TARGA RESOURCES CORP. PHILADELPHIA, Nov. 3, 2014 /PRNewswire/ --
-- Adjusted EBITDA for third quarter 2014 was $106.6 million, a 27%
increase year-over-year
-- Distributable Cash Flow for third quarter 2014 was $74.6 million, a 47%
increase year-over-year
-- Previously announced growth of quarterly distribution to $0.64 per
common limited partner unit, at approximately 1.2x coverage
-- Processed gas volumes of approximately 1.57 billion cubic feet per day
(BCFD) in third quarter 2014
-- Partnership expands company-wide processing capacity to approximately
2.0 BCFD with the addition of the Edward, Stonewall and Silver Oak II
plants, servicing increased producer activities
-- Atlas Pipeline Partners, L.P. and its general partner to be acquired by
Targa for a total of approximately $7.7 billion
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 $106.6 million for the third quarter of 2014. Processed natural gas volumes averaged 1,566 million cubic feet per day ("MMCFD"), a 14% increase over the third quarter of 2013. Distributable Cash Flow was $74.6 million for the third quarter of 2014, or $0.90 per average common limited partner unit, compared to $50.6 million for the prior year's third quarter, a 47% increase year-over-year. The Partnership recognized net income of $49.4 million for the third quarter of 2014, compared to net loss of $25.6 million for the prior year's third quarter. Net income was higher for third quarter 2014 compared to the prior year's third quarter, mainly due to a $23.0 million increase in gross margin driven by 14% processed volume growth across all of the Partnership's operating areas and a $48.7 million increase in the valuation of the Partnership's risk management portfolio. 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 release. The Partnership believes these non-GAAP measures provide a more accurate comparison of the operating results for the periods presented.
On October 13, 2014, the Partnership announced that it has entered into a definitive agreement to be acquired by Targa Resources Partners L.P. (NYSE: NGLS) in a transaction valuing the Partnership at $7.7 billion, including debt and an approximate $1.9 billion acquisition of its general partner interests by Targa Resources Corp. (NYSE: TRGP). The Partnership's common limited unitholders will receive 0.5846 units of Targa Resources Partners L.P. (NYSE: NGLS) and $1.26 in cash for each outstanding Partnership common unit. The transaction is expected to close during the first quarter of 2015 and is subject to customary closing conditions, as well as approval by the unitholders of the Partnership.
On October 28, 2014, the Partnership declared a cash distribution for the third quarter of 2014 of $0.64 per common limited partner unit to holders of record on November 10, 2014, which will be paid on November 14, 2014. This distribution represents Distributable Cash Flow coverage per limited partner unit of approximately 1.2x for the third quarter of 2014.
Eugene Dubay, Chief Executive Officer of the Partnership, commented, "As you can see from the quarterly results, we remain on track with our goals and ambitions. Distributions have increased, distribution coverage has increased, leverage has decreased, and we have successfully brought into service three new plants this year that increases the processing capacity at APL by approximately 35% to 2.0 billion cubic feet per day. As we have executed this year, our growing organic footprint and enviable customer base have been noticed throughout the mid-continent and on October 13(th) it was announced that Atlas Pipeline and its general partner are expected to be acquired by Targa at a transaction valued at $7.7 billion dollars. Until the transaction is finalized, which is expected sometime in the first quarter of 2015 if approved, we will continue to execute for our stakeholders and our producer customers can expect the same exceptional service going forward."
Capitalization and Liquidity
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $603.3 million as of September 30, 2014. Total debt outstanding was $1,754.4 million at September 30, 2014, compared to $1,707.3 million at December 31, 2013, an increase of $47.1 million. On August 28, 2014, the Partnership entered into an amended and restated credit agreement with its lending group, which, among other things, increased the commitment from $600.0 million to $800.0 million, extended the term to August 2019 and lowered borrowing costs. Based upon total debt outstanding at September 30, 2014, total leverage was approximately 4.1x for purposes of calculations under our revolving credit facility, and debt to total capital was 42%.
Risk Management
The Partnership continues to add further protection to its risk management portfolio for forecasted production in 2014 through 2017. As of November 3, 2014, the Partnership had natural gas, natural gas liquids and condensate protection in place for the remainder of 2014, 2015 and 2016 for approximately 68%, 53%, and 20%, respectively, of associated margin value (exclusive of ethane). The Partnership had protection in place for approximately 68% of its equity natural gas production over the next two quarters with an average price of $4.22 per million British thermal units ("MMBtu"). Natural gas liquids were approximately 63% protected (exclusive of ethane), with propane and natural gasoline each approximately 75% protected for the next two quarters. The Partnership's condensate production is 79% protected for the next two quarters. 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 November 3, 2014 is included in this release.
Operating Results
Gathered volumes for the three months ended September 30, 2014 were approximately 1.68 BCFD and processed volumes were approximately 1.57 BCFD, an increase of approximately 13% and 14%, respectively, compared to the Partnership's third quarter 2013 results. Growth capital spending, including contributions to joint ventures, was $191.4 million during the third quarter of 2014, as organic expansion projects continue across all gathering and processing systems, including the completion of two, 200 MMCFD cryogenic processing facilities, the Edward and Silver Oak II plants, during the quarter, and the continued construction of the 200 MMCFD Buffalo plant in WestTX, as well as multiple gathering pipeline projects, including the pipeline connecting the Velma and Arkoma portions of the SouthOK system.
Gross margin from operations was $137.8 million for the third quarter 2014, compared to $114.8 million for the prior year period. The 20% higher gross margin for the quarter was primarily due to increased producer activity in APL's areas of operation and gathering and/or processing expansions that have been completed on each of the Partnership's systems. 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 gross margin for the quarter does not include approximately $2.5 million of realized derivative settlement losses, which are excluded in the calculation of gross margin, compared to $0.9 million realized derivative settlement losses excluded from gross margin in the third quarter of 2013.
WestTX System
The WestTX system's average natural gas processed volume was 473.6 MMCFD for the third quarter of 2014, compared to 355.2 MMCFD for the third quarter of 2013, an increase of 33% over the past year. Average natural gas liquids (NGL) production was 62,086 barrels per day ("BPD") for the third quarter of 2014, a 30% increase over the third quarter of 2013. Increased processed volumes are primarily due to continued drilling activity in the Permian Basin, supported by the completion of the Edward plant on September 15, 2014. This system continues to operate in partial ethane rejection due to the value of ethane compared to the value of residue natural gas.
The completion of the Edward plant increased the name-plate processing capacity on the WestTX system to 655 MMCFD. The Edward plant is currently utilizing 87% of its available capacity as the Partnership optimizes its system for efficiencies. The previously announced Buffalo plant, another 200 MMCFD cryogenic processing plant under construction in WestTX, will be located in the northern part of the system and is expected to be completed in the third quarter of 2015. This facility will increase 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 545.3 MMCFD for the third quarter of 2014, a 14% increase from the third quarter of 2013. Average NGL production was 26,223 BPD for the third quarter of 2014, a 22% increase from the third quarter of 2013, due to the continued increased production on the gathering system.
The Partnership continues to add capital projects in the Mississippi Lime to accommodate growing development from its producer customers, 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 409.5 MMCFD for the third quarter 2014, a 3% increase from third quarter 2013. The increase in processed volumes is primarily due to the start-up of the previously announced Stonewall plant in the second quarter of 2014, which increased processing capacity by 120 MMCFD. Average NGL production was 28,298 BPD for the third quarter 2014, a decrease of approximately 14% compared to the third quarter 2013, as ethane rejection capabilities have been enhanced. 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 NGLs produced, however enhancing profits.
The Stonewall plant, a new cryogenic processing facility, was brought into operation on May 1, 2014 and was constructed under the Centrahoma joint venture, which is a joint venture with MarkWest Energy Partners, of which APL owns a 60% interest. 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 in early 2015. Additionally, construction is continuing on the project to connect the Velma and Arkoma portions of the SouthOK system, which is expected be complete in November 2014.
SouthTX System
The SouthTX system recognized revenues on average natural gas processed volumes of 137.6 MMCFD for the third quarter 2014 an 11% increase over 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, and APL 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.
Corporate and Other
General and administrative costs for the third quarter of 2014, excluding non-cash compensation, totaled $11.7 million, compared to $11.9 million in the same period in 2013. Net of deferred financing costs, interest expense was $20.8 million for the third quarter of 2014, as compared to $22.5 million in the third quarter of 2013.
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership's third quarter 2014 results on Tuesday, November 4, 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 3:00 pm ET on Tuesday, November 4, 2014. To access the replay, dial 1-888-286-8010 and enter conference code 29166064.
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 17 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.
Where to Obtain Additional Information
In connection with the proposed merger referenced herein, Targa Resources Corp. ("TRC") will file with the U.S. Securities and Exchange Commission (the "SEC") a registration statement on Form S-4 that will include a joint proxy statement of Atlas Energy, L.P. ("ATLS") and TRC and a prospectus of TRC (the "TRC joint proxy statement/prospectus"). TRC plans to mail the definitive TRC joint proxy statement/prospectus to its shareholders and ATLS plans to mail the definitive TRC joint proxy statement/prospectus to its unitholders. Also in connection with the proposed merger, Targa Resources Partners LP ("TRP") will file with the SEC a registration statement on Form S-4 that will include a proxy statement of Atlas Pipeline Partners, L.P. ("APL") and a prospectus of TRP (the "TRP proxy statement/prospectus") . APL plans to mail the definitive TRP proxy statement/prospectus to its unitholders.
INVESTORS, SHAREHOLDERS AND UNITHOLDERS ARE URGED TO READ THE TRC JOINT PROXY STATEMENT/PROSPECTUS, THE TRP PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT TRC, TRP, ATLS AND APL, AS WELL AS THE PROPOSED TRANSACTION AND RELATED MATTERS.
This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval.
A free copy of the TRC Joint Proxy Statement/Prospectus, the TRP Proxy Statement/Prospectus and other filings containing information about TRC, TRP, ATLS and APL may be obtained at the SEC's Internet site at www.sec.gov. In addition, the documents filed with the SEC by TRC and TRP may be obtained free of charge by directing such request to: Targa Resources, Attention: Investor Relations, 1000 Louisiana, Suite 4300, Houston, Texas 77002, calling (713) 584-1000 or emailing jkneale@targaresources.com. These documents may also be obtained for free from TRC's and TRP's investor relations website at www.targaresources.com. The documents filed with the SEC by ATLS may be obtained free of charge by directing such request to: Atlas Energy, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia, Pennsylvania 19103 or emailing InvestorRelations@atlasenergy.com. These documents may also be obtained for free from ATLS's investor relations website at www.atlasenergy.com. The documents filed with the SEC by APL may be obtained free of charge by directing such request to: Atlas Pipeline Partners, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia, Pennsylvania 19103 or emailing IR@atlaspipeline.com. These documents may also be obtained for free from APL's investor relations website at www.atlaspipeline.com.
Participants in Solicitation Relating to the Merger
TRC, TRP, ATLS and APL and their respective directors, executive officers and other persons may be deemed to be participants in the solicitation of proxies from TRC, ATLS or APL shareholders or unitholders, as applicable, in respect of the proposed transaction that will be described in the TRC joint proxy statement/prospectus and TRP proxy statement/prospectus. Information regarding TRC's directors and executive officers is contained in TRC's definitive proxy statement dated April 7, 2014, which has been filed with the SEC. Information regarding directors and executive officers of TRP's general partner is contained in TRP's Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with the SEC. Information regarding directors and executive officers of ATLS's general partner is contained in ATLS's definitive proxy statement dated March 21, 2014, which has been filed with the SEC. Information regarding directors and executive officers of APL's general partner is contained in APL's Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with the SEC.
A more complete description will be available in the registration statement and the proxy statement/prospectus.
Contact: Matthew Skelly
VP - Investor Relations
1845 Walnut Street
Philadelphia, PA 19103
(877) 280-2857
(215) 561-5692 (facsimile)
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,
------------- -------------
2014 2013 2014 2013
---- ---- ---- ----
Revenue:
Natural gas and liquids sales $673,888 $535,719 $2,004,567 $1,410,797
Transportation, processing and other fees(2) 49,578 43,725 143,058 116,756
Derivative gain (loss), net 24,155 (24,517) 9,117 (9,493)
Other income, net 13,561 2,943 18,400 8,661
------ ----- ------ -----
Total revenues 761,182 557,870 2,175,142 1,526,721
------- ------- --------- ---------
Costs and expenses:
Natural gas and liquids cost of sales 586,448 463,564 1,742,801 1,213,320
Operating expenses 29,837 24,806 81,948 71,435
General and administrative 11,698 11,889 35,172 30,413
General and administrative - non-cash unit-based compensation(3) 6,376 5,998 19,258 13,818
Other costs (1) 685 16 19,585
Depreciation and amortization 50,173 51,080 148,632 127,921
Interest 22,553 24,347 69,275 65,614
------ ------ ------ ------
Total costs and expenses 707,084 582,369 2,097,102 1,542,106
-------
Equity loss in joint ventures (4,711) (1,882) (10,464) (314)
Loss on early extinguishment of debt - - - (26,601)
Gain (loss) on asset dispositions (636) - 47,829 (1,519)
Income (loss) before income taxes 48,751 (26,381) 115,405 (43,819)
Income tax benefit (623) (817) (1,519) (854)
Net income (loss) 49,374 (25,564) 116,924 (42,965)
Income attributable to non-controlling interests (4,029) (1,514) (10,456) (4,693)
Preferred unit dividends (2,609) - (5,624) -
Preferred unit imputed dividend effect (11,378) (11,378) (34,134) (18,107)
Preferred unit dividends in kind (11,408) (9,072) (31,533) (14,413)
------- ------ ------- -------
Net income (loss) attributable to common limited partners and the General Partner $19,950 $(47,528) $35,177 $(80,178)
======= ======== ======= ========
Net income (loss) attributable to common limited partners per unit:
Basic and diluted $0.13 $(0.66) $0.18 $(1.25)
Weighted average common limited partner units (basic) 82,892 78,398 81,497 72,512
Weighted average common limited partner units (diluted) 99,368 78,398 97,465 72,512
(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,
------------- -------------
2014 2013 2014 2013
---- ---- ---- ----
Summary Cash Flow Data:
Cash provided by operating activities $94,252 $79,400 $234,161 $151,121
Cash used in investing activities (199,677) (121,905) (350,089) (1,338,149)
Cash provided by financing activities 108,087 31,863 117,750 1,194,069
Capital Expenditure Data:
Maintenance capital expenditures $7,417 $6,416 $18,297 $14,119
Expansion capital expenditures 185,151 105,736 454,850 313,742
Acquisitions ? ? ? 1,000,785
--- --- --- ---------
Total $192,568 $112,152 $473,147 $1,328,646
======== ======== ======== ==========
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited; in thousands)
ASSETS September 30, December 31,
2013
2014
----
Current assets:
Cash and cash equivalents $6,736 $4,914
Other current assets 286,275 236,864
Total current assets 293,011 241,778
Property, plant and
equipment, net 3,132,810 2,724,192
Intangible assets, net 980,580 1,064,843
Equity method investment
in joint ventures 180,602 248,301
Other assets, net 51,409 48,731
$4,638,412 $4,327,845
========== ==========
LIABILITIES AND EQUITY
Current liabilities $378,657 $320,226
Long-term debt, less
current portion 1,754,093 1,706,786
Deferred income taxes, net 31,771 33,290
Other long-term
liabilities 6,960 7,638
Total partners' capital 2,390,668 2,200,645
Non-controlling interest 76,263 59,260
------ ------
Total equity 2,466,931 2,259,905
$4,638,412 $4,327,845
========== ==========
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,
------------- -------------
2014 2013 2014 2013
---- ---- ---- ----
Gross margin calculations:
Natural gas and liquids sales $673,888 $535,719 $2,004,567 $1,410,797
Transportation, processing, and other fees 49,578 43,725 143,058 116,756
Less: non-cash linefill gain (loss) (811) 1,039 (717) (332)
Less: natural gas and liquids cost of sales 586,448 463,564 1,742,801 1,213,320
------- ------- --------- ---------
Gross margin $137,829 $114,841 $405,541 $314,565
-------- -------- -------- --------
Reconciliation of net income (loss) to other non-GAAP measures(1):
Net income (loss) $49,374 $(25,564) $116,924 $(42,965)
Depreciation and amortization 50,173 51,080 148,632 127,921
Income tax benefit (623) (817) (1,519) (854)
Interest expense 22,553 24,347 69,275 65,614
------ ------ ------ ------
EBITDA 121,477 49,046 333,312 149,716
Income attributable to non-controlling interests(2) (4,029) (1,514) (10,456) (4,693)
Non-controlling interest depreciation, amortization and interest(3) (1,018) (917) (2,630) (2,888)
Adjustment for cash flow from investment in joint ventures 5,775 3,682 15,728 5,714
(Gain) loss on asset disposition 636 ? (47,829) 1,519
Non-cash (gain) loss on derivatives (26,684) 23,610 (28,100) 13,066
Other costs (1) 685 16 19,585
Premium expense on derivative instruments 1,311 4,824 4,826 11,844
Unrecognized economic impact of acquisitions ? 42 ? 1,168
Loss on early termination of debt ? ? ? 26,601
Other non-cash losses(4) 9,122 4,743 25,413 16,587
Adjusted EBITDA 106,589 84,201 290,280 238,219
Interest expense (22,553) (24,347) (69,275) (65,614)
Amortization of deferred finance costs 1,772 1,836 5,502 5,119
Preferred dividend obligation (2,609) ? (5,624) ?
Premium expense on derivative instruments (1,311) (4,824) (4,826) (11,844)
Maintenance capital expenditures(5) (7,277) (6,232) (17,815) (13,759)
------ ------ ------- -------
Distributable Cash Flow $74,611 $50,634 $198,242 $152,121
======= ======= ======== ========
(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 $140
thousand and $184 thousand for
the three months ended September
30, 2014 and 2013, respectively,
and $482 thousand and $360
thousand for the nine months
ended September 30, 2014 and
2013, respectively.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2014 2013 Percent Change 2014 2013 Percent Change
---- ---- -------------- ---- ---- --------------
Pricing (unhedged):
Weighted average market prices:
NGL price per gallon - Conway hub $0.80 0.81 (1.2)% 0.89 0.80 11.3%
NGL price per gallon - Mt. Belvieu hub 0.82 0.85 (3.5)% 0.89 0.83 7.2%
Natural gas sales ($/MMBTU):
SouthOK 3.80 3.37 12.8% 4.23 3.47 21.9%
SouthTX 4.02 N/A N/A 4.29 N/A N/A
WestOK 3.70 3.30 12.1% 4.17 3.45 20.9%
WestTX 3.80 3.32 14.5% 4.21 3.40 23.8%
Weighted average 3.75 3.34 12.3% 4.19 3.46 21.1%
NGL sales ($/gallon):
SouthOK 1.03 0.87 18.4% 1.03 0.74 39.2%
SouthTX 0.82 0.75 9.3% 0.90 0.73 23.3%
WestOK 1.08 1.08 0.0% 1.12 1.01 10.9%
WestTX 0.92 0.92 0.0% 0.94 0.90 4.4%
Weighted average 0.98 0.92 6.5% 1.01 0.87 16.1%
Condensate sales ($/barrel):
SouthOK 91.10 103.45 (11.9)% 92.43 94.53 (2.2)%
SouthTX 83.43 92.94 (10.2)% 85.79 91.05 (5.8)%
WestOK 91.49 96.86 (5.5)% 91.41 88.10 3.8 %
WestTX 88.41 106.27 (16.8)% 92.91 98.78 (5.9)%
Weighted average 90.09 101.48 (11.2)% 91.78 92.82 (1.1)%
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2014 2013 Percent Change 2014 2013 Percent Change
---- ---- -------------- ---- ---- --------------
Volumes:
SouthOK system(2):
Gathered gas volume (MCFD) 435,018 423,322 2.8% 422,800 412,715 2.4%
Processed gas volume(3) (MCFD) 409,452 397,358 3.0% 397,041 385,854 2.9%
Residue gas volume (MCFD) 376,350 338,369 11.2% 363,508 322,804 12.6%
Processed NGL volume (BPD) 28,298 32,951 (14.1)% 28,638 36,425 (21.4)%
Condensate volume (BPD) 530 441 20.2% 639 513 24.6%
WestOK system:
Gathered gas volume (MCFD) 573,957 505,222 13.6% 553,434 488,219 13.4%
Processed gas volume(3) (MCFD) 545,301 479,270 13.8% 528,768 462,932 14.2%
Residue gas volume (MCFD) 498,451 442,304 12.7% 484,762 428,056 13.2%
Processed NGL volume (BPD) 26,223 21,522 21.8% 24,315 20,021 21.4%
Condensate volume (BPD) 2,533 1,759 44.0% 2,374 1,892 25.5%
SouthTX system(4):
Gathered gas volume (MCFD) 137,918 141,282 (2.4)% 127,978 131,815 (2.9)%
Processed gas volume(3) (MCFD) 137,573 140,557 (2.1)% 125,844 131,000 (3.9)%
Residue gas volume (MCFD) 106,332 114,287 (7.0)% 92,399 105,495 (12.4)%
Processed NGL volume (BPD) 16,336 17,990 (9.2)% 14,020 16,524 (15.2)%
Condensate volume (BPD) 191 108 76.9% 170 85 100%
WestTX system(2):
Gathered gas volume (MCFD) 508,010 383,466 32.5% 459,348 349,894 31.3%
Processed gas volume(3) (MCFD) 473,644 355,203 33.3% 434,675 316,760 37.2%
Residue gas volume (MCFD) 348,921 265,648 31.3% 321,510 235,310 36.6%
Processed NGL volume (BPD) 62,086 47,663 30.3% 56,215 40,322 39.4%
Condensate volume (BPD) 2,490 2,598 (4.2)% 1,972 1,881 4.8%
Other systems:
Gathered gas volumes (MCFD) 27,703 30,779 (10.0)% 28,322 29,973 (5.5)%
Consolidated Volumes:
Gathered gas volume (MCFD) 1,682,606 1,484,071 13.1% 1,591,822 1,412,616 11.9%
Processed gas volume (MCFD) 1,565,970 1,372,388 13.8% 1,486,328 1,296,546 13.7%
Residue gas volume (MCFD) 1,330,054 1,160,608 14.6% 1,262,179 1,091,665 15.6%
Processed NGL volume (BPD) 132,943 120,126 10.7% 123,188 113,292 8.7%
Condensate volume (BPD) 5,744 4,906 17.1% 5,155 4,371 17.9%
(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 134,064 MCFD and 133,719 MCFD, respectively, during the
three months ended September 30, 2014, and 116,315 MCFD and 114,180 MCFD, respectively, during the nine months ended September 30, 2014
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of November 3, 2014)
SWAP CONTRACTS
NATURAL GAS LIQUIDS
-------------------
Production Purchased / Commodity Gallons Avg. Fixed
Period Sold Price
------ ---- -----
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 13,860,000 1.05
3Q15 Sold Natural Gasoline 3,780,000 2.00
4Q15 Sold Propane 13,608,000 1.03
4Q15 Sold Natural Gasoline 1,260,000 2.00
1Q16 Sold Propane 9,450,000 1.03
2Q16 Sold Propane 7,560,000 1.03
3Q16 Sold Propane 8,820,000 1.03
4Q16 Sold Propane 8,820,000 1.03
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
CONDENSATE
----------
Production Purchased / Commodity Barrels Avg. Fixed
Period Sold Price
------ ---- -----
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
-----------
Production Purchased / Commodity MMBTUs Avg. Fixed
Period Sold Price
------ ---- -----
4Q14 Sold Natural Gas 5,350,000 4.15
1Q15 Sold Natural Gas 6,865,000 4.27
2Q15 Sold Natural Gas 5,215,000 4.04
3Q15 Sold Natural Gas 5,215,000 4.05
4Q15 Sold Natural Gas 4,915,000 4.10
1Q16 Sold Natural Gas 4,350,000 4.01
2Q16 Sold Natural Gas 2,250,000 3.65
3Q16 Sold Natural Gas 2,250,000 3.65
4Q16 Sold Natural Gas 2,850,000 3.75
1Q17 Sold Natural Gas 2,400,000 4.44
2Q17 Sold Natural Gas 600,000 4.46
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions
(as of November 3, 2014)
OPTION CONTRACTS
NATURAL GAS LIQUIDS
-------------------
Production Purchased/ Type Commodity Gallons Avg. Strike
Period Sold Price
------ ---- -----
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
CONDENSATE
----------
Production Purchased/ Type Commodity Barrels Avg. Strike
Period Sold Price
------ ---- -----
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
SOURCE Atlas Pipeline Partners, L.P.
