Market Snapshot
  • U.S.
  • Europe
  • Asia
Ticker Volume Price Price Delta
DJIA 16,408.54 -16.31 -0.10%
S&P 500 1,864.85 2.54 0.14%
NASDAQ 4,095.52 9.29 0.23%
Ticker Volume Price Price Delta
STOXX 50 3,155.81 16.55 0.53%
FTSE 100 6,625.25 41.08 0.62%
DAX 9,409.71 91.89 0.99%
Ticker Volume Price Price Delta
NIKKEI 14,516.27 98.74 0.68%
TOPIX 1,173.37 6.78 0.58%
HANG SENG 22,760.24 64.23 0.28%

Atlas Pipeline Partners, L.P. Reports Third Quarter 2013 Results



       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
Sponsored Links
Advertisement
Advertisements
Sponsored Links
Advertisement