XFRA:ZVK Targa Resources Partners LP Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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 March 31, 2012

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
 
GRAPHIC
 
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 May 1, 2012, there were 89,170,989 Common Units and 1,819,817 General Partner Units outstanding.
 
 
 

 

PART I—FINANCIAL INFORMATION
 
   
   
   
   
   
   
   
19 
   
33 
   
35 
   
PART II—OTHER INFORMATION
 
   
36 
   
36 
   
36 
   
36 
   
36 
   
36 
   
37 
   
SIGNATURES
 
   
38 
 
 
1

 
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” or “our”) 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 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 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, 2011 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

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
U.S. gallons
LPG
Liquefied petroleum gas
MBbl
Thousand barrels
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
NGL(s)
Natural gas liquid(s)
NYMEX
New York Mercantile Exchange
GAAP
Accounting principles generally accepted in the United States of America
NYSE
New York Stock 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


PART I – FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
  TARGA RESOURCES PARTNERS LP
 
  CONSOLIDATED BALANCE SHEETS
 
 
March 31,
 
December 31,
 
 
2012
 
2011
 
 
 
 
 
 
 
(Unaudited)
 
 
(In millions)
 
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
$ 86.3   $ 55.6  
Trade receivables, net of allowances of $1.9 million and $2.2 million
  462.6     575.9  
Inventory
  45.4     92.1  
Assets from risk management activities
  40.5     41.0  
Other current assets
  2.4     2.7  
Total current assets
  637.2     767.3  
Property, plant and equipment
  3,885.9     3,786.9  
Accumulated depreciation
  (1,026.7 )   (980.8 )
Property, plant and equipment, net
  2,859.2     2,806.1  
Long-term assets from risk management activities
  9.0     10.9  
Investment in unconsolidated affiliate
  42.7     36.8  
Other long-term assets
  39.0     36.9  
Total assets
$ 3,587.1   $ 3,658.0  
 
           
LIABILITIES AND OWNERS' EQUITY
       
Current liabilities:
           
Accounts payable and accrued liabilities
$ 501.1   $ 647.8  
Accounts payable to Targa Resources Corp.
  54.0     60.0  
Liabilities from risk management activities
  28.3     41.1  
Total current liabilities
  583.4     748.9  
Long-term debt
  1,380.4     1,477.7  
Long-term liabilities from risk management activities
  13.9     15.8  
Deferred income taxes
  9.9     9.5  
Other long-term liabilities
  45.3     44.4  
 
           
Commitments and contingencies (see Note 11)
           
 
           
Owners' equity:
           
Common unitholders (89,170,989 and 84,756,009 units issued and
           
outstanding as of March 31, 2012  December 31, 2011)
  1,389.9     1,221.2  
General partner (1,819,817 and 1,729,715 units issued and
           
outstanding as of March 31, 2012  December 31, 2011)
  32.5     27.2  
Accumulated other comprehensive loss
  (10.1 )   (25.6 )
 
  1,412.3     1,222.8  
Noncontrolling interests in subsidiaries
  141.9     138.9  
Total owners' equity
  1,554.2     1,361.7  
Total liabilities and owners' equity
$ 3,587.1   $ 3,658.0  
 
           
See notes to consolidated financial statements.
       
 
 
TARGA RESOURCES PARTNERS LP
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
 
 
 
 
 
(Unaudited)
 
 
(In millions, except per unit amounts)
 
Revenues
$ 1,645.5   $ 1,615.1  
Costs and expenses:
           
Product purchases
  1,384.1     1,401.2  
Operating expenses
  71.6     65.9  
Depreciation and amortization expenses
  46.7     42.7  
General and administrative expenses
  32.9     31.8  
Income from operations
  110.2     73.5  
Other income (expense):
           
Other interest expense, net
  (29.4 )   (27.5 )
Equity in earnings of unconsolidated investment
  2.1     1.7  
Other
  (0.1 )   (0.2 )
Income before income taxes
  82.8     47.5  
Income tax expense:
           
Current
  (0.6 )   (1.4 )
Deferred
  (0.4 )   (0.4 )
 
  (1.0 )   (1.8 )
Net income
  81.8     45.7  
Less: Net income attributable to noncontrolling interests
  11.7     7.9  
Net income attributable to Targa Resources Partners LP
$ 70.1   $ 37.8  
 
           
Net income attributable to general partner
  14.1     7.6  
Net income attributable to limited partners
  56.0     30.2  
Net income attributable to Targa Resources Partners LP
$ 70.1   $ 37.8  
 
           
Net income per limited partner unit - basic
$ 0.64   $ 0.37  
Net income per limited partner unit - diluted
$ 0.63   $ 0.37  
Weighted average limited partner units outstanding - basic
  88.1     82.3  
Weighted average limited partner units outstanding - diluted
  88.2     82.3  
 
           
See notes to consolidated financial statements.
 
 
 
TARGA RESOURCES PARTNERS LP
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
 
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
 
 
 
 
 
(Unaudited)
 
 
(In millions)
 
Net income
$ 81.8   $ 45.7  
Other comprehensive income:
           
Commodity hedging contracts:
           
Change in fair value
  15.4     (61.3 )
Settlements reclassified to revenues
  (2.2 )   4.6  
Interest rate swaps:
           
Change in fair value
  -     0.2  
Settlements reclassified to interest expense, net
  2.3     2.5  
Other comprehensive income (loss)
  15.5     (54.0 )
Comprehensive income (loss)
  97.3     (8.3 )
Less: Comprehensive income attributable to
           
noncontrolling interests
  11.7     7.9  
Comprehensive income (loss) attributable to
           
Targa Resources Partners LP
$ 85.6   $ (16.2 )
 
           
See notes to consolidated financial statements.
 
 
 
TARGA RESOURCES PARTNERS LP
 
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
Limited Partner
 
General Partner
 
Comprehensive
 
Noncontrolling
 
 
 
 
Units
 
Amount
 
Units
 
Amount
 
Income (Loss)
 
Interests
 
Total
 
 
(Unaudited)
 
 
(In millions, except units in thousands)
 
Balance, December 31, 2011
84,756   $ 1,221.2   1,730   $ 27.2     (25.6 )   138.9     1,361.7  
Compensation on equity grants
10     1.0   -     -     -     -     1.0  
Proceeds from equity offerings
4,405     165.0   90     3.4     -     -     168.4  
Contributions from Targa Resources Corp.
-     0.4   -     0.1     -     -     0.5  
Distributions to noncontrolling interests
-     -   -     -     -     (10.1 )   (10.1 )
Contributions from noncontrolling interests
-     -   -     -     -     1.4     1.4  
Other comprehensive income
-     -   -     -     15.5     -     15.5  
Net income
-     56.0   -     14.1     -     11.7     81.8  
Distributions to unitholders
-     (53.7 ) -     (12.3 )   -     -     (66.0 )
Balance, March 31, 2012
89,171   $ 1,389.9   1,820   $ 32.5   $ (10.1 ) $ 141.9   $ 1,554.2  
 
                                     
Balance, December 31, 2010
75,545   $ 935.3   1,542   $ 15.1     (30.6 )   129.3     1,049.1  
Compensation on equity grants
11     0.2   -     -     -     -     0.2  
Proceeds from equity offerings
9,200     298.1   188     6.3     -     -     304.4  
Contributions from Targa Resources Corp.
-     2.2   -     0.3     -     -     2.5  
Distributions to noncontrolling interests
-     -   -     -     -     (3.5 )   (3.5 )
Contributions from noncontrolling interests
-     -   -     -     -     0.6     0.6  
Other comprehensive loss
-     -   -     -     (54.0 )   -     (54.0 )
Net income
-     30.2   -     7.6     -     7.9     45.7  
Distributions to unitholders
-     (46.4 ) -     (7.1 )   -     -     (53.5 )
Balance, March 31, 2011
84,756   $ 1,219.6   1,730   $ 22.2   $ (84.6 ) $ 134.3   $ 1,291.5  
 
                                     
See notes to consolidated financial statements.
 
 
 
TARGA RESOURCES PARTNERS LP
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
 
 
 
 
 
(Unaudited)
 
 
(In millions)
 
Cash flows from operating activities
 
 
 
 
Net income
$ 81.8   $ 45.7  
Adjustments to reconcile net income to net cash provided by operating activities:
           
    Amortization in interest expense
  4.6     1.8  
    Compensation on equity grants
  1.0     0.2  
    Depreciation and amortization expense
  46.7     42.7  
    Accretion of asset retirement obligations
  1.0     0.9  
    Deferred income tax expense
  0.4     0.4  
    Equity earnings, net of distributions
  -     (1.7 )
    Risk management activities
  1.1     0.2  
    Changes in operating assets and liabilities:
        -  
   Receivables and other assets
  113.9     24.0  
   Inventory
  44.3     47.3  
  Accounts payable and other liabilities
  (148.1 )   (62.9 )
    Net cash provided by operating activities
  146.7     98.6  
Cash flows from investing activities
           
Outlays for property, plant and equipment
  (102.7 )   (55.5 )
Business acquisition
  -     (29.0 )
Investment in unconsolidated affiliate
  (6.2 )   (4.4 )
Return of capital from unconsolidated affiliate
  0.3     -  
Other, net
  0.8     -  
  Net cash used in investing activities
  (107.8 )   (88.9 )
Cash flows from financing activities
           
Proceeds from borrowings under credit facility
  145.0     268.0  
Repayments of credit facility
  (643.0 )   (832.0 )
Proceeds from issuance of senior notes
  400.0     325.0  
Cash paid on note exchange
  -     (27.7 )
Proceeds from equity offerings
  168.4     304.4  
Distributions to unitholders
  (66.0 )   (53.5 )
Costs incurred in connection with financing arrangements
  (4.4 )   (6.2 )
Contributions from parent
  0.5     2.5  
Contributions from noncontrolling interests
  1.4     0.6  
Distributions to noncontrolling interests
  (10.1 )   (3.5 )
   Net cash used in financing activities
  (8.2 )   (22.4 )
Net change in cash and cash equivalents
  30.7     (12.7 )
Cash and cash equivalents, beginning of period
  55.6     76.3  
Cash and cash equivalents, end of period
$ 86.3   $ 63.6  
 
           
See notes to consolidated financial statements.
 
 
 
TARGA RESOURCES PARTNERS LP
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 GAAP. Except as noted within the context of each footnote disclosure, 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 NYSE 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. In this Quarterly Report, unless the context requires otherwise, references to “Targa” are intended to mean Targa Resources Corp. together with its 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 March 31, 2012, Targa owns a 16.2% interest in us in the form of 1,819,817 general partner units and 12,945,659 common units. In addition, Targa Resources GP LLC owns incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48% of distributable cash for a quarter after payments to common unitholders.

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 Targa employees deployed to our operating segments, as well 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 12 for an analysis of our operations by segment.

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with 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. 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.

The unaudited consolidated financial statements for the three months ended March 31, 2012 and 2011 include all adjustments which we believe are necessary for a fair presentation of the results for interim periods. Certain amounts in prior periods have been reclassified to conform to the current year presentation.

Our financial results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2012.
 
Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no significant changes to these policies during the three months ended March 31, 2012.

Accounting Standards Update No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, was implemented in this Quarterly Report. We have made additional disclosures in Note 9 – Fair Value Measurements to report the fair value of financial instruments reported at carrying value on our Consolidated Balance Sheets and their classification in the fair value hierarchy. Although we have no financial instruments classified as Level 3, the new standard would have also required that we disclose our valuation methodology including quantitative inputs and qualitative assumptions.

Note 4 — Property, Plant and Equipment

         
Estimated
useful lives
 
 
March 31, 2012
 
December 31, 2011
 
(In years)
 
Natural gas gathering systems
$ 1,761.9   $ 1,740.6  
5 to 20
 
Processing and fractionation facilities
  1,108.1     1,062.7  
5 to 25
 
Terminaling and storage facilities
  389.6     380.7  
5 to 25
 
Transportation assets
  281.8     281.2  
10 to 25
 
Other property, plant and equipment
  57.1     54.9  
3 to 25
 
Land
  72.0     71.2   -  
Construction in progress
  215.4     195.6   -  
  $ 3,885.9   $ 3,786.9      

Note 5 — Accounts Payable and Accrued Liabilities

The components of accounts payable and accrued liabilities consist of the following:

 
March 31, 2012
 
December 31, 2011
 
Commodities
$ 403.6   $ 514.0  
Other goods and services
  57.8     86.3  
Interest
  26.6     32.3  
Other
  13.1     15.2  
  $ 501.1   $ 647.8  
 

Note 6 — Debt Obligations

 
March 31, 2012
 
December 31, 2011
 
Senior secured revolving credit facility, variable rate, due July 2015 (1)
$ -   $ 498.0  
Senior unsecured notes, 8¼% fixed rate, due July 2016
  209.1     209.1  
Senior unsecured notes, 11¼% fixed rate, due July 2017
  72.7     72.7  
Unamortized discount
  (2.8 )   (2.9 )
Senior unsecured notes, 7⅞% fixed rate, due October 2018
  250.0     250.0  
Senior unsecured notes, 6⅞% fixed rate, due February 2021
  483.6     483.6  
Unamortized discount
  (32.2 )   (32.8 )
Senior unsecured notes, 6⅜% fixed rate, due August 2022
  400.0     -  
  $ 1,380.4   $ 1,477.7  
             
Letters of credit issued
$ 77.6   $ 92.5  
________
(1)  
As of March 31, 2012, availability under our $1.1 billion senior secured revolving credit facility was $1,022.4 million.

The following table shows the range of interest rates and the weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2012:

 
Range of Interest Rates Incurred
 
Weighted Average Interest Rate Incurred
Senior secured revolving credit facility
  2.5% - 2.9%     2.8%

As of March 31, 2012, we were in compliance with the covenants contained in our various debt agreements.

6⅜% Senior Notes

On January 30, 2012, we privately placed $400.0 million in aggregate principal amount of 6⅜% Senior Notes due 2022 (the “6⅜% Notes”). The 6⅜% Notes resulted in approximately $395.6 million of net proceeds, which were used to reduce borrowings under our senior secured revolving credit facility (the "Revolver") and for general partnership purposes.

The 6⅜% 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 6⅜% 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 6⅜% Notes accrues at the rate of 6⅜% per annum and is payable semi-annually in arrears on February 1 and August 1, commencing on August 1, 2012.

We may redeem 35% of the aggregate principal amount of the 6⅜% Notes at any time prior to February 1, 2015, with the net cash proceeds of one or more equity offerings. We must pay a redemption price of 106.375% 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 6⅜% Notes (excluding the 6⅜% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

2)  
the redemption occurs within 180 days of the date of the closing of such equity offering.
 
 
We may also redeem all or part of the 6⅜% Notes on or after February 1, 2017 at the prices set forth below plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve month period beginning on February. Redemption periods begin on February 1 of each year indicated below:
 
Year
 
Redemption Price
 
2017
  103.188%  
2018
  102.125%  
2019
 
101.063%
 
2020 and thereafter
  100.000%  

Note 7 — Partnership Units and Related Matters

Public Offerings of Common Units

On January 23, 2012, we completed a public offering of 4,000,000 common units at a price of $38.30 per common unit ($37.11 per common unit, net of underwriting discounts). Net proceeds from this offering were approximately $150.0 million. Pursuant to the exercise of the underwriters’ overallotment option, we issued an additional 405,000 common units, providing net proceeds of approximately $15.0 million. As part of this offering, Targa purchased 1,300,000 common units with an aggregate value of $49.8 million (based on the offering price of $38.30). The units purchased by Targa were not subject to any underwriter discounts or commissions. In addition, Targa contributed $3.4 million to us for 89,898 general partner units to maintain its 2% general partner interest in us. We used the net proceeds from this offering for general partnership purposes, including the repayment of indebtedness.

Distributions

Distributions for the three months ended March 31, 2012 and December 31, 2011 were as follows:
 
      Distributions      
Three Months Ended
Date Paid or to be Paid
 
Limited Partners
 
General Partner
       
Distributions per  limited
partner unit
 
Common
 
Incentive
 
2%
 
Total
 
                                 
       
(In millions, except per unit amounts)
March 31, 2012
May 15, 2012
 
$
 55.5 
 
$
 12.7 
 
$
 1.4 
 
$
 69.6 
 
$
 0.6225 
December 31, 2011
February 14, 2012
   
 53.7 
   
 11.0 
   
 1.3 
   
 66.0 
   
 0.6025 

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 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 may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations which closely approximate our actual natural gas and NGL 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 March 31, 2012, the notional volumes of our commodity hedges for our equity volumes were:

Commodity
 
Instrument
 
Unit
 
2012
 
2013
 
2014
 
Natural Gas
 
Swaps
 
MMBtu/d
  31,790   17,089   -  
NGL
 
Swaps
 
Bbl/d
  9,361   4,150   -  
NGL
 
Puts (propane)   
 
Bbl/d
  294   -   -  
NGL
 
Calls (ethane) (1)
 
Bbl/d
  2,000   -   -  
Condensate
 
Swaps
 
Bbl/d
  1,660   1,795   700  
______
(1) Utilized in connection with 2,000 Bbl/d of 2012 ethane swaps providing a floor on ethane with upside.
 
We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and we record changes in fair value and cash settlements to revenues.

The following schedules reflect the fair values of our derivative instruments:

     
Derivative Assets
 
Derivative Liabilities
     
Balance
 
Fair Value as of
 
Balance
 
Fair Value as of
     
Sheet
 
March 31,
 
December 31,
 
Sheet
 
March 31,
 
December 31,
     
Location
 
2012 
 
2011 
 
Location
 
2012 
 
2011 
Derivatives designated as hedging instruments
                           
 
Commodity contracts
Current assets
 
$
 40.0 
 
$
 40.3 
 
Current liabilities
$
 27.8 
 
$
 40.6 
     Long-term assets     9.0      
 10.9 
   Long-term liabilities   13.9      15.8 
Total derivatives designated  as hedging instruments
 
$
 49.0 
 
$
 51.2 
     
$
 41.7 
 
$
 56.4 
                                   
Derivatives not designated as hedging instruments
                         
 
Commodity contracts
Current assets
 
$
 0.5 
 
$
 0.7 
 
Current liabilities
$
 0.5 
 
$
 0.5 
Total derivatives not designated as hedging instruments
$
 0.5 
 
$
 0.7 
     
$
 0.5 
 
$
 0.5 
Total derivatives
     
$
 49.5 
 
$
 51.9 
     
$
 42.2 
 
$
 56.9 

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 estimated fair value of our derivative instruments was a net asset of $7.3 million as of March 31, 2012, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. These default probabilities have been applied to the unadjusted fair values of the derivative instruments to arrive at the credit risk adjustment, which aggregates to $0.1 million as of March 31, 2012.

Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas, NGL and crude oil 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.
 

The following tables reflect amounts recorded in other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue and expense for the three months ended March 31, 2012 and 2011:

 
   
Gain (Loss) Recognized in OCI on Derivatives
 
Derivatives in
 
(Effective Portion)
 
Cash Flow Hedging
 
Three Months Ended March 31,
 
Relationships
 
2012
 
2011
 
Interest rate contracts
  $ -   $ 0.2  
Commodity contracts
    15.4     (61.3 )
    $ 15.4   $ (61.1 )

   
Gain (Loss) Reclassified from OCI into Income
 
   
(Effective Portion)
 
   
Three Months Ended March 31,
 
Location of Gain (Loss)
 
2012
 
2011
 
Interest expense, net
  $ (2.3 ) $ (2.5 )
Revenues
    2.2     (4.6 )
    $ (0.1 ) $ (7.1 )
 
Hedge ineffectiveness has been immaterial for all periods presented.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative 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 commodity price indices. During the three months ended March 31, 2012 and 2011, we recorded the following mark-to-market gains:

       
Gain Recognized in Income on Derivatives
 
       
Three Months Ended March 31,
 
 Derivatives not Designated as Hedging Instruments    Location of Gain Recognized in Income on Derivatives  
2012
   
2011
 
Commodity contracts
 
Revenue
  $ 0.1     $ 1.0  

The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2014:

   
March 31, 2012
 
December 31, 2011
 
Commodity hedges
  $ 3.9   $ (9.4 )
Interest rate hedges
    (14.1 )   (16.4 )

As of March 31, 2012, deferred net gains of $7.5 million on commodity hedges and deferred net losses of $7.4 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.

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 fair values of our derivative instruments, which aggregate to a net asset position of $7.3 million as of March 31, 2012, are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This asset position reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $34.1 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $48.1 million, ignoring an adjustment for counterparty credit risk.

The following table reflects the classification within the fair value hierarchy of derivative contracts that are recorded on our Consolidated Balance Sheets at fair value:

 
March 31, 2012
 
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Assets from commodity derivative contracts
$ 49.5   $ -   $ 49.5   $ -  
Liabilities from commodity derivative contracts
$ 42.2   $ -   $ 42.2   $ -  
                         
 
December 31, 2011
 
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Assets from commodity derivative contracts
$ 51.9   $ -   $ 51.9   $ -  
Liabilities from commodity derivative contracts
$ 56.9   $ -   $ 56.9   $ -  

The following table reflects the classification within the fair value hierarchy of financial instruments that are not recorded on our Consolidated Balance Sheets at fair value:

 
March 31, 2012
 
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Long term debt
$ 1,494.6   $ -   $ 1,494.6   $ -  

There have been no transfers of assets or liabilities between the three levels of the fair value hierarchy during the three months ended March 31, 2012.
 
 
Note 10 — Fair Value of Financial Instruments

The estimated fair values of our 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 instruments included in our financial statements are stated at fair value.
 
The carrying value of our Revolver approximates fair value as its interest rate is based on prevailing market rates. The fair value of our senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

 
March 31, 2012
 
December 31, 2011
 
 
Carrying
 
Fair
 
Carrying
 
Fair
 
 
Amount
 
Value
 
Amount
 
Value
 
Senior unsecured notes, 8¼% fixed rate
$ 209.1   $ 220.7   $ 209.1   $ 220.5  
Senior unsecured notes, 11¼% fixed rate
  69.9     83.0     69.8     82.1  
Senior unsecured notes, 7⅞% fixed rate
  250.0     271.6     250.0     264.5  
Senior unsecured notes, 6⅞% fixed rate
  451.4     510.5     450.8     490.2  
Senior unsecured notes, 6⅜% fixed rate
  400.0     408.8     -     -  

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.

Environmental liabilities were not significant as of March 31, 2012.
 
Targa has reimbursed us for maintenance capital expenditures of $16.2 million as of March 31, 2012, which are required to be made in connection with a settlement agreement with the New Mexico Environment Department relating to air emissions at three gas processing plants operated by our Versado Gas Processors, LLC joint venture, with $0.6 million reimbursed to us during the first quarter of 2012. These capital projects were substantially complete as of March 31, 2012.
 
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 — 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 mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations.
 
Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. 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.

Our 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 and other value added activities related to third-party natural gas in selected United States markets.

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

Our reportable segment information is shown in the following tables:

Three Months Ended March 31, 2012
 
   
Field
 
Coastal
                     
   
Gathering
 
Gathering
     
Marketing
     
Corporate
     
   
and
 
and
 
Logistics
 
and
     
and
     
   
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Total
 
Revenues
                             
Sales of commodities
  $ 45.4   $ 59.8   $ 45.7   $ 1,417.2   $ 1.4   $ -   $ 1,569.5  
Fees from midstream services
    8.0     2.9     36.2     18.7     -     0.1     65.9  
Other
    2.9     0.8     2.5     4.0     -     (0.1 )   10.1  
      56.3     63.5     84.4     1,439.9     1.4     -     1,645.5  
Intersegment revenues
                                           
Sales of commodities
    317.4     220.0     -     132.0     -     (669.4 )   -  
Fees from midstream services
    0.3     -     23.8     2.5     -     (26.6 )   -  
Other
    -     0.1     0.2     6.8     -     (7.1 )   -  
      317.7     220.1     24.0     141.3     -     (703.1 )   -  
Revenues
  $ 374.0   $ 283.6   $ 108.4   $ 1,581.2   $ 1.4   $ (703.1 ) $ 1,645.5  
Operating margin
  $ 73.0   $ 46.3   $ 43.0   $ 26.1   $ 1.4   $ -   $ 189.8  
Other financial information:
                                           
Total assets
  $ 1,661.1   $ 422.5   $ 823.0   $ 507.9   $ 49.5   $ 123.0   $ 3,587.1  
Capital expenditures
  $ 26.2   $ 2.0   $ 60.1   $ 9.1   $ -   $ 0.6   $ 98.0  

Three Months Ended March 31, 2011
 
   
Field
 
Coastal
                     
   
Gathering
 
Gathering
     
Marketing
     
Corporate
     
   
and
 
and
 
Logistics
 
and
     
and
     
   
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Total
 
Revenues
                             
Sales of commodities
  $ 45.7   $ 79.2   $ -   $ 1,446.3   $ (4.4 ) $ -   $ 1,566.8  
Fees from midstream services
    5.9     4.5     22.9     9.4     -     -     42.7  
Other
    0.4     0.3     0.3     4.6     -     -     5.6  
      52.0     84.0     23.2     1,460.3     (4.4 )   -     1,615.1  
Intersegment revenues
                                           
Sales of commodities
    299.4     217.0     0.1     110.3     -     (626.8 )   -  
Fees from midstream services
    0.3     0.4     19.0     2.0     -     (21.7 )   -  
Other
    -     -     -     5.6     -     (5.6 )   -  
      299.7     217.4     19.1     117.9     -     (654.1 )   -  
Revenues
  $ 351.7   $ 301.4   $ 42.3   $ 1,578.2   $ (4.4 ) $ (654.1 ) $ 1,615.1  
Operating margin
  $ 61.1   $ 36.3   $ 22.3   $ 32.7   $ (4.4 ) $ -   $ 148.0  
Other financial information:
                                           
Total assets
  $ 1,641.8   $ 431.3   $ 506.6   $ 458.7   $ 34.5   $ 67.8   $ 3,140.7  
Capital expenditures
  $ 31.8   $ 1.4   $ 45.2   $ 0.1   $ -   $ -   $ 78.5  
 
 
The following table shows our consolidated revenues by product and service for the periods presented:

   
Three Months Ended March 31,
 
   
2012
   
2011
 
Sales of commodities
           
Natural gas sales
  $ 202.9     $ 248.7  
NGL sales
    1,290.2       1,301.7  
Condensate sales
    29.0       21.6  
Petroleum products
    45.5       -  
Derivative activities
    1.9       (5.2 )
      1,569.5       1,566.8  
Fees from midstream services
               
Fractionating and treating fees
    26.9       11.1  
Storage and terminaling fees
    11.5       13.9  
Transportation fees
    19.0       10.6  
Gas processing fees
    8.6       7.1  
      66.0       42.7  
Other
    10.0       5.6  
    $ 1,645.5     $ 1,615.1  

The following table is a reconciliation of operating margin to net income for the periods presented:

   
Three Months Ended March 31,
 
   
2012
   
2011
 
Reconciliation of operating margin to net income:
           
Operating margin
  $ 189.8     $ 148.0  
Depreciation and amortization expense
    (46.7 )     (42.7 )
General and administrative expense
    (32.9 )     (31.8 )
Interest expense, net
    (29.4 )     (27.5 )
Income tax expense
    (1.0 )     (1.8 )
Other, net
    2.0       1.5  
Net income
  $ 81.8     $ 45.7  
 
 
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, 2011 (“Annual Report”), 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 NYSE under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” or “our” 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.

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 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, refined petroleum products and crude oil. 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 refined petroleum products and crude oil. 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.

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 and other value added activities related to third-party natural gas in selected United States markets.

Other contains the results of commodity hedging activities included in operating margin.
 
2012 Developments

In January 2012, we completed an equity offering of 4,405,000 common units and a $400 million senior notes offering, resulting in $564.0 million of combined net proceeds. As part of the equity offering, a wholly owned subsidiary of Targa purchased 1,300,000 common units. We used the net proceeds from these offerings for general partnership purposes and the repayment of indebtedness. See “—Cash Flow from Financing Activities”.
 
 
2012 Accounting Pronouncements

Accounting Standards Update No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, was implemented in this Quarterly Report. We have made additional disclosures in Note 9 – Fair Value Measurements to report the fair value of financial instruments reported at carrying value on our Consolidated Balance Sheets and their classification in the fair value hierarchy. Although we have no financial instruments classified as Level 3, the new standard would have also required that we disclose our valuation methodology including quantitative inputs and qualitative assumptions.

How We Evaluate Our Operations

Our profitability is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs and condensate we sell, and (ii) 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, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based revenues. Our growth strategy, largely based on expansion of our existing facilities as well as third-party acquisitions of businesses and assets, includes an increasing percentage of assets that generate fee-based revenues. Fixed fees for services such as storage and terminaling are not directly tied to changes in market prices for commodities.
 
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 oil and 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 facilities.
 
In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing 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 sale of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Logistics Assets gross margin consists primarily of service fee revenue. 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.
 
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 the noncontrolling interest portion of depreciation and amortization expense 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 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 months ended March 31, 2012 and 2011:

   
Three Months Ended March 31,
 
   
2012
 
2011
 
           
Reconciliation of gross margin and
 
(In millions)
 
operating margin to net income:
         
Gross margin
  $ 261.4   $ 213.9  
 Operating expenses
    (71.6 )   (65.9 )
Operating margin
    189.8     148.0  
 Depreciation and amortization expenses
    (46.7 )   (42.7 )
 General and administrative expenses
    (32.9 )   (31.8 )
 Interest expense, net
    (29.4 )   (27.5 )
 Income tax expense
    (1.0 )   (1.8 )
 Other, net
    2.0     1.5  
Net income
  $ 81.8   $ 45.7  

   
Three Months Ended March 31,
 
   
2012
 
2011
 
           
   
(In millions)
 
Reconciliation of net cash provided by
         
operating activities to Adjusted EBITDA:
         
Net cash provided by operating activities
  $ 146.7   $ 98.6  
Net income attributable to noncontrolling interests
    (11.7 )   (7.9 )
Interest expense, net (1)
    24.8     25.7  
Current income tax expense
    0.6     1.4  
Other (2)
    (4.9 )   (2.0 )
Changes in operating assets and liabilities which used (provided) cash:
             
  Accounts receivable and other assets
    (158.2 )   (71.3 )
  Accounts payable and other liabilities
    148.1     62.9  
Adjusted EBITDA
  $ 145.4   $ 107.4  
_________
(1)  
Net of amortization of debt issuance costs, discount and premium included in interest expense of $4.6 million and $1.8 million for the three months ended March 31, 2012 and 2011.
(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 March 31,
 
   
2012
 
2011
 
           
   
(In millions)
 
Reconciliation of net income attributable to
         
Targa Resources Partners LP to Adjusted EBITDA:
         
Net income attributable to Targa Resources Partners LP
  $ 70.1   $ 37.8  
Add:
             
Interest expense, net
    29.4     27.5  
Income tax expense
    1.0     1.8  
Depreciation and amortization expenses
    46.7     42.7  
Risk management activities
    1.0     0.2  
Noncontrolling interests adjustment (1)
    (2.8 )   (2.6 )
Adjusted EBITDA
  $ 145.4   $ 107.4  
______
(1) Noncontrolling interest portion of depreciation and amortization expenses.
 

 
   
Three Months Ended March 31,
 
   
2012
 
2011
 
           
   
(In millions)
 
Reconciliation of net income attributable to Targa
         
Resources Partners LP to distributable cash flow:
         
Net income attributable to Targa Resources Partners LP
  $ 70.1   $ 37.8  
Depreciation and amortization expenses
    46.7     42.7  
Deferred income tax expense
    0.4     0.4  
Amortization in interest expense
    4.6     1.8  
Risk management activities
    1.0     0.2  
Maintenance capital expenditures
    (16.5 )   (12.8 )
Other (1)
    (0.6 )   2.0  
Distributable cash flow
  $ 105.7   $ 72.1  
_______
(1)  
Includes reimbursements of certain environmental maintenance capital expenditures by Targa and the noncontrolling interest portion of maintenance capital expenditures, depreciation and amortization expense.
 
 
Results of Operations

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2012 and 2011 (in millions, except operating statistics and price amounts):

 
Three Months Ended March 31,
         
 
2012
 
2011
 
2012 vs. 2011
 
Revenues
$ 1,645.5   $ 1,615.1   $ 30.4   2%  
Product purchases
  1,384.1     1,401.2     (17.1 ) (1%
Gross margin (1)
  261.4     213.9     47.5   22%  
Operating expenses
  71.6     65.9     5.7   9%  
Operating margin (2)
  189.8     148.0     41.8   28%  
Depreciation and
  amortization expenses
  46.7     42.7     4.0   9%  
General and
   administrative expenses
  32.9     31.8     1.1   3%  
Income from operations
  110.2     73.5     36.7   50%  
Interest expense, net
  (29.4 )   (27.5 )   (1.9 ) 7%  
Equity in earnings of
    unconsolidated investments
  2.1     1.7     0.4   24%  
Other
  (0.1 )   (0.2 )   0.1   50%  
Income tax expense
  (1.0 )   (1.8 )   0.8   44%  
Net income
  81.8     45.7     36.1   79%  
Less: Net income attributable to
     noncontrolling interests
  11.7     7.9     3.8   48%  
Net income (loss) attributable to
    Targa Resources Partners LP
$ 70.1   $ 37.8   $ 32.3   85%  
Financial and operating data:
                     
Financial data:
                     
Adjusted EBITDA (3)
$ 145.4   $ 107.4   $ 38.0   35%  
Distributable cash flow (4)
  105.7     72.1     33.6   47%  
Operating data:
                     
Plant natural gas inlet, MMcf/d (5)(6)
  2,232.7     2,168.6     64.1   3%  
Gross NGL production, MBbl/d
  132.3     119.1     13.2   11%  
Natural gas sales, BBtu/d (6)
  860.5     682.4     178.1   26%  
NGL sales, MBbl/d
  279.1     275.6     3.5   1%  
Condensate sales, MBbl/d
  3.1     2.6     0.5   19%  
_________
(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 March 31, 2012 Compared to Three Months Ended March 31, 2011

Revenues, including the impacts of hedging, increased due to higher commodity sales volumes ($105.1 million), higher fee-based and other revenues ($72.0 million) and the higher impact of realized prices on condensate ($3.3 million), partially offset by the impact of lower realized prices on natural gas and NGLs ($150.0 million).

The increase in operating margin reflects higher gross margin, partially offset by higher operating expenses. The increase in gross margin resulted from higher revenues ($30.4 million) and lower product purchase costs
($17.0 million). The increase in operating expenses primarily reflects increased compensation and benefits
($3.0 million), and higher maintenance ($1.8 million). See “—Results of Operations – By Reportable Segment” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to the impact of assets purchased in 2011, including the acquisitions of petroleum logistics assets and expansion projects at Mont Belvieu ($6.4 million) partially offset by assets that became fully depreciated after the first quarter of  2011 ($2.4 million).

General and administrative expenses increased primarily due to compensation and benefits.

The increase in interest expense was the result of higher borrowings ($2.5 million) partially offset by lower effective interest rates ($0.6 million).

The increase in net income attributable to noncontrolling interests reflects the impact of higher earnings at our non-wholly owned consolidated subsidiaries.

Results of Operations—By Reportable Segment

Our operating margin by reportable segment is:

 
Field
 
Coastal
                 
 
Gathering
 
Gathering
     
Marketing
         
 
and
 
and
 
Logistics
 
and
         
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Total
 
                         
Three Months Ended:
(In millions)
 
March 31, 2012
$ 73.0   $ 46.3   $ 43.0   $ 26.1   $ 1.4   $ 189.8  
March 31, 2011
  61.1     36.3     22.3     32.7     (4.4 )   148.0  
 
Natural Gas Gathering and Processing Segments
 
Field Gathering and Processing
 
   Three Months Ended March 31,        
 
2012
 
2011
 
2012 vs. 2011
 
               
 
($ in millions)
       
Gross margin
$ 102.3   $ 87.9   $ 14.4   16%  
Operating expenses
  29.3     26.8     2.5   9%  
Operating margin
$ 73.0   $ 61.1   $ 11.9   19%  
Operating statistics:
                     
Plant natural gas inlet, MMcf/d (1),(2)
  655.4     572.8     82.6   14%  
Gross NGL production, MBbl/d
  79.1     69.5     9.6   14%  
Natural gas sales, BBtu/d (2),(3)
  313.3     263.1     50.2   19%  
NGL sales, MBbl/d (3)
  65.0     56.4     8.6   15%  
Condensate sales, MBbl/d (3)
  2.9     2.3     0.6   26%  
Average realized prices (4):
                     
Natural gas, $/MMBtu
  2.57     3.80     (1.23   (32% )
NGL, $/gal
  1.06     1.11     (0.05   (5% )
Condensate, $/Bbl
  99.23     91.04     8.19   9%  
 
 (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 quarter and the denominator is the number of calendar days during the quarter.
(4)   
Average realized prices exclude the impact of hedging activities.
 
 
Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

The increase in gross margin was primarily due to higher NGL and natural gas sales volumes due to higher throughput, and higher condensate prices partially offset by lower natural gas and NGL sales prices. The increase in plant inlet volumes was largely attributable to new well connects, particularly at North Texas, Sand Hills and SAOU, as well as to the negative impact of severe cold weather and operational outages in the first quarter of 2011.

The increase in operating expenses was primarily related to higher system maintenance expenses and repair costs.
 
Coastal Gathering and Processing

   Three Months Ended March 31,          
 
2012
 
2011
 
2012 vs. 2011
 
 
($ in millions)
         
Gross margin
$ 56.7   $ 46.5   $ 10.2   22%  
Operating expenses
  10.4     10.2     0.2   2%  
Operating margin
$ 46.3   $ 36.3   $ 10.0   28%  
Operating statistics:
                     
Plant natural gas inlet, MMcf/d (1),(2)
  1,577.3     1,595.8     (18.5 ) (1% )
Gross NGL production, MBbl/d
  53.2     49.6     3.6   7%  
Natural gas sales, BBtu/d (2),(3)
  282.0     254.5     27.5   11%  
NGL sales, MBbl/d (3)
  47.3     43.5     3.8   9%  
Condensate sales, MBbl/d (3)
  0.3     0.3     -   -  
Average realized prices:
                     
Natural gas, $/MMBtu
  2.62     4.15     (1.53 ) (37% )
NGL, $/gal
  1.16     1.21     (0.05 ) (4% )
Condensate, $/Bbl
  127.86     92.23     35.63   39%  
 
(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 quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

The increase in gross margin is primarily due to the significant increase in gas purchased for processing at VESCO and Lowry and the favorable frac spread as a result of low gas prices relative to NGLs and crude oil. The slight decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes largely offset by increased traditional wellhead volumes. NGL production and sales volumes increased as a result of the optimization of throughput to more efficient, higher recovery plants. Natural gas sales volumes increased due to an increase in demand from industrial customers and increased sales to other reportable segments for resale.

Operating expenses were flat.

 
Logistics and Marketing Segments

Logistics Assets
 
   Three Months Ended March 31,        
 
2012
 
2011
 
2012 vs. 2011
 
               
 
($ in millions)
       
Gross margin
$ 64.4   $ 42.3   $ 22.1   52%  
Operating expenses
  21.4     20.0     1.4   7%  
Operating margin
$ 43.0   $ 22.3   $ 20.7   93%  
Operating statistics (1):
                     
Fractionation volumes, MBbl/d
  293.7     209.3     84.4   40%  
Treating volumes, MBbl/d (2)
  19.1     10.2     8.9   87%  
 
(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 quarter and the denominator is the number of calendar days during the quarter.
(2)  
Includes the volumes related to the natural gasoline hydrotreater at our Mt. Belvieu facility.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

The increase in gross margin was primarily due to higher fractionation and treating fees and the impact of the 2011 petroleum logistics acquisitions. The higher fractionation fees are largely attributable to the Cedar Bayou facility Train 3 expansion of an additional 78 MBbl/d in mid-year 2011. Treating fees were up due to increases in throughput and the operational start up of the benzene treating facility in 2012.

The increase in operating expenses was primarily due to the operating costs of the petroleum logistics terminals acquired after the first quarter of 2011, resulting in higher compensation and benefits, higher system maintenance costs, higher contract labor and ad valorem taxes. Outside professional services increased due to an increase in, and timing of, well work-over costs. These increased costs were largely offset by system product gains.

Marketing and Distribution
 
    Three Months Ended March 31,          
 
2012
 
2011
 
2012 vs. 2011
 
 
($ in millions)
         
Gross margin
$ 35.4   $ 44.6   $ (9.2 ) (21%