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APL > SEC Filings for APL > Form 10-Q on 5-Nov-2012All Recent SEC Filings

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Form 10-Q for ATLAS PIPELINE PARTNERS LP


5-Nov-2012

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption "Risk Factors", in our Annual Report on Form 10-K for the year ended December 31, 2011. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report and with our Annual Report on Form 10-K for the year ended December 31, 2011.

Overview

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol "APL." We are a leading provider of natural gas gathering and processing services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwestern region of the United States.

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Gathering and Processing; and Pipeline Transportation.

The Gathering and Processing segment consists of (1) the WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins; (2) the natural gas gathering assets located in Tennessee; and (3) the revenues and gain on sale related to our former 49% interest in Laurel Mountain. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and gathering and processing of natural gas.

Our Gathering and Processing operations, own, have interests in and operate nine natural gas processing plants with aggregate capacity of approximately 870 MMCFD, which are connected to approximately 9,600 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas. In addition, we own and operate approximately 100 miles of active natural gas gathering systems located in Tennessee. Our gathering systems gather gas from wells and central delivery points and deliver to natural gas processing plants, as well as third-party pipelines.

Our Pipeline Transportation operations consist of a 20% interest in West Texas LPG Pipeline Limited Partnership ("WTLPG"), which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation ("Chevron" - NYSE: CVX), which owns the remaining 80% interest.


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Recent Events

In February 2012, we acquired a gas gathering system and related assets, within our WestOK system, for an initial net purchase price of $19.0 million. We agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. In connection with this acquisition, we received assignment of gas purchase agreements for gas currently gathered on the acquired system. We accounted for the acquisition as a business combination.

On May 31, 2012, we entered into an amendment to the revolving credit facility agreement, which among other changes: (1) increased the revolving credit facility from $450.0 million to $600.0 million; (2) extended the maturity date from December 22, 2015 to May 31, 2017; (3) reduced the Applicable Margin used to determine interest rates by 0.50%; (4) revised the negative covenants to
(i) permit investments in joint ventures equal to the greater of 20% of Consolidated Net Tangible Assets (as defined in the Credit Agreement) or $340 million, provided we meet certain requirements, and (ii) increased the general investment basket to 5% of Consolidated Net Tangible Assets; (5) revised the definition of "Consolidated EBITDA" to provide for the inclusion of the first twelve months of projected revenues for identified capital expansion projects, upon completion of the projects; and (6) provided for the option of additional revolving credit commitments of up to $200.0 million.

In June 2012, we completed construction of, and started processing through, a 60 MMCFD cryogenic facility at the Velma gas plant, increasing capacity at Velma to 160 MMCFD. This expansion supports our long-term fee-based agreement with XTO Energy, Inc., a subsidiary of ExxonMobil, to provide natural gas gathering and processing services for up to an incremental 60 MMCFD from the Woodford Shale.

In June 2012, we acquired a gas gathering system and related assets in the Barnett Shale play in Tarrant County, Texas for an initial net purchase price of $18.0 million. We accounted for the acquisition as a business combination. The system consists of 19 miles of gathering pipeline that is used to facilitate gathering some of the newly acquired production for our affiliate, Atlas Resources Partners, L.P. ("ARP"). ARP's general partner is wholly-owned by ATLS, and two members of our General Partner's managing board are members of ARP's board of directors. By virtue of the acquisition we became party to a management and operating services agreement (which had been negotiated and was in existence between unaffiliated third parties prior to the acquisition), whereby ARP now operates the gathering system on our behalf and we will pay them annual management and operating fees of approximately $325 thousand to cover ARP's cost of services.

In August 2012, we filed a registration statement describing our intention to enter into an equity distribution program with Citigroup Global Markets, Inc. ("Citigroup"). Pursuant to this program, we may offer and sell from time to time through Citigroup, common units having an aggregate value of up to $150.0 million. Citigroup will not be required to sell any specific number or dollar amount of the common units, but will use its reasonable efforts, consistent with its normal trading and sales practices, to sell such units. Such sales will be at market prices prevailing at the time of the sale. We intend to use the net proceeds from any such offering for general partnership purposes. As of September 30, 2012, the equity distribution agreement had not been signed and no common units have been offered or sold under the registration statement. We will file a prospectus supplement upon the execution of the equity distribution agreement.


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In September 2012, we issued $325.0 million of 6.625% senior unsecured notes due on October 1, 2020 ("6.625% Senior Notes") in a private placement transaction. We received net proceeds of $319.1 million and utilized the proceeds to reduce the outstanding balance on our revolving credit facility (see Senior Notes).

In September 2012, we completed construction of, and started processing through, a 200 MMCFD cryogenic processing plant, referred to as the Waynoka II plant, on our WestOK gathering and processing system. This expansion brings the total nameplate processing capacity in the WestOK system to 458 MMCFD.

How We Evaluate Our Operations

Our principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Our profitability is a function of the difference between the revenues we receive and the costs associated with conducting our operations, including the cost of natural gas and NGLs we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Variables that affect our profitability are:

the volumes of natural gas we gather and process, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas the wells produce, and the demand for natural gas, NGLs and condensate;

the price of the natural gas we gather and process and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

the NGL and BTU content of the gas gathered and processed;

the contract terms with each producer; and

the efficiency of our gathering systems and processing plants.

Revenue consists of the sale of natural gas and NGLs and the fees earned from our gathering and processing operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems and then sell the natural gas and NGLs off delivery points on our systems. Under other agreements, we gather natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. (See "Item
1. Notes to Consolidated Financial Statements (Unaudited) - Note 2 - Revenue Recognition" for further discussion of contractual revenue arrangements).

Our management uses a variety of financial measures and operational measurements other than our GAAP financial statements to analyze our performance. These include: (1) volumes, (2) operating expenses and (3) the following non-GAAP measures - gross margin, adjusted EBITDA and distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

Volumes. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering


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and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production. Our performance at our plants is also significantly impacted by the quality of the natural gas we process, the NGL content of the natural gas and the plant's recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations.

Operating Expenses. Plant operating, transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, ad valorem taxes and other overhead costs.

Gross Margins. We define gross margin as natural gas and liquids sales plus transportation, compression and other fees less purchased product costs, subject to certain non-cash adjustments. Product costs include the cost of natural gas and NGLs we purchase from third parties. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories.

Gross margin is a non-GAAP measure. The GAAP measure most directly comparable to gross margin is net income. Gross margin is not an alternative to GAAP net income and has important limitations as an analytical tool. Investors should not consider gross margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of gross margin may not be comparable to gross margin measures of other companies, thereby diminishing its utility.

EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as non-recurring cash derivative early termination expense. The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation utilized within our financial covenants under our credit facility, with the exception that Adjusted EBITDA includes certain non-cash items specifically excluded under our credit facility and excludes the capital expansion add back included in Consolidated EBITDA as defined in the credit facility (see " - Revolving Credit Facility").

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as indicators of our operating performance or liquidity. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. We define distributable cash flow as net income plus depreciation and amortization; amortization of deferred financing costs included in interest expense; and non-cash gain (losses) on derivative contracts, less income attributable to non-controlling interests, preferred unit dividends, maintenance capital expenditures, gain (losses) on asset sales and other non-cash gain (losses).


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Distributable cash flow is a significant performance metric used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can compute the ratio of distributable cash flow per unit to the declared cash distribution per unit to determine the rate at which the distributable cash flow covers the distribution. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income or GAAP cash flows from operating activities. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.


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Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measurements used by management to their most directly comparable GAAP measures for the three and nine months ended September 30, 2012 and 2011 (in thousands):

                         RECONCILIATION OF GROSS MARGIN



                                              Three Months Ended              Nine Months Ended
                                                September 30,                   September 30,
                                             2012          2011(1)          2012           2011(1)

Net income (loss)                          $ (6,356 )     $  50,258       $  74,966       $  300,651
Derivative (gain) loss, net(1)               18,907         (23,760 )       (36,905 )         (8,952 )
Other income, net(1)                         (2,585 )        (2,831 )        (7,588 )         (8,365 )
Operating expenses(2)                        15,700          14,353          44,657           40,843
General and administrative expense(3)        12,123           9,149          32,513           26,821
Other costs                                    (108 )             8            (303 )            583
Depreciation and amortization                23,161          19,471          65,715           57,499
Interest                                      9,692           5,935          27,669           24,525
Equity income in joint ventures              (1,422 )        (1,785 )        (4,235 )         (2,934 )
Gain on asset sale(4)                            -               -               -          (255,593 )
Loss on early extinguishment of debt             -               -               -            19,574
Non-cash linefill (gain) loss(5)               (375 )           422           2,120              665


Gross margin                               $ 68,737       $  71,220       $ 198,609       $  195,317

(1) Adjusted to separately present derivative gain (loss), net instead of combining these amounts in other income, net.

(2) Operating expenses include plant operating expenses; and transportation and compression expenses.

(3) General and administrative includes compensation reimbursement to affiliates.

(4) Represents the gain on sale of Laurel Mountain and an adjustment to the gain on the sale of Elk City system.

(5) Represents the non-cash impact of commodity price movements on pipeline linefill.


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     RECONCILIATION OF EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW



                                              Three Months Ended              Nine Months Ended
                                                September 30,                   September 30,
                                             2012           2011            2012             2011

Net income                                 $ (6,356 )     $  50,258       $  74,966       $  300,651
Income attributable to non-controlling
interests(1)                                 (1,511 )        (1,760 )        (4,108 )         (4,492 )
Interest expense                              9,692           5,935          27,669           24,525
Depreciation and amortization                23,161          19,471          65,715           57,499


EBITDA                                       24,986          73,904         164,242          378,183
Equity income in joint ventures              (1,422 )        (1,785 )        (4,235 )         (2,934 )
Distributions from joint ventures             1,800             784           5,400            2,548
Gain on asset sale(2)                            -               -               -          (255,593 )
Loss on early extinguishment of debt             -               -               -            19,574
Non-cash (gain) loss on derivatives(3)       22,477         (27,049 )       (31,568 )        (22,477 )
Premium expense on derivative
instruments                                   4,855           2,599          12,591            9,314
Non-cash compensation                         3,620             828           7,538            2,507
Non-cash line fill (gain) loss(4)              (375 )           422           2,120              665


Adjusted EBITDA                              55,941          49,703         156,088          131,787
Interest expense                             (9,692 )        (5,935 )       (27,669 )        (24,525 )
Amortization of deferred finance costs        1,061           1,053           3,356            3,354
Preferred dividend obligation                    -               -               -              (389 )
Proceeds remaining from asset sale(5)            -               -               -             5,850
Premium expense on derivative
instruments                                  (4,855 )        (2,599 )       (12,591 )         (9,314 )
Other costs                                    (108 )             8            (303 )            583
Maintenance capital                          (4,732 )        (4,980 )       (13,242 )        (13,451 )


Distributable Cash Flow                    $ 37,615       $  37,250       $ 105,639       $   93,895

(1) Represents Anadarko's non-controlling interest in the operating results of the WestOK and WestTX systems.

(2) Represents the gain on sale of Laurel Mountain and an adjustment to the gain on sale of our Elk City system.

(3) Represents non-cash derivative (gains) losses as a result of the mark-to-market revaluation recognized on open derivative contracts, which have not yet been settled and the non-cash recognition of previously settled contracts reclassified from accumulated other comprehensive loss into natural gas and liquids sales

(4) Represents the non-cash impact of commodity price movements on pipeline linefill.

(5) Net proceeds remaining from the sale of Laurel Mountain after repayment of the amount outstanding on our revolving credit facility, redemption of our 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018.


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Results of Operations

The following table illustrates selected pricing before the effect of
derivatives and volumetric information for the periods indicated:



                                              Three Months Ended September 30,                 Nine Months Ended September 30,
                                                                           Percent                                         Percent
                                             2012              2011         Change            2012             2011         Change
Pricing:
Weighted Average Market Prices:
NGL price per gallon - Conway hub        $       0.70       $     1.13        (38.1 )%    $       0.78       $    1.11        (29.7 )%
NGL price per gallon - Mt. Belvieu hub           0.86             1.36        (36.8 )%            0.99            1.30        (23.8 )%
Natural gas sales ($/Mcf):
Velma                                            2.64             4.02        (34.3 )%            2.41            4.04        (40.3 )%
WestOK                                           2.62             4.04        (35.1 )%            2.43            4.05        (40.0 )%
WestTX                                           2.54             4.05        (37.3 )%            2.32            4.04        (42.6 )%
Weighted Average                                 2.60             4.04        (35.6 )%            2.39            4.04        (40.8 )%
NGL sales ($/gallon):
Velma                                            0.73             1.16        (37.1 )%            0.79            1.12        (29.5 )%
WestOK                                           0.86             1.17        (26.5 )%            0.86            1.13        (23.9 )%
WestTX                                           0.96             1.42        (32.4 )%            1.01            1.32        (23.5 )%
Weighted Average                                 0.87             1.27        (31.5 )%            0.90            1.21        (25.6 )%
Condensate sales ($/barrel):
Velma                                           91.40            88.54          3.2 %            96.93           94.39          2.7 %
WestOK                                          82.06            81.23          1.0 %            87.29           86.75          0.6 %
WestTX                                          90.41            87.68          3.1 %            90.81           92.77         (2.1 )%
Weighted Average                                86.65            85.77          1.0 %            90.07           90.91         (0.9 )%

Operating data:
Velma system:
Gathered gas volume (MCFD)                    136,939          111,777         22.5 %          134,248         101,593         32.1 %
Processed gas volume (MCFD)                   133,166          104,930         26.9 %          128,398          95,643         34.2 %
Residue gas volume (MCFD)                     108,609           87,099         24.7 %          105,135          78,462         34.0 %
NGL volume (BPD)                               14,866           12,198         21.9 %           14,306          11,219         27.5 %
Condensate volume (BPD)                           283              346        (18.2 )%             427             439         (2.7 )%
WestOK system:
Gathered gas volume (MCFD)                    403,304          277,794         45.2 %          346,318         260,863         32.8 %
Processed gas volume (MCFD)                   380,113          263,654         44.2 %          326,337         247,259         32.0 %
Residue gas volume (MCFD)                     360,688          242,744         48.6 %          302,486         224,158         34.9 %
NGL volume (BPD)                               12,998           13,392         (2.9 )%          13,810          13,395          3.1 %
Condensate volume (BPD)                         1,341              786         70.6 %            1,318             842         56.5 %
WestTX system(1):
. . .
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