10-Q 1 form10-q.htm FORM 10-Q QUARTERLY REPORT form10-q.htm
 
 




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File Number: 001-33303
 
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)


Delaware
 
65-1295427
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
1000 Louisiana St, Suite 4300, Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
 
(713) 584-1000
(Registrant’s telephone number, including area code)


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer R
Accelerated filer £
Non-accelerated filer £
Smaller reporting company £
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes £ No R.

As of November 1, 2011, there were 84,756,009 Common Units and 1,729,715 General Partner Units outstanding.
 
 
 
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we”, “us”, “our” or the “Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Part II-Other Information, Item 1A. Risk Factors” of this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as the following risks and uncertainties:

·  
our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;

·  
the amount of collateral required to be posted from time to time in our transactions;

·  
our success in risk management activities, including the use of derivative financial instruments to hedge commodity risks;

·  
the level of creditworthiness of counterparties to transactions;

·  
changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

·  
the timing and extent of changes in natural gas, natural gas liquids (“NGL”) and other commodity prices, interest rates and demand for our services;

·  
weather and other natural phenomena;

·  
industry changes, including the impact of consolidations and changes in competition;

·  
our ability to obtain necessary licenses, permits and other approvals;

·  
the level and success of oil and natural gas drilling around our assets and our success in connecting natural gas supplies to our gathering and processing systems and NGL supplies to our logistics and marketing facilities;

·  
our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;

·  
general economic, market and business conditions; and

·  
the risks described elsewhere in “Part II–Other Information, Item 1A. Risk Factors” of this Quarterly Report, our Annual Report on Form 10-K for the year ended December 31, 2010 (“Annual Report”) and our reports and registration statements filed from time to time with the Securities and Exchange Commission.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II–Other Information, Item 1A. Risk Factors” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

 
As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

Bbl
Barrels (equal to 42 gallons)
Btu
British thermal units, a measure of heating value
BBtu
Billion British thermal units
/d
Per day
/hr
Per hour
gal
Gallons
LPG
Liquefied petroleum gas
MBbl
Thousand barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
NGL(s)
Natural gas liquid(s)
NYMEX
New York Mercantile Exchange
   
Price Index
 
Definitions
 
IF-NGPL MC
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB
Inside FERC Gas Market Report, Permian Basin
IF-WAHA
Inside FERC Gas Market Report, West Texas WAHA
NY-WTI
NYMEX, West Texas Intermediate Crude Oil
OPIS-MB
Oil Price Information Service, Mont Belvieu, Texas
 
 
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
 
September 30,
   
December 31,
 
 
2011
   
2010
 
 
  (Unaudited)  
 
  (In millions)  
ASSETS
Current assets:
 
   
 
 
Cash and cash equivalents
$ 68.9     $ 76.3  
Trade receivables, net of allowances of $2.0 million and $7.7 million
  544.5       466.1  
Inventory
  139.3       50.3  
Assets from risk management activities
  35.2       25.2  
Other current assets
  8.4       2.9  
Total current assets
  796.3       620.8  
Property, plant and equipment, at cost
  3,538.5       3,299.5  
Accumulated depreciation
  (935.2 )     (804.3 )
Property, plant and equipment, net
  2,603.3       2,495.2  
Long-term assets from risk management activities
  20.8       18.9  
Investment in unconsolidated affiliate
  28.5       15.2  
Other long-term assets
  173.1       36.3  
Total assets
$ 3,622.0     $ 3,186.4  
 
             
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
             
Accounts payable to third parties
$ 299.7     $ 250.5  
Accounts payable to Targa Resources Corp.
  60.2       51.4  
Accrued liabilities
  294.4       273.7  
Liabilities from risk management activities
  34.7       34.2  
Total current liabilities
  689.0       609.8  
Long-term debt
  1,514.1       1,445.4  
Long-term liabilities from risk management activities
  10.7       32.8  
Deferred income taxes
  9.3       8.7  
Other long-term liabilities
  43.9       40.6  
 
             
Commitments and contingencies (see Note 11)
             
 
             
Owners' equity:
             
Common unitholders (84,756,009 and 75,545,409 units issued and
             
outstanding as of September 30, 2011 and December 31, 2010)
  1,203.4       935.3  
General partner (1,729,715 and 1,541,744 units issued and
             
outstanding as of September 30, 2011 and December 31, 2010)
  24.7       15.1  
Accumulated other comprehensive loss
  (12.2 )     (30.6 )
 
  1,215.9       919.8  
Noncontrolling interests in subsidiaries
  139.1       129.3  
Total owners' equity
  1,355.0       1,049.1  
Total liabilities and owners' equity
$ 3,622.0     $ 3,186.4  
 
             
See notes to consolidated financial statements
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
   
 
   
 
   
 
 
 
 
 
   
 
   
 
   
 
 
 
 
Three Months Ended September 30,
   
 
Nine Months Ended September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
 
 
(Unaudited)
 
 
 
(In millions, except per unit amounts)
 
Revenues
  $ 1,712.7     $ 1,218.4     $ 5,053.8     $ 3,944.6  
Costs and expenses:
                               
Product purchases
    1,485.5       1,033.6       4,364.5       3,394.0  
Operating expenses
    76.5       66.0       214.1       190.2  
Depreciation and amortization expenses
    45.0       43.3       132.2       128.3  
General and administrative expenses
    33.7       26.7       98.6       80.0  
Other operating expense
    (0.3 )     -       (0.4 )     -  
Income from operations
    72.3       48.8       244.8       152.1  
Other income (expense):
                               
Interest expense from affiliate
    -       (2.5 )     -       (23.8 )
Interest expense allocated from Parent
    -       (1.4 )     -       (5.6 )
Other interest expense, net
    (25.7 )     (24.0 )     (80.4 )     (57.2 )
Equity in earnings of unconsolidated investment
    2.2       1.1       5.2       3.8  
Gain (loss) on mark-to-market derivative instruments
    (1.8 )     (1.9 )     (5.0 )     26.0  
Other
    (0.6 )     -       (0.8 )     -  
Income before income taxes
    46.4       20.1       163.8       95.3  
Income tax expense:
                               
Current
    (2.4 )     (1.8 )     (4.6 )     (3.6 )
Deferred
    0.9       0.1       (0.6 )     (0.3 )
 
    (1.5 )     (1.7 )     (5.2 )     (3.9 )
Net income
    44.9       18.4       158.6       91.4  
Less: Net income attributable to noncontrolling interests
    9.0       4.6       29.6       18.2  
Net income attributable to Targa Resources Partners LP
  $ 35.9     $ 13.8     $ 129.0     $ 73.2  
 
                               
Net income (loss) attributable to predecessor operations
  $ -     $ (1.3 )   $ -     $ 25.8  
Net income attributable to general partner
    9.5       5.0       26.0       12.0  
Net income attributable to limited partners
    26.4       10.1       103.0       35.4  
Net income attributable to Targa Resources Partners LP
  $ 35.9     $ 13.8     $ 129.0     $ 73.2  
 
                               
Net income per limited partner unit - basic and diluted
  $ 0.31     $ 0.14     $ 1.23     $ 0.51  
Weighted average limited partner units outstanding - basic and diluted
    84.8       72.0       83.9       69.2  
 
                               
See notes to consolidated financial statements
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
   
 
   
 
   
 
 
 
    Three Months Ended       Nine Months Ended  
 
    September 30,       September 30,  
 
 
2011
   
2010
   
2011
   
2010
 
 
(Unaudited)
 
 
(In millions)
 
Net income
  $ 44.9     $ 18.4     $ 158.6     $ 91.4  
Other comprehensive income:
                               
Commodity hedging contracts:
                               
Change in fair value
    47.0       (1.2 )     (9.7 )     58.8  
Settlements reclassified to revenues
    10.3       (7.1 )     26.7       (7.0 )
Interest rate hedges:
                               
Change in fair value
    (2.3 )     (6.7 )     (4.3 )     (23.5 )
Settlements reclassified to interest expense, net
    1.0       3.5       5.7       8.5  
Other comprehensive income (loss)
    56.0       (11.5 )     18.4       36.8  
Comprehensive income
    100.9       6.9       177.0       128.2  
Less: Comprehensive income attributable to
                               
noncontrolling interests
    9.0       4.6       29.6       18.2  
Comprehensive income attributable to
                               
Targa Resources Partners LP
  $ 91.9     $ 2.3     $ 147.4     $ 110.0  
 
                               
See notes to consolidated financial statements
 
 
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
 
 
 
   
 
   
 
   
 
   
 
   
 
   
 
 
 
 
 
   
 
   
 
   
 
   
Accumulated
   
 
   
 
 
 
 
Limited
   
General
   
Other
   
 
   
 
 
 
 
Partner
   
Partner
   
Comprehensive
   
Noncontrolling
   
 
 
 
 
Units
   
Amount
   
Units
   
Amount
   
Income (Loss)
   
Interests
   
Total
 
 
(Unaudited)
 
 
(In millions, except units in thousands)
 
Balance, December 31, 2010
    75,545     $ 935.3       1,542     $ 15.1     $ (30.6 )   $ 129.3     $ 1,049.1  
Compensation on equity grants
    11       1.2       -       -       -       -       1.2  
Proceeds from equity offerings
    9,200       298.0       188       6.3       -       -       304.3  
Contributions from Targa Resources Corp.
    -       7.9       -       1.2       -       -       9.1  
Distributions to noncontrolling interests
    -       -       -       -       -       (19.8 )     (19.8 )
Other comprehensive income
    -       -       -       -       18.4       -       18.4  
Net income
    -       103.0       -       26.0       -       29.6       158.6  
Distributions to unitholders
    -       (142.0 )     -       (23.9 )     -       -       (165.9 )
Balance, September 30, 2011
    84,756     $ 1,203.4       1,730     $ 24.7     $ (12.2 )   $ 139.1     $ 1,355.0  
 
                                                       
See notes to consolidated financial statements
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
   
 
 
 
 
Nine Months Ended September 30,
 
 
 
2011
   
2010
 
 
 
(Unaudited)
 
 
 
(In millions)
 
Cash flows from operating activities
 
 
   
 
 
Net income
  $ 158.6     $ 91.4  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Amortization in interest expense
    6.7       4.4  
Compensation on equity grants
    1.2       0.3  
Interest expense on affiliate and allocated indebtedness
    -       29.4  
Depreciation and other amortization expense
    132.2       128.3  
Accretion of asset retirement obligations
    2.7       2.4  
Deferred income tax expense
    0.6       0.3  
Equity in earnings of unconsolidated investment, net of distributions
    (1.4 )     -  
Risk management activities
    (15.1 )     (5.4 )
Gain on sale of assets
    (0.4 )     -  
Changes in operating assets and liabilities:
               
Receivables and other assets
    (82.9 )     56.3  
Inventory
    (86.9 )     (16.0 )
Accounts payable and other liabilities
    76.0       (52.5 )
Net cash provided by operating activities
    191.3       238.9  
Cash flows from investing activities
               
Outlays for property, plant and equipment
    (211.4 )     (82.5 )
Business acquisitions
    (164.2 )     -  
Investment in unconsolidated affiliate
    (11.9 )     -  
Unconsolidated affiliate distributions in excess of accumulated earnings
    -       1.1  
Other, net
    0.3       2.1  
Net cash used in investing activities
    (387.2 )     (79.3 )
Cash flows from financing activities
               
Proceeds from borrowings under credit facility
    1,426.0       1,178.1  
Repayments of credit facility
    (1,656.3 )     (904.0 )
Proceeds from issuance of senior notes
    325.0       250.0  
Cash paid on note exchange
    (27.7 )     -  
Costs incurred in connection with financing arrangements
    (6.2 )     (20.2 )
Repayment of affiliated and allocated indebtedness
    -       (740.2 )
Proceeds from equity offerings
    304.3       317.8  
Distributions to unitholders
    (165.9 )     (117.8 )
Contributions from (distributions to) parent
    9.1       (95.7 )
Distributions under common control
    -       (46.6 )
Distributions to noncontrolling interests
    (19.8 )     (17.4 )
Net cash provided by (used in) financing activities
    188.5       (196.0 )
Net change in cash and cash equivalents
    (7.4 )     (36.4 )
Cash and cash equivalents, beginning of period
    76.3       90.9  
Cash and cash equivalents, end of period
  $ 68.9     $ 54.5  
 
               
See notes to consolidated financial statements
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. Except where otherwise noted, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1 — Organization and Operations

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Targa Resources GP LLC is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of September 30, 2011, Targa and its subsidiaries own a 15.5% interest in us in the form of 1,729,715 general partner units and 11,645,659 common units as well as all of the incentive distribution rights.

We acquired Targa’s ownership interests in the following assets, liabilities and operations on the dates indicated:

·  
February 2007 – North Texas System;

·  
October 2007 – San Angelo (“SAOU”) and Louisiana (“LOU”);

·  
September 2009 – Downstream Business;

·  
April 2010 – Permian Business and Straddle Assets (See Note 4);

·  
August 2010 – Versado (See Note 4); and

·  
September 2010 – Venice Operations (See Note 4).

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these conveyances collectively as our “predecessors.”

Allocation of costs. The employees supporting our operations are employed by Targa Resources LLC, a Delaware limited liability company and an indirect wholly-owned subsidiary of Targa. Our financial statements include the direct costs of employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa centralized general and administrative services and related administrative assets.

Our Operations

We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and storing and terminaling refined petroleum products and crude oil. See Note 13 for an analysis of our operations by segment.

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. Certain amounts in prior periods have been reclassified to conform to the current year presentation. The unaudited consolidated financial statements for the three and nine months ended September 30, 2011 and 2010 include all adjustments which we believe are necessary for a fair presentation of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation.
 

Our financial results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report for the year ended December 31, 2010.

We are required by GAAP to record the acquisitions described in Note 1 based on Targa’s historical amounts, assuming that the acquisitions occurred at the date they qualified as entities under common control (October 31, 2005) following the acquisition of SAOU and LOU. We recognize the difference between our acquisition cost and the Targa basis in the net assets as an adjustment to owners’ equity. We have retrospectively adjusted the financial statements, footnotes and other financial information presented for any period affected by common control accounting to reflect the results of the combined entities.

Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies that we follow are set forth in Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no significant changes to these policies during the nine months ended September 30, 2011.

2011 Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, requires additional disclosures with regard to fair value measurements categorized within Level 3 of the fair value hierarchy. Early adoption is not permitted.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, stipulates the financial statement presentation requirements for other comprehensive income. Our financial statement presentation complies with this standards update.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, allows entities to first assess qualitative factors when testing goodwill for impairment. Early adoption is permitted. Adoption of this amendment has no impact on our current financial presentation.
 

Note 4 — Acquisitions

Acquisitions Under Common Control

On April 27, 2010, we acquired Targa’s interests in its Permian Business and Straddle Assets for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million of consideration reported as a parent distribution.

On August 25, 2010, we acquired Targa’s 63% equity interest in Versado Gas Processors L.L.C. (“Versado”), effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. This consideration was used to repay $247.2 million of affiliated indebtedness. Targa contributed the remaining $205.8 million of affiliate indebtedness as a capital contribution. Under the terms of the Versado acquisition purchase and sale agreement, Targa will reimburse us for future maintenance capital expenditures required pursuant to the New Mexico Environmental Department (“NMED”) settlement agreement, of which our share is currently estimated to be $21.0 million, including $13.3 million that has been incurred as of September 30, 2011.

On September 28, 2010, we acquired Targa’s Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), for aggregate consideration of $175.6 million, effective September 1, 2010. This consideration was used to repay $160.2 million of affiliate indebtedness, with the remaining $15.4 million of consideration reported as a parent distribution.

These acquisitions have been accounted for as acquisitions under common control, resulting in the retrospective adjustment of our prior results.

Other Acquisitions – Petroleum Logistics

On March 15, 2011, we acquired a refined petroleum products and crude oil storage and terminaling facility in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel (the "Channelview Terminal") for $29.0 million. The Channelview Terminal, with storage capacity of 544,000 barrels, can handle multiple grades of blend stocks, petroleum products and crude and has potential for expansion, as well as integration with our other logistics operations.

On September 30, 2011 we acquired two refined petroleum products and crude oil storage and terminaling facilities. The facility on the Hylebos Waterway in the Port of Tacoma, Washington has 758,000 barrels of capacity and handles refined petroleum products, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland has approximately 505,000 barrels of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total consideration for both facilities was $127.7 million plus an additional $7.5 million for estimated working capital and has been included in our other long-term assets in our September 30, 2011 balance sheet pending finalization of fair value accounting under ASC 805.

Note 5 — Property, Plant and Equipment

   
September 30,
   
December 31,
   
Estimated useful lives
 
   
2011
   
2010
   
(In years)
 
Natural gas gathering systems
  $ 1,710.9     $ 1,630.9    
5 to 20
 
Processing and fractionation facilities
    1,058.4       961.9    
5 to 25
 
Terminaling and storage facilities
    272.7       244.7    
5 to 25
 
Transportation assets
    275.5       275.6    
10 to 25
 
Other property, plant and equipment
    51.2       46.8    
3 to 25
 
Land
    53.2       51.2       -  
Construction in progress
    116.6       88.4       -  
    $ 3,538.5     $ 3,299.5          

Note 6 — Debt Obligations

   
September 30,
   
December 31,
 
   
2011
   
2010
 
Senior secured revolving credit facility, variable rate, due July 2015
  $ 535.0     $ 765.3  
Senior unsecured notes, 8¼% fixed rate, due July 2016
    209.1       209.1  
Senior unsecured notes, 11¼% fixed rate, due July 2017
    72.7       231.3  
Unamortized discount
    (3.0 )     (10.3 )
Senior unsecured notes, 7⅞% fixed rate, due October 2018
    250.0       250.0  
Senior unsecured notes, 6⅞% fixed rate, due February 2021
    483.6       -  
Unamortized discount
    (33.3 )     -  
    $ 1,514.1     $ 1,445.4  
                 
Letters of credit issued
  $ 88.3     $ 101.3  
 

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during the nine months ended September 30, 2011:

 
Range of Interest Rates Paid
 
Weighted Average Interest Rate Paid
Senior secured revolving credit facility
2.4% - 4.8%
 
2.7%

Compliance with Debt Covenants

As of September 30, 2011, we were in compliance with the covenants contained in our various debt agreements.

Senior Secured Credit Facility

As of September 30, 2011, availability under our senior secured credit facility was $476.7 million, after giving effect to $88.3 million in outstanding letters of credit.

6⅞% Senior Notes

On February 2, 2011, we closed a private placement of $325.0 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”). The net proceeds of this offering were $318.8 million after deducting expenses of the offering. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility and for general partnership purposes.

On February 4, 2011, we exchanged an additional $158.6 million principal amount of 6⅞% Notes plus payments of $28.6 million including $0.9 million of accrued interest for $158.6 million aggregate principal amount of our 11¼% Senior Notes due 2017 (the “11¼% Notes”). The holders of the exchanged Notes are subject to the provisions of the 6⅞% Notes described below. The debt covenants related to the remaining $72.7 million of face value of our 11¼% Notes were removed. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.
 
The 6⅞% Notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by certain of our subsidiaries. These notes are effectively subordinated to all secured indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.
 
Interest on the 6⅞% Notes accrues at the rate of 6⅞% per annum and is payable semi-annually in arrears on February 1 and August 1, commencing on August 1, 2011.
 
We may redeem 35% of the aggregate principal amount of the 6⅞% Notes at any time prior to February 1, 2014, with the net cash proceeds of one or more equity offerings. We must pay a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:
 
1)  
at least 65% of the aggregate principal amount of the 6⅞% Notes (excluding 6⅞% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and
 
2)  
the redemption occurs within 90 days of the date of the closing of such equity offering.
 
We may also redeem all or part of the 6⅞% Notes on or after August 1, 2016 at the prices set forth below plus accrued and unpaid interest and liquidated damages, if any. Redemption periods begin on August 1 of each year indicated below:
 
Year
 
Percentage
2016
 
103.44%
2017
 
102.29%
2018
 
101.15%
2019 and thereafter
 
100.00%
 
 
Note 7 — Partnership Equity and Distributions

Partnership Equity

On January 24, 2011, we completed a public offering of 8,000,000 common units under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.2 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011, we issued an additional 1,200,000 common units, providing net proceeds of $38.8 million. In addition, Targa contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us.

Distributions

Distributions for the nine months ended September 30, 2011 and 2010 were as follows:

       
Distributions
       
   
For the Three
 
Limited Partners
   
General Partner
         
Distributions per limited
 
Date Paid
 
Months Ended
 
Common
   
Incentive
      2%    
Total
   
partner unit
 
       
(In millions, except per unit amounts)
       
August 12, 2011
 
June 30, 2011
  $ 48.3     $ 7.8     $ 1.2     $ 57.3     $ 0.5700  
May 13, 2011
 
March 31, 2011
    47.3       6.8       1.1       55.2       0.5575  
February 14, 2011
 
December 31, 2010
    46.4       6.0       1.1       53.5       0.5475  
November 12, 2010
 
September 30, 2010
    40.6       4.6       0.9       46.1       0.5375  
August 13, 2010
 
June 30, 2010
    35.9       3.5       0.8       40.2       0.5275  
May 14, 2010
 
March 31, 2010
    35.2       2.8       0.8       38.8       0.5175  
February 12, 2010
 
December 31, 2009
    35.2       2.8       0.8       38.8       0.5175  

Subsequent Event. On October 11, 2011, we announced a cash distribution of $0.5825 per common unit on our outstanding common units for the three months ended September 30, 2011, to be paid on November 14, 2011. The distribution to be paid is $42.6 million to our third-party limited partners, and $6.8 million, $8.8 million and $1.2 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in us.

Note 8 — Derivative Instruments and Hedging Activities

Commodity Hedges

The primary purpose of our commodity risk management activities is to hedge the exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas and NGL equity volumes through 2013 and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (floors).

The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, the NGL hedges are based on published index prices for delivery at Mont Belvieu and the natural gas hedges are based on published index prices for delivery at Permian Basin, Mid-Continent and WAHA, which closely approximate our actual NGL and natural gas delivery points.

We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying West Texas condensate equity volumes.
 
 
At September 30, 2011, the notional volumes of our commodity hedges were:

Commodity
 
Instrument
 
Unit
 
2011 
 
2012 
 
2013 
 
2014 
Natural Gas
 
Swaps
 
MMBtu/d
 
 38,470 
 
 31,790 
 
 17,089 
 
 - 
NGL
 
Swaps
 
Bbl/d
 
 10,118 
 
 9,361 
 
 4,150 
 
 - 
NGL
 
Floors
 
Bbl/d
 
 253 
 
 294 
 
 - 
 
 - 
Condensate
 
Swaps
 
Bbl/d
 
 1,730 
 
 1,660 
 
 1,795 
 
 700 

We frequently enter into derivative instruments to manage location basis differentials with short-term fractionation arrangements. Based on the current application of the basis derivatives, we do not account for these derivatives as hedges and we record changes in fair value and cash settlements to revenues.

Interest Rate Swaps

On September 6, 2011, we paid $24.2 million, including $1.2 million in accrued interest, to terminate all of our interest rate swaps.  The interest rate swaps were originally entered into to mitigate interest rate risk on our senior secured revolving credit facility.  A total of $19.6 million in losses are deferred in other comprehensive income (“OCI”). As long as we maintain variable rate debt through our senior secured revolving credit facility, this deferred loss will be amortized into interest expense over the original terms of the swap contracts, which extend to April 2014.

The following schedules reflect the fair values of derivative instruments in our financial statements:
 
        Derivative Assets  
Derivative Liabilities
 
   
Balance
     Fair Value as of  
Balance
 
Fair Value as of
 
   
Sheet
 
September 30,
   
December 31,
 
Sheet
 
September 30,
   
December 31,
 
   
Location
 
2011
   
2010
 
Location
 
2011
   
2010
 
Designated as hedging instruments
                   
Commodity contracts
 
Current assets
  $ 34.7     $ 24.8  
Current liabilities
  $ 34.6     $ 25.5  
   
Long-term assets
    20.8       18.9  
Long-term liabilities
    10.7       20.5  
Interest rate contracts
 
Current assets
    -       -  
Current liabilities
    -       7.8  
   
Long-term assets
    -       -  
Long-term liabilities
    -       12.3  
Total designated as hedging instruments
  $ 55.5     $ 43.7       $ 45.3     $ 66.1  
                                       
Not designated as hedging instruments
                         
Commodity contracts
 
Current assets
  $ 0.5     $ 0.4  
Current liabilities
  $ 0.1     $ 0.9  
   
Long-term assets
    -       -  
Long-term liabilities
    -       -  
Total not designated as hedging instruments
  $ 0.5     $ 0.4       $ 0.1     $ 0.9  
Total derivatives
      $ 56.0     $ 44.1       $ 45.4     $ 67.0  
 
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.
 

The following tables reflect amounts recorded in OCI, amounts reclassified from OCI to revenue and expense and amounts recognized in income on the ineffective portion of our hedges:
 
   
Gain (Loss) Recognized in OCI on Derivatives
Derivatives in
 
(Effective Portion)
Cash Flow Hedging
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Relationships
 
2011 
 
2010 
 
2011 
 
2010 
Interest rate contracts
 
$
 (2.3)
 
$
 (6.7)
 
$
 (4.3)
 
$
 (23.5)
Commodity contracts
   
 47.0 
   
 (1.2)
   
 (9.7)
   
 58.8 
   
$
 44.7 
 
$
 (7.9)
 
$
 (14.0)
 
$
 35.3 
                         
   
Gain (Loss) Reclassified from OCI into Income
   
(Effective Portion)
   
Three Months Ended September 30,
 
Nine Months Ended September 30,
Location of Gain (Loss)
 
2011 
 
2010 
 
2011 
 
2010 
Interest expense, net
 
$
 (1.0)
 
$
 (3.5)
 
$
 (5.7)
 
$
 (8.5)
Revenues
   
 (10.3)
   
 7.1 
   
 (26.7)
   
 7.0 
   
$
 (11.3)
 
$
 3.6 
 
$
 (32.4)
 
$
 (1.5)
                         
   
Gain (Loss) Recognized in Income on Derivatives
   
(Ineffective Portion)
   
Three Months Ended September 30,
 
Nine Months Ended September 30,
Location of Gain (Loss)
 
2011 
 
2010 
 
2011 
 
2010 
Revenues
  $
 0.2 
  $
 0.7 
  $
 0.2 
  $
 0.4 
   
$
 0.2 
 
$
 0.7 
 
$
 0.2 
 
$
 0.4 
                         

Our earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying price indices. During the three and nine months ended September 30, 2011 and 2010, we recorded the following mark-to-market gains (losses):
 
          Gain (Loss)  
          Recognized in Income on Derivatives  
   
Location of Gain (Loss)
    Three Months Ended  
Nine Months Ended
 
Derivatives Not Designated
 
Recognized in Income
    September 30,  
September 30,
 
As Hedging Instruments
 
On Derivatives
 
2011
 
2010
 
2011
 
2010
 
Commodity contracts
 
Revenue
  $ 0.4   $ (0.2 ) $ 1.4   $ (0.9 )
Commodity contracts
 
Other income (expense)
    -     (1.9 )   -     26.0  
Interest rate swaps
 
Other income (expense)
    (1.8 )   -     (5.0 )   -  
        $ (1.4 ) $ (2.1 ) $ (3.6 ) $ 25.1  
 
 
The following table shows the unrealized gains (losses) included in OCI:
 
   
September 30,
   
December 31,
 
   
2011
   
2010
 
Unrealized gain (loss) on commodity hedges
  $ 6.3     $ (10.5 )
Unrealized loss on interest rate swaps
  $ (18.7 )   $ (20.1 )
 
As of September 30, 2011, deferred net losses of $3.6 million on commodity hedges and $8.4 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.

In July 2008, we and Targa paid $77.8 million and $9.6 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. We and Targa also entered into new natural gas and NGL commodity swaps at then current market prices that matched the production volumes of the terminated swaps. Prior to the terminations, these swaps were designated as cash flow hedges. During the three and nine months ended September 30, 2011, an immaterial amount of deferred loss related to the terminated swaps was reclassified from OCI as a non-cash reduction to revenue. During the three and nine months ended September 30, 2010, $6.6 million and $20.5 million of deferred losses related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue.

See Note 3 and Note 9 for additional disclosures related to derivative instruments and hedging activities.

Note 9 — Fair Value Measurements

We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

·  
Level 1 – observable inputs such as quoted prices in active markets;

·  
Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable to the extent that the markets are liquid for the relevant settlement periods; and

·  
Level 3 – unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity swap and option contracts and fixed price commodity contracts with certain counterparties. We determine the value of our derivative contracts using a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold.
 

The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

   
September 30, 2011
 
   
Total
   
Level 1
   
Level 2
   
Level 3
 
Assets from commodity derivative contracts
  $ 56.0     $ -     $ 56.0     $ -  
Total assets
  $ 56.0     $ -     $ 56.0     $ -  
Liabilities from commodity derivative contracts
  $ 45.4     $ -     $ 45.4     $ -  
Total liabilities
  $ 45.4     $ -     $ 45.4     $ -  
                                 
   
December 31, 2010
 
   
Total
   
Level 1
   
Level 2
   
Level 3
 
Assets from commodity derivative contracts
  $ 44.1     $ -     $ 43.9     $ 0.2  
Total assets
  $ 44.1     $ -     $ 43.9     $ 0.2  
Liabilities from commodity derivative contracts
  $ 46.9     $ -     $ 35.1     $ 11.8  
Liabilities from interest rate derivatives
    20.1       -       20.1       -  
Total liabilities
  $ 67.0     $ -     $ 55.2     $ 11.8  

The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

   
Commodity Derivative Contracts
 
Balance, December 31, 2010
  $ (11.6 )
Settlements included in Net Income
    3.7  
Transfers out of Level 3
    7.9  
Balance, September 30, 2011
  $ -  

We transferred $7.9 million in derivative liabilities from Level 3 to Level 2 for the nine months ended September 30, 2011. The transfers are attributable to increased transparency and liquidity in the NGL markets, specifically with regard to 2013 prices.

We designate all Level 3 derivative instruments as cash flow hedges, and, as such, all changes in their fair value are reflected in OCI. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.
 

Note 10 — Fair Value of Financial Instruments

The estimated fair values of assets and liabilities classified as financial instruments have been determined using available market information and the valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.

The carrying value of our senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

 
September 30, 2011
 
December 31, 2010
 
 
Carrying
 
Fair
 
Carrying
 
Fair
 
 
Amount
 
Value
 
Amount
 
Value
 
Senior unsecured notes, 8¼% fixed rate
$ 209.1   $ 218.6   $ 209.1   $ 219.4  
Senior unsecured notes, 11¼% fixed rate
  69.7     81.8     221.0     253.2  
Senior unsecured notes, 7⅞% fixed rate
  250.0     258.4     250.0     259.7  
Senior unsecured notes, 6⅞% fixed rate
  450.3     467.6     N/A     N/A  

Note 11 — Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

Our environmental liability at September 30, 2011 and December 31, 2010 was $1.4 million and $1.6 million. Our September 30, 2011 liability was for ground water assessment and remediation.

In May 2007, the NMED alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants, which are operated by us and owned by Versado, were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.

In January 2010, Versado settled the alleged violations with NMED for a penalty of approximately $1.5 million. As part of the settlement, Versado agreed to install two acid gas injection wells, additional emission control equipment and monitoring equipment. We estimate the total cost to complete these projects to be approximately $33.4 million, of which our portion of the cost is projected to be $21.0 million. As of September 30, 2011, Versado’s project expenditures total $21.1 million, of which our share was $13.3 million. Under the terms of the Versado acquisition purchase and sale agreement between Targa and us, Targa is obligated to reimburse us for maintenance capital expenditures required pursuant to the NMED settlement agreement.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business that have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows.
 

Note 12 — Supplemental Cash Flow Information

Supplemental cash flow information was as follows for the periods indicated:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2011
 
2010
 
2011
 
2010
 
Interest paid
$ 34.6   $ 28.9   $ 81.6   $ 60.6  
Taxes paid
  0.1     0.7     2.3     2.3  
Non-cash adjustment to line-fill
  -     (0.1 )   (2.1 )   0.4  

Note 13 — Segment Information

We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution.  The financial results of our hedging activities are reported in Other.

Our Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico. The Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business includes all the activities necessary to convert raw NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, crude and refined products. It also includes certain natural gas supply and marketing activities in support of our other operations.
 
The Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling crude oil and refined petroleum products. These assets are generally connected to, and supplied in part by, our Natural Gas Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the 2011 acquisitions of refined petroleum products and crude storage and terminaling facilities.

The Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes: (1) marketing our own NGL production and purchasing NGL products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.

Other contains the results of our commodity hedging activities.  Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.

 
Our reportable segment information is shown in the following tables:

Three Months Ended September 30, 2011
 
   
Field
   
Coastal
                               
   
Gathering
   
Gathering
         
Marketing
         
Corporate
       
   
and
   
and
   
Logistics
   
and
         
and
       
   
Processing
   
Processing
   
Assets
   
Distribution
   
Other
   
Eliminations
   
Total
 
Revenues
                                         
Sales of commodities
  $ 47.9     $ 75.2     $ -     $ 1,530.3     $ (10.8 )   $ 0.1     $ 1,642.7  
Fees from midstream services
    7.0       3.6       35.5       15.8       -       -       61.9  
Other
    (0.2 )     0.3       0.3       7.7       -       -       8.1  
      54.7       79.1       35.8       1,553.8       (10.8 )     0.1       1,712.7  
Intersegment revenues
                                                       
Sales of commodities
    385.4       242.9       0.1       186.0       -       (814.4 )     -  
Fees from midstream services
    0.2       -       24.2       1.8       -       (26.2 )     -  
Other
    -       -       -       7.0       -       (7.0 )     -  
      385.6       242.9       24.3       194.8       -       (847.6 )     -  
Revenues
  $ 440.3     $ 322.0     $ 60.1     $ 1,748.6     $ (10.8 )   $ (847.5 )   $ 1,712.7  
Operating margin
  $ 71.8     $ 39.8     $ 30.1     $ 19.7     $ (10.8 )   $ 0.1     $ 150.7  
Other financial information:
                                                       
Total assets
  $ 1,647.3     $ 425.2     $ 713.2     $ 702.3     $ 56.0     $ 78.0     $ 3,622.0  
Capital expenditures (1)
  $ 40.2     $ 4.2     $ 165.0     $ 0.6     $ -     $ 0.8     $ 210.8  
________
(1)  
Logistics Assets segment capital expenditures includes petroleum logistics acquisitions. See Note 4.
 
Three Months Ended September 30, 2010
 
   
Field
   
Coastal
                               
   
Gathering
   
Gathering
         
Marketing
         
Corporate
       
   
and
   
and
   
Logistics
   
and
         
and
       
   
Processing
   
Processing
   
Assets
   
Distribution
   
Other
   
Eliminations
   
Total
 
Revenues
                                         
Sales of commodities
  $ 42.2     $ 109.1     $ -     $ 1,013.6     $ 7.1     $ (0.1 )   $ 1,171.9  
Fees from midstream services
    6.2       3.4       23.2       9.6       -       -       42.4  
Other
    (0.5 )     0.8       -       3.7       -       0.1       4.1  
      47.9       113.3       23.2       1,026.9       7.1       -       1,218.4  
Intersegment revenues
                                                       
Sales of commodities
    253.4       163.2       0.2       113.3       -       (530.1 )     -  
Fees from midstream services
    0.3       -       19.7       0.2       -       (20.2 )     -  
Other
    -       -       -       5.0       -       (5.0 )     -  
      253.7       163.2       19.9       118.5       -       (555.3 )     -  
Revenues
  $ 301.6     $ 276.5     $ 43.1     $ 1,145.4     $ 7.1     $ (555.3 )   $ 1,218.4  
Operating margin
  $ 49.6     $ 23.5     $ 23.6     $ 15.0     $ 7.1     $ -     $ 118.8  
Other financial information:
                                                       
Total assets
  $ 1,627.7     $ 448.5     $ 432.7     $ 426.4     $ 65.4     $ 62.3     $ 3,063.0  
Capital expenditures
  $ 13.6     $ 2.0     $ 19.3     $ 1.2     $ -     $ -     $ 36.1  

Nine Months Ended September 30, 2011
 
   
Field
   
Coastal
                               
   
Gathering
   
Gathering
         
Marketing
         
Corporate
       
   
and
   
and
   
Logistics
   
and
         
and
       
   
Processing
   
Processing
   
Assets
   
Distribution
   
Other
   
Eliminations
   
Total
 
Revenues
                                         
Sales of commodities
  $ 145.3     $ 243.9     $ 0.1     $ 4,505.5     $ (28.4 )   $ -     $ 4,866.4  
Fees from midstream services
    19.4       12.5       91.3       37.3       -       -       160.5  
Other
    0.2       0.9       0.8       24.8       -       0.2       26.9  
      164.9       257.3       92.2       4,567.6       (28.4 )     0.2       5,053.8  
Intersegment revenues
                                                       
Sales of commodities
    1,051.8       704.9       0.4       465.9       -       (2,223.0 )     -  
Fees from midstream services
    0.7       0.4       67.7       6.0       -       (74.8 )     -  
Other
    -       -       -       19.7       -       (19.7 )     -  
      1,052.5       705.3       68.1       491.6       -       (2,317.5 )     -  
Revenues
  $ 1,217.4     $ 962.6     $ 160.3     $ 5,059.2     $ (28.4 )   $ (2,317.3 )   $ 5,053.8  
Operating margin
  $ 213.0     $ 121.8     $ 85.9     $ 82.8     $ (28.4 )   $ 0.1     $ 475.2  
Other financial information:
                                                       
Total assets
  $ 1,647.3     $ 425.2     $ 713.2     $ 702.3     $ 56.0     $ 78.0     $ 3,622.0  
Capital expenditures (1)
  $ 112.0     $ 9.8     $ 252.6     $ 1.5     $ -     $ 1.4     $ 377.3  
________
(1)  
Logistics Assets segment capital expenditures includes petroleum logistics acquisitions. See Note 4.
 
Nine Months Ended September 30, 2010
 
   
Field
   
Coastal
                               
   
Gathering
   
Gathering
         
Marketing
         
Corporate
       
   
and
   
and
   
Logistics
   
and
         
and
       
   
Processing
   
Processing
   
Assets
   
Distribution
   
Other
   
Eliminations
   
Total
 
Revenues
                                         
Sales of commodities
  $ 144.7     $ 340.2     $ -     $ 3,323.1     $ 7.0     $ (0.1 )   $ 3,814.9  
Fees from midstream services
    17.7       9.2       60.1       32.9       -       -       119.9  
Other
    (1.9 )     0.6       (0.4 )     11.5       -       -       9.8  
      160.5       350.0       59.7       3,367.5       7.0       (0.1 )     3,944.6  
Intersegment revenues
                                                       
Sales of commodities
    792.6       565.2       0.5       379.6       -       (1,737.9 )     -  
Fees from midstream services
    0.8       2.0       61.3       0.7       -       (64.8 )     -  
Other
    -       -       -       16.3       -       (16.3 )     -  
      793.4       567.2       61.8       396.6       -       (1,819.0 )     -  
Revenues
  $ 953.9     $ 917.2     $ 121.5     $ 3,764.1     $ 7.0     $ (1,819.1 )   $ 3,944.6  
Operating margin
  $ 176.8     $ 74.9     $ 52.9     $ 48.8     $ 7.0     $ -     $ 360.4  
Other financial information:
                                                       
Total assets
  $ 1,627.7     $ 448.5     $ 432.7     $ 426.4     $ 65.4     $ 62.3     $ 3,063.0  
Capital expenditures
  $ 41.0     $ 6.2     $ 33.1     $ 1.8     $ -     $ -     $ 82.1  
 
 
The following table shows our revenues by product and service for each period presented:

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Sales of commodities
                       
Natural gas sales
  $ 304.6     $ 261.7     $ 846.2     $ 832.8  
NGL sales
    1,323.4       880.4       3,969.1       2,901.1  
Condensate sales
    25.7       22.4       80.3       73.6  
Derivative activities
    (11.0 )     7.4       (29.2 )     7.4  
Fees from midstream services
                               
Fractionating and treating fees
    25.7       12.4       60.1       40.7  
Storage and terminaling fees
    11.7       11.4       38.9       30.2  
Transportation fees
    16.2       10.3       38.4       25.6  
Gas processing fees
    8.3       8.3       23.1       23.4  
Other
    8.1       4.1       26.9       9.8  
    $ 1,712.7     $ 1,218.4     $ 5,053.8     $ 3,944.6  

The following table is a reconciliation of operating margin to net income for each period presented:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Reconciliation of operating margin to net income:
                       
Operating margin
  $ 150.7     $ 118.8     $ 475.2     $ 360.4  
Depreciation and amortization expense
    (45.0 )     (43.3 )     (132.2 )     (128.3 )
General and administrative expense
    (33.7 )     (26.7 )     (98.6 )     (80.0 )
Interest expense, net
    (25.7 )     (27.9 )     (80.4 )     (86.6 )
Income tax expense
    (1.5 )     (1.7 )     (5.2 )     (3.9 )
Other, net
    0.1       (0.8 )     (0.2 )     29.8  
Net income
  $ 44.9     $ 18.4     $ 158.6     $ 91.4  
 
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2010, as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

Overview

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Targa Resources GP LLC (the “General Partner”) is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.

We acquired Targa’s ownership interests in the following assets, liabilities and operations on the dates indicated (collectively, the “dropdown transactions”):

·  
February 2007 – North Texas System;

·  
October 2007 – San Angelo (“SAOU”) and Louisiana (“LOU”);

·  
September 2009 – Downstream Business;

·  
April 2010 – Permian Business and Straddle Assets;

·  
August 2010 – Versado; and

·  
September 2010 – Venice Operations.

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions as our “predecessors.”

Our Operations

We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and storing and terminaling refined petroleum products and crude oil.

We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution.  The financial results of our hedging activities are reported in Other.

Our Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing such raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico. The Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business includes all the activities necessary to convert raw NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, crude and refined products. It also includes certain natural gas supply and marketing activities in support of our other operations.
 
 
The Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling crude oil and refined petroleum products. These assets are generally connected to, and supplied in part by, our Natural Gas Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities. See “2011 Developments”.

The Marketing and Distribution segment covers activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing our own NGL production and purchasing NGL products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.

Other contains the results of our commodity hedging activities.

2011 Developments

On January 24, 2011, we completed a public offering of 8,000,000 common units representing limited partner interests in us (“common units”) under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.2 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 we issued an additional 1,200,000 common units, providing net proceeds of $38.8 million. In addition, our general partner contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.

On February 2, 2011, we closed a private placement of $325.0 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”). The net proceeds of this offering were $318.8 million after deducting expenses of the offering. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.

On February 4, 2011, we exchanged an additional $158.6 million principal amount of our 6⅞% Notes plus payments of $28.6 million, including $0.9 million of accrued interest, for $158.6 million aggregate principal amount of our 11¼% Senior Notes due 2017 (the “11¼% Notes”). The debt covenants related to the remaining $72.7 million of face value of our 11¼% Notes were removed. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.

On March 15, 2011, we acquired a refined petroleum products and crude oil storage and terminaling facility in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel (the "Channelview Terminal") for $29.0 million. The Channelview Terminal, with storage capacity of 544,000 barrels, can handle multiple grades of blend stocks, petroleum products and crude and has potential for expansion, as well as integration with our other logistics operations.

On May 9, 2011, we announced a 100,000 barrel per day expansion of our majority owned Cedar Bayou Fractionator (“CBF”) at Mont Belvieu, Texas. Substantially all of the capacity of this expansion is currently contracted with long-term, use-or-pay, firm capacity fractionating agreements. The 100,000 barrel per day expansion will be fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park, Texas on the Houston Ship Channel. We estimate that the total capital expenditures for the CBF expansion and our related infrastructure enhancements at Mont Belvieu will be approximately $360 million and construction will be completed in the first quarter of 2013.

On September 19, 2011, we announced a $250 million expansion of our Mont Belvieu complex and our existing import/export marine terminal at Galena Park to provide export capability for more than 5,000 barrels per hour (Bbl/hr) of fully refrigerated, low ethane propane. The expansion project, expected to be operational in the third quarter of 2013, will allow us to load three to four VLGC (very large gas carrier) class ships per month and is in addition to our existing capabilities to handle multiple MGC (medium gas carrier) export cargos of HD-5 grade propane, imports/exports of LPGs and petrochemicals and other spot ship and barge business.

On September 30, 2011 we acquired two refined petroleum products and crude oil storage and terminaling facilities. The facility on the Hylebos Waterway in the Port of Tacoma, Washington (the “Tacoma Terminal”) has 758,000 barrels of capacity and handles refined petroleum products, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland (the “Baltimore Terminal”) has approximately 505,000 barrels of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total consideration for both facilities was $127.7 million plus an additional $7.5 million for estimated working capital.
 
On October 19, 2011, we announced a new 200 MMcf/d cryogenic processing plant for our North Texas System to meet increasing production, continued producer activity and expected volumes from significant new acreage dedications in the liquids-rich, oily areas of the Barnett Shale.  The new processing plant, which will be located in Wise County, Texas, is expected to be operational in mid-2013, subject to regulatory approvals, and is expected to require a capital investment related to the plant and associated projects that are currently estimated at approximately $150 million.
 
 
2011 Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, requires additional disclosures with regard to fair value measurements categorized within Level 3 of the fair value hierarchy. Early adoption is not permitted.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, stipulates the financial statement presentation requirements for other comprehensive income. Our financial statement presentation complies with this standards update.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, allows entities to first assess qualitative factors when testing goodwill for impairment. Early adoption is permitted.

How We Evaluate Our Operations

Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas and mixed NGLs that 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. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs and the volumes of natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services and changes in our customer mix.
 
Our management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses and (3) the following non-GAAP measures — gross margin, operating margin, adjusted EBITDA and distributable cash flow.
 
Throughput Volumes, Facility Efficiencies and Fuel Consumption. 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 and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business’ fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party gathering or fractionation facilities.
 
In addition, we seek to increase operating margin by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
 
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for our logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.
 
 
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.
 
Gross Margin. We define gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and hedging program. We define Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue, less product purchases, which consists primarily of NGL purchases. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.
 
Operating Margin. Operating margin is an important performance measure of the core profitability of our operations. We define operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.
 
Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by us and by external users of our financial statements, including investors and commercial banks, to assess:

·  
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·  
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

·  
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Adjusted EBITDA. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others.

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 investors.

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
 
 
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Distributable Cash Flow. We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in this measure.

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. 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 and limited liability companies 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 attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. 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.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision making processes.
 
 
Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three and nine months ended September 30, 2011 and 2010:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Reconciliation of gross margin and
 
(In millions)
 
    operating margin to net income:
                       
Gross margin
  $ 227.2     $ 184.8     $ 689.3     $ 550.6  
Operating expenses
    (76.5 )     (66.0 )     (214.1 )     (190.2 )
Operating margin
    150.7       118.8       475.2       360.4  
Depreciation and amortization expenses
    (45.0 )     (43.3 )     (132.2 )     (128.3 )
General and administrative expenses
    (33.7 )     (26.7 )     (98.6 )     (80.0 )
Interest expense, net
    (25.7 )     (27.9 )     (80.4 )     (86.6 )
Income tax expense
    (1.5 )     (1.7 )     (5.2 )     (3.9 )
Gain (loss) on sale of assets
    0.3       -       0.4       -  
Other, net  (1)
    (0.2 )     (0.8 )     (0.6 )     29.8  
Net income
  $ 44.9     $ 18.4     $ 158.6     $ 91.4  
_________
(1)  
Includes gain on mark-to-market derivatives, equity in earnings of unconsolidated investment, insurance claims, and other income (expense).

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(In millions)
 
Reconciliation of net cash provided by
                       
operating activities to Adjusted EBITDA:
                       
Net cash provided by (used in) operating activities
  $ (61.3 )   $ 60.3     $ 191.3     $ 238.9  
Net income attributable to noncontrolling interests
    (9.0 )     (4.6 )     (29.6 )     (18.2 )
Interest expense, net (1)
    24.7       22.2       73.7       52.8  
Current income tax expense
    2.4       1.8       4.6       3.6  
Other (2)
    18.8       (7.6 )     10.8       (7.3 )
Changes in operating assets and liabilities which used (provided) cash:
                               
Accounts receivable and other assets
    105.4       24.5       169.8       (40.3 )
Accounts payable and other liabilities
    26.3       (6.1 )     (76.0 )     52.5  
Adjusted EBITDA
  $ 107.3     $ 90.5     $ 344.6     $ 282.0  
_________
(1)  
Net of amortization of debt issuance costs, discount and premium included in interest expense of: $1.0 million and $6.7 million for the three and nine months ended September 30, 2011; and $1.8 million and $4.4 million for the three and nine months ended September 30, 2010. Excludes affiliate and allocated interest expense.
(2)  
Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.
 
 
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(In millions)
 
Reconciliation of net income attributable to
                       
Targa Resources Partners LP to Adjusted EBITDA:
                       
Net income attributable to Targa Resources Partners LP
  $ 35.9     $ 13.8     $ 129.0     $ 73.2  
Add:
                               
Interest expense, net (1)
    25.7       27.9       80.4       86.6  
Income tax expense
    1.5       1.7       5.2       3.9  
Depreciation and amortization expenses
    45.0       43.3       132.2       128.3  
Risk management activities
    2.0       6.1       6.0       (2.9 )
Noncontrolling interests adjustment
    (2.8 )     (2.3 )     (8.2 )     (7.1 )
Adjusted EBITDA
  $ 107.3     $ 90.5     $ 344.6     $ 282.0  
________
(1)  
Includes affiliate and allocated interest expense.

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(In millions)
 
Reconciliation of net income attributable to Targa
                       
Resources Partners LP to distributable cash flow:
                       
Net income attributable to Targa Resources Partners LP
  $ 35.9     $ 13.8     $ 129.0     $ 73.2  
Affiliate and allocated interest expense
    -       3.9       -       29.4  
Depreciation and amortization expenses
    45.0       43.3       132.2       128.3  
Deferred income tax expense
    (0.9 )     (0.1 )     0.6       0.3  
Amortization in interest expense
    2.5       2.4       8.1       5.1  
Risk management activities
    2.0       6.1       6.0       (2.9 )
Maintenance capital expenditures
    (24.7 )     (12.7 )     (57.2 )     (29.7 )
Other (1)
    5.6       (0.3 )     10.8       (2.9 )
Distributable cash flow
  $ 65.4     $ 56.4     $ 229.5     $ 200.8  
_______
(1)  
Includes reimbursements of certain environmental maintenance capital expenditures by Targa and the non-controlling interest portion of maintenance capital expenditures and depreciation expense.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are set forth in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. There have been no material changes to these policies and estimates during the nine months ended September 30, 2011.
 

Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010 (in millions, except operating and price amounts):

   
Three Months Ended
               
Nine Months Ended
           
   
September 30,
   
2011 vs. 2010
   
September 30,
 
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
   
2011
 
2010
   
$ Change
   
% Change
 
Revenues
  $ 1,712.7     $ 1,218.4     $ 494.3       41%     $ 5,053.8   $ 3,944.6     $ 1,109.2       28%  
Product purchases
    1,485.5       1,033.6       451.9       44%       4,364.5     3,394.0       970.5       29%  
Gross margin (1)
    227.2       184.8       42.4       23%       689.3     550.6       138.7       25%  
Operating expenses
    76.5       66.0       10.5       16%       214.1     190.2       23.9       13%  
Operating margin (2)
    150.7       118.8       31.9       27%       475.2     360.4       114.8       32%  
Depreciation and
  amortization expenses
    45.0       43.3       1.7       4%       132.2     128.3       3.9       3%  
General and
   administrative expenses
    33.7       26.7       7.0       26%       98.6     80.0       18.6       23%  
Other
    (0.3 )     -       (0.3  
nm
      (0.4 )   -       (0.4  
nm
 
Income from operations
    72.3       48.8       23.5       48%       244.8     152.1       92.7       61%  
Interest expense, net
    (25.7 )     (27.9 )     2.2       (8% )     (80.4 )   (86.6 )     6.2       (7% )
Equity in earnings of unconsolidated investments
    2.2       1.1       1.1       100%       5.2     3.8       1.4       37%  
Gain (loss) on mark-to-market derivative instruments
    (1.8 )     (1.9 )     0.1       (5% )     (5.0 )   26.0       (31.0 )     (119% )
Other
    (0.6 )     -       (0.6 )  
nm
      (0.8 )   -       (0.8 )  
nm
 
Income tax expense
    (1.5 )     (1.7 )     0.2       (12% )     (5.2 )   (3.9 )     (1.3 )     33%  
Net income
    44.9       18.4       26.5       144%       158.6     91.4       67.2       74%  
Less: Net income attributable to
     noncontrolling interests
    9.0       4.6       4.4       96%       29.6     18.2       11.4       63%  
Net income attributable to Targa Resources Partners LP
  $ 35.9     $ 13.8     $ 22.1       160%     $ 129.0   $ 73.2     $ 55.8       76%  
Financial and operating data:
                             
Financial data:
                             
Adjusted EBITDA (3)
  $ 107.3     $ 90.5     $ 16.8       19%     $ 344.6   $ 282.0     $ 62.6       22%  
Distributable cash flow (4)
    65.4       56.4       9.0       16%       229.5     200.8       28.7       14%  
Operating data:
                             
Plant natural gas inlet, MMcf/d (5)(6)
    2,087.0       2,216.4       (129.4 )     (6% )     2,152.8     2,296.5       (143.7 )     (6% )
Gross NGL production, MBbl/d
    121.4       121.6       (0.2 )     (0% )     122.2     120.8       1.4       1%  
Natural gas sales, BBtu/d (6)
    799.7       673.1       126.6       19%       746.6     679.3       67.3       10%  
NGL sales, MBbl/d
    258.9       244.2       14.7       6%       265.1     246.0       19.1       8%  
Condensate sales, MBbl/d
    3.2       3.4       (0.2 )     (6% )     3.2     3.6       (0.4 )     (11% )
__________
(1)  
Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”
(2)  
Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”
(3)  
Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”
(4)  
Distributable cash flow is net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”
(5)  
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(6)  
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
 
 
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Consolidated revenues (including the impacts of hedging) increased due to the higher net impact of realized prices on NGLs and condensate ($377.9 million), higher NGL and natural gas sales volumes ($103.6 million) and higher fee-based and other revenues ($23.1 million), partially offset by lower realized prices on natural gas ($9.2 million) and lower condensate sales volumes ($1.1 million).

Consolidated operating margin increased $31.9 million, reflecting higher gross margin and higher revenues ($494.3 million), partially offset by increases in product purchase costs ($451.9 million) and increased operating expenses ($10.5 million). The increase in operating expenses primarily reflects increased compensation and benefits, maintenance and fuel, utilities and catalyst costs. See “Results of Operations—By Segment” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses of $1.7 million is primarily due to the impact of gathering, fractionating and storage terminal assets purchased in 2011 and expansion projects in service since the third quarter of 2010 ($3.7 million) offset by assets that became fully depreciated in 2010 ($2.0 million).

General and administrative expenses increased $7.0 million reflecting increased compensation and benefits.

Interest expense decreased by $2.2 million attributable to $1.7 million increase in interest expense on third party debt, due to higher borrowings and a higher effective interest rate, offset by a $3.9 million decrease on affiliate and allocated interest expense. There was no interest expense related to affiliate or allocated debt in 2011 as these balances were retired as part of the Permian, Versado and VESCO acquisitions in 2010.

See “—Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Consolidated revenues (including the impacts of hedging) increased due to the net impact of higher realized prices on NGLs and condensate ($823.8 million), higher NGL and natural gas sales volumes ($309.2 million) and higher fee-based and other revenues ($57.2 million), partially offset by lower realized prices on natural gas ($71.9 million) and lower condensate sales volumes ($9.1 million).

Consolidated operating margin increased $114.8 million, reflecting higher gross margin, higher revenues ($1,109.2 million) partially offset by increases in product purchase costs ($970.5 million). The increase in consolidated operating expenses of $23.9 million primarily reflects increased compensation and benefits, maintenance and fuel, utilities and catalyst costs. See “Results of Operations—By Segment” for additional information regarding changes in the components of operating margin on a disaggregated basis.
 
 
The increase in depreciation and amortization expenses of $3.9 million is primarily due to the impact of new gathering, fractionating and storage terminal assets in service since the third quarter of 2010 ($8.6 million) offset by assets that became fully depreciated in 2010 ($4.7 million).

General and administrative expenses increased $18.6 million reflecting increased compensation and benefits.

Interest expense decreased by $6.2 million attributable to $23.2 million increase in interest expense on third party debt, due to higher borrowings and a higher effective interest rate, offset by $29.4 million decrease on affiliate and allocated interest expense. There was no interest expense related to affiliate or allocated debt in 2011 as these balances were retired as part of the Permian, Versado and VESCO acquisitions in 2010.

See “—Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Mark-to-market gains decreased $31.0 million, moving from a gain of $26.0 million to a loss of $5.0 million.  The gain in 2010 is attributable to the accounting treatment of commodity derivatives related to the Permian and Versado acquisitions during 2010. Under common control accounting, these derivatives did not qualify for hedge accounting treatment for predecessor periods prior to our acquisition of the assets. Therefore, changes in fair value for these instruments were recorded in earnings. These derivative instruments were designated as hedges as of the date of these acquisitions, and therefore changes in value subsequent to those dates are recorded in OCI until the underlying transactions settle. The loss in 2011 is attributable to interest rate swaps that did not qualify for hedge accounting as of February 11, 2011 and losses recorded when we terminated these swaps on September 6, 2011.

Results of Operations—By Segment

Our operating margin by reportable segment is:
 
 
Field
 
Coastal
                     
 
Gathering
 
Gathering
     
Marketing
     
Corporate
     
 
and
 
and
 
Logistics
 
and
     
and
     
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Total
 
 
(In millions)
 
Three Months Ended September 30, 2011
$ 71.8   $ 39.8   $ 30.1   $ 19.7   $ (10.8 ) $ 0.1   $ 150.7  
Three Months Ended September 30, 2010
  49.6     23.5     23.6     15.0     7.1     -     118.8  
                                           
Nine Months Ended September 30, 2011
$ 213.0   $ 121.8   $ 85.9   $ 82.8   $ (28.4 ) $ 0.1   $ 475.2  
Nine Months Ended September 30, 2010
  176.8     74.9     52.9     48.8     7.0     -     360.4  
 
 
Natural Gas Gathering and Processing Segments
 
Field Gathering and Processing
 
   
Three Months Ended
               
Nine Months Ended
             
   
September 30,
   
2011 vs. 2010
   
September 30,
   
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
   
2011
   
2010
   
$ Change
   
% Change
 
   
($ in millions)
 
Gross margin
  $ 102.4     $ 77.4     $ 25.0       32%     $ 299.3     $ 250.4     $ 48.9       20%  
Operating expenses
    30.6       27.8       2.8       10%       86.3       73.6       12.7       17%  
Operating margin
  $ 71.8     $ 49.6     $ 22.2       45%     $ 213.0     $ 176.8     $ 36.2       20%  
Operating statistics:
                                                               
Plant natural gas inlet, MMcf/d (1),(2)
    628.2       583.7       44.5       8%       604.4       582.0       22.4       4%  
Gross NGL production, MBbl/d
    75.1       70.6       4.5       6%       73.1       70.2       2.9       4%  
Natural gas sales, BBtu/d (2),(3)
    295.8       254.5       41.3       16%       281.2       257.2       24.0       9%  
NGL sales, MBbl/d (3)
    60.2       54.9       5.3       10%       58.9       55.6       3.3       6%  
Condensate sales, MBbl/d (3)
    3.0       3.1       (0.1 )     (3% )     2.9       3.0       (0.1 )     (3% )
Average realized prices (4):
                                                               
Natural gas, $/MMBtu
    4.03       3.99       0.04       1%       3.96       4.29       (0.33 )     (8% )
NGL, $/gal
    1.29       0.85       0.44       52%       1.22       0.90       0.32       36%  
Condensate, $/Bbl
    85.99       72.10       13.89       19%       91.99       73.82       18.17       25%  
________
(1)  
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(2)
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(3)
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(4)
Average realized prices exclude the impact of hedging activities.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $25.0 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($106.1 million), higher natural gas and NGL sales volumes ($32.4 million) and higher fee based and other revenues ($0.9 million), partially offset by higher product purchases ($113.7 million) and lower condensate sales volumes ($0.7 million). The increase in plant inlet volumes was largely attributable to new well connects throughout the systems, particularly North Texas, SAOU and Sand Hills, partially offset by operational outages and production declines at the Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.
 
The $2.8 million increase in operating expenses was primarily due to higher fuel, utilities and catalysts expenses ($0.9 million), higher compensation and benefit costs ($1.0 million) and higher contract and professional service expenses ($0.4 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $48.9 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($225.6 million), higher natural gas and NGL volumes ($61.9 million) and  higher fee based and other revenues ($3.1 million), partially offset by higher product purchases ($214.5 million), lower natural gas sales prices ($24.8 million), and lower condensate sales volumes ($2.2 million). The increase in plant inlet volumes was largely attributable to new well connects throughout the systems, particularly North Texas and SAOU, partially offset by the impact of severe cold weather in the first quarter of 2011 and operational outages in the first quarter and third quarter of 2011and production declines at the Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.
 
The $12.7 million increase in operating expenses was primarily due to higher fuel, utilities and catalysts expenses ($3.7 million), higher system maintenance expenses ($3.0 million) due to severe cold weather and operational outages in the first quarter of 2011, higher compensation and benefit costs ($3.8 million) and higher contract and professional service expenses ($2.5 million).
 
 
Coastal Gathering and Processing

   
Three Months Ended
September 30,
   
2011 vs. 2010
   
Nine Months Ended
September 30,
   
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
   
2011
   
2010
   
$ Change
   
% Change
 
   
($ in millions)
 
Gross margin
  $ 52.9     $ 34.2     $ 18.7       55%     $ 156.6     $ 106.3     $ 50.3       47%  
Operating expenses
    13.1       10.7       2.4       22%       34.8       31.4       3.4       11%  
Operating margin
  $ 39.8     $ 23.5     $ 16.3       69%     $ 121.8     $ 74.9     $ 46.9       63%  
Operating statistics:
                                                               
Plant natural gas inlet, MMcf/d (1),(2),(3)
    1,458.8       1,632.7       (173.9 )     (11% )     1,548.3       1,714.5       (166.2 )     (10% )
Gross NGL production, MBbl/d
    46.3       51.0       (4.7 )     (9% )     49.1       50.5       (1.4 )     (3% )
Natural gas sales, Bbtu/d (3),(4)
    256.6       293.1       (36.5 )     (12% )     261.0       306.2       (45.2 )     (15% )
NGL sales, MBbl/d (4)
    41.6       42.4       (0.8 )     (2% )     43.0       44.0       (1.0 )     (2% )
Condensate sales, MBbl/d (4)
    0.2       0.2       -       -       0.3       0.6       (0.3 )     (50% )
Average realized prices (5):
                                                               
Natural gas, $/MMBtu
    4.21       4.40       (0.19 )     (4% )     4.24       4.64       (0.40 )     (9% )
NGL, $/gal
    1.35       0.93       0.42       45%       1.30       1.00       0.30       30%  
Condensate, $/Bbl
    107.72       72.42       35.30       49%       102.38       78.45       23.93       31%  
__________
(1)  
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(2)  
The majority of our Coastal Straddle plant volumes are gathered on thirt-party offshore pipeline systems and delivered to the plant inlets.
(3)  
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(4)  
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation.
(5)  
Average realized prices exclude the impact of hedging activities.
 
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $18.7 million increase in gross margin for 2011 is primarily due to higher NGL and condensate sales prices ($68.0 million), partially offset by an increase in product purchases ($26.8 million), and by decreases in commodity sales volumes ($17.7 million), natural gas sales prices ($4.5 million) and fee-based and other revenues ($0.3 million). The decrease in plant inlet volumes was largely attributable to a decline in traditional wellhead and offshore supply volumes. The decreased NGL sales volumes were primarily due to lower throughput and NGL production volumes. Natural gas sales volumes decreased due to lower inlet volumes.

The $2.4 million increase in operating expenses was primarily due to higher compensation and benefit costs ($0.4 million), higher contract and professional service expenses ($0.6 million) and higher miscellaneous expenses ($1.3 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $50.3 million increase in gross margin for 2011 is primarily due to an increase in NGL and condensate sales prices ($148.8 million), an increase in fee-based and other revenues ($2.0 million) and a decrease in product purchases ($4.9 million), partially offset by a decrease in natural gas sales prices ($28.7 million) and a decrease in commodity sales volumes ($76.7 million). The decrease in plant inlet volumes was largely attributable to a decline in traditional wellhead and offshore supply volumes. The decreased NGL sales volumes were primarily due to lower throughput and NGL production volumes. Natural gas sales volumes decreased due to lower inlet volumes.

The $3.4 million increase in operating expenses was primarily due to higher compensation and benefit costs ($0.9 million), higher contract and professional service expenses ($0.2 million) and higher miscellaneous expenses ($1.7 million).
 
 
Logistics and Marketing Segments

Logistics Assets

   
Three Months Ended
September 30,
   
2011 vs. 2010
   
Nine Months Ended
September 30,
   
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
   
2011
   
2010
   
$ Change
   
% Change
 
   
($ in millions)
 
Gross margin
  $ 60.1     $ 43.1     $ 17.0       39%     $ 160.3     $ 121.5     $ 38.8       32%  
Operating expenses
    30.0       19.5       10.5       54%       74.4       68.6       5.8       8%  
Operating margin
  $ 30.1     $ 23.6     $ 6.5       28%     $ 85.9     $ 52.9     $ 33.0       62%  
Operating statistics: (1)
                                                               
Fractionation volumes, MBbl/d
    290.4       224.6       65.8       29%       260.1       220.9       39.2       18%  
Treating volumes, MBbl/d
    23.3       23.8       (0.5 )     (2% )     20.5       17.8       2.7       15%  
________
(1)
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010
 
The $17.0 million increase in gross margin primarily reflects increased fractionation volumes ($13.1 million) and higher terminaling and storage revenue ($3.4 million).  Growth in terminaling and storage revenue is primarily due to increased supply services to petrochemical customers at the Mont Belvieu terminal and higher LPG exports at the Galena Park terminal. Additionally, operations of the recently acquired Channelview Terminal and one full quarter of operations of the 78 MBbl/d expansion of the Cedar Bayou facility resulted in higher throughput and increased gross margin.
 
The $10.5 million increase in operating expenses was primarily due to increases in natural gas volumes for fuel to fractionators due to the expansion of the Cedar Bayou fractionation facility, utilities ($2.9 million), NGL transportation fees ($2.5 million), higher costs associated with fractionation maintenance ($2.3 million), contractor and professional services ($1.5 million) and compensation and benefit costs ($1.4 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010
 
The $38.8 million increase in gross margin reflects higher terminaling and storage revenue ($14.7 million) and increased fractionation volumes ($21.3 million). Growth in terminaling and storage revenue is primarily due to increased supply services to petrochemical customers at the Mont Belvieu terminal and higher LPG exports at the Galena Park terminal. Additionally, two full quarters of operations of the recently acquired Channelview Terminal and of the 78 MBbl/d expansion of the Cedar Bayou facility resulted in higher throughput and increased gross margin.

The $5.8 million increase in operating expenses was primarily due to increases in natural gas volumes for fuel to fractionators due to the expansion of the Cedar Bayou fractionation facility, utilities ($5.1 million), compensation and benefits ($3.4 million), NGL transportation fees ($3.4 million), maintenance ($2.4 million) and contractor and professional services ($1.4 million), partially offset by a more favorable system product volume gain ($8.0 million) and a decrease in miscellaneous expenses ($1.5 million).
 
 
Marketing and Distribution

   
Three Months Ended
               
Nine Months Ended
             
   
September 30,
   
2011 vs. 2010
   
September 30,
   
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
   
2011
   
2010
   
$ Change
   
% Change
 
   
($ in millions)
 
Gross margin
  $ 30.1     $ 26.4     $ 3.7       14%     $ 116.0     $ 82.3     $ 33.7       41%  
Operating expenses
    10.4       11.4       (1.0 )     (9% )     33.2       33.5       (0.3 )     (1% )
Operating margin
  $ 19.7     $ 15.0     $ 4.7       31%     $ 82.8     $ 48.8     $ 34.0       70%  
Operating statistics: (1)
                                                               
Natural gas sales, BBtu/d
    962.1       612.6       349.5       57%       829.1       630.1       199.0       32%  
NGL sales, MBbl/d
    264.5       242.9       21.6       9%       267.3       241.3       26.0       11%  
Average realized prices:
                                                               
Natural gas, $/MMBtu
    4.10       4.22       (0.12 )     (3% )     4.15       4.50       (0.35 )     (8% )
NGL realized price, $/gal
    1.32       0.95       0.37       39%       1.32       1.06       0.26       25%  
________
(1)  
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $3.7 million increase in gross margin was due to higher NGL volumes ($79.0 million) and natural gas volumes ($135.6 million), higher NGL prices ($386.0 million) and higher fee-based and other revenues ($13.6 million), offset by lower natural gas prices ($10.7 million) and increased product purchases ($599.5 million).  Increased NGL export sales contributed to a higher operating margin in 2011. Natural gas sales volumes increased due to higher purchases for resale.

Operating expenses decreased by $1.0 million due to lower contractor and professional services expenses ($1.3 million) offset by higher compensation benefits ($0.3 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $33.7 million increase in gross margin was due to higher NGL volumes ($314.6 million) and natural gas volumes ($244.4 million), higher NGL prices ($789.6 million) and higher fee-based and other revenues ($25.7 million), offset by lower natural gas prices ($79.0 million) and increased product purchases ($1,269.7 million). Factors contributing to a higher operating margin in 2011 included increased NGL export sales and the positive impact of a contract settlement ($7.5 million) related to the current contract period of a multi-year propane exchange agreement.  The contract, as restructured, provides for future payments during future contract periods through November 2014. Natural gas sales volumes increased due to higher purchases for resale.

Other

   
Three Months Ended
         
Nine Months Ended
       
   
September 30,
         
September 30,
       
   
2011
   
2010
   
Change
   
2011
   
2010
   
Change
 
   
(In millions)
 
Gross margin
  $ (10.8 )   $ 7.1     $ (17.9 )   $ (28.4 )   $ 7.0     $ (35.4 )
Operating margin
  $ (10.8 )   $ 7.1     $ (17.9 )   $ (28.4 )   $ 7.0     $ (35.4 )

Other contains the financial effects of our hedging program on profitability.  The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. We have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes by entering into derivative financial instruments. These hedge positions will increase our margins in periods of falling prices and decrease our margins in periods of rising prices.
 
 
The following table provides a breakdown of our hedge results by product:

 
Three Months Ended
       
Nine Months Ended
       
 
September 30,
       
September 30,
       
 
2011
 
2010
   
Change
 
2011
 
2010
   
Change
 
 
(In Millions)
 
Natural Gas
  $ 6.4     $ 7.8     $ (1.4 )   $ 14.2     $ 14.8     $ (0.6 )
NGL
    (15.8 )     (0.7 )     (15.1 )     (38.0 )     (6.8 )     (31.2 )
Crude
    (1.4 )     -       (1.4 )     (4.6 )     (1.0 )     (3.6 )
    $ (10.8 )   $ 7.1     $ (17.9 )   $ (28.4 )   $ 7.0     $ (35.4 )

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness and to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our senior secured credit facility, the issuance of additional common units and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

We may issue additional equity or debt securities to assist us in meeting future liquidity and capital spending requirements. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $500.0 million of debt or equity securities (the “2009 Shelf”). As of September 30, 2011, we had $245.3 million of unsold securities available under the 2009 Shelf. On October 21, 2011, we filed a prospectus supplement under the 2009 Shelf that allows us to issue common units, representing limited partner interests having an aggregate offering price of up to $100.0 million from time to time through an Equity Distribution Agreement with Citigroup Global Markets, Inc. Sales of common units, if any, will be by means of ordinary brokers’ transactions through the facilities of the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent.

We also have filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. Our April 2010, August 2010 and January 2011 equity offerings were conducted under the 2010 Shelf.
 
We continue to evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
 
Crude oil and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas and NGL equity volumes through 2013 and our condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations to the extent that such operating margins and cash flows derive from the portion of equity volumes that are not hedged.

Our risk management position has moved from a net liability of $22.9 million at December 31, 2010 to a net asset of $10.6 million at September 30, 2011. We terminated our interest rate swap contracts in September 2011, which eliminated a liability of $23.0 million from our books. Additionally, forward prices for crude and natural gas have decreased to levels below the fixed prices we receive on our derivative contracts. Therefore, our expected future receipts on these contracts are greater than our expected future payments, resulting in a net asset position. We account for derivatives that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in OCI until the underlying hedged transactions settle.
 
 
As of September 30, 2011, our liquidity of $545.6 million consisted of $68.9 million of available cash and $476.7 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.
 
Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facility should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distribution for at least the next twelve months.
  
A significant portion of our capital resources may be utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status, as assigned to us by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation, and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At September 30, 2011, our total outstanding letter of credit postings were $88.3 million.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily due to changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities and availability under our credit facility will be sufficient to meet our operating requirements for the next twelve months.

Cash Flow

The following table and discussion summarize our consolidated cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated:

     
Nine Months Ended September 30,
   
2011 vs. 2010
 
   
2011
   
2010
   
$ Change
   
% Change
 
 
(In millions)
           
Net cash provided by (used in):
                       
Operating activities
  $ 191.3     $ 238.9     $ (47.6 )     (20% )
Investing activities
    (387.2 )     (79.3 )     (307.9 )     (388% )
Financing activities
    188.5       (196.0 )     384.5       196%  
 
 
Operating Activities

Our Consolidated Statement of Cash Flows employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented. The following table displays our operating cash flows using the direct method as a supplement to the presentation in our financial statements.

             
   
Nine Months Ended September 30,
       
   
2011
   
2010
   
Variance
 
Cash flows from operating activities:
                 
Cash received from customers
  $ 5,005.9     $ 3,993.2     $ 1,012.7  
Cash received (paid) on derivative transactions (1)
    (47.7 )     28.5       (76.2 )
Cash paid for:
                       
Product purchases
    (4,379.5 )     (3,478.5 )     (901.0 )
Operating expenses
    (211.3 )     (192.5 )     (18.8 )
General and administrative expenses (2)
    (95.2 )     (52.4 )     (42.8 )
Cash distributions from equity investment
    3.7       3.7       -  
Interest paid - net
    (81.6 )     (60.7 )     (20.9 )
Income taxes paid
    (2.3 )     (2.3 )     -  
Other cash receipts (payments)
    (0.7 )     (0.1 )     (0.6 )
Net cash provided by operating activities
  $ 191.3     $ 238.9     $ (47.6 )
_______
(1)  
The change in cash paid to derivative counterparties reflects the change in our net position from in-the-money for the period ending September 30, 2010 to out-of-the-money for the period ending September 30, 2011, and a payment for interest rate swap termination in the amount of $23.0 million, excluding $1.2 million accrued interest, in September 2011.
(2)  
The increase in general and administrative cash payments results from higher 2011 intercompany settlements following the completion during April through September 2010 of the remaining asset drop downs.

Investing Activities

Net cash used in investing activities increased by $307.9 million for the nine months ended September 30, 2011 compared to 2010. The increase was primarily due to our petroleum logistics acquisitions of $164.2 million and a $103.5 million increase in expansion capital projects in gathering and processing assets and in fractionation assets. We also invested $11.9 million in equity contributions associated with the expansion at Gulf Coast Fractionators.

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2011 was $188.5 million compared to net cash used in financing activities of $196.0 million for the nine months ended September 30, 2010. The increase was due to two primary factors: changes in our equity offerings and financing activities and distributions.
 
 
Net proceeds from public offerings, issuance of senior notes and borrowings under our credit facility less repayments on our credit facility increased $269.6 million from $101.7 million for the nine months ended September 30, 2010 to $371.3 million for the nine months ended September 30, 2011. Our primary financing activities that occurred during the nine months ended September 30, 2011 were:
 
·  
On January 24, 2011, we completed a public offering of 8,000,000 common units in us under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.2 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 we issued an additional 1,200,000 common units, providing net proceeds of approximately $38.8 million. In addition, our general partner contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us.

·  
On February 2, 2011, we closed a private placement of $325.0 million in aggregate principal amount of our 6⅞% Notes resulting in net proceeds of $318.8 million.

·  
On February 4, 2011, we exchanged an additional $158.6 million principal amount of our 6⅞% Notes for $158.6 million aggregate principal amount of our 11¼% Notes. In conjunction with the exchange we paid a cash premium of $28.6 million including $0.9 million of accrued interest.

Net cash from the completion of the unit offering and the note offering less cash paid in connection with the exchange offer was used to reduce outstanding borrowings under our senior secured credit facility by $595.2 million.

Distributions to our Unitholders

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 6 and Note 7 of the notes to Consolidated Financial Statements included in this Quarterly Report.

We intend to make cash distributions to our unitholders and our general partner of at least the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of September 30, 2011, such annual minimum amounts would have been approximately $101.0 million. In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate. The quarterly distribution per limited partner unit paid in August 2011 for the second quarter of 2011 was $0.5700 per unit.

For the nine months ended September 30, 2011 compared to 2010, total distributions increased by $48.1 million. The following table shows the distributions for 2011 and 2010:

     
Distributions (1)
       
     
Limited Partners
   
General Partner
             
Date Paid
For the Three Months Ended
 
Common
   
Incentive
      2%    
Total
   
Distribution per limited partner unit
 
     
(In millions, except per unit amounts)
       
August 12, 2011
June 30, 2011
  $ 48.3     $ 7.8     $ 1.2     $ 57.3     $ 0.5700  
May 13, 2011
March 31, 2011
    47.3       6.8       1.1       55.2       0.5575  
February 14, 2011
December 31, 2010
    46.4       6.0       1.1       53.5       0.5475  
 November 12, 2010
September 30, 2010
    40.6       4.6       0.9       46.1       0.5375  
August 13, 2010
June 30, 2010
    35.9       3.5       0.8       40.2       0.5275  
May 14, 2010
March 31, 2010
    35.2       2.8       0.8       38.8       0.5175  
February 12, 2010
December 31, 2009
    35.2       2.8       0.8       38.8       0.5175  
_______
(1)  
On October 11, 2011, we announced a cash distribution of $0.5825 per common unit on our outstanding common units for the three months ended September 30, 2011, to be paid on November 14, 2011. The distribution to be paid is $42.6 million to our third-party limited partners, and $6.8 million, $8.8 million and $1.2 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in us.
 
 
Capital Requirements

The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and equipment additions and the difference, which is primarily settled accruals and non-cash additions:

 
Nine Months Ended
 
 
September 30,
 
 
2011
 
2010
 
     
Gross additions to property, plant and equipment
$ 242.1   $ 82.1  
Change in accruals
  (1.7 )   0.4  
Cash expenditures
$ 240.4   $ 82.5  
             

The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and the expansion of our logistics assets.

We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets.

 
Nine Months Ended
 
 
September 30,
 
 
2011
 
2010
 
Capital expenditures:
 
Business acquisitions
$ 164.2   $ -  
Expansion
  155.9     52.4  
Maintenance
  57.2     29.7  
  $ 377.3   $ 82.1  

Including business acquisitions, we estimate that our total capital expenditures for 2011 will be approximately $520 million gross and $480 million net of non-controlling interest share and reimbursements.  We also estimate that of the $480 million net capital expenditures, approximately 15% will be for maintenance. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Major capital projects include:

·  
$360 million expansion project at CBF to add a fourth fractionation train and related infrastructure enhancements at Mont Belvieu;

·  
$250 million expansion of our Mont Belvieu complex and our existing import/export marine terminal at Galena Park to export international grade propane;

·  
$150 million for a new cryogenic processing plant and associated projects for our North Texas System;

·  
$60 million expansion of our petroleum logistics assets;

·  
$40 million capital expansion project to expand the gathering and processing capability of our North Texas System;

·  
$35 million benzene treatment project at Mont Belvieu to construct a treater designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards;

·  
$30 million capital expansion project to expand the gathering and processing capability of our SAOU System;

·  
$13 million expansion of our dock facilities and related infrastructure enhancements at Galena Park; and

·  
our portion of the $75 million expansion at Gulf Coast Fractionators, which is expected to be approximately $29 million.
 
 
These capital projects will extend through 2013. Future expansion capital expenditures may vary significantly based on investment opportunities.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured revolving credit facility, the issuance of additional common units and debt offerings.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, changes in interest rates, as well as nonperformance by our customers. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk.  A majority of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk” in our Annual Report.

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover specific NGL products based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our NGL hedges’ fair values are based on published index prices for delivery at Mont Belvieu through 2013. Our natural gas hedges’ fair values are based on published index prices for delivery at various locations which closely approximate the actual NGL and natural gas delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
 
These commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.
 
For all periods presented we have entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). During the three and nine months ended September 30, 2011, our operating revenues were increased (decreased) by net hedge adjustments on commodity derivative contracts of $(10.8) million and $(28.4) million. During the three and nine months ended September 30, 2010 our operating revenues were increased (decreased) by net hedge adjustments on commodity derivative contracts of $7.1 million and $7.0 million.


As of September 30, 2011, we had the following hedge arrangements which will settle during the years ending December 31, 2011 through 2014 (except as indicated otherwise, the 2011 volumes reflect daily volumes for the period from October 1, 2011 through December 31, 2011):
 
Natural Gas
     
Instrument
     
Price
 
MMBtu per day
           
Type
 
Index
 
$/MMBtu
 
2011 
 
2012 
 
2013 
 
Fair Value
     
                       
(In millions)
     
Swap
 
IF-WAHA
 
6.29 
 
 23,750 
         
$
 5.7 
     
Swap
 
IF-WAHA
 
6.61 
     
 14,850 
       
 13.5 
     
Swap
 
IF-WAHA
 
5.28 
         
 7,230 
   
 1.6 
     
Total Swaps
         
 23,750 
 
 14,850 
 
 7,230 
           
Swap
 
IF-PB
 
4.58 
 
 6,565 
           
 0.6 
     
Swap
 
IF-PB
 
4.98 
     
 10,200 
       
 3.4 
     
Swap
 
IF-PB
 
5.23 
         
 7,084 
   
 1.6 
     
Total Swaps
         
 6,565 
 
 10,200 
 
 7,084 
           
Swap
 
IF-NGPL MC
 
5.66 
 
 8,155 
           
 1.5 
     
Swap
 
IF-NGPL MC
 
6.03 
     
 6,740 
       
 4.7 
     
Swap
 
IF-NGPL MC
 
4.89 
         
 2,775 
   
 0.3 
     
Total Swaps
         
 8,155 
 
 6,740 
 
 2,775 
           
Total Sales
         
 38,470 
 
 31,790 
 
 17,089 
           
Natural Gas Basis Swaps
                   
Basis Swaps
 
Various Indexes, Maturities Through December 2012
 
 0.3 
     
                       
$
 33.2 
     
           
 
                   
NGL
     
Instrument
     
Price
 
 Barrels per day
           
 Type
 
 Index
 
 $/Gal
 
2011 
 
2012 
 
2013 
 
 Fair Value
     
                       
(In millions)
     
Swap
 
 OPIS-MB
 
0.92 
 
10,118 
         
 $
 (14.0)
     
Swap
 
 OPIS-MB
 
0.95 
     
9,361 
       
 (20.3)
     
Swap
 
 OPIS-MB
 
0.98 
         
4,150 
   
 (3.9)
     
Total Swaps
         
 10,118 
 
 9,361 
 
 4,150 
           
 Floor
 
 OPIS-MB
 
1.44 
 
 253 
           
 - 
     
 Floor
 
 OPIS-MB
 
1.43 
     
 294 
       
 0.6 
     
Total Floors
         
 253 
 
 294 
 
 - 
           
Total Sales
         
 10,371 
 
 9,655 
 
 4,150 
           
                       
$
 (37.6)
     
                                 
Condensate
Instrument
     
Price
 
 Barrels per day
     
 Type
 
 Index
 
 $/Bbl
 
2011 
 
2012 
 
2013 
 
2014 
 
 Fair Value
                           
(In millions)
Swap
 
NY-WTI
 
87.87 
 
 1,730 
             
$
 1.3 
Swap
 
NY-WTI
 
91.37 
     
 1,660 
           
 6.2 
Swap
 
NY-WTI
 
91.34 
         
 1,795 
       
 6.2 
Swap
 
NY-WTI
 
90.03 
             
 700 
   
 1.3 
Total Sales
         
 1,730 
 
 1,660 
 
 1,795 
 
 700 
     
                           
$
 15.0 
 
 
These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
 
We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our NGL derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options based on inputs that are readily available in public markets. For the NGL contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those NGL contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity swap and options, the NGL valuations are classified as Level 3 within the fair value hierarchy. See Note 8 to the Consolidated Financial Statements in this Quarterly Report for more information regarding classifications within the fair value hierarchy.
 
Interest Rate Risk. We are exposed to the risk of changes in interest rates as a result of variable rate borrowings under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of September 30, 2011, we had variable rate borrowings of $535.0 million. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $5.4 million.

Counterparty Risk – Credit and Concentration

Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
 
 
As of September 30, 2011, affiliates of Barclays PLC (“Barclays”) and Natixis accounted for 35% and 15% of our counterparty credit exposure related to commodity derivative instruments. Barclays and Natixis are major financial institutions that possess investment grade credit ratings based upon minimum credit ratings assigned by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation.

Customer Credit Risk. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.
 
Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2011, our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered by this Quarterly Report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the three months ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
 
PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 11 – Commitments and Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this Item.

Item 1A. Risk Factors.

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report. These risks and uncertainties are not the only ones facing us, and there may be additional matters of which we are unaware, or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

Recently proposed rules regulating air emissions from oil and natural gas operations could cause us as well as natural gas exploration and production operators to incur increased capital expenditures and operating costs as well as cause us to experience reduced demand for our gathering, processing or fractionation services.

On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules combined with other federal and state rules that regulate air emissions that impact natural gas gathering and processing operations would establish new operating requirements for our business. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our customer’s as well as our operations including the installation of new equipment. Compliance with such rules could result in significant costs as well as delays in well completions by our customers, including increased capital expenditures and operating costs, which may adversely impact our business. Moreover, the incurrence of such expenditures and costs by our exploration and production customers’ could result in reduced production by those customers and thus translate into reduced demand for our gathering, processing or fractionation services.

Pipeline safety legislation and regulations expanding integrity management programs or requiring the use of certain safety technologies could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.
 
Congress is currently considering adopting legislation that would establish more stringent pipeline safety requirements. The proposed legislation, if adopted, could impose strengthened pipeline integrity management system requirements, including expanding those requirements to pipelines outside high consequence areas, as well as more stringent non-integrity pipeline measures such as the use of automatic or remote-controlled shut-off valves on pipeline facilities. In addition, on May 5, 2011, the federal Pipeline and Hazardous Materials Safety Administration, or “PHMSA” published a final rule expanding pipeline safety requirements including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner. Also, on August 25, 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines, gathering lines and related facilities including, among other things, whether PHMSA should: (i) re-define the term “gathering line,” (ii) require the submission of annual, incident and safety-related conditions reports by operators of all gathering lines, (iii) establish a new, risk-based regime of safety requirements for large-diameter, high pressure gas gathering lines in rural locations, (iv) enhance the requirements for internal corrosion control of gathering lines, and (v) apply its gas integrity management requirements to onshore gas gathering lines. The adoption of legislation or regulations that apply more comprehensive or stringent safety standards to gathering lines could require us to install new or modified safety controls, pursue added capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant and have a material adverse effect on our financial position or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. (Removed and Reserved.)

Item 5. Other Information.

Not applicable.
 
 
Item 6. Exhibits.

Exhibit
Number
 
Description
     
3.1
 
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
     
3.2
 
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
     
3.3
 
Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
     
3.4
 
First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
     
3.5
 
Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
     
3.6
 
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
     
4.1*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated June 18, 2008, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
4.2*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated August 13, 2010, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
4.3*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated February 2, 2011, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
10.1
 
Equity Distribution Agreement, dated October 21, 2011 by and among Targa Resources Partners LP and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 1.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2011 (File No. 001-33303)).
     
31.1*
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
31.2*
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
32.1**
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
32.2**
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
101.INS**
 
XBRL Instance Document
     
101.SCH**
 
XBRL Taxonomy Extension Schema Document
     
101.CAL**
 
XBRL Taxonomy Extension Calculation Linkbase Document
     
101.DEF**
 
XBRL Taxonomy Extension Definition Linkbase Document
     
101.LAB**
 
XBRL Taxonomy Extension Label Linkbase Document
     
101.PRE**
 
XBRL Taxonomy Extension Presentation Linkbase Document
     
*
 
Filed herewith
     
**
 
Furnished herewith
 
 
Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Targa Resources Partners LP
(Registrant)

By:   Targa Resources GP LLC,
 its general partner


By:   /s/ Matthew J. Meloy
Matthew J. Meloy
Senior Vice President, Chief Financial Officer and Treasurer
(Authorized Officer and Principal Financial Officer)


Date: November 4, 2011
 
 
Exhibit Index

Exhibit
Number
 
Description
     
3.1
 
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
     
3.2
 
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
     
3.3
 
Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
     
3.4
 
First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
     
3.5
 
Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
     
3.6
 
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
     
4.1*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated June 18, 2008, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
4.2*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated August 13, 2010, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
4.3*
 
Supplemental Indenture dated October 28, 2011 to Indenture dated February 2, 2011, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
     
10.1
 
Equity Distribution Agreement, dated October 21, 2011 by and among Targa Resources Partners LP and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 1.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2011 (File No. 001-33303)).
     
31.1*
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
31.2*
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
32.1**
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
32.2**
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
101.INS**
 
XBRL Instance Document
     
101.SCH**
 
XBRL Taxonomy Extension Schema Document
     
101.CAL**
 
XBRL Taxonomy Extension Calculation Linkbase Document
     
101.DEF**
 
XBRL Taxonomy Extension Definition Linkbase Document
     
101.LAB**
 
XBRL Taxonomy Extension Label Linkbase Document
     
101.PRE**
 
XBRL Taxonomy Extension Presentation Linkbase Document
     
*
 
Filed herewith
     
**
 
Furnished herewith
 
 
49