form10-q.htm

 




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

For the quarterly period ended September 30, 2011

or

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

For the transition period from _____ to _____

Commission File Number: 001-34991
 
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)


Delaware
 
20-3701075
(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 £
Accelerated filer £
Non-accelerated filer R
Smaller reporting company £
(Do not check if a smaller reporting company)

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

As of November 1, 2011, there were 42,400,818 shares of the registrant’s common stock, $0.001 par value, outstanding.

 
 

 
 
 
                
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
 
 
50
 
 
52
 
 
PART II—OTHER INFORMATION
53
 
 
53
 
 
53
 
 
53
 
 
53
 
 
53
 
 
53
 
 
54
 
 
1

 
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP, collectively “we,” “us,” “Targa,” “TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, 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:

·  
Targa Resources Partners LP’s (the “Partnership”) and 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 the Partnership’s transactions;

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

·  
the level of creditworthiness of counterparties to transactions;

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

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

·  
weather and other natural phenomena;

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

·  
the Partnership’s ability to obtain necessary licenses, permits and other approvals;

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

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

·  
general economic, market and business conditions; and

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

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II–Other Information, Item 1A. Risk Factors” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
 
 
2

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

Bbl
Barrels (equal to 42 gallons)
Btu
British thermal units, a measure of heating value
BBtu
Billion British thermal units
/d
Per day
/hr
Per hour
gal
Gallons
LPG
Liquefied petroleum gas
MBbl
Thousand barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
NGL(s)
Natural gas liquid(s)
NYMEX
New York Mercantile Exchange
   
Price Index
 
Definitions
 
IF-NGPL MC
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB
Inside FERC Gas Market Report, Permian Basin
IF-WAHA
Inside FERC Gas Market Report, West Texas WAHA
NY-WTI
NYMEX, West Texas Intermediate Crude Oil
OPIS-MB
Oil Price Information Service, Mont Belvieu, Texas
 
 
3

 
PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.
 
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
 
 
 
   
 
 
 
 
September 30,
   
December 31,
 
 
 
2011
   
2010
 
 
 
(Unaudited)
 
 
 
(In millions)
 
ASSETS
Current assets:
 
 
   
 
 
Cash and cash equivalents
  $ 154.1     $ 188.4  
Trade receivables, net of allowances of $2.2 million and $7.9 million
    544.5       466.6  
Inventory
    139.4       50.4  
Deferred income taxes
    -       3.6  
Assets from risk management activities
    35.2       25.2  
Other current assets
    17.5       16.3  
Total current assets
    890.7       750.5  
Property, plant and equipment, at cost
    3,572.2       3,331.4  
Accumulated depreciation
    (955.4 )     (822.4 )
Property, plant and equipment, net
    2,616.8       2,509.0  
Long-term assets from risk management activities
    20.8       18.9  
Other long-term assets
    262.1       115.4  
Total assets
  $ 3,790.4     $ 3,393.8  
 
               
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
               
Accounts payable
  $ 298.9     $ 254.2  
Accrued liabilities
    339.7       335.8  
Deferred income taxes
    0.2       -  
Liabilities from risk management activities
    34.7       34.2  
Total current liabilities
    673.5       624.2  
Long-term debt
    1,603.4       1,534.7  
Long-term liabilities from risk management activities
    10.7       32.8  
Deferred income taxes
    117.6       111.6  
Other long-term liabilities
    52.7       54.4  
 
               
Commitments and contingencies (see Note 13)
               
 
               
Owners' equity:
               
Targa Resources Corp. stockholders' equity:
               
Common stock ($0.001 par value, 300,000,000 shares authorized, 42,400,818 and 42,292,348 shares issued and outstanding as of September 30, 2011 and December 31, 2010)
    -       -  
Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding as of September 30, 2011 and December 31, 2010)
    -       -  
Additional paid-in capital
    243.9       244.5  
Accumulated deficit
    (78.6 )     (100.8 )
Accumulated other comprehensive income
    0.4       0.6  
Total Targa Resources Corp. stockholders' equity
    165.7       144.3  
Noncontrolling interests in subsidiaries
    1,166.8       891.8  
Total owners' equity
    1,332.5       1,036.1  
Total liabilities and owners' equity
  $ 3,790.4     $ 3,393.8  
 
               
See notes to consolidated financial statements
 
 
4

 
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
   
 
 
 
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
 
 
(Unaudited)
 
 
 
(In millions, except per share amounts)
 
Revenues
  $ 1,713.6     $ 1,220.0     $ 5,060.5     $ 3,948.3  
Costs and expenses:
                               
Product purchases
    1,485.5       1,033.7       4,364.5       3,393.9  
Operating expenses
    76.5       66.2       214.1       190.4  
Depreciation and amortization expenses
    45.7       50.2       134.3       136.9  
General and administrative expenses
    35.4       27.0       105.1       81.0  
Other
    (0.3 )     (0.4 )     (0.3 )     (0.4 )
 
    1,642.8       1,176.7       4,817.7       3,801.8  
Income from operations
    70.8       43.3       242.8       146.5  
Other income (expense):
                               
Interest expense, net
    (26.8 )     (30.0 )     (83.3 )     (83.9 )
Equity in earnings of unconsolidated investment
    2.2       1.1       5.2       3.8  
Loss on debt repurchases (see Note 6)
    -       -       -       (17.4 )
Gain (loss) on early debt extinguishment, net (see Note 6)
    -       (10.6 )     -       8.1  
Loss on mark-to-market derivative instruments
    (1.8 )     (0.1 )     (5.0 )     (0.4 )
Other income (expense), net
    (0.5 )     0.6       (0.6 )     0.8  
Income before income taxes
    43.9       4.3       159.1       57.5  
Income tax benefit (expense):
                               
Current
    2.5       0.8       (7.6 )     (0.9 )
Deferred
    (9.9 )     (9.4 )     (10.9 )     (17.6 )
 
    (7.4 )     (8.6 )     (18.5 )     (18.5 )
Net income (loss)
    36.5       (4.3 )     140.6       39.0  
Less: Net income attributable to noncontrolling interests
    31.6       13.2       118.4       46.2  
Net income (loss) attributable to Targa Resources Corp.
    4.9       (17.5 )     22.2       (7.2 )
Dividends on Series B preferred stock
    -       (1.4 )     -       (8.4 )
Dividends on common equivalents
    -       -       -       (177.8 )
Net income (loss) available to common shareholders
  $ 4.9     $ (18.9 )   $ 22.2     $ (193.4 )
 
                               
Net income (loss) available per common share - basic
  $ 0.12     $ (3.77 )   $ 0.54     $ (45.00 )
Net income (loss) available per common share - diluted
  $ 0.12     $ (3.77 )   $ 0.54     $ (45.00 )
Weighted average shares outstanding - basic
    41.0       5.0       41.0       4.3  
Weighted average shares outstanding - diluted
    41.5       5.0       41.4       4.3  
 
                               
See notes to consolidated financial statements
 
 
5

 
TARGA RESOURCES CORP.
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
 
   
 
 
 
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
 
 
(Unaudited)
 
 
 
(In millions)
 
Net income (loss) attributable to Targa Resources Corp.
  $ 4.9     $ (17.5 )   $ 22.2     $ (7.2 )
Other comprehensive income (loss) attributable to Targa Resources Corp.
                               
Commodity hedging contracts:
                               
Change in fair value
    7.3       (0.8 )     (1.3 )     44.3  
Settlements reclassified to revenues
    0.8       (1.7 )     0.4       (1.8 )
Interest rate swaps:
                               
Change in fair value
    (0.4 )     (1.2 )     (0.4 )     (3.1 )
Settlements reclassified to interest expense, net
    0.2       0.6       0.9       1.7  
Related income taxes
    (3.1 )     (1.7 )     0.2       (19.8 )
Other comprehensive income (loss) attributable to Targa Resources Corp.
    4.8       (4.8 )     (0.2 )     21.3  
Comprehensive income (loss) attributable to Targa Resources Corp.
    9.7       (22.3 )     22.0       14.1  
 
                               
Net income attributable to noncontrolling interests
    31.6       13.2       118.4       46.2  
Other comprehensive income (loss) attributable to noncontrolling interests
                               
Commodity hedging contracts:
                               
Change in fair value
    39.7       (0.9 )     (8.5 )     44.0  
Settlements reclassified to revenues
    8.7       (5.9 )     22.6       (6.2 )
Interest rate swaps:
                               
Change in fair value
    (1.9 )     (5.5 )     (3.9 )     (20.6 )
Settlements reclassified to interest expense, net
    0.8       2.9       4.8       6.8  
Other comprehensive income (loss) attributable to noncontrolling interests
    47.3       (9.4 )     15.0       24.0  
Comprehensive income attributable to noncontrolling interests
    78.9       3.8       133.4       70.2  
 
                               
Total comprehensive income (loss)
  $ 88.6     $ (18.5 )   $ 155.4     $ 84.3  
 
                               
See notes to consolidated financial statements
 
 
 
6

 
TARGA RESOURCES CORP.
 
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
Additional
 
 
 
Other
 
Non
 
 
 
 
 
Common Stock
 
Paid in
 
Accumulated
 
Comprehensive
 
Controlling
 
 
 
 
 
Shares
 
Amount
 
Capital
 
Deficit
 
Income (Loss)
 
Interests
 
Total
 
 
 
(Unaudited)
 
 
 
(In millions, except shares in thousands)
 
Balance, December 31, 2010
  42,292   $ -   $ 244.5   $ (100.8 ) $ 0.6   $ 891.8   $ 1,036.1  
Compensation on equity grants
  109     -     10.7     -     -     0.7     11.4  
Sale of Partnership limited partner interests
  -     -     -     -     -     298.0     298.0  
Impact of Partnership equity transactions
  -     -     15.1     -     -     (15.1 )   -  
Dividends
  -     -     (26.4 )   -     -     -     (26.4 )
Distributions to noncontrolling interests
  -     -     -     -     -     (142.0 )   (142.0 )
Other comprehensive income (loss)
  -     -     -     -     (0.2 )   15.0     14.8  
Net income
  -     -     -     22.2     -     118.4     140.6  
Balance, September 30, 2011
  42,401   $ -   $ 243.9   $ (78.6 ) $ 0.4   $ 1,166.8   $ 1,332.5  
 
                                         
See notes to consolidated financial statements
 
 
 
7

 
TARGA RESOURCES CORP.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
   
 
 
 
 
Nine Months Ended September 30,
 
 
 
2011
   
2010
 
 
 
(Unaudited)
 
Cash flows from operating activities
 
(In millions)
 
Net income
  $ 140.6     $ 39.0  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Amortization in interest expense
    7.2       6.2  
Paid-in-kind interest expense
    -       9.0  
Compensation on equity grants
    11.4       0.5  
Depreciation and amortization expense
    134.3       136.9  
Accretion of asset retirement obligations
    2.7       2.4  
Deferred income tax expense
    10.9       17.6  
Equity in earnings of unconsolidated investment, net of distributions
    (1.4 )     -  
Risk management activities
    (18.8 )     (16.5 )
Gain on sale of assets
    (0.4 )     (0.4 )
Loss on debt repurchases
    -       17.4  
Gain on early debt extinguishment
    -       (8.1 )
Changes in operating assets and liabilities:
               
Receivables and other assets
    (75.3 )     (7.7 )
Inventory
    (86.9 )     (16.0 )
Accounts payable and other liabilities
    40.3       (54.3 )
Net cash provided by operating activities
    164.6       126.0  
Cash flows from investing activities
               
Outlays for property, plant and equipment
    (214.3 )     (84.2 )
Business acquisitions
    (164.2 )     -  
Investment in unconsolidated affiliate
    (11.9 )     -  
Unconsolidated affiliate distributions in excess of accumulated earnings
    -       1.1  
Other
    0.3       2.4  
Net cash used in investing activities
    (390.1 )     (80.7 )
Cash flows from financing activities
               
Partnership loan facilities:
               
Borrowings
    1,426.0       1,178.1  
Repayments
    (1,656.3 )     (904.0 )
Proceeds from issuance of senior notes
    325.0       250.0  
Cash paid on note exchange
    (27.7 )     -  
Non-Partnership loan facilities:
               
Borrowings
    -       495.0  
Repayments
    -       (949.5 )
Costs incurred in connection with financing arrangements
    (6.2 )     (39.5 )
Distributions to noncontrolling interests
    (142.0 )     (101.2 )
Proceeds from sale of Partnership interests
    -       224.7  
Partnership equity transactions
    298.0       317.8  
Repurchases of common stock
    -       (0.1 )
Stock options exercised
    -       0.9  
Dividends to common and common equivalent shareholders
    (25.6 )     (200.0 )
Dividends to preferred shareholders
    -       (219.9 )
Net cash provided by financing activities
    191.2       52.3  
Net change in cash and cash equivalents
    (34.3 )     97.6  
Cash and cash equivalents, beginning of period
    188.4       252.4  
Cash and cash equivalents, end of period
  $ 154.1     $ 350.0  
 
               
See notes to consolidated financial statements
 
 
 
8

 
TARGA RESOURCES CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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

Note 1 — Organization

Targa Resources Corp. (“TRC”) is a Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations, including our wholly-owned subsidiary TRI Resources Inc. (“TRI”).

Note 2 — Basis of Presentation

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

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

Targa Resources GP LLC (the “General Partner”), an indirect wholly owned subsidiary of ours, is the general partner of Targa Resources Partners LP (the “Partnership”). Because we control the General Partner of the Partnership, under GAAP, we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results in our consolidated financial statements, even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by our controlled affiliates are reflected in our results of operations as net income attributable to non-controlling interests and in our balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.

As of September 30, 2011, our interests in the Partnership consist of the following:

·  
a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;

·  
all Incentive Distribution Rights; and

·  
11,645,659 common units of the Partnership, representing a 13.7% limited partnership interest.

The Partnership is 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 15 for an analysis of our and the Partnership’s operations by segment.
 
 
9

 
Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

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

2011 Accounting Pronouncements

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

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

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

Note 4 – Partnership Business Acquisitions

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

On September 30, 2011 the Partnership acquired two refined petroleum products and crude oil storage and terminaling facilities. The facility on the Hylebos Waterway in the Port of Tacoma, Washington has 758,000 barrels of capacity and handles refined petroleum products, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland has approximately 505,000 barrels of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total consideration for both facilities was $127.7 million plus an additional $7.5 million for estimated working capital and has been included in the Partnership’s other long-term assets in the Partnership’s September 30, 2011 balance sheet pending finalization of fair value accounting under ASC 805.
 
 
10

 
Note 5 — Property, Plant and Equipment

 
 
September 30, 2011
   
December 31, 2010
   
 
 
 
 
 
   
 
   
Targa
   
 
   
 
   
Targa
   
Estimated
 
 
 
Targa
   
TRC
   
Resources
   
Targa
   
TRC
   
Resources
   
Useful
 
 
 
Resources
   
Non-
   
Corp.
   
Resources
   
Non-
   
Corp.
   
Lives
 
 
 
Partners LP
   
Partnership
   
Consolidated
   
Partners LP
   
Partnership
   
Consolidated
   
(In Years)
 
Natural gas gathering systems
  $ 1,710.9     $ -     $ 1,710.9     $ 1,630.9     $ -     $ 1,630.9    
5 to 20
 
Processing and fractionation facilities
    1,058.4       6.6       1,065.0       961.9       6.6       968.5    
5 to 25
 
Terminaling and storage facilities
    272.7       -       272.7       244.7       -       244.7    
5 to 25
 
Transportation assets
    275.5       -       275.5       275.6       -       275.6    
10 to 25
 
Other property, plant and equipment
    51.2       22.6       73.8       46.8       22.6       69.4    
3 to 25
 
Land
    53.2       -       53.2       51.2       -       51.2     -  
Construction in progress
    116.6       4.5       121.1       88.4       2.7       91.1     -  
 
  $ 3,538.5     $ 33.7     $ 3,572.2     $ 3,299.5     $ 31.9     $ 3,331.4        

Note 6 — Debt Obligations

 
September 30,
 
December 31,
 
 
2011
 
2010
 
Long-term debt:
 
 
 
 
Non-Partnership obligations:
 
 
 
 
TRC Holdco loan facility, variable rate, due February 2015
$ 89.3   $ 89.3  
TRI Senior secured revolving credit facility, variable rate, due July 2014 (1)
  -     -  
Obligations of the Partnership: (2)
           
Senior secured revolving credit facility, variable rate, due July 2015 (3)
  535.0     765.3  
Senior unsecured notes, 8¼% fixed rate, due July 2016
  209.1     209.1  
Senior unsecured notes, 11¼% fixed rate, due July 2017
  72.7     231.3  
Unamortized discount
  (3.0   (10.3 )
Senior unsecured notes, 7⅞% fixed rate, due October 2018
  250.0     250.0  
Senior unsecured notes, 6⅞% fixed rate, due February 2021
  483.6     -  
Unamortized discount
  (33.3   -  
Total long-term debt
$ 1,603.4   $ 1,534.7  
Irrevocable standby letters of credit:
           
Letters of credit outstanding under TRI Senior secured credit facility (1)
$ -   $ -  
Letters of credit outstanding under the Partnership Senior secured revolving credit facility (3)
  88.3     101.3  
 
$ 88.3   $ 101.3  
___________
(1)  
As of September 30, 2011, the entire amount of TRI’s $75.0 million credit facility was available for letters of credit and available capacity under this facility was $75.0 million.
(2)  
While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
(3)  
As of September 30, 2011, availability under the Partnership’s $1.1 billion senior secured revolving credit facility was $476.7 million.
 
 
11

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

 
Range of Interest
 
Weighted Average
 
Rates Paid
 
Interest Rate Paid
TRC Holdco loan facility
3.2% - 3.3%   3.3%
TRI Senior secured term loan facility, due 2014
N/A   N/A
Partnership Senior secured revolving credit facility
2.4% - 4.8%   2.7%

Compliance with Debt Covenants

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

Holdco Credit Agreement

During the nine months ended September 30, 2010, we completed transactions that have been recognized in our consolidated financial statements as a debt extinguishment, and recognized a pretax gain of $32.8 million. The transactions included payments of $131.4 million to acquire $164.2 million of outstanding borrowings under our Holdco credit agreement and write offs of associated debt issue costs totaling $1.2 million.

TRI Senior Secured Credit Agreement

During the nine months ended September 30, 2010, we incurred a loss on debt repurchases of $17.4 million comprising $10.9 million of premiums paid and $6.5 million from the write-off of debt issue costs related to the repurchase of our 8½% senior notes. The premiums paid were included as a cash outflow from a financing activity in the Statement of Cash Flows.

During the nine months ended September 30, 2010, we also incurred a loss on debt extinguishments of $12.9 million from the write-off of debt issue costs related to the repayments of our term loan and terminations of our synthetic letter of credit and revolving credit facilities.
 
 
12

 
Partnership 6⅞% Senior Notes

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

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

The 6⅞% Notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the Partnership’s credit facility. They are senior in right of payment to any of the Partnership’s future subordinated indebtedness and are unconditionally guaranteed by certain of the Partnership’s subsidiaries. These notes are effectively subordinated to all secured indebtedness under the Partnership’s credit agreement, which is secured by substantially all of the Partnership’s assets, to the extent of the value of the collateral securing that indebtedness.
 
Interest on the 6⅞% Notes accrues at the rate of 6⅞% per annum and is payable semi-annually in arrears on February 1 and August 1, commencing on August 1, 2011.
 
The Partnership may redeem 35% of the aggregate principal amount of the 6⅞% Notes at any time prior to February 1, 2014, with the net cash proceeds of one or more equity offerings. The Partnership must pay a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:
 
1)  
at least 65% of the aggregate principal amount of the 6⅞% Notes (excluding 6⅞% Notes held by the Partnership) remains outstanding immediately after the occurrence of such redemption; and
 
2)  
the redemption occurs within 90 days of the date of the closing of such equity offering.
 
The Partnership may also redeem all or part of the 6⅞% Notes on or after August 1, 2016 at the prices set forth below plus accrued and unpaid interest and liquidated damages, if any. Redemption periods begin on August 1 of each year indicated below:

Year
 
Percentage
2016
 
103.44%
2017
 
102.29%
2018
 
101.15%
2019 and thereafter
 
100.00%
 
 
13

 
Note 7 — Partnership Units and Related Matters

Partnership Equity

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

Distributions

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

 
 
 
 
Distributions
 
 
 
 
 
 
 
For the Three
 
Limited Partners
 
General Partner
 
 
 
Distributions to Targa Resources
 
Distributions per limited
 
Date Paid
 
Months Ended
 
Common
 
Incentive
    2%  
Total
 
Corp.
 
partner unit
 
 
 
 
 
(In millions, except per unit amounts)
 
 
 
 
 
August 12, 2011
 
June 30, 2011
  $ 48.3   $ 7.8   $ 1.2   $ 57.3   $ 15.6   $ 0.5700  
May 13, 2011
 
March 31, 2011
    47.3     6.8     1.1     55.2     14.4     0.5575  
February 14, 2011
 
December 31, 2010
    46.4     6.0     1.1     53.5     13.5     0.5475  
November 12, 2010
 
September 30, 2010
    40.6     4.6     0.9     46.1     11.8     0.5375  
August 13, 2010
 
June 30, 2010
    35.9     3.5     0.8     40.2     10.4     0.5275  
May 14, 2010
 
March 31, 2010
    35.2     2.8     0.8     38.8     9.6     0.5175  
February 12, 2010
 
December 31, 2009
    35.2     2.8     0.8     38.8     14.0     0.5175  

Subsequent Event. On October 11, 2011, the Partnership announced a cash distribution of $0.5825 per common unit on its outstanding common units for the three months ended September 30, 2011, to be paid on November 14, 2011. The distribution to be paid is $42.6 million to the Partnership’s third-party limited partners, and $6.8 million, $8.8 million and $1.2 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in the Partnership.
 
Note 8 — Common Stock and Related Matters

Secondary Offering

On April 26, 2011, certain of our stockholders sold, in a secondary public offering, 5,650,000 shares of our common stock under a registration statement on Form S-1 at a price of $31.73 per share of common stock ($30.65 per share, net of underwriting discounts), providing additional net proceeds of $173.2 million to selling stockholders. We received no proceeds from the sale of shares by the selling stockholders. Pursuant to the exercise of the underwriters’ overallotment option, selling stockholders also sold an additional 847,500 shares of our common stock, providing net proceeds of $26.0 million. We incurred approximately $0.6 million of expenses in connection with the offering, including all expenses of the selling stockholders which we have paid.
 
 
14

 
Dividends

Dividends since our initial public offering on December 10, 2010 through September 30, 2011 were as follows:

Date Paid
 
For the Three Months Ended
 
Total Dividend Declared
 
Amount of Dividend Paid
 
Accrued Dividends (1)
 
Dividend Declared per Share of Common Stock
 
(In millions, except per share amounts)
 
August 16, 2011
 
June 30, 2011
  $ 12.3   $ 11.9   $ 0.4   $ 0.2900
 
May 13, 2011
 
March 31, 2011
    11.5     11.2     0.3     0.2725
 
February 14, 2011
 
December 31, 2010
    2.6     2.5     0.1     0.0616 (2)
________
(1)  
Represents accrued dividends on the restricted shares that are payable upon vesting.
(2)  
Represents a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public.

Subsequent Event. On October 11, 2011, we announced a quarterly dividend of $0.3075 per share of our common stock on our outstanding common stock for the three months ended September 30, 2011, to be paid on November 15, 2011.
 
Note 9 — Earnings per Common Share

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2011
 
2010
 
2011
 
2010
 
Net income
$ 36.5   $ (4.3 ) $ 140.6   $ 39.0  
Less: Net income attributable to noncontrolling interest
  31.6     13.2     118.4     46.2  
 Net income attributable to Targa Resources Corp.
  4.9     (17.5 )   22.2     (7.2 )
Dividends on Series B preferred stock
  -     (1.4 )   -     (8.4 )
Dividends to common equivalents
  -     -     -     (177.8 )
 Net income attributable to common shareholders
$ 4.9   $ (18.9 ) $ 22.2   $ (193.4 )
 
                       
Weighted average shares outstanding - basic
  41.0     5.0     41.0     4.3  
 
                       
Net income (loss) available per common share - basic
$ 0.12   $ (3.77 ) $ 0.54   $ (45.00 )
 
                       
Weighted average shares outstanding
  41.0     5.0     41.0     4.3  
Dilutive effect of unvested stock awards
  0.5     -     0.4     -  
Weighted average shares outstanding - diluted
  41.5     5.0     41.4     4.3  
 
                       
Net income (loss) available per common share - diluted
$ 0.12   $ (3.77 ) $ 0.54   $ (45.00 )
 
 
15

 
Note 10 — Derivative Instruments and Hedging Activities

Commodity Hedges

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

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

The Partnership hedges a portion of its 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 the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of its underlying West Texas condensate equity volumes.

At September 30, 2011, the notional volumes of the Partnership’s commodity hedges were:

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

The Partnership frequently enters into derivative instruments to manage location basis differentials with short-term fractionation arrangements. Based on the current application of the basis derivatives, the Partnership does not account for these derivatives as hedges and records changes in fair value and cash settlements to revenues.
 
Interest Rate Swaps

On September 6, 2011, the Partnership paid $24.2 million, including $1.2 million in accrued interest, to terminate all of its interest rate swaps. The interest rate swaps were originally entered into to mitigate interest rate risk on the Partnership’s senior secured revolving credit facility. A total of $19.6 million in losses are deferred in other comprehensive income (“OCI”). As long as the Partnership maintains variable rate debt through its senior secured revolving credit facility, this deferred loss will be amortized into interest expense over the original terms of the swap contracts, which extend to April 2014.
 
The following schedules reflect the fair values of the Partnership’s derivative instruments in our financial statements:
 
 
 
Derivative Assets
 
Derivative Liabilities
 
     Balance     Fair Value as of  
Balance
 
Fair Value as of
 
     Sheet  
September 30,
   
December 31,
 
Sheet
 
September 30,
   
December 31,
 
     Location  
2011
   
2010
 
Location
 
2011
   
2010
 
Designated as hedging instruments
     
 
   
 
 
 
 
 
   
 
 
Commodity contracts
  Current assets    $ 34.7     $ 24.8  
Current liabilities
  $ 34.6     $ 25.5  
    Long-term assets      20.8       18.9  
Long-term liabilities
    10.7       20.5  
Interest rate contracts
  Current assets      -       -  
Current liabilities
    -       7.8  
    Long-term assets      -       -  
Long-term liabilities
    -       12.3  
Total designated  as hedging instruments
      $ 55.5     $ 43.7  
 
  $ 45.3     $ 66.1  
 
                   
 
               
Not designated as hedging instruments
                   
 
               
Commodity contracts
  Current assets    $ 0.5     $ 0.4  
Current liabilities
  $ 0.1     $ 0.9  
    Long-term assets      -       -  
Long-term liabilities
    -       -  
Total not designated as hedging instruments
      $ 0.5     $ 0.4  
 
  $ 0.1     $ 0.9  
Total derivatives
      $ 56.0     $ 44.1  
 
  $ 45.4     $ 67.0  
 
The fair value of the Partnership’s 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.
 
 
16

 
The following tables reflect amounts recorded in OCI, amounts reclassified from OCI to revenue and expense and amounts recognized in income on the ineffective portion of the Partnership’s hedges:
 
 
 
Gain (Loss)
 
 
 
Recognized in OCI on
 
Derivatives in
 
Derivatives (Effective Portion)
 
Cash Flow Hedging
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
Relationships
 
2011
   
2010
   
2011
   
2010
 
Interest rate contracts
  $ (2.3 )   $ (6.7 )   $ (4.3 )   $ (23.7 )
Commodity contracts
    47.0       (1.7 )     (9.8 )     88.3  
 
  $ 44.7     $ (8.4 )   $ (14.1 )   $ 64.6  
 
                               
 
 
Gain (Loss)
 
 
 
Reclassified from OCI into
 
 
 
Income (Effective Portion)
 
 
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
Location of Gain (Loss)
    2011       2010       2011       2010  
Interest expense, net
  $ (1.0 )   $ (3.5 )   $ (5.7 )   $ (8.5 )
Revenues
    (9.5 )     7.6       (23.0 )     8.0  
 
  $ (10.5 )   $ 4.1     $ (28.7 )   $ (0.5 )
 
                               
 
 
Gain (Loss)
 
 
 
Recognized in Income on
 
 
 
Derivatives (Ineffective Portion)
 
 
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
Location of Gain (Loss)
    2011       2010       2011       2010  
Revenues
  $ 0.2     $ 0.4     $ 0.2     $ 0.1  
 
 
17

 
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying price indices. During the three and nine months ended September 30, 2011 and 2010, we recorded the following mark-to-market gains (losses):

       
Gain (Loss)
Recognized in Income on
Derivatives
 
 Derivatives Note Designated    Location of Gain (Loss)  
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 As Hedging Instruments    Recognized in Income on Derivatives  
2011
 
2010
 
2011
 
2010
 
Commodity contracts
 
Revenue
  $ 0.4   $ (0.2 ) $ 1.4   $ (0.9 )
Commodity contracts
 
Other income (expense)
    -     (0.1 )   -     (0.4 )
Interest rate swaps
 
Other income (expense)
    (1.8 )   -     (5.0 )   -  
 
 
 
  $ (1.4 ) $ (0.3 ) $ (3.6 ) $ (1.3 )
 
The following table shows the unrealized gains (losses) included in OCI:

 
 
September 30,
   
December 31,
 
 
 
2011
   
2010
 
Unrealized gain on commodity hedges, before tax
  $ 3.5     $ 4.5  
Unrealized gain on commodity hedges, net of tax
    2.1       2.7  
Unrealized loss on interest rate swaps, before tax
    (2.9 )     (3.4 )
Unrealized loss on interest rate swaps, net of tax
    (1.7 )     (2.1 )

As of September 30, 2011, deferred net losses of $7.2 million on commodity hedges and $8.4 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.

In July 2008, Targa and the Partnership paid $9.6 million and $77.8 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Targa and the Partnership also entered into new natural gas and NGL commodity swaps at then current market prices that matched the production volumes of the terminated swaps. Prior to the terminations, these swaps were designated as cash flow hedges. During the three and nine months ended September 30, 2011, an immaterial amount of deferred loss related to the terminated swaps was reclassified from OCI as a non-cash reduction to revenue. During the three and nine months ended September 30, 2010, $7.1 million and $22.2 million of deferred losses related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue.

See Note 3 and Note 11 for additional disclosures related to derivative instruments and hedging activities.
 
 
18

 
Note 11 — Fair Value Measurements

We categorize the inputs to the fair value of 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.

The Partnership’s derivative instruments consist of financially settled commodity swap and option contracts and fixed price commodity contracts with certain counterparties. The Partnership determines the value of its 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. The Partnership has consistently applied these valuation techniques in all periods presented and we believe the Partnership has obtained the most accurate information available for the types of derivative contracts the Partnership holds.
 
The following tables present the fair value of the Partnership’s financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

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

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

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

The Partnership designates all Level 3 derivative instruments as cash flow hedges, and, as such, all changes in their fair value are reflected in OCI. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.
 
 
19

 
Note 12 — Fair Value of Financial Instruments

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

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.
 
The carrying value of the senior secured revolving credit facilities approximate their fair value, as its interest rate is based on prevailing market rates. The fair value of the Partnership’s senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

 
 
September 30, 2011
   
December 31, 2010
 
 
 
Carrying
   
Fair
   
Carrying
   
Fair
 
 
 
Amount
   
Value
   
Amount
   
Value
 
Holdco loan facility (1)
  $ 89.3     $ 87.5     $ 89.3     $ 86.8  
Senior unsecured notes of the Partnership, 8¼% fixed rate
    209.1       218.6       209.1       219.4  
Senior unsecured notes of the Partnership, 11¼% fixed rate
    69.7       81.8       221.0       253.2  
Senior unsecured notes of the Partnership, 7⅞% fixed rate
    250.0       258.4       250.0       259.7  
Senior unsecured notes of the Partnership, 6⅞% fixed rate
    450.3       467.6       N/A       N/A  
________
(1)  
The Holdco loan is not widely held, and we are not able to obtain an indicative quote from external sources. The December 31, 2010 fair value was based on the November 2010 repurchases. The September 30, 2011 fair value is based on management’s consideration of changes in settlement value given the trades that took place in November 2010.

Note 13 — 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.

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

In May 2007, the New Mexico Environment Department (“NMED”) alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants, which are operated by the Partnership and owned by Versado Gas Processors, LLC (“Versado”), a joint venture that owns these plants and in which the Partnership owns a 63% interest, were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.

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

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

 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
Interest paid
  $ 35.1     $ 32.4     $ 83.7     $ 80.4  
Taxes paid
    0.1       54.4       34.2       58.5  
Non-cash adjustment to line-fill
    -       (0.1 )     (2.1 )     0.4  

Note 15 — Segment Information

With the conveyance of all of our remaining operating assets to the Partnership in September 2010, all operating assets are now owned by the Partnership.

The Partnership reports its 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 the Partnership’s hedging activities are reported in Other.

The Partnership’s 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.

The Partnership’s Logistics and Marketing division is also referred to as the Downstream Business. The Downstream Business includes all the activities necessary to convert raw NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, crude and refined products. It also includes certain natural gas supply and marketing activities in support of the Partnership’s other operations.

The Partnership’s Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling crude and refined petroleum products. These assets are generally connected to, and supplied in part by, the Partnership’s 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 Partnership’s 2011 acquisitions of refined petroleum products and crude storage and terminaling facilities.

The Partnership’s 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 the Partnership’s 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 the Partnership from the Partnership’s Natural Gas Gathering and Processing division and the purchase and resale of  natural gas in selected United States markets.

Other contains the results of the Partnership’s commodity hedging activities. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.
 
 
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Segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities. Partnership activities have been presented on a common control accounting basis which reflects the dropdown transactions between Targa and the Partnership as if they occurred in prior periods similar to a pooling of interests. The non-Partnership results include activities related to certain assets and liabilities contractually excluded from the dropdown transactions and certain historical hedge activities that could not be reflected under GAAP in the Partnership common control results.

 
 
Three Months Ended September 30, 2011
 
 
 
Partnership
   
 
   
 
 
 
 
Field
   
Coastal
   
 
   
 
   
 
   
 
   
 
   
 
 
 
 
Gathering
   
Gathering
   
 
   
Marketing
   
 
   
Corporate
   
 
   
 
 
 
 
and
   
and
   
Logistics
   
and
   
 
   
and
   
TRC Non-
   
 
 
 
 
Processing
   
Processing
   
Assets
   
Distribution
   
Other
   
Eliminations
   
Partnership
   
Consolidated
 
Revenues
 
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 
Sales of commodities
  $ 47.9     $ 75.2     $ -     $ 1,530.3     $ (10.8 )   $ 0.1     $ 1.0     $ 1,643.7  
Fees from midstream services
    7.0       3.6       35.5       15.8       -       -       -       61.9  
Other
    (0.2 )     0.3       0.3       7.7       -       -       (0.1 )     8.0  
 
    54.7       79.1       35.8       1,553.8       (10.8 )     0.1       0.9       1,713.6  
Intersegment revenues
                                                               
Sales of commodities
    385.4       242.9       0.1       186.0       -       (814.4 )     -       -  
Fees from midstream services
    0.2       -       24.2       1.8       -       (26.2 )     -       -  
Other
    -       -       -       7.0       -       (7.0 )     -       -  
 
    385.6       242.9       24.3       194.8       -       (847.6 )     -       -  
Revenues
  $ 440.3     $ 322.0     $ 60.1     $ 1,748.6     $ (10.8 )   $ (847.5 )   $ 0.9     $ 1,713.6  
Operating margin
  $ 71.8     $ 39.8     $ 30.1     $ 19.7     $ (10.8 )   $ 0.1     $ 0.9     $ 151.6  
Other financial information:
                                                               
Total assets
  $ 1,647.3     $ 425.2     $ 713.2     $ 702.3     $ 56.0     $ 78.0     $ 168.4     $ 3,790.4  
Capital expenditures (1)
  $ 40.2     $ 4.2     $ 165.0     $ 0.6     $ -     $ 0.8     $ 0.5     $ 211.3  
________
(1)  
Logistics Assets segment capital expenditures includes petroleum logistics acquisitions. See Note 4.

 
 
Three Months Ended September 30, 2010
 
 
 
Partnership
   
 
   
 
 
 
 
Field