XFRA:ZVK Targa Resources Partners LP Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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 June 30, 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 August 1, 2012, there were 89,170,989 Common Units and 1,819,817 General Partner Units outstanding.
 
 
 

 
 
PART I—FINANCIAL INFORMATION
     
     
 
     
 
5 
     
 
6 
     
 
7 
     
 
     
 
9 
     
     
     
     
PART II—OTHER INFORMATION
     
     
     
     
     
     
     
     
SIGNATURES
     
 
 
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
 
June 30,
 
December 31,
 
 
2012
 
2011
 
 
(Unaudited)
 
 
(In millions)
 
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
$ 89.5   $ 55.6  
Trade receivables, net of allowances of $1.9 million and $2.2 million
  368.1     575.9  
Inventory
  89.6     92.1  
Assets from risk management activities
  56.3     41.0  
Other current assets
  2.2     2.7  
Total current assets
  605.7     767.3  
Property, plant and equipment
  4,026.5     3,786.9  
Accumulated depreciation
  (1,074.2 )   (980.8 )
Property, plant and equipment, net
  2,952.3     2,806.1  
Long-term assets from risk management activities
  21.3     10.9  
Investment in unconsolidated affiliate
  50.1     36.8  
Other long-term assets
  37.0     36.9  
Total assets
$ 3,666.4   $ 3,658.0  
 
           
LIABILITIES AND OWNERS' EQUITY
       
Current liabilities:
           
Accounts payable and accrued liabilities
$ 425.5   $ 647.8  
Accounts payable to Targa Resources Corp.
  52.3     60.0  
Liabilities from risk management activities
  2.8     41.1  
Total current liabilities
  480.6     748.9  
Long-term debt
  1,521.0     1,477.7  
Long-term liabilities from risk management activities
  4.1     15.8  
Deferred income taxes
  10.7     9.5  
Other long-term liabilities
  46.4     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 June 30, 2012 and December 31, 2011)
  1,365.5     1,221.2  
General partner (1,819,817 and 1,729,715 units issued and outstanding as of June 30, 2012 and December 31, 2011)
  33.9      27.2   
Accumulated other comprehensive income (loss)
  55.9     (25.6 )
 
  1,455.3     1,222.8  
Noncontrolling interests in subsidiaries
  148.3     138.9  
Total owners' equity
  1,603.6     1,361.7  
Total liabilities and owners' equity
$ 3,666.4   $ 3,658.0  
 
           
See notes to consolidated financial statements.
     
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2012
 
2011
 
2012
 
2011
 
 
(Unaudited)
 
 
(In millions, except per unit amounts)
 
Revenues
$ 1,318.4   $ 1,726.0   $ 2,963.9   $ 3,341.1  
Costs and expenses:
                       
Product purchases
  1,074.6     1,477.8     2,458.7     2,879.0  
Operating expenses
  77.2     71.6     148.8     137.6  
Depreciation and amortization expenses
  47.6     44.5     94.3     87.2  
General and administrative expenses
  33.5     33.2     66.4     64.9  
Other operating
  -     -     (0.1 )   -  
Income from operations
  85.5     98.9     195.8     172.4  
Other income (expense):
                       
Interest expense, net
  (29.4   (27.2   (58.8 )   (54.6 )
Equity earnings (loss)
  (0.2   1.3     1.9     3.0  
Loss on mark-to-market derivative instruments
  -     (3.2   -     (3.2 )
Other
  (0.4   0.1     (0.5 )   (0.1 )
Income before income taxes
  55.5     69.9     138.4     117.5  
Income tax expense:
                       
Current
  (0.4   (0.8   (1.0 )   (2.2 )
Deferred
  (0.4   (1.1   (0.8 )   (1.5 )
 
  (0.8   (1.9   (1.8 )   (3.7 )
Net income
  54.7     68.0     136.6     113.8  
Less: Net income attributable to noncontrolling interests
  7.9     12.8     19.6     20.7  
Net income attributable to Targa Resources Partners LP
$ 46.8   $ 55.2   $ 117.0   $ 93.1  
 
                       
Net income attributable to general partner
  15.4     8.9     29.5     16.5  
Net income attributable to limited partners
  31.4     46.3     87.5     76.6  
Net income attributable to Targa Resources Partners LP
$ 46.8   $ 55.2   $ 117.0   $ 93.1  
 
                       
Net income per limited partner unit - basic and diluted
$ 0.35   $ 0.55   $ 0.99   $ 0.92  
Weighted average limited partner units outstanding - basic
  89.2     84.8     88.6     83.5  
Weighted average limited partner units outstanding - diluted
  89.3     84.8     88.7     83.5  
 
                       
See notes to consolidated financial statements.
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30,
 
 
 
2012
 
2011
 
 
 
Pre-Tax
 
Related Income Tax
 
After Tax
 
Pre-Tax
 
Related Income Tax
 
After Tax
 
 
 
(Unaudited)
 
 
 
(In millions)
 
Net income
 
 
 
 
  $ 54.7  
 
 
 
  $ 68.0  
Other comprehensive income:
 
 
 
 
       
 
 
 
       
Commodity hedging contracts:
 
 
 
 
       
 
 
 
       
Change in fair value
  $ 77.3   $ (0.5 )   76.8   $ 4.4   $ -     4.4  
Settlements reclassified to revenues
    (12.9 )   0.1     (12.8 )   11.9     -     11.9  
Interest rate swaps:
                                     
Change in fair value
    -     -     -     (2.2 )   -     (2.2 )
Settlements reclassified to interest expense, net
    1.9     -     1.9     2.2     -     2.2  
Other comprehensive income
  $ 66.3   $ (0.4 )   65.9   $ 16.3   $ -     16.3  
Comprehensive income
              $ 120.6               $ 84.3  
Less Comprehensive income attributable to noncontrolling interests
                 7.9                 12.8   
Comprehensive income attributable to Targa Resources Partners LP
              $ 112.7               $ 71.5  
 
                                     
 
 
 
Six Months Ended June 30,
 
 
 
2012
 
2011
 
 
 
Pre-Tax
 
Related Income Tax
 
After Tax
 
Pre-Tax
 
Related Income Tax
 
After Tax
 
 
 
(Unaudited)
 
 
 
(In millions)
 
Net income
 
 
 
 
  $ 136.6  
 
 
 
  $ 113.8  
Other comprehensive income:
 
 
 
 
       
 
 
 
       
Commodity hedging contracts:
 
 
 
 
       
 
 
 
       
Change in fair value
  $ 92.8   $ (0.5 )   92.3   $ (56.9 ) $ -     (56.9 )
Settlements reclassified to revenues
    (15.1 )   0.1     (15.0 )   16.5     -     16.5  
Interest rate swaps:
                                     
Change in fair value
    -     -     -     (1.8 )   -     (1.8 )
Settlements reclassified to interest expense, net
    4.2     -     4.2     4.6     -     4.6  
Other comprehensive income
  $ 81.9   $ (0.4 )   81.5   $ (37.6 ) $ -     (37.6 )
Comprehensive income                 218.1                   76.2  
Less: Comprehensive income attributable to noncontrolling interests
              $ 19.6               $ 20.7  
Comprehensive income attributable to Targa Resources Partners LP
                 198.5                  55.5  
 
                                     
See notes to consolidated financial statements.
 
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS 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     1.6   -     -     -     -     1.6  
Proceeds from equity offerings
4,405     164.9   90     3.5     -     -     168.4  
Contributions from Targa Resources Corp.
-     0.7   -     0.1     -     -     0.8  
Distributions to noncontrolling interests
-     (1.2 -     -     -     (15.0   (16.2 )
Contributions from noncontrolling interests
-     -   -     -     -     4.8     4.8  
Other comprehensive income
-     -   -     -     81.5     -     81.5  
Net income
-     87.5   -     29.5     -     19.6     136.6  
Distributions to unitholders
-     (109.2 -     (26.4   -     -     (135.6 )
Balance, June 30, 2012
89,171   $ 1,365.5   1,820   33.9   $ 55.9   $ 148.3   $ 1,603.6  
 
                                     
Balance, December 31, 2010
75,545   $ 935.3   1,542   15.1   $ (30.6 $ 129.3   $ 1,049.1  
Compensation on equity grants
11     0.8   -     -     -     -     0.8  
Proceeds from equity offerings
9,200     298.0   188     6.3     -     -     304.3  
Contributions from Targa Resources Corp.
-     4.4   -     0.6     -     -     5.0  
Distributions to noncontrolling interests
-     -   -     -     -     (11.6   (11.6 )
Contributions from noncontrolling interests
-     -   -     -     -     1.3     1.3  
Other comprehensive loss
-     -   -     -     (37.6   -     (37.6 )
Net income
-     76.6   -     16.5     -     20.7     113.8  
Distributions to unitholders
-     (93.6 -     (15.0   -     -     (108.6 )
Balance, June 30, 2011
84,756   $ 1,221.5   1,730   23.5   $ (68.2 $ 139.7   $ 1,316.5  
 
                                     
See notes to consolidated financial statements.
 
 
TARGA RESOURCES PARTNERS LP
 
 
 
 
 
 
Six Months Ended June 30,
 
 
2012
 
2011
 
 
(Unaudited)
 
 
(In millions)
 
Cash flows from operating activities
 
 
 
 
Net income
$ 136.6   $ 113.8  
Adjustments to reconcile net income to net cash provided by operating activities:
           
Amortization in interest expense
  9.1     5.7  
Compensation on equity grants
  1.6     0.8  
Depreciation and amortization expense
  94.3     87.2  
Accretion of asset retirement obligations
  2.0     1.8  
Deferred income tax expense
  0.8     1.5  
Risk management activities
  2.0     4.0  
Gain on sale of assets
  (0.1 )   -  
Changes in operating assets and liabilities:
           
Receivables and other assets
  209.0     (47.0 )
Inventory
  (0.3 )   (17.4 )
Accounts payable and other liabilities
  (230.0 )   102.3  
Net cash provided by operating activities
  225.0     252.7  
Cash flows from investing activities
           
Outlays for property, plant and equipment
  (238.4 )   (135.7 )
Business acquisition
  -     (29.0 )
Investment in unconsolidated affiliate
  (13.7 )   (6.0 )
Return of capital from unconsolidated affiliate
  0.4     0.6  
Other, net
  0.9     -  
Net cash used in investing activities
  (250.8 )   (170.1 )
Cash flows from financing activities
           
Proceeds from borrowings under credit facility
  325.0     611.0  
Repayments of credit facility
  (683.0 )   (1,178.3 )
Proceeds from issuance of senior notes
  400.0     325.0  
Cash paid on note exchange
  -     (27.7 )
Proceeds from equity offerings
  168.4     304.3  
Distributions to unitholders
  (135.6 )   (108.6 )
Costs incurred in connection with financing arrangements
  (4.5 )   (6.2 )
Contributions from parent
  0.8     5.0  
Contributions from noncontrolling interests
  4.8     1.3  
Distributions to noncontrolling interests
  (16.2 )   (11.6 )
Net cash provided by (used in) financing activities
  59.7     (85.8 )
Net change in cash and cash equivalents
  33.9     (3.2 )
Cash and cash equivalents, beginning of period
  55.6     76.3  
Cash and cash equivalents, end of period
$ 89.5   $ 73.1  
 
           
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 June 30, 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 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 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 and six months ended June 30, 2012 and 2011 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.  Certain amounts in prior periods have been reclassified to conform to the current year presentation.

Our financial results for the three and six months ended June 30, 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 six months ended June 30, 2012.

Earnings per unit. We account for earnings per unit (“EPU”) in accordance with ASC 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU. For the six months ended June 30, 2012, the dilutive effect of equity-settled performance units under our Long Term Incentive Plan did not have a material impact on our reported earnings per unit.
 
The limited partners’ net income per unit is based on net income after allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distributions payable to holders of incentive distribution rights to a percentage of Available Cash (as defined in our Partnership Agreement), the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period.

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 2012. 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. Additionally, we have provided information regarding the unobservable inputs used in the fair value measurement of derivative contracts classified as Level 3 within the fair value hierarchy. The impact of Level 3 inputs on our financial statements is immaterial to both net assets and other comprehensive income, and there is no impact whatsoever to net income or cash flows. It is our policy that transfers between levels of the fair value hierarchy are deemed to occur at the end of the reporting period.

Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, was implemented during 2012. We have made new disclosures this year, applied retroactively to prior periods, in the Consolidated Statements of Comprehensive Income (Loss) to report the tax effect of each component of other comprehensive income.

Note 4 — Property, Plant and Equipment

   
June 30, 2012
 
December 31, 2011
 
Estimated useful lives
(In years)
Natural gas gathering systems
  $ 1,774.3   $ 1,740.6  
5 to 20
Processing and fractionation facilities
    1,130.3     1,062.7  
5 to 25
Terminaling and storage facilities
    400.3     380.7  
5 to 25
Transportation assets
    291.5     281.2  
10 to 25
Other property, plant and equipment
    57.8     54.9  
3 to 25
Land
    72.0     71.2    -
Construction in progress
    300.3     195.6    -
    $ 4,026.5   $ 3,786.9    
 
Note 5 — Accounts Payable and Accrued Liabilities

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

 
June 30, 2012
 
December 31, 2011
 
Commodities
$ 292.9   $ 515.3  
Other goods and services
  78.0     86.3  
Interest
  42.8     32.3  
Other
  11.8     13.9  
  $ 425.5   $ 647.8  
 
 
Note 6 — Debt Obligations

 
June 30, 2012
 
December 31, 2011
 
Senior secured revolving credit facility, variable rate, due July 2015 (1)
$ 140.0   $ 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
  (2.7 )   (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
  (31.7 )   (32.8 )
Senior unsecured notes, 6⅜% fixed rate, due August 2022
  400.0     -  
  $ 1,521.0   $ 1,477.7  
             
Letters of credit issued
$ 70.2   $ 92.5  
________
(1)  
As of June 30, 2012, availability under our $1.1 billion senior secured revolving credit facility was $889.8 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 six months ended June 30, 2012:
 
 
Range of Interest Rates Incurred
 
Weighted Average Interest Rate Incurred
 
Senior secured revolving credit facility
2.5% - 4.5%   2.8%  

As of June 30, 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 $395.5 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. The 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 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

The following table details the distributions paid during or pertaining to the first six months of 2012:
 
 
 
 
   Distributions    
Distributions per limited partner unit
Three Months Ended
 
Date Paid or to be Paid
   Limited Partners    General Partner  
 
 
 
 
   Common    Incentive    2%    Total  
 
(In millions, except per unit amounts)
June 30, 2012   August 14, 2012  
$
57.3   
$
14.4   
$
1.5    $ 73.2   
$
0.6425 
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 (i) natural gas equity volumes in Field Gathering and Processing Operations through 2015 and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations through 2014 that result from its percent of proceeds processing arrangement by entering into derivative instruments including swaps and purchased puts (floors) and calls (caps). We have designated these derivative contracts as cash flow hedges.

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 June 30, 2012, the notional volumes of our commodity hedges for our equity volumes were:

Commodity
 
Instrument
 
Unit
 
2012
 
2013
 
2014
 
2015
 
Natural Gas
 
Swaps
 
MMBtu/d
  31,790   26,089   18,000   4,500  
NGL
 
Swaps
 
Bbl/d
  9,361   5,650   1,000   -  
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
 
June 30,
 
December 31,
 
Sheet
 
June 30,
 
December 31,
 
 
 
Location
 
2012 
 
2011 
 
Location
 
2012 
 
2011 
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Current assets
 
$
 55.4 
 
$
 40.3 
 
Current liabilities
$
 2.6 
 
$
 40.6 
 
 
 
Long-term assets    
 21.3 
 
 
 10.9 
 
Long-term liabilities  
 
 4.1 
 
 
 15.8 
Total derivatives designated as hedging instruments
 
$
 76.7 
 
$
 51.2 
 
 
 
$
 6.7 
 
$
 56.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
Current assets
 
$
 0.9 
 
$
 0.7 
 
Current liabilities
$
 0.2 
 
$
 0.5 
Total derivatives not designated as hedging instruments
$
 0.9 
 
$
 0.7 
 
 
 
$
 0.2 
 
$
 0.5 
Total derivatives
 
 
 
$
 77.6 
 
$
 51.9 
 
 
 
$
 6.9 
 
$
 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 $70.7 million as of June 30, 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 $0.5 million as of June 30, 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 periods indicated:
 
   
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
 
   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
Derivatives in Cash Flow Hedging Relationships
 
2012
 
2011
 
2012
 
2011
 
Interest rate contracts
  $ -   $ (2.2 ) $ -   $ (1.8 )
Commodity contracts
    77.3     4.4     92.8     (56.9 )
 
  $ 77.3   $ 2.2   $ 92.8   $ (58.7 )
 
 
 
Gain (Loss) Reclassified from OCI into Income (Effective Portion)
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
Location of Gain (Loss)
 
2012
 
2011
 
2012
 
2011
 
Interest expense, net
  $ (1.9 ) $ (2.2 ) $ (4.2 ) $ (4.6 )
Revenues
    12.9     (11.9 )   15.1     (16.5 )
 
  $ 11.0   $ (14.1 ) $ 10.9   $ (21.1 )
 
Hedge ineffectiveness was 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. We recorded the following mark-to-market gains (losses) for the periods indicated:
 
       
Gain (Loss) Recognized in Income on Derivatives
 
       
Three Months Ended June 30,
 
Six Months Ended June 30,
 
Derivatives not Designated as Hedging Instruments    Location of Gain Recognized in Income on Derivatives  
2012
 
2011
 
2012
 
2011
 
Commodity contracts
 
Revenue
  $ 0.8   $ -   $ 0.9   $ 1.0  
Interest rate swaps
 
Interest expense
    -     (3.2 )   -     (3.2 )
 
The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2015:
 
 
 
June 30, 2012
 
December 31, 2011
 
Commodity hedges, before tax
  $ 68.3   $ (9.4
Commodity hedges, after tax
    (12.2   (16.4
 
As of June 30, 2012, deferred net gains of $48.2 million on commodity hedges and deferred net losses of $7.0 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 $70.7 million as of June 30, 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 asset of $29.3 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 $111.5 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:

 
June 30, 2012
 
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Assets from commodity derivative contracts
$ 77.6   $ -   $ 77.6   $ -  
Liabilities from commodity derivative contracts
$ 6.9   $ -   $ 6.5   $ 0.4  
                         
 
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:

 
June 30, 2012
 
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Long term debt
$ 1,475.1   $ -   $ 1,475.1   $ -  

Additional Information Regarding Level 3 Fair Value Measurements

As of June 30, 2012, certain of our natural gas basis swaps were reported at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract term extends into unobservable periods.

The fair value of these natural gas basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve which is based on observable or public data sources and extrapolated when observable prices are not available.

The significant unobservable input used in the fair value measurement of our Level 3 derivatives is the forward natural gas basis curve beginning in year 2015. Because a significant portion of the derivative’s term is in 2015 and beyond, the entire valuation is categorized as Level 3. The change in the fair value of our Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

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, 2011
  $ -  
Unrealized losses included in OCI
    0.4  
Transfers into Level 3
    -  
Transfers out of Level 3
    -  
Balance, June 30, 2012
  $ 0.4  

There have been no transfers of assets or liabilities between the three levels of the fair value hierarchy during the six months ended June 30, 2012. Our balance in Level 3 is attributable to a new hedge we entered into during the second quarter of 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 senior secured revolving credit facility approximates fair value as its interest rate is based on prevailing market rates. The fair values of our fixed rate debt instruments are based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

 
June 30, 2012
 
December 31, 2011
 
 
Carrying
 
Fair
 
Carrying
 
Fair
 
 
Amount
 
Value
 
Amount
 
Value
 
Senior unsecured notes, 8¼% fixed rate
$ 209.1   $ 217.8   $ 209.1   $ 220.5  
Senior unsecured notes, 11¼% fixed rate
  70.0     82.4     69.8     82.1  
Senior unsecured notes, 7⅞% fixed rate
  250.0     269.7     250.0     264.5  
Senior unsecured notes, 6⅞% fixed rate
  451.9     503.9     450.8     490.2  
Senior unsecured notes, 6⅜% fixed rate
  400.0     401.3     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.

Environmental liabilities were not significant as of June 30, 2012.

Targa has reimbursed us for maintenance capital expenditures of $16.6 million as of June 30, 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 $0.9 million reimbursed to us during the six months ended June 30, 2012. These capital projects were substantially complete as of June 30, 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 June 30, 2012
 
 
 
Field
 
Coastal
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathering
 
Gathering
 
 
 
Marketing
 
 
 
Corporate
 
 
 
 
 
and
 
and
 
Logistics
 
and
 
 
 
and
 
 
 
 
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Consolidated
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales of commodities
  $ 46.6   $ 51.7   $ 54.5   $ 1,068.5   $ 12.8   $ -   $ 1,234.1  
Fees from midstream services
    8.0     4.8     43.1     28.4     -     -     84.3  
 
    54.6     56.5     97.6     1,096.9     12.8     -     1,318.4  
Intersegment revenues
                                           
Sales of commodities
    259.7     162.2     -     114.9     -     (536.8 )   -  
Fees from midstream services
    0.3     -     24.6     7.0     -     (31.9 )   -  
 
    260.0     162.2     24.6     121.9     -     (568.7 )   -  
Revenues
  $ 314.6   $ 218.7   $ 122.2   $ 1,218.8   $ 12.8   $ (568.7 ) $ 1,318.4  
Operating margin
  $ 53.9   $ 28.0   $ 45.7   $ 26.2   $ 12.8   $ -   $ 166.6  
Other financial information:
                                           
Total assets
  $ 1,677.2   $ 423.8   $ 925.8   $ 448.8   $ 77.6   $ 113.2   $ 3,666.4  
Capital expenditures
  $ 46.6   $ 2.6   $ 89.9   $ 0.4   $ -   $ 0.9   $ 140.4  
 
 
 
Three Months Ended June 30, 2011
 
 
 
Field
 
Coastal
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathering
 
Gathering
 
 
 
Marketing
 
 
 
Corporate
 
 
 
 
 
and
 
and
 
Logistics
 
and
 
 
 
and
 
 
 
 
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Consolidated
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales of commodities
  $ 51.6   $ 89.8   $ -   $ 1,528.9   $ (13.2 ) $ (0.1 ) $ 1,657.0  
Fees from midstream services
    6.6     4.5     33.1     24.7     -     0.1     69.0  
 
    58.2     94.3     33.1     1,553.6     (13.2 )   -     1,726.0  
Intersegment revenues
                                           
Sales of commodities
    367.0     244.9     0.1     169.6     -     (781.6 )   -  
Fees from midstream services
    0.2     -     23.7     9.3     -     (33.2 )   -  
 
    367.2     244.9     23.8     178.9     -     (814.8 )   -  
Revenues
  $ 425.4   $ 339.2   $ 56.9   $ 1,732.5   $ (13.2 ) $ (814.8 ) $ 1,726.0  
Operating margin
  $ 80.2   $ 45.7   $ 33.4   $ 30.5   $ (13.2 ) $ -   $ 176.6  
Other financial information:
                                           
Total assets
  $ 1,650.4   $ 430.5   $ 546.9   $ 573.1   $ 35.7   $ 91.8   $ 3,328.4  
Capital expenditures
  $ 40.0   $ 4.2   $ 42.5   $ 0.8   $ -   $ 0.5   $ 88.0  
 
 
17

 
 
 
 
Six Months Ended June 30, 2012
 
 
 
Field
 
Coastal
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathering
 
Gathering
 
 
 
Marketing
 
 
 
Corporate
 
 
 
 
 
and
 
and
 
Logistics
 
and
 
 
 
and
 
 
 
 
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Consolidated
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales of commodities
  $ 92.0   $ 111.5   $ 100.0   $ 2,485.8   $ 14.1   $ -   $ 2,803.4  
Fees from midstream services
    18.9     8.5     82.0     51.1     -     -     160.5  
 
    110.9     120.0     182.0     2,536.9     14.1     -     2,963.9  
Intersegment revenues
                                           
Sales of commodities
    577.1     382.2     -     246.8     -     (1,206.1 )   -  
Fees from midstream services
    0.6     0.1     48.7     16.3     -     (65.7 )   -  
 
    577.7     382.3     48.7     263.1     -     (1,271.8 )   -  
Revenues
  $ 688.6   $ 502.3   $ 230.7   $ 2,800.0   $ 14.1   $ (1,271.8 ) $ 2,963.9  
Operating margin
  $ 126.9   $ 74.3   $ 88.7   $ 52.4   $ 14.1   $ -   $ 356.4  
Other financial information:
                                           
Total assets
  $ 1,677.2   $ 423.8   $ 925.8   $ 448.8   $ 77.6   $ 113.2   $ 3,666.4  
Capital expenditures
  $ 72.8   $ 4.6   $ 150.0   $ 9.5   $ -   $ 1.5   $ 238.4  
 
 
 
Six Months Ended June 30, 2011
 
 
 
Field
 
Coastal
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathering
 
Gathering
 
 
 
Marketing
 
 
 
Corporate
 
 
 
 
 
and
 
and
 
Logistics
 
and
 
 
 
and
 
 
 
 
 
Processing
 
Processing
 
Assets
 
Distribution
 
Other
 
Eliminations
 
Consolidated
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales of commodities
  $ 97.4   $ 168.7   $ 0.1   $ 2,975.2   $ (17.6 ) $ -   $ 3,223.8  
Fees from midstream services
    12.8     9.6     56.3     38.6     -     -     117.3  
 
    110.2     178.3     56.4     3,013.8     (17.6 )   -     3,341.1  
Intersegment revenues
                                           
Sales of commodities
    666.4     461.9     0.2     279.9     -     (1,408.4 )   -  
Fees from midstream services
    0.5     0.4     42.7     17.0     -     (60.6 )   -  
 
    666.9     462.3     42.9     296.9     -     (1,469.0 )   -  
Revenues
  $ 777.1   $ 640.6   $ 99.3   $ 3,310.7   $ (17.6 ) $ (1,469.0 ) $ 3,341.1  
Operating margin
  $ 141.3   $ 82.0   $ 55.7   $ 63.1   $ (17.6 ) $ -   $ 324.5  
Other financial information:
                                           
Total assets
  $ 1,650.4   $ 430.5   $ 546.9   $ 573.1   $ 35.7   $ 91.8   $ 3,328.4  
Capital expenditures
  $ 71.8   $ 5.6   $ 87.6   $ 0.9   $ -   $ 0.6   $ 166.5
 
 
The following table shows our consolidated revenues by product and service for the periods presented:

   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
   
2012
 
2011
 
2012
 
2011
 
Sales of commodities
                 
Natural gas sales
  $ 188.0   $ 292.9   $ 390.7   $ 541.7  
NGL sales
    950.7     1,344.0     2,240.9     2,645.7  
Condensate sales
    29.0     33.1     58.0     54.6  
Petroleum products
    54.3     -     99.8     -  
Derivative activities
    12.1     (13.0 )   14.0     (18.2 )
      1,234.1     1,657.0     2,803.4     3,223.8