) Operating data for the Arkoma and WestTX systems and for West Texas LPG Partnership represents 100% of operating activity (3) Processed gas volumes include volumes offloaded and processed by third parties as well as volumes bypassed and delivered as residue gas ^ ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of November 4, 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 4Q13 Sold Propane 16,254,000 1.20 4Q13 Sold Propane - Conway 1,260,000 1.06 4Q13 Sold Normal Butane 1,260,000 1.31 1Q14 Sold Propane 16,758,000 0.98 1Q14 Sold Iso Butane 1,260,000 1.26 1Q14 Sold Normal Butane 2,520,000 1.37 1Q14 Sold Natural Gasoline 1,890,000 2.01 2Q14 Sold Propane 14,490,000 0.95 2Q14 Sold Iso Butane 2,520,000 1.25 2Q14 Sold Normal Butane 2,520,000 1.38 2Q14 Sold Natural Gasoline 3,780,000 1.93 3Q14 Sold Propane 10,836,000 0.98 3Q14 Sold Iso Butane 1,260,000 1.26 3Q14 Sold Normal Butane 1,260,000 1.50 3Q14 Sold Natural Gasoline 3,150,000 1.93 4Q14 Sold Propane 10,836,000 0.99 4Q14 Sold Iso Butane 1,260,000 1.26 4Q14 Sold Normal Butane 1,260,000 1.53 4Q14 Sold Natural Gasoline 3,150,000 1.93 1Q15 Sold Propane 11,844,000 0.97 1Q15 Sold Natural Gasoline 2,142,000 1.91 2Q15 Sold Propane 9,993,690 0.94 2Q15 Sold Natural Gasoline 630,000 1.97 3Q15 Sold Propane 4,788,000 1.00 3Q15 Sold Natural Gasoline 630,000 1.97 4Q15 Sold Propane 6,678,000 0.98 4Q15 Sold Natural Gasoline 630,000 1.97 1Q16 Sold Propane 1,260,000 1.02 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of November 4, 2013) SWAP CONTRACTS CONDENSATE HEDGES Production Period Purchased /Sold Commodity Barrels Avg. Fixed Price 4Q13 Sold Crude Oil 75,000 96.66 1Q14 Sold Crude Oil 93,000 95.45 2Q14 Sold Crude Oil 99,000 93.29 3Q14 Sold Crude Oil 75,000 89.86 4Q14 Sold Crude Oil 45,000 88.16 1Q15 Sold Crude Oil 15,000 85.13 2Q15 Sold Crude Oil 15,000 85.13 3Q15 Sold Crude Oil 15,000 85.13 4Q15 Sold Crude Oil 15,000 85.13 NATURAL GAS HEDGES Production Period Purchased /Sold Commodity MMBTUs Avg. Fixed Price 4Q13 Sold Natural Gas 1,870,000 3.80 1Q14 Sold Natural Gas 1,650,000 3.97 2Q14 Sold Natural Gas 2,650,000 3.89 3Q14 Sold Natural Gas 4,000,000 3.95 4Q14 Sold Natural Gas 4,300,000 4.08 1Q15 Sold Natural Gas 3,865,000 4.30 2Q15 Sold Natural Gas 3,865,000 4.17 3Q15 Sold Natural Gas 3,865,000 4.20 4Q15 Sold Natural Gas 3,565,000 4.27 1Q16 Sold Natural Gas 1,500,000 4.45 2Q16 Sold Natural Gas 750,000 4.36 3Q16 Sold Natural Gas 750,000 4.36 4Q16 Sold Natural Gas 750,000 4.36 ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Unaudited Current Commodity Risk Management Positions (as of November 4, 2013) OPTION CONTRACTS NGL OPTIONS Production Period Purchased/Sold Type Commodity Gallons Avg. Strike Price 4Q13 Purchased Put Normal Butane 3,780,000 1.6613 4Q13 Purchased Put Iso Butane 1,512,000 1.6622 4Q13 Purchased Put Natural 6,552,000 2.0933 Gasoline 1Q14 Purchased Put Iso Butane 1,260,000 1.2225 2Q14 Purchased Put Propane 630,000 0.8880 3Q14 Purchased Put Propane 1,260,000 0.9088 4Q14 Purchased Put Propane 1,260,000 0.9288 1Q15 Purchased Put Propane 630,000 0.9375 3Q15 Purchased Put Propane 1,260,000 0.8825 CRUDE OPTIONS Production Period Purchased/Sold Type Commodity Barrels Avg. Strike Price 4Q13 Purchased Put Crude Oil 75,000 100.1000 1Q14 Purchased Put Crude Oil 181,500 100.9690 2Q14 Purchased Put Crude Oil 60,000 88.9100 3Q14 Purchased Put Crude Oil 90,000 89.9133 4Q14 Purchased Put Crude Oil 117,000 91.5692 1Q15 Purchased Put Crude Oil 45,000 91.3333 2Q15 Purchased Put Crude Oil 75,000 89.4900 3Q15 Purchased Put Crude Oil 75,000 88.5900 4Q15 Purchased Put Crude Oil 75,000 88.1500 NATURAL GAS OPTIONS Production Period Purchased/Sold Type Commodity MMBTUs Avg. Strike Price 2Q 2014 Purchased Put Natural Gas 300,000 4.10 3Q 2014 Purchased Put Natural Gas 300,000 4.15 Contact: Matthew Skelly VP – Investor Relations 1845 Walnut Street Philadelphia, PA 19103 (877) 280-2857 (215) 561-5692 (facsimile) SOURCE Atlas Pipeline Partners, L.P. Website: http://www.atlaspipeline.com
Atlas Pipeline Partners, L.P. Reports Third Quarter 2013 Results
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