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APL > SEC Filings for APL > Form 10-Q on 6-May-2013All Recent SEC Filings

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Form 10-Q for ATLAS PIPELINE PARTNERS LP


6-May-2013

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, 2012. 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, 2012.

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, processing and treating services in the Anadarko, Arkoma 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 Transportation and Treating.

The Gathering and Processing segment consists of (1) the Arkoma, WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko, Arkoma and Permian Basins; and (2) natural gas gathering assets located in the Barnett Shale play in Texas and the Appalachian Basin in Tennessee. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas.

As of March 31, 2013, our Gathering and Processing operations, own, have interests in and operate twelve natural gas processing plants with aggregate capacity of approximately 1,090 MMCFD located in Oklahoma and Texas; a gas treating facility located in Oklahoma; and approximately 10,100 miles of active natural gas gathering systems located in Oklahoma, Kansas, Tennessee and Texas. Our gathering systems gather natural gas from oil and natural gas wells and central delivery points and deliver to this gas to processing plants, as well as third-party pipelines.


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Our Gathering and Processing operations are all located in or near areas of abundant and long-lived natural gas production, including the Golden Trend, Mississippian Limestone and Hugoton field in the Anadarko Basin; the Woodford Shale; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin; and the Barnett Shale. Our gathering systems are connected to approximately 8,600 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. We believe we have significant scale in each of our primary service areas. We provide gathering, processing and treating services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering, processing and treating assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

Our Transportation and Treating operations consist of (1) seventeen gas treating facilities used to provide contract treating services to natural gas producers located in Arkansas, Louisiana, Oklahoma and Texas; and (2) a 20% interest in WTLPG, which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The contract gas treating operations are located in various shale plays, including the Avalon, Eagle Ford, Granite Wash, Haynesville, Fayetteville and Woodford. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation ("Chevron" NYSE: CVX), which owns the remaining 80% interest.

Recent Events

On January 7, 2013, we paid $6.0 million for the first of two contingent payments related to the acquisition of a gas gathering system and related assets in February 2012. We agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes were achieved on the acquired gathering system within specified periods of time. Sufficient volumes were achieved in December 2012 to meet the required volumes for the first contingent payment.

On February 11, 2013, we issued $650.0 million of 5.875% unsecured senior notes due August 1, 2023 ("5.875% Senior Notes") in a private placement transaction. The 5.875% Senior Notes were issued at par. We received net proceeds of $637.1 million and utilized the proceeds to redeem our outstanding 8.75% senior unsecured notes due June 15, 2018 ("8.75% Senior Notes") and repay a portion of our outstanding indebtedness under our revolving credit facility.

Prior to issuance of the 5.875% Senior Notes and in anticipation thereof, on January 28, 2013, we commenced a cash tender offer for any and all of our outstanding $365.8 million 8.75% Senior Notes, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% Senior Notes ("8.75% Senior Notes Indenture"). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes (representing approximately 73.4% of the outstanding 8.75% Senior Notes), were validly tendered as of the expiration date of the consent solicitation. In February 2013, we accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture. We also issued a notice to redeem all the 8.75% Senior Notes not purchased in connection with the tender offer.

On March 12, 2013, we paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% Senior Notes plus a $6.3 million make-whole premium and $2.0 million in accrued interest. We funded the redemption with a portion of the net proceeds from the issuance of the 5.875% Senior Notes.


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Subsequent Events

On April 16, 2013 we entered into a definitive agreement with TEAK Midstream Holdings, LLC and its wholly owned subsidiary TEAK Midstream, L.L.C. ("TEAK") to purchase 100% of the outstanding ownership interests in TEAK for $1.0 billion in cash, subject to customary purchase price adjustments (the "TEAK Acquisition"). TEAK's assets primarily include gas gathering, processing and treating facilities in South Texas. Closing of the pending TEAK Acquisition is subject to customary closing conditions and is expected to occur in May 2013, with an effective date of April 1, 2013.

On April 16, 2013, we executed a Class D preferred unit purchase agreement for a private placement of $400 million of Class D convertible preferred units ("Class D Preferred Units") to third party investors, at a negotiated price per unit of $30.41, subject to adjustment. The Class D Preferred Units will be offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The issuance of the Class D Preferred Units is subject to customary closing conditions, conditioned upon the closing of the TEAK Acquisition. We will have the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units at the end of eight full quarterly periods following their issuance. The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of our General Partner. Distributions will be determined based upon the cash distribution declared each quarter for payment on our common limited partner units. Upon the issuance of the Class D Preferred Units, we will enter into a registration rights agreement pursuant to which we will agree to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. We will agree to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion. The General Partner will also contribute $8.2 million to maintain its 2% general partnership interest, upon the issuance of the Class D Preferred Units. We expect to use all of the proceeds to fund a portion of the purchase price of the TEAK Acquisition.

On April 17, 2013, we entered into an underwriting agreement for the sale and issuance of 11,845,000 of our common units (including 1,545,000 common units to cover the underwriters' over-allotment option) at a price to the public of $34.00 per unit. The underwriters exercised their over-allotment option in full on April 18, 2013. We received $388.4 million in proceeds after underwriting commissions and estimated expenses, plus the General Partner contributed $8.3 million to maintain its 2% general partnership interest. We expect to use all of the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition.

On April 19, 2013, we entered into an amendment to our credit agreement, which among other changes:

allowed the pending TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement;

will not require the joint venture interests, which will be acquired in the pending TEAK Acquisition, to be guarantors;

permitted the payment of cash distributions, if any, on the Class D Preferred Units so long as we have a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million; and


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modified the definition of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been adjusted; and

permitted the Consolidated Funded Debt Ratio to be greater than:

5.50 to 1.00 for the last day of any fiscal quarter during an Acquisition Period (as defined by the credit agreement);

5.75 to 1.00 for the last day of the fiscal quarter in which the TEAK Acquisition is consummated;

5.50 to 1.00 for last day of the two fiscal quarters immediately following the fiscal quarter in which the TEAK Acquisition is consummated; or

5.00 to 1.00 for the last day of any other fiscal quarter.

Acquisitions

In December 2012, we acquired 100% of the equity interests held by Cardinal Midstream, LLC ("Cardinal") in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments, less cash received (the "Cardinal Acquisition"). The assets of these companies represented the majority of the operating assets of Cardinal (the "Arkoma system") and include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas as follows:

the Tupelo plant, which is a 120 MMCFD cryogenic processing facility;

approximately 60 miles of gathering pipeline;

the East Rockpile treating facility, a 250 GPM amine treating plant;

a fixed fee contract gas treating business that includes 15 amine treating plants and two propane refrigeration plants; and

a 60% interest in a joint venture known as Centrahoma Processing, LLC ("Centrahoma"). The remaining 40% interest is owned by MarkWest Oklahoma Gas Company, LLC, ("MarkWest"), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). Centrahoma owns the following assets:

the Coalgate and Atoka plants, which are cryogenic processing facilities with a combined current processing capacity of approximately 100 MMCFD;

the prospective Stonewall plant, for which construction has been approved, with anticipated processing capacity of 120 MMCFD; and

15 miles of NGL pipeline.

How We Evaluate Our Operations

Our principal revenue is generated from the gathering, processing and treating of natural gas and the 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, NGLs and condensate 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, process and treat, 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;


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the price of the natural gas we gather, process and treat, and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent 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 and treating plants.

Revenue consists of the sale of natural gas, NGLs and condensate; and the fees earned from our gathering, processing and treating 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, NGLs and condensate 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, EBITDA, 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, processing and treating 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, processing and other fees less purchased product costs, subject to certain non-cash adjustments. Product costs include the cost of natural gas, NGLs and condensate 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.


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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 the 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 tax, 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).

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.


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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.

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 months ended March 31, 2013 and 2012 (in thousands):

                         RECONCILIATION OF GROSS MARGIN



                                                     Three Months Ended
                                                          March 31,
                                                     2013           2012
           Net income (loss)                       $ (27,492 )    $  6,471
           Adjustments:
           Derivative loss, net                       12,083        12,035
           Other income, net                          (3,422 )      (2,415 )
           Operating expenses(1)                      22,389        14,111
           General and administrative expense(2)      13,798         9,945
           Depreciation and amortization              30,458        20,842
           Interest                                   18,686         8,708
           Income tax expense                             (9 )          -
           Equity income in joint venture             (2,040 )        (896 )
           Loss on early extinguishment of debt       26,582            -
           Non-cash linefill (gain) loss(3)               32           272

           Gross margin                            $  91,065      $ 69,073

(1) Operating expenses include plant operating expenses; transportation and compression expenses; and other costs.

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

(3) 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
                                                                       March 31,
                                                                  2013           2012
Net income (loss)                                               $ (27,492 )    $  6,471
Adjustments:
Income attributable to non-controlling interests(1)                (1,369 )      (1,536 )
Interest expense                                                   18,686         8,708
Income tax benefit                                                     (9 )          -
Depreciation and amortization                                      30,458        20,842
Non-controlling interest depreciation, amortization and
interest expense(2)                                                  (850 )          -

EBITDA                                                             19,424        34,485
Adjustments:
Equity income in joint venture                                     (2,040 )        (896 )
Distributions from joint venture                                    1,800         1,800
Loss on early extinguishment of debt                               26,582            -
Non-cash loss on derivatives                                       13,719        10,696
Premium expense on derivative instruments                           3,275         3,752
Acquisitions costs                                                    530            -
Non-cash compensation                                               4,384           978
Non-cash line fill (gain) loss(3)                                      32           272

Adjusted EBITDA                                                    67,706        51,087
Adjustments:
Interest expense                                                  (18,686 )      (8,708 )
Amortization of deferred finance costs                              1,544         1,165
Premium expense on derivative instruments                          (3,275 )      (3,752 )
Other costs                                                            -            (34 )
Maintenance capital(4)                                             (3,814 )      (4,510 )

Distributable Cash Flow                                         $  43,475      $ 35,248

(1) 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.

(2) Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest's interest in Centrahoma.

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

(4) Represents maintenance capital expenditures net of amounts attributable to non-controlling interest for MarkWest's interest in Centrahoma.

. . .

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