e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
June 30, 2008
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission File Number
001-33303
TARGA RESOURCES PARTNERS
LP
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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65-1295427
(I.R.S. Employer
Identification No.)
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1000 Louisiana, Suite 4300, Houston, Texas
(Address of principal
executive offices)
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77002
(Zip
Code)
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Registrants telephone number, including area code:
(713) 584-1000
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 þ No o
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 Ruler
12b-2 of the
Exchange Act. (Check one):
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Large accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange Act) Yes
o No þ
There were 34,652,000 Common Units, 11,528,231 Subordinated
Units and 942,455 General Partner Units outstanding as of
August 1, 2008.
As generally used in the energy industry and in this Quarterly
Report on
Form 10-Q,
the identified terms have the following meanings:
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Bbl
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Barrels
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BBtu
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Billion British thermal units, a measure of heating value
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/d
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Per day
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gal
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Gallons
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MBbl
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Thousand barrels
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MMBtu
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Million British thermal units
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MMcf
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Million cubic feet
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NGL(s)
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Natural gas liquid(s)
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Price Index
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Definitions
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GD-HH
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Henry Hub Gas Daily average
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IF-HH
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Inside FERC Gas Market Report, Henry Hub
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IF-HSC
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Inside FERC Gas Market Report, Houston Ship Channel/Beaumont,
Texas
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IF-NGPL MC
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Inside FERC Gas Market Report, Natural Gas Pipeline,
Mid-Continent
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IF-Waha
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Inside FERC Gas Market Report, West Texas Waha
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NY-HH
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NYMEX, Henry Hub Natural Gas
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NY-WTI
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NYMEX, West Texas Intermediate Crude Oil
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OPIS-MB
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Oil Price Information Service, Mont Belvieu, Texas
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As used in this Quarterly Report, unless the context
otherwise requires, we, us,
our, the Partnership and similar terms
refer to Targa Resources Partners LP, together with its
consolidated subsidiaries.
Cautionary
Statement About Forward-Looking Statements
This Quarterly Report contains forward-looking
statements as defined in Section 21E of the
Securities Exchange Act of 1934, as amended. All statements,
other than statements of historical fact, included in this
Quarterly Report are forward-looking statements. Forward-looking
statements include, without limitation, statements regarding our
future financial position, business strategy, future capital and
other expenditures, plans and objectives of management for
future operations. You can typically identify forward-looking
statements by the use of forward-looking words such as
may, potential, project,
plan, believe, expect,
anticipate, intend, estimate
or similar expressions or variations on such expressions. Each
forward-looking statement reflects our current view of future
events and is subject to risks, uncertainties and other factors,
known and unknown, which could cause our actual results to
differ materially from any results expressed or implied by our
forward-looking statements. These risks and uncertainties, many
of which are beyond our control, include, but are not limited to:
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our ability to access the debt and equity markets, which will
depend on general market conditions and the credit ratings for
our debt obligations;
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our success in risk management activities, including the use of
derivative financial instruments to hedge commodity and interest
rate risks;
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the level of creditworthiness of counterparties to transactions;
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the amount of collateral required to be posted from time to time
in our transactions;
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changes in laws and regulations, particularly with regard to
taxes, safety and protection of the environment or the gathering
and processing industry;
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2
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the timing and extent of changes in natural gas, NGL and
commodity prices, interest rates and demand for our services;
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weather and other natural phenomena;
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industry changes, including the impact of consolidations and
changes in competition;
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our ability to obtain necessary licenses, permits and other
approvals;
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our ability to grow through acquisitions or internal growth
projects, and the successful integration and future performance
of such assets;
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the level and success of natural gas drilling around our assets,
and our success in connecting natural gas supplies to our
gathering and processing systems;
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general economic, market and business conditions; and
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the risks described in this Quarterly Report and our Annual
Report on
Form 10-K
for the year ended December 31, 2007.
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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 this Quarterly Report and under
Item 1A. Risk Factors in our Annual Report on
Form 10-K
for the year ended December 31, 2007. 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.
Forward-looking statements contained in this Quarterly Report
and all subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly
qualified in their entirety by this cautionary statement.
3
PART I
FINANCIAL INFORMATION
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Item 1.
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Financial
Statements
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TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
BALANCE SHEETS
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June 30,
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December 31,
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2008
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2007
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(Unaudited)
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(In thousands)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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31,988
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$
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50,994
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Receivables from third parties
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84,847
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59,346
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Receivables from affiliated companies
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107,367
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87,547
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Inventory
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2,350
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1,624
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Assets from risk management activities
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1,926
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8,695
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Other current assets
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395
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269
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Total current assets
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228,873
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208,475
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Property, plant and equipment, at cost
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1,455,834
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1,433,955
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Accumulated depreciation
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(210,923
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)
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(174,361
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)
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Property, plant and equipment, net
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1,244,911
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1,259,594
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Debt issue costs
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12,321
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6,588
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Long-term assets from risk management activities
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3,362
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3,040
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Other assets
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2,285
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2,275
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Total assets
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$
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1,491,752
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$
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1,479,972
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LIABILITIES AND PARTNERS CAPITAL
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Current liabilities:
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Accounts payable
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$
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5,616
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$
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5,693
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Accrued liabilities
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198,820
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142,836
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Liabilities from risk management activities
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115,293
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44,003
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Total current liabilities
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319,729
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192,532
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Long-term debt
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575,000
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626,300
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Long-term liabilities from risk management activities
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153,697
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43,109
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Deferred income taxes
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1,259
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559
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Other long-term liabilities
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3,451
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3,266
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Commitments and contingencies (Note 8)
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Partners capital:
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Common unitholders (34,652,000 and 34,636,000 units issued
and outstanding at June 30, 2008 and December 31,
2007, respectively)
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778,039
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770,207
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Subordinated unitholders (11,528,231 units issued and
outstanding at June 30, 2008 and December 31, 2007)
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(82,431
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)
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(84,999
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)
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General partner (942,455 and 942,128 units issued and
outstanding at June 30, 2008 and December 31, 2007,
respectively)
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8,424
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4,234
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Accumulated other comprehensive loss
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(265,416
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)
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(75,236
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)
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Total partners capital
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438,616
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614,206
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Total liabilities and partners capital
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$
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1,491,752
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$
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1,479,972
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See notes to consolidated financial statements
4
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months
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Six Months
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Ended
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Ended
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June 30,
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June 30,
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2008
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2007
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2008
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2007
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(Unaudited)
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(In thousands, except per unit amounts)
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Revenues from third parties
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$
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243,138
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$
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175,149
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$
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438,210
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$
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315,339
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Revenues from affiliates
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387,382
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258,466
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704,379
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467,057
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Total operating revenues
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630,520
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433,615
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1,142,589
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782,396
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Costs and expenses:
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Product purchases from third parties
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478,890
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310,465
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854,515
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564,619
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Product purchases from affiliates
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76,269
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61,236
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|
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142,794
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|
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101,580
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Operating expenses
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|
14,701
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|
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11,795
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|
|
|
27,271
|
|
|
|
23,947
|
|
Depreciation and amortization expense
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|
18,421
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|
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17,619
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|
|
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36,669
|
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35,657
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General and administrative expense
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5,715
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4,632
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|
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10,916
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7,986
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Gain on sale of assets
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(1
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)
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(315
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)
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(75
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)
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(315
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)
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|
|
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|
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|
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|
|
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|
|
|
|
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593,995
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405,432
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|
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|
1,072,090
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|
733,474
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Income from operations
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36,525
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28,183
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70,499
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48,922
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Other income (expense):
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|
|
|
|
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|
|
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Interest expense, net
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(7,976
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)
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|
(5,154
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)
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(16,694
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)
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(7,859
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)
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Interest expense allocated from Parent
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(2,732
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)
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|
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(16,175
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)
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Loss on mark-to-market derivative instruments
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(6,122
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)
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(21,002
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)
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Other
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20
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|
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(16
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)
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36
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|
5
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Income before income taxes
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28,569
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14,159
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53,841
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3,891
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|
Deferred income tax expense
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|
|
363
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|
|
|
348
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|
|
|
700
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|
|
|
707
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|
|
|
|
|
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|
|
|
|
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|
|
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Net income
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28,206
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|
13,811
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53,141
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3,184
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Net income (loss) attributable to predecessor operations
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|
|
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9,771
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(3,009
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)
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Net income allocable to partners
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28,206
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|
4,040
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53,141
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|
|
|
6,193
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|
Net income attributable to general partner interests
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|
|
3,384
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|
|
|
81
|
|
|
|
5,230
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|
|
|
124
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|
|
|
|
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|
|
|
|
|
|
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Net income available to common and subordinated unitholders
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|
$
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24,822
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|
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$
|
3,959
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|
|
$
|
47,911
|
|
|
$
|
6,069
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|
|
|
|
|
|
|
|
|
|
|
|
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|
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Basic net income per common and subordinated unit
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|
$
|
0.54
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|
|
$
|
0.13
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|
|
$
|
1.04
|
|
|
$
|
0.20
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Diluted net income per common and subordinated unit
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|
$
|
0.54
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|
|
$
|
0.13
|
|
|
$
|
1.04
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and subordinated units outstanding
|
|
|
46,154
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|
|
|
30,848
|
|
|
|
46,152
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|
|
|
30,848
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|
Diluted average number of common and subordinated units
outstanding
|
|
|
46,163
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|
|
|
30,855
|
|
|
|
46,160
|
|
|
|
30,854
|
|
See notes to consolidated financial statements
5
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
28,206
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|
|
$
|
13,811
|
|
|
$
|
53,141
|
|
|
$
|
3,184
|
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Commodity hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of commodity hedges
|
|
|
(168,452
|
)
|
|
|
(7,440
|
)
|
|
|
(220,236
|
)
|
|
|
(33,335
|
)
|
Reclassification adjustment for settled periods
|
|
|
19,714
|
|
|
|
(1,004
|
)
|
|
|
29,711
|
|
|
|
(5,000
|
)
|
Related income taxes
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
311
|
|
Interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest rate swaps
|
|
|
9,165
|
|
|
|
44
|
|
|
|
(270
|
)
|
|
|
(531
|
)
|
Reclassification adjustment for settled periods
|
|
|
848
|
|
|
|
(88
|
)
|
|
|
615
|
|
|
|
(88
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss
|
|
|
(138,725
|
)
|
|
|
(8,480
|
)
|
|
|
(190,180
|
)
|
|
|
(38,643
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(110,519
|
)
|
|
$
|
5,331
|
|
|
$
|
(137,039
|
)
|
|
$
|
(35,459
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
6
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS
CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Partners Capital
|
|
|
|
|
|
|
Comprehensive
|
|
|
Limited Partners
|
|
|
General
|
|
|
|
|
|
|
Loss
|
|
|
Common
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Total
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Balance as of December 31, 2007
|
|
$
|
(75,236
|
)
|
|
$
|
770,207
|
|
|
$
|
(84,999
|
)
|
|
$
|
4,234
|
|
|
$
|
614,206
|
|
Other contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
8
|
|
Amortization of equity awards
|
|
|
|
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
|
119
|
|
Other comprehensive loss
|
|
|
(190,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(190,180
|
)
|
Net income
|
|
|
|
|
|
|
35,948
|
|
|
|
11,963
|
|
|
|
5,230
|
|
|
|
53,141
|
|
Distributions
|
|
|
|
|
|
|
(28,235
|
)
|
|
|
(9,395
|
)
|
|
|
(1,048
|
)
|
|
|
(38,678
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2008
|
|
$
|
(265,416
|
)
|
|
$
|
778,039
|
|
|
$
|
(82,431
|
)
|
|
$
|
8,424
|
|
|
$
|
438,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
7
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
53,141
|
|
|
$
|
3,184
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
36,607
|
|
|
|
35,596
|
|
Amortization
|
|
|
1,038
|
|
|
|
1,173
|
|
Accretion of asset retirement obligations
|
|
|
72
|
|
|
|
204
|
|
Deferred income tax expense
|
|
|
700
|
|
|
|
707
|
|
Risk management activities
|
|
|
1,011
|
|
|
|
21,087
|
|
Gain on sale of assets
|
|
|
(75
|
)
|
|
|
(315
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(45,321
|
)
|
|
|
(7,151
|
)
|
Inventory
|
|
|
(726
|
)
|
|
|
(270
|
)
|
Other
|
|
|
(2,992
|
)
|
|
|
(503
|
)
|
Accounts payable
|
|
|
(77
|
)
|
|
|
2,641
|
|
Accrued liabilities
|
|
|
55,984
|
|
|
|
12,549
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
99,362
|
|
|
|
68,902
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Purchases of property, plant and equipment
|
|
|
(17,586
|
)
|
|
|
(23,352
|
)
|
Other
|
|
|
(4,150
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(21,736
|
)
|
|
|
(23,382
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Proceeds from equity offerings
|
|
|
|
|
|
|
380,768
|
|
Costs incurred in connection with public offerings
|
|
|
(72
|
)
|
|
|
(3,175
|
)
|
General partner contributions
|
|
|
8
|
|
|
|
|
|
Distributions
|
|
|
(38,678
|
)
|
|
|
(5,315
|
)
|
Proceeds from borrowings under credit facility
|
|
|
|
|
|
|
342,500
|
|
Proceeds from issuance of senior notes
|
|
|
250,000
|
|
|
|
|
|
Costs incurred in connection with financing arrangements
|
|
|
(6,590
|
)
|
|
|
(4,145
|
)
|
Repayments of loans:
|
|
|
|
|
|
|
|
|
Affiliated
|
|
|
|
|
|
|
(665,692
|
)
|
Credit facility
|
|
|
(301,300
|
)
|
|
|
(48,000
|
)
|
Deemed Parent distributions
|
|
|
|
|
|
|
(33,100
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(96,632
|
)
|
|
|
(36,159
|
)
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(19,006
|
)
|
|
|
9,361
|
|
Cash and cash equivalents, beginning of period
|
|
|
50,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
31,988
|
|
|
$
|
9,361
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
Net settlement of allocated indebtedness and debt issue costs
|
|
$
|
|
|
|
$
|
239,065
|
|
Net contribution of affiliated receivables
|
|
|
|
|
|
|
38,856
|
|
See notes to consolidated financial statements
8
Targa
Resources Partners LP
|
|
Note 1
|
Organization
and Operations
|
Targa Resources Partners LP (we, us,
our or the Partnership) is a publicly
traded Delaware limited partnership. Our common units are listed
on The NASDAQ Stock Market LLC under the symbol
NGLS. We were formed on October 26, 2006 by
Targa Resources, Inc. (Targa or Parent),
a leading provider of midstream natural gas and NGL services in
the United States, to own, operate, acquire and develop a
diversified portfolio of complementary midstream energy assets.
We are engaged in the business of gathering, compressing,
treating, processing and selling natural gas and fractionating
and selling natural gas liquids (NGLs) and NGL
products. We currently operate in the Fort Worth Basin/Bend
Arch in North Texas (the North Texas system), the
Permian Basin in West Texas (the SAOU system) and in
Southwest Louisiana (the LOU system).
|
|
Note 2
|
Basis of
Presentation
|
These unaudited consolidated financial statements have been
prepared 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.
The year-end balance sheet data was derived from audited
financial statements, but does not include all disclosures
required by GAAP. The unaudited consolidated financial
statements for the three and six month periods ended
June 30, 2008 and 2007 include all adjustments, both normal
and recurring, which are, in the opinion of management,
necessary for a fair statement of the results for the interim
periods. All significant intercompany balances and transactions
have been eliminated in consolidation. Transactions between us
and other Targa operations have been identified in the unaudited
consolidated financial statements as transactions between
affiliates (see Note 5). Our results of operations for the
three and six month periods ended June 30, 2007 were
adjusted to reflect the consideration of common control
accounting and change in predecessor entities as discussed in
Notes 4 and 15 in our Annual Report on
Form 10-K
for the year ended December 31, 2007. Our financial results
for the three and six month periods ended June 30, 2008 are
not necessarily indicative of the results that may be expected
for the full year ending December 31, 2008. These unaudited
consolidated financial statements and other information included
in this Quarterly Report on
Form 10-Q
should be read in conjunction with our consolidated financial
statements and notes thereto included in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
|
|
Note 3
|
Accounting
Pronouncements
|
Accounting
Pronouncements Recently Adopted.
In September 2006, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting
Standards (SFAS) 157, Fair Value
Measurements. SFAS 157 establishes a framework
for measuring fair value and expands disclosures about fair
value measurements. The FASB partially deferred the effective
date of SFAS 157 for nonfinancial assets and liabilities
that are recognized or disclosed at fair value in the financial
statements on a nonrecurring basis. We adopted SFAS 157
with respect to financial assets and liabilities that are
recognized on a recurring basis on January 1, 2008.
Although the adoption of SFAS 157 did not materially impact
our financial condition, results of operations, or cash flow,
the Company is now required to provide additional disclosures as
part of its financial statements.
SFAS 157 establishes a three-tier fair value hierarchy,
which prioritizes the inputs used in measuring fair value. These
tiers include: Level 1, defined as observable inputs such
as quoted prices in active markets; Level 2, defined as
inputs other than quoted prices in active markets that are
either directly or indirectly observable; and Level 3,
defined as unobservable inputs in which little or no market data
exists, therefore requiring an entity to develop its own
assumptions.
Our derivative instruments consist of financially settled
commodity and interest rate swap and option contracts and fixed
price commodity contracts with certain customers. We determine
the value of our
9
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
derivative contracts utilizing a discounted cash flow model for
swaps and a standard option pricing model for options, based on
inputs that are either readily available in public markets or
are quoted by counterparties to these contracts. In situations
where we obtain inputs via quotes from our counterparties, we
verify the reasonableness of these quotes via similar quotes
from another source for each date for which financial statements
are presented. 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. We have categorized the inputs for
these contracts as Level 2 or Level 3. The price
quotes for the Level 3 inputs are provided by a
counterparty with whom we regularly transact business.
The fair value of our financial instruments as of June 30,
2008 was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
(In thousands)
|
|
|
Assets from commodity derivative contracts
|
|
$
|
3,756
|
|
|
$
|
|
|
|
$
|
1,939
|
|
|
$
|
1,817
|
|
Assets from interest rate swaps
|
|
|
1,532
|
|
|
|
|
|
|
|
1,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
5,288
|
|
|
$
|
|
|
|
$
|
3,471
|
|
|
$
|
1,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities from commodity derivative contracts
|
|
$
|
266,572
|
|
|
$
|
|
|
|
$
|
72,845
|
|
|
$
|
193,728
|
|
Liabilities from interest rate swaps
|
|
|
2,418
|
|
|
|
|
|
|
|
2,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
268,990
|
|
|
$
|
|
|
|
$
|
75,263
|
|
|
$
|
193,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
(In thousands)
|
|
|
Beginning balance
|
|
$
|
(71,370
|
)
|
Losses included in other comprehensive income
|
|
|
(148,160
|
)
|
Settlements
|
|
|
27,619
|
|
Transfers in/out of Level 3
|
|
|
|
|
|
|
|
|
|
Ending balance, June 30, 2008
|
|
$
|
(191,911
|
)
|
|
|
|
|
|
In February 2007, the FASB issued SFAS 159, The
Fair Value Option for Financial Assets and Financial
Liabilities, including an amendment of FASB Statement
No. 115. SFAS 159 expands opportunities to
use fair value measurements in financial reporting and permits
entities to choose to measure many financial instruments and
certain other items at fair value. Our adoption of SFAS 159
on January 1, 2008 did not have a material impact on our
consolidated financial statements.
Accounting
Pronouncements Recently Issued
In March 2008, the FASBs Emerging Issues Task Force
(EITF) reached a consensus on
EITF 07-4,
Application of the Two-Class Method under FASB
Statement No. 128, Earnings per Share, to Master Limited
Partnerships.
EITF 07-4
improves the comparability of earnings per unit calculations for
master limited partnerships (MLPs) with incentive
distribution rights (IDRs) in accordance with
Statement 128 and its related interpretations. Under
EITF 07-4,
when a MLPs current-period earnings are in excess of cash
distributions and the IDRs are a separate limited partner
interest, undistributed earnings should be allocated to the
general partner (GP), limited partners
(LPs) and IDR holder utilizing the contractual terms
of the partnership agreement. The distribution formula for
available cash specified in the partnership agreement
contractually mandates the way in which earnings are distributed.
10
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
Additionally,
EITF 07-4
requires a MLP to reflect its contractual obligation to make
distributions as of the end of the current reporting period.
Therefore, a MLP would reduce (increase) income (loss) from
continuing operations (or net income or loss) for the current
reporting period by the amount of available cash that has been
or will be distributed to the GP, LPs, and IDR holder for that
current reporting period. If distributions to the IDR holder are
contractually limited to available cash as defined in the
partnership agreement, then the specified threshold for the
current reporting period would be the holders share of
available cash that has been or will be distributed to the IDR
holder for that current reporting period.
EITF 07-4
is effective for financial statements issued for fiscal years
beginning after December 15, 2008, and interim periods
within those fiscal years. Earlier application is not permitted.
Our adoption of
EITF 07-4
will not impact our consolidated financial position, results of
operations or cash flows. We are currently evaluating the effect
this pronouncement will have on our present computation of
earnings per unit.
In March 2008, the FASB issued SFAS 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133. SFAS 161 changes the disclosure
requirements for derivative instruments and hedging activities.
Entities are required to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments,
(b) how derivative instruments and related hedged items are
accounted for under SFAS 133 and its related
interpretations, and (c) how derivative instruments and
related hedged items affect an entitys financial position,
financial performance, and cash flows. SFAS 161 is
effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008. Early
adoption is encouraged. Our adoption of SFAS 161 will not
impact our consolidated financial position, results of
operations or cash flows.
|
|
Note 4
|
Net
Income per Limited Partner Unit and Distributions
|
Our net income is allocated to the general partner and the
limited partners, including the holders of the subordinated
units, in accordance with their respective ownership
percentages, after giving effect to incentive distributions paid
to the general partner.
Securities that meet the definition of a participating security
are required to be considered for inclusion in the computation
of basic earnings per unit using the two-class method. Under the
two-class method, earnings per unit is calculated as if all of
the earnings for the period were distributed under the terms of
the partnership agreement, regardless of whether the general
partner has discretion over the amount of distributions to be
made in any particular period, whether those earnings would
actually be distributed during a particular period from an
economic or practical perspective, or whether the general
partner has other legal or contractual limitations on its
ability to pay distributions that would prevent it from
distributing all of the earnings for a particular period.
These required disclosures do not impact our overall net income
or other financial results; however, in periods in which
aggregate net income exceeds the First Target Distribution
Level, it will have the impact of reducing net income per
limited partner unit. This result occurs as a larger portion of
our aggregate earnings, as if distributed, is allocated to the
incentive distribution rights held by the general partner, even
though we make distributions on the basis of Available Cash and
not earnings. In periods in which our aggregate net income does
not exceed the First Target Distribution Level, there is no
impact on our calculation of earnings per limited partner unit.
For the three and six months ended June 30, 2008, our
aggregate net income per limited partner unit was greater than
the First Target Distribution level, and as a result we
allocated $2.8 million and $4.2 million in additional
earnings to the general partner. For the three months and six
months ended June 30, 2007, our aggregate net income per
limited partner unit was less than the First Target
Distribution, and as a result there was no impact on our
calculation of earnings per limited partner unit.
Basic and diluted net income per limited partner unit is
calculated by dividing limited partners interest in net
income, less pro forma general partner incentive distributions
as described above, by the weighted-average number of
outstanding limited partner units during the period.
11
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
The following table shows the distributions that we made to
unitholders during the six months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution per
|
|
Distribution per
|
|
|
|
|
Quarter Ended
|
|
Common Unit
|
|
Subordinated Unit
|
|
Date Paid
|
|
Total Distribution
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
December 31, 2007
|
|
$
|
0.3975
|
|
|
$
|
0.3975
|
|
|
|
February 14, 2008
|
|
|
$
|
18,792
|
|
March 31, 2008
|
|
|
0.4175
|
|
|
|
0.4175
|
|
|
|
May 15, 2008
|
|
|
$
|
19,886
|
|
See also Note 10 Subsequent Events regarding
subsequent distributions.
The following table illustrates our calculation of net income
per common and subordinated partner unit for the three and six
months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
28,206
|
|
|
$
|
13,811
|
|
|
$
|
53,141
|
|
|
$
|
3,184
|
|
Less: Net income (loss) attributable to predeccessor operations
|
|
|
|
|
|
|
9,771
|
|
|
|
|
|
|
|
(3,009
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocable to partners
|
|
|
28,206
|
|
|
|
4,040
|
|
|
|
53,141
|
|
|
|
6,193
|
|
Net income attributable to general partner interests
|
|
|
3,384
|
|
|
|
81
|
|
|
|
5,230
|
|
|
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and subordinated unitholders
|
|
$
|
24,822
|
|
|
$
|
3,959
|
|
|
$
|
47,911
|
|
|
$
|
6,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common and subordinated unit
|
|
$
|
0.54
|
|
|
$
|
0.13
|
|
|
$
|
1.04
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common and subordinted unit
|
|
$
|
0.54
|
|
|
$
|
0.13
|
|
|
$
|
1.04
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and subordinated units outstanding
|
|
|
46,154
|
|
|
|
30,848
|
|
|
|
46,152
|
|
|
|
30,848
|
|
Restrictive equivalents
|
|
|
9
|
|
|
|
7
|
|
|
|
8
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted average number of common and subordinated units
outstanding
|
|
|
46,163
|
|
|
|
30,855
|
|
|
|
46,160
|
|
|
|
30,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5
|
Related-Party
Transactions
|
Targa
Resources, Inc.
We are a party to various agreements with Targa, our general
partner and others that address (i) the reimbursement of
our general partner for costs incurred on our behalf,
(ii) our sales of certain NGLs and NGL products to, and
purchases from Targa; and (iii) our sales of our natural
gas to, and purchases from Targa.
12
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes the sales to and purchases from
affiliates of Targa, payments made or received by Targa on
behalf of the Partnership and allocations of costs from Targa
which were settled through adjustments to partners
capital. Management believes these transactions are executed on
terms that are fair and reasonable.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
Sales to affiliates
|
|
$
|
387,382
|
|
|
$
|
258,466
|
|
|
$
|
704,379
|
|
|
$
|
467,057
|
|
Purchases from affiliates
|
|
|
76,269
|
|
|
|
61,236
|
|
|
|
142,794
|
|
|
|
101,580
|
|
Allocations of general & administrative
expenses pre IPO
|
|
|
|
|
|
|
2,679
|
|
|
|
|
|
|
|
5,157
|
|
Allocations of general & administrative expenses under
Omnibus Agreement
|
|
|
4,236
|
|
|
|
1,953
|
|
|
|
8,098
|
|
|
|
2,829
|
|
Allocated interest
|
|
|
|
|
|
|
2,743
|
|
|
|
|
|
|
|
16,186
|
|
Payments made by Parent on our behalf
|
|
|
|
|
|
|
143,961
|
|
|
|
|
|
|
|
233,979
|
|
Net change in affiliate receivable
|
|
|
4,558
|
|
|
|
22,062
|
|
|
|
19,820
|
|
|
|
50,701
|
|
Centralized
Cash Management
Prior to the contribution of the North Texas, SAOU and LOU
Systems to us, the excess cash from these subsidiaries was held
in separate bank accounts and swept to a centralized account
under Targa. After the contribution of these systems, their bank
accounts are maintained under the Partnerships separate
centralized cash management system.
For the North Texas System, prior to February 14, 2007,
cash distributions are deemed to have occurred through
partners capital and are reflected as an adjustment to
partners capital. For the period from January 1, 2007
through February 13, 2007, deemed net capital distributions
from the Partnership were $0.5 million.
For the SAOU and LOU Systems, for the period from
January 1, 2007 though June 30, 2007, deemed net
capital distributions from the Partnership were
$32.6 million.
Other
Commodity hedges. We have entered into various
commodity derivative transactions with Merrill Lynch Commodities
Inc. (MLCI), an affiliate of Merrill Lynch, Pierce,
Fenner & Smith Incorporated (Merrill
Lynch). Merrill Lynch holds an equity interest in the
holding company that indirectly owns our general partner. Under
the terms of these various commodity derivative transactions,
MLCI has agreed to pay us specified fixed prices in relation to
specified notional quantities of natural gas and condensate over
periods ending in 2010, and we have agreed to pay MLCI floating
prices based on published index prices of such commodities for
delivery at specified locations. The following table shows our
open commodity derivatives with MLCI as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
Instrument Type
|
|
|
Daily Volumes
|
|
Average Price
|
|
Index
|
|
|
Jul 2008 Dec 2008
|
|
Natural gas
|
|
|
Swap
|
|
|
|
3,847
|
|
|
MMBtu
|
|
$
|
8.76
|
|
|
per MMBtu
|
|
|
IF-Waha
|
|
Jan 2009 Dec 2009
|
|
Natural gas
|
|
|
Swap
|
|
|
|
3,556
|
|
|
MMBtu
|
|
$
|
8.07
|
|
|
per MMBtu
|
|
|
IF-Waha
|
|
Jan 2010 Dec 2010
|
|
Natural gas
|
|
|
Swap
|
|
|
|
3,289
|
|
|
MMBtu
|
|
$
|
7.39
|
|
|
per MMBtu
|
|
|
IF-Waha
|
|
Jul 2008 Dec 2008
|
|
NGL
|
|
|
Swap
|
|
|
|
3,175
|
|
|
Bbl
|
|
$
|
1.06
|
|
|
per gallon
|
|
|
OPIS-MB
|
|
Jan 2009 Dec 2009
|
|
NGL
|
|
|
Swap
|
|
|
|
3,000
|
|
|
Bbl
|
|
$
|
0.98
|
|
|
per gallon
|
|
|
OPIS-MB
|
|
Jul 2008 Dec 2008
|
|
Condensate
|
|
|
Swap
|
|
|
|
264
|
|
|
Bbl
|
|
$
|
72.66
|
|
|
per barrel
|
|
|
NY-WTI
|
|
Jan 2009 Dec 2009
|
|
Condensate
|
|
|
Swap
|
|
|
|
202
|
|
|
Bbl
|
|
$
|
70.60
|
|
|
per barrel
|
|
|
NY-WTI
|
|
Jan 2010 Dec 2010
|
|
Condensate
|
|
|
Swap
|
|
|
|
181
|
|
|
Bbl
|
|
$
|
69.28
|
|
|
per barrel
|
|
|
NY-WTI
|
|
13
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
As of June 30, 2008, the fair value of these open positions
is a liability of $70.4 million. For the three and six
months ended June 30, 2008, we paid MLCI $7.4 million
and $11.7 million to settle payments due under hedge
transactions. For the three and six months ended June 30,
2007, we paid MLCI $1.1 million and $1.8 million to
settle payments due under hedge transactions.
Our outstanding debt, including outstanding borrowings, issued
letters of credit and available borrowings under our senior
secured credit facility as of the dates shown below was:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Senior notes,
81/4%
fixed rate, due July 1, 2016
|
|
$
|
250,000
|
|
|
$
|
|
|
Senior secured credit facility, variable rate, due
February 14, 2012
|
|
|
325,000
|
|
|
|
626,300
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
575,000
|
|
|
$
|
626,300
|
|
|
|
|
|
|
|
|
|
|
Letters of credit issued
|
|
$
|
41,250
|
|
|
$
|
25,900
|
|
|
|
|
|
|
|
|
|
|
Available borrowings under credit facility
|
|
$
|
483,750
|
|
|
$
|
97,800
|
|
|
|
|
|
|
|
|
|
|
81/4% Senior
Notes due 2016
On June 18, 2008, we completed the private placement under
Rule 144A and Regulation S of the Securities Act of
1933 (Rule 144A) of $250 million in
aggregate principal amount of
81/4% senior
notes due 2016 (the Notes). Proceeds from the Notes
were used to repay borrowings under our senior secured credit
facility.
The Notes:
|
|
|
|
|
are our unsecured senior obligations;
|
|
|
|
rank pari passu in right of payment with our existing and
future senior indebtedness, including indebtedness under our
senior secured credit facility;
|
|
|
|
are senior in right of payment to any of our future subordinated
indebtedness; and
|
|
|
|
are unconditionally guaranteed by us.
|
The Notes are effectively subordinated to all secured
indebtedness under our senior secured 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 Notes accrues at the rate of
81/4%
per annum and is payable semi-annually in arrears on
January 1, and July 1, commencing on January 1,
2009. Interest is computed on the basis of a
360-day year
comprising twelve
30-day
months.
At any time prior to July 1, 2011, we may on any one or
more occasions redeem up to 35% of the aggregate principal
amount of the Notes with the net cash proceeds of one or more
equity offerings by us; at a redemption price of 108.25% 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
Notes (including any additional notes) (excluding Notes held by
us) remains outstanding immediately after the occurrence of such
redemption; and
(2) the redemption occurs within 90 days of the date
of the closing of such equity offering.
14
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
At any time prior to July 1, 2012, we may also redeem all
or a part of the Notes, at a redemption price equal to 100% of
the principal amount of the Notes redeemed plus the applicable
premium as defined in the indenture agreement, as of, and
accrued and unpaid interest and liquidated damages, if any, to
the date of redemption.
On or after July 1, 2012, we may redeem all or a part of
the Notes, at the redemption prices set forth below (expressed
as percentages of principal amount) plus accrued and unpaid
interest and liquidated damages, if any, on the Notes redeemed,
if redeemed during the twelve-month period beginning on July 1
of each year indicated below:
|
|
|
|
|
Year
|
|
Percentage
|
|
|
2012
|
|
|
104.125
|
%
|
2013
|
|
|
102.063
|
%
|
2014 and thereafter
|
|
|
100.000
|
%
|
The Notes are subject to a registration rights agreement dated
as of June 18, 2008. Under the registration rights
agreement, we are required to file by June 19, 2009 a
registration statement with respect to any Notes that are not
freely transferable without volume restrictions by holders of
the Notes that are not affiliates of the Partnership. If we fail
to do so, additional interest will accrue on the principal
amount of the Notes. Under
EITF 00-19-2,
Accounting for Registration Payment
Arrangements, we have determined that the payment of
additional interest is not probable, as that term is defined in
SFAS 5, Accounting for Contingencies. As
a result, we have not recorded a liability for any contingent
obligation. Any subsequent accruals of a liability or payments
made under this registration rights agreement will be charged to
earnings as interest expense in the period they are recognized
or paid.
Senior
Secured Credit Facility
Concurrent with the closing of the private placement of the
$250 million senior notes, we increased the commitments
under our senior secured credit facility by $100 million,
bringing the total commitments under our senior secured credit
facility to $850 million. We may still request additional
commitments of up to $150 million under the senior secured
credit facility, which would increase the total commitments
under our senior secured credit facility to $1 billion.
Our weighted average interest rate on outstanding borrowings
under our senior secured credit facility for the six months
ended June 30, 2008 was 5.0%.
|
|
Note 7
|
Derivative
Instruments and Hedging Activities
|
As of June 30, 2008 and December 31, 2007, accumulated
other comprehensive income (loss) (OCI) included
$264.5 million and $74.0 million of unrealized net
losses, respectively, on commodity hedges.
For the three and six months ended June 30, 2008, deferred
net losses on commodity hedges of $19.7 million and
$29.7 million were reclassified from OCI to revenues,
respectively. For the three and six months ended
June 30, 2007, deferred net gains on commodity hedges of
$1.0 million and $5.0 million were reclassified from
OCI to revenues, respectively. There were no adjustments for
hedge ineffectiveness.
As of June 30, 2008 and December 31, 2007, OCI also
included $0.9 million and $1.2 million of unrealized
losses, respectively, on interest rate hedges. For the three and
six months ended June 30, 2008, unrealized losses on
interest rate hedges of $0.8 million and $0.6 million
were reclassified from OCI to interest expense. For the three
and six months ended June 30, 2007, unrealized gains on
interest rate hedges of $0.1 million were reclassified from
OCI to interest expense. There were no adjustments for hedge
ineffectiveness.
15
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
As of June 30, 2008, deferred net losses of
$111.4 million on commodity hedges and $2.1 million on
interest rate hedges recorded in OCI are expected to be
reclassified to revenues from third parties and interest
expense, respectively, during the next twelve months.
As of June 30, 2008, we had the following hedge
arrangements which will settle during the years ended
December 31, 2008 through 2012 (except as indicated
otherwise, the 2008 volumes reflect daily volumes for the period
from July 1, 2008 through December 31, 2008):
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/MMBtu
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Natural Gas Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
NY-HH
|
|
|
8.43
|
|
|
|
1,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-HSC
|
|
|
8.09
|
|
|
|
2,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,143
|
)
|
Swap
|
|
IF-HSC
|
|
|
7.39
|
|
|
|
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,236
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,328
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.43
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,088
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
8.02
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,016
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(5,536
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(2,316
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(2,309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
(21,266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-Waha
|
|
|
8.20
|
|
|
|
7,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,101
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.61
|
|
|
|
|
|
|
|
6,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,380
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
5,709
|
|
|
|
|
|
|
|
|
|
|
|
(5,699
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
|
|
|
|
(2,786
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
(2,924
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,389
|
|
|
|
6,936
|
|
|
|
5,709
|
|
|
|
3,250
|
|
|
|
3,250
|
|
|
|
(25,890
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
16,681
|
|
|
|
15,158
|
|
|
|
11,394
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
(51,277
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-Waha
|
|
|
6.85
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Floor
|
|
IF-Waha
|
|
|
6.55
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(51,228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
NGLs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/gal
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
NGL Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
OPIS-MB
|
|
|
|
1.01
|
|
|
|
7,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(45,341
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.96
|
|
|
|
|
|
|
|
6,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(62,001
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
4,809
|
|
|
|
|
|
|
|
|
|
|
|
(40,124
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,400
|
|
|
|
|
|
|
|
(26,650
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,700
|
|
|
|
(19,612
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
7,095
|
|
|
|
6,248
|
|
|
|
4,809
|
|
|
|
3,400
|
|
|
|
2,700
|
|
|
|
(193,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floors
|
|
|
OPIS-MB
|
|
|
|
1.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
|
|
|
|
|
|
860
|
|
Floors
|
|
|
OPIS-MB
|
|
|
|
1.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
422
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
|
|
422
|
|
|
|
1,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(191,911
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/Bbl
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Condensate Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
NY-WTI
|
|
|
|
67.19
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(4,922
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
69.00
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,937
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(6,821
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(19,680
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.50
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.00
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(19,677
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
Hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
Instrument Type
|
|
Daily Volume
|
|
|
Average Price
|
|
|
Index
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul 2008 Dec 2008
|
|
Natural gas
|
|
Swap
|
|
|
7,043 MMBtu
|
|
|
$
|
12.81 per MMBtu
|
|
|
|
NY-HH
|
|
|
$
|
453
|
|
Jan 2009 Dec 2009
|
|
Natural gas
|
|
Swap
|
|
|
658 MMBtu
|
|
|
|
11.95 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
123
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul 2008 Dec 2008
|
|
Natural gas
|
|
Fixed price sale
|
|
|
7,043 MMBtu
|
|
|
|
12.81 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
(453)
|
|
Jan 2009 Dec 2009
|
|
Natural gas
|
|
Fixed price sale
|
|
|
658 MMBtu
|
|
|
|
11.95 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
(123)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
The fair value of 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. These contracts may expose us to the risk of financial
loss in certain circumstances. Our hedging arrangements provide
us protection on the hedged volumes if prices decline below the
prices at which these hedges are set. If prices rise above the
prices at which we have hedged, we will receive less revenue on
the hedged volumes than we would receive in the absence of
hedges.
See also Note 10 Subsequent Events regarding
termination and rehedging of commodity hedges.
As of June 30, 2008, we had the following open interest
rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
|
|
|
|
|
Notional
|
|
Effective Date
|
|
Date
|
|
|
Rate
|
|
|
Amount
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
12/13/2007
|
|
|
01/24/2011
|
|
|
|
4.0775
|
%
|
|
$
|
50,000
|
|
12/18/2007
|
|
|
01/24/2011
|
|
|
|
4.2100
|
%
|
|
|
50,000
|
|
12/21/2007
|
|
|
01/24/2012
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
12/21/2007
|
|
|
01/24/2012
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
01/09/2008
|
|
|
01/24/2012
|
|
|
|
3.6990
|
%
|
|
|
50,000
|
|
01/11/2008
|
|
|
01/24/2012
|
|
|
|
3.6400
|
%
|
|
|
50,000
|
|
Each swap fixes the three month LIBOR rate as indicated for the
specified notional amount outstanding under our senior secured
credit facility over the term of each swap agreement. The fair
value of our outstanding interest rate swaps was a liability of
$0.9 million as of June 30, 2008. We have designated
all interest rate swaps as cash flow hedges. Accordingly,
unrealized gains and losses relating to the interest rate swaps
are recorded in OCI until the interest expense on the related
debt is recognized in earnings.
|
|
Note 8
|
Commitments
and Contingencies
|
Environmental
For environmental matters, we record liabilities when remedial
efforts are probable and the costs are reasonably estimated in
accordance with the American Institute of Certified Public
Accountants Statement of Position
96-1,
Environmental Remediation Liabilities.
Environmental reserves do not reflect managements
assessment of the 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. This liability was transferred as part
of the assets contributed to us at the time of our initial
public offering.
Our environmental liability was $0.3 million as of
June 30, 2008, primarily for ground water assessment and
remediation.
Litigation
On December 8, 2005, WTG Gas Processing (WTG)
filed suit in the 333rd District Court of Harris County,
Texas against several defendants, including Targa Resources,
Inc., and three other Targa entities and private equity funds
affiliated with Warburg Pincus LLC, seeking damages from the
defendants. The suit alleges that Targa and private equity funds
affiliated with Warburg Pincus, along with ConocoPhillips
Company (ConocoPhillips) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to
have had to purchase the SAOU system from ConocoPhillips, and
(ii) prospective business relations of WTG. WTG claims the
alleged interference resulted from Targas competition to
purchase the ConocoPhillips assets and its successful
acquisition of those assets in 2004. On October 2, 2007,
the District Court granted defendants motions for summary
judgment on all of WTGs claims. Targa has agreed to
indemnify us for any claim or
18
Targa
Resources Partners LP
Notes to
Consolidated Financial
Statements (Continued)
liability arising out of the WTG suit. WTGs motion to
reconsider and for a new trial was overruled. On January 2,
2008, WTG filed a notice of appeal, and on May 6, 2008
filed its appellants brief with the 14th Court of
Appeals in Houston, Texas. Targa filed its appellees brief
on June 26, 2008. Targa will contest the appeal, but can
give no assurances regarding the outcome of the proceeding.
|
|
Note 9
|
Share-Based
Compensation
|
Our general partner has adopted a long-term incentive plan
(the Plan) for employees, consultants and directors
of the general partner and its affiliates who perform services
for us. We account for awards under the Plan utilizing the fair
value recognition provisions of SFAS 123R,
Share-Based Payment.
Non-Employee
Director Grants
On March 25, 2008, our general partner made equity-based
awards of 16,000 restricted common units of the Partnership
(2,000 restricted common units in the Partnership to each of the
Partnerships non-management directors and to each of Targa
Resources Investments Inc.s independent directors) under
the Plan. The awards will settle with the delivery of common
units and are subject to three-year vesting, without a
performance condition, and will vest ratably on each anniversary
of the grant date.
Compensation expense on the restricted common units is
recognized on a straight-line basis over the vesting period. The
fair value of an award of restricted common units is measured on
the grant date using the market price of a common unit on such
date. For the three and six months ended June 30, 2008, we
recognized compensation expense of approximately $78,000 and
$119,000 related to equity-based awards, respectively. For the
three months ended June 30, 2007 and for the period of
commencement of Partnership operations (February 14,
2007) through June 30, 2007, we recognized
compensation expense of approximately $60,000 and $76,000
related to equity-based awards, respectively. We estimate that
the remaining fair value of $400,000 will be recognized in
expense over a weighted average period of approximately two
years.
|
|
Note 10
|
Subsequent
Events
|
During July 2008, we borrowed from our senior secured credit
facility $87.4 million to terminate certain
out-of-the-money natural gas and NGL commodity swaps. Prior to
the terminations, the swaps were designated as hedges in
accordance with SFAS 133, Derivative Instruments
and Hedging Activities. Deferred losses of
approximately $20.8 million, $38.2 million and
$27.9 million will be reclassified from OCI as a non-cash
reduction of revenue during 2008, 2009 and 2010, respectively,
when the hedged forecasted sales transactions are expected to
occur. We also entered into new natural gas and NGL commodity
swaps at then current market prices that match the production
volumes of the terminated swaps through 2010.
On July 23, 2008, our general partner announced a quarterly
distribution of available cash of $0.5125 per common and
subordinated unit (approximately $25.9 million, including
distributions to the general partner and the holder of the
incentive distributions rights), for the quarter ended
June 30, 2008, payable on August 14, 2008 to
unitholders of record as of the close of business on
August 4, 2008.
19
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion analyzes our financial condition and
results of operations. You should read the following discussion
of our financial condition and results of operations in
conjunction with our consolidated financial statements and notes
included elsewhere in this
Form 10-Q
and in our consolidated financial statements and notes thereto
included in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Overview
We are a Delaware limited partnership formed by Targa Resources,
Inc. (Targa) to own, operate, acquire and develop a
diversified portfolio of complementary midstream energy assets.
We are engaged in the business of gathering, compressing,
treating, processing and selling natural gas and fractionating
and selling NGLs and NGL products. We currently operate in the
Fort Worth Basin in North Texas, the Permian Basin in West
Texas and in Southwest Louisiana.
We are owned 98% by our limited partners and 2% by our general
partner, Targa Resources GP LLC, an indirect, wholly-owned
subsidiary of Targa. Our limited partner common units are
publicly traded on The NASDAQ Stock Market LLC under the symbol
NGLS.
Our
Operations
We sell the majority of our processed natural gas, NGLs and high
pressure condensate to Targa at market-based rates pursuant to
natural gas, NGL and condensate purchase agreements.
Low-pressure condensate is sold to third parties. For a more
complete description of these arrangements, please see
Item 13. Certain Relationships and Related
Transactions and Director Independence and
Item 1. Business Market Access in
our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Critical
Accounting Policies and Estimates
There have been no significant changes to our critical
accounting policies and estimates since December 31, 2007.
For a more complete description of our critical accounting
polices and estimates, please see Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Critical Accounting
Policies and Estimates in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Recent
Accounting Pronouncements
On January 1, 2008, we adopted the provisions of Statement
of Financial Accounting Standards (SFAS) 157.
SFAS 157 defines fair value as the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at a specified
measurement date. See Note 3 of the Notes to Unaudited
Consolidated Financial Statements for information regarding fair
value disclosures pertaining to our financial assets and
liabilities.
The accounting standard-setting bodies have recently issued the
following accounting guidelines that will or may affect our
future financial statements:
|
|
|
|
|
EITF 07-4,
Application of the Two-Class Method under FASB
Statement No. 128, Earnings per Share, to Master Limited
Partnerships.
|
|
|
|
SFAS 161, Disclosures about Derivative Instruments
and Hedging Activities an amendment of FASB
Statement No. 133.
|
For additional information regarding these recent accounting
developments and others that may affect our future financial
statements, see Note 3 of the Notes to Consolidated
Financial Statements included in Item 1 of this Quarterly
Report.
20
Results
of Operations
The following table and discussion relate to the three and six
months ended June 30, 2008 and 2007 and is a summary of our
results of operations for the periods then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions, except operating and price data)
|
|
|
|
|
|
Revenues
|
|
$
|
630.5
|
|
|
$
|
433.6
|
|
|
$
|
1,142.6
|
|
|
$
|
782.4
|
|
|
|
|
|
Product purchases
|
|
|
555.2
|
|
|
|
371.7
|
|
|
|
997.3
|
|
|
|
666.2
|
|
|
|
|
|
Operating expense, excluding DD&A
|
|
|
14.7
|
|
|
|
11.8
|
|
|
|
27.3
|
|
|
|
23.9
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
18.4
|
|
|
|
17.6
|
|
|
|
36.7
|
|
|
|
35.7
|
|
|
|
|
|
General and administrative expense
|
|
|
5.7
|
|
|
|
4.6
|
|
|
|
10.9
|
|
|
|
8.0
|
|
|
|
|
|
Gain on sale of assets
|
|
|
|
|
|
|
(0.3
|
)
|
|
|
(0.1
|
)
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
36.5
|
|
|
|
28.2
|
|
|
|
70.5
|
|
|
|
48.9
|
|
|
|
|
|
Interest expense, net
|
|
|
(8.0
|
)
|
|
|
(5.2
|
)
|
|
|
(16.7
|
)
|
|
|
(7.8
|
)
|
|
|
|
|
Interest expense, allocated from Parent
|
|
|
|
|
|
|
(2.7
|
)
|
|
|
|
|
|
|
(16.2
|
)
|
|
|
|
|
Loss on mark-to-market derivative instruments
|
|
|
|
|
|
|
(6.2
|
)
|
|
|
|
|
|
|
(21.0
|
)
|
|
|
|
|
Deferred income tax expense
|
|
|
(0.3
|
)
|
|
|
(0.3
|
)
|
|
|
(0.7
|
)
|
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
28.2
|
|
|
$
|
13.8
|
|
|
$
|
53.1
|
|
|
$
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(1)
|
|
$
|
60.7
|
|
|
$
|
50.1
|
|
|
$
|
118.1
|
|
|
$
|
92.3
|
|
|
|
|
|
Adjusted EBITDA(2)
|
|
|
55.5
|
|
|
|
45.5
|
|
|
|
108.2
|
|
|
|
84.8
|
|
|
|
|
|
Distributable cash flow(3)
|
|
|
40.1
|
|
|
|
33.0
|
|
|
|
79.6
|
|
|
|
51.6
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput,
MMcf/d(4)
|
|
|
463.9
|
|
|
|
453.1
|
|
|
|
463.4
|
|
|
|
439.2
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d(5)(6)
|
|
|
435.2
|
|
|
|
427.1
|
|
|
|
436.4
|
|
|
|
412.5
|
|
|
|
|
|
Gross NGL production, MBbl/d
|
|
|
44.5
|
|
|
|
43.2
|
|
|
|
44.1
|
|
|
|
41.1
|
|
|
|
|
|
Natural gas sales, BBtu/d(6)
|
|
|
410.0
|
|
|
|
414.6
|
|
|
|
414.2
|
|
|
|
397.5
|
|
|
|
|
|
NGL sales, MBbl/d
|
|
|
39.1
|
|
|
|
36.5
|
|
|
|
38.5
|
|
|
|
34.8
|
|
|
|
|
|
Condensate sales, MBbl/d
|
|
|
3.7
|
|
|
|
3.7
|
|
|
|
3.7
|
|
|
|
3.6
|
|
|
|
|
|
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, $/MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
|
10.52
|
|
|
|
7.30
|
|
|
|
9.22
|
|
|
|
6.97
|
|
|
|
|
|
Impact of hedging
|
|
|
(0.05
|
)
|
|
|
0.06
|
|
|
|
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
|
10.47
|
|
|
|
7.36
|
|
|
|
9.22
|
|
|
|
7.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL, $/gal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
|
1.46
|
|
|
|
0.97
|
|
|
|
1.38
|
|
|
|
0.90
|
|
|
|
|
|
Impact of hedging
|
|
|
(0.11
|
)
|
|
|
(0.01
|
)
|
|
|
(0.09
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
|
1.35
|
|
|
|
0.96
|
|
|
|
1.29
|
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate, $/ Bbl
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
|
106.17
|
|
|
|
59.36
|
|
|
|
96.84
|
|
|
|
55.34
|
|
|
|
|
|
Impact of hedging
|
|
|
(5.06
|
)
|
|
|
0.90
|
|
|
|
(3.46
|
)
|
|
|
1.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
|
101.11
|
|
|
|
60.26
|
|
|
|
93.38
|
|
|
|
56.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Operating margin is total operating revenues less product
purchases and operating expense. See
Non-GAAP Financial Measures. |
21
|
|
|
(2) |
|
Adjusted EBITDA is net income before interest, income taxes,
depreciation and amortization and non-cash loss related to
derivative instruments. See Non-GAAP Financial
Measures. |
|
(3) |
|
Distributable Cash Flow is net income plus depreciation and
amortization and deferred taxes, adjusted for losses (gains) on
mark-to-market derivative contracts, less maintenance capital
expenditures. See Non-GAAP Financial Measures. |
|
(4) |
|
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points. |
|
(5) |
|
Plant natural gas inlet represents the volume of natural gas
passing through the meter located at the inlet of a natural gas
processing plant. |
|
(6) |
|
Plant inlet volumes include producer
take-in-kind,
while natural gas sales exclude producer
take-in-kind
volumes. |
Three
Months Ended June 30, 2008 Compared to Three Months Ended
June 30, 2007
Revenues increased $196.9 million, or 45%, to
$630.5 million for the three months ended June 30,
2008 compared to $433.6 million for the three months ended
June 30, 2007. The increase is primarily due to:
|
|
|
|
|
An increase attributable to commodity prices of
$189.1 million, comprising increases in natural gas, NGL
and condensate revenues of $115.9 million,
$59.3 million and $13.9 million, respectively;
|
|
|
|
An increase attributable to commodity sales volume of
$6.4 million comprising a decrease in natural gas revenues
of $3.1 million, flat condensate revenues, and an increase
in NGL revenues of $9.5 million, and
|
|
|
|
An increase in other revenue of $1.4 million, primarily
from miscellaneous processing activities.
|
Average realized prices for natural gas increased by $3.11 per
MMBtu (net of an $0.11 decrease related to hedge settlements),
or 42%, to $10.47 per MMBtu for the three months ended
June 30, 2008 compared to $7.36 per MMBtu for the three
months ended June 30, 2007. The average realized price for
NGLs increased by $0.39 per gallon (net of a $0.10 decrease
related to hedge settlements), or 41%, to $1.35 per gallon for
the three months ended June 30, 2008 compared to $0.96 per
gallon for the three months ended June 30, 2007. The
average realized price for condensate increased by $40.85 per
barrel (net of a $5.96 decrease related to hedge settlements),
or 68%, to $101.11 per barrel for the three months ended
June 30, 2008 compared to $60.26 per barrel for the three
months ended June 30, 2007.
Natural gas sales volumes decreased by 4.6 BBtu/d, or 1%, to
410.0 BBtu/d for the three months ended June 30, 2008
compared to 414.6 BBtu/d for the three months ended
June 30, 2007. The decrease in natural gas sales volumes
were attributable to volume decreases in purchases from
affiliates for resale.
NGL sales volumes increased by 2.6 MBbl/d, or 7%, to
39.1 MBbl/d for the three months ended June 30, 2008
compared to 36.5 MBbl/d for the three months ended
June 30, 2007. The increase was primarily due to increased
plant inlet volume of
8.1 MMcf/d
as a result of new well connects and increased producer
production.
Product purchases increased by $183.5 million, or 49%, to
$555.2 million for the three months ended June 30,
2008 compared to $371.7 million for the three months ended
June 30, 2007. The increase in product purchase cost was
due primarily to higher commodity prices in the three months
ended June 30, 2008 versus the three months ended
June 30, 2007, partially offset by a volume decrease in gas
purchases. Natural gas index prices increased an average of
48.2% for the comparative periods.
Operating expenses increased by $2.9 million, or 25%, to
$14.7 million for the three months ended June 30, 2008
compared to $11.8 million for the three months ended
June 30, 2007. The increase in operating expenses was
primarily the result of increases in compensation related
expenses of $1.4 million, utility costs of
$0.5 million and other maintenance and supplies costs of
$0.9 million.
General and administrative expenses increased by
$1.1 million, or 24%, to $5.7 million for the three
months ended June 30, 2008 compared to $4.6 million
for the three months ended June 30, 2007. The increase
22
consisted primarily of $0.3 million in professional
services fees and $0.5 million in the allocation of
corporate level expenses. For additional information regarding
our allocation of general and administrative costs, see
Item 13. Certain Relationships and Related
Transactions, and Director Independence Omnibus
Agreement in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Six
Months Ended June 30, 2008 Compared to Six Months Ended
June 30, 2007
Revenues increased $360.2 million, or 46%, to
$1,142.6 million for the six months ended June 30,
2008 compared to $782.4 million for the six months ended
June 30, 2007. The increase is primarily due to:
|
|
|
|
|
An increase attributable to commodity prices of
$305.3 million, comprising increases in natural gas, NGL
and condensate revenues of $164.7 million,
$115.4 million and $25.2 million, respectively;
|
|
|
|
An increase attributable to commodity sales volume of
$52.9 million comprising increases in natural gas, NGL and
condensate revenues of $24.2 million, $27.2 million
and $1.5 million, respectively; and
|
|
|
|
An increase in other revenue of $2.0 million, primarily
from miscellaneous processing activities.
|
Average realized prices for natural gas increased by $2.18 per
MMBtu (net of a $0.07 decrease related to hedge settlements), or
31%, to $9.22 per MMBtu for the six months ended June 30,
2008 compared to $7.04 per MMBtu for the six months ended
June 30, 2007. The average realized price for NGLs
increased by $0.39 per gallon (net of a $0.09 decrease related
to hedge settlements), or 43%, to $1.29 per gallon for the
six months ended June 30, 2008 compared to $0.90 per
gallon for the six months ended June 30, 2007. The average
realized price for condensate increased by $36.68 per barrel
(net of a $4.82 decrease related to hedge settlements), or 65%,
to $93.38 per for the six months ended June 30, 2008
compared to $56.70 per barrel for the six months ended
June 30, 2007.
Natural gas sales volumes increased by 16.7 BBtu/d, or 4%, to
414.2 BBtu/d for the six months ended June 30, 2008
compared to 397.5 BBtu/d for the six months ended June 30,
2007. Sales volume increases were attributable to increased
demand by our industrial customers, partially offset by
increases in residue
take-in-kind
volumes.
NGL sales volumes increased by 3.7 MBbl/d, or 11%, to
38.5 MBbl/d for the six months ended June 30, 2008
compared to 34.8 MBbl/d for the six months ended
June 30, 2007. The increase was primarily due to increased
plant inlet through put of
23.9 MMcf/d
as a result of new well connects and increased producer
production.
Product purchases increased by $331.1 million, or 50%, to
$997.3 million for the six months ended June 30, 2008
compared to $666.2 million for the six months ended
June 30, 2007. The increase in product purchases was due
primarily to increased sales volumes and higher commodity prices
in the six months ended June 30, 2008 versus the six months
ended June 30, 2007. Natural gas index prices increased an
average of 24.6% for the comparative periods.
Operating expenses increased by $3.4 million, or 14%, to
$27.3 million for the six months ended June 30, 2008
compared to $23.9 million for the six months ended
June 30, 2007. The increase in operating expenses was
primarily the result of increases in compensation related
expenses of $2.0 million, utility costs of
$0.5 million and other maintenance and supplies costs of
$0.9 million.
General and administrative and other expenses increased by
$2.9 million, or 36%, to $10.9 million for the six
months ended June 30, 2008 compared to $8.0 million
for the six months ended June 30, 2007. The increase
consisted primarily of $0.8 million in professional
services fees and $1.7 million in the allocation of
corporate level expenses. For additional information regarding
our allocation of general and administrative costs, see
Item 13. Certain Relationships and Related
Transactions, and Director Independence Omnibus
Agreement in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
23
Liquidity
and Capital Resources
Our ability to finance our operations, including to fund capital
expenditures and acquisitions, to meet our indebtedness
obligations, to refinance our indebtedness or to meet our
collateral requirements depends on our ability to generate cash
in the future. Our ability to generate cash is subject to a
number of factors, some of which are beyond our control,
including commodity prices, particularly for natural gas and
NGLs, operating costs and maintenance capital expenditures. See
Item 1A. Risk Factors in this Quarterly Report
and in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Historically, our cash generated from operations has been
sufficient to finance our operating expenditures and maintenance
and expansion capital expenditures, with remaining amounts being
distributed to Targa, during its period of ownership and to our
unitholders since Targas contribution of assets to us and
our acquisition of assets from Targa. Our sources of liquidity
include:
|
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|
|
|
cash generated from operations;
|
|
|
|
borrowings under our senior secured credit facility;
|
|
|
|
issuance of additional partnership units; and
|
|
|
|
debt offerings.
|
We believe that cash generated from these sources will be
sufficient to meet our short-term working capital requirements,
long-term capital expenditure requirements and our minimum
quarterly cash distributions for at least the next year.
We intend to make cash distributions to our unitholders and our
general partner at least at the minimum quarterly distribution
rate of $0.3375 per common unit per quarter ($1.35 per common
unit on an annualized basis). Due to our cash distribution
policy, we expect that we will distribute to our unitholders
most of the cash generated by our operations. As a result, we
expect that we will rely upon external financing sources,
including other debt and common unit issuances, to fund our
acquisition and expansion capital expenditures, as well as our
working capital needs. Historically, we have relied on
internally generated cash flows for these purposes. During the
six months ended June 30, 2008, we made the following
distributions:
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|
|
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|
|
|
|
|
|
|
|
|
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|
|
|
Distribution per
|
|
|
Annualized
|
|
|
Distribution per
|
|
|
|
|
Total
|
|
Quarter Ended
|
|
Common Unit
|
|
|
Distribution
|
|
|
Subordinated Unit
|
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|
Date Paid
|
|
Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
December 31, 2007
|
|
$
|
0.3975
|
|
|
$
|
1.59
|
|
|
$
|
0.3975
|
|
|
February 14, 2008
|
|
$
|
18.8
|
|
March 31, 2008
|
|
|
0.4175
|
|
|
|
1.67
|
|
|
|
0.4175
|
|
|
May 15, 2008
|
|
|
19.9
|
|
Working Capital. Working capital is the amount
by which current assets exceed current liabilities. Our working
capital requirements are primarily driven by changes in accounts
receivable and accounts payable. These changes are impacted by
changes in the prices of commodities that we buy and sell. In
general, our working capital requirements increase in periods of
rising commodity prices and decrease in periods of declining
commodity prices. However, our working capital needs do not
necessarily change at the same rate as commodity prices because
both accounts receivable and accounts payable are impacted by
the same commodity prices. In addition, the timing of payments
received from our customers or paid to our suppliers can also
cause fluctuations in working capital because we settle with
most of our larger suppliers and customers on a monthly basis
and often near the end of the month. We expect that our future
working capital requirements will be impacted by these same
factors.
As of June 30, 2008, we had a working capital deficit of
$90.9 million, including a net short-term liability for
commodity and interest rate derivatives of $113.4 million.
In accordance with SFAS 133 Accounting for
Derivative Instruments and Hedging Activities, we
record the fair value of all derivative instruments on the
balance sheet. Our hedge agreements provide for monthly
settlement (quarterly for interest rate swaps) based on the
differential between the agreement price and published commodity
price and interest rate indexes. Cash received from physical
sales of commodities and cash paid for interest will be based on
actual market prices and interest rates and will generally
offset any gains or losses realized on the derivative
instruments. Our derivative contracts do not have margin
requirements or collateral provisions that could require funding
prior
24
to the scheduled cash settlement date. Excluding derivatives our
working capital surplus was $22.5 million. See
Item 3. Quantitative and Qualitative Disclosures
about Market Risk in this Quarterly Report and in our
Annual Report on
Form 10-K
for the year ended December 31, 2007.
Cash Flow. Net cash provided by or used in
operating activities, investing activities and financing
activities for the six months ended June 30, 2008 and 2007
were as follows:
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|
|
|
|
|
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net cash provided by operating activities
|
|
$
|
99.4
|
|
|
$
|
68.9
|
|
Net cash used in investing activities
|
|
|
(21.7
|
)
|
|
|
(23.4
|
)
|
Net cash used in financing activities
|
|
|
(96.6
|
)
|
|
|
(36.2
|
)
|
Operating Activities. Net cash provided by
operating activities increased by $30.5 million, or 44%,
for the six months ended June 30, 2008 compared to the six
months ended June 30, 2007. This increase is primarily
attributable to an increase in our net income, adjusted for
non-cash charges related to risk management activities and other
non-cash charges, as presented in the combined statements of
cash flows.
Investing Activities. Net cash used in
investing activities for the six months ended June 30, 2008
decreased $1.7 million, or 7%, compared to the six months
ended June 30, 2007. Purchases of property, plant and
equipment during the six months ended June 30, 2008 versus
the six months ended June 30, 2007 were down due to the
timing of expansion capital projects. Other investing activities
for the six months ended June 30, 2008 included
approximately $4.2 million for contractually obligated line
fill on a third party owned pipeline.
Financing Activities. Net cash used in
financing activities increased $60.4 million to
$96.6 million for the six months ended June 30, 2008
compared to the six months ended June 30, 2007. Net cash
used in financing activities for the six months ended
June 30, 2008 is primarily associated with distributions to
unitholders of $38.7 million and the repayment of
$301.3 million on our senior secured credit facility, which
was offset by the net proceeds of $243.4 million from our
issuance of the
81/4% Senior
Notes due 2016 (the Notes). The net cash used in
financing activities for the six months ended June 30, 2007
is primarily associated with the completion of our IPO, the
establishment of our senior secured credit facility, deemed
parent contribution prior to the IPO and subsequent drop down of
assets to us and the contribution of the North Texas System to
us, which were offset by payments of debt, offering costs and
debt issuance costs related to our senior secured credit
facility.
Contractual Obligations. In June 2008, we
issued $250 million aggregate principal amount of the
Notes. The proceeds from the offering were used to reduce
outstanding indebtedness under our senior secured credit
facility. The interest rate on the Notes is fixed at 8.25% with
interest to be paid on January 1 and July 1 of each year and the
Notes mature on July 1, 2016.
Available Credit. As of June 30, 2008, we
had approximately $483.8 million in capacity available
under our senior secured credit facility, after giving effect to
outstanding borrowings of $325.0 million and the issuance
of $41.2 million of letters of credit. Our senior secured
credit facility allows us to request increases in the
commitments under the facility by up to $150 million.
Capital Requirements. The midstream energy
business can be capital intensive, requiring significant
investment to maintain and upgrade existing operations. A
significant portion of the cost of constructing new gathering
lines to connect to our gathering system is generally paid for
by the natural gas producer. However, we expect to continue to
incur significant expenditures throughout 2008 related to the
expansion of our natural gas gathering and processing
infrastructure.
We categorize our capital expenditures as either:
(i) maintenance expenditures or (ii) expansion
expenditures. Maintenance expenditures are those expenditures
that are necessary to maintain the service capability of our
existing assets including the replacement of system components
and equipment which is worn, obsolete or
25
completing its useful life, the addition of new sources of
natural gas supply to our systems to replace natural gas
production declines and expenditures to remain in compliance
with environmental laws and regulations. Expansion expenditures
improve the service capability of the existing assets, extend
asset useful lives, increase capacities from existing levels,
reduce costs or enhance revenues.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion
|
|
$
|
3.1
|
|
|
$
|
6.4
|
|
|
$
|
6.1
|
|
|
$
|
13.3
|
|
Maintenance
|
|
|
7.4
|
|
|
|
5.1
|
|
|
|
11.8
|
|
|
|
10.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10.5
|
|
|
$
|
11.5
|
|
|
$
|
17.9
|
|
|
$
|
23.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that our total capital expenditures for 2008 will be
approximately $70 million. Given our objective of growth
through acquisitions, expansions of existing assets and other
internal growth projects, we anticipate that we will invest
significant amounts of capital to grow and acquire assets.
Expansion capital expenditures may vary significantly based on
investment opportunities.
We expect to fund future capital expenditures with funds
generated from our operations, borrowings under our senior
secured credit facility, the issuance of additional partnership
units and debt offerings.
26
Non-GAAP Financial
Measures
For a complete discussion of the measures that management uses
to evaluate our operations, see Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations How We Evaluate our
Operations in our Annual Report on
Form 10-K
for the year ended December 31, 2007. The following tables
reconcile the non-GAAP financial measures used by management to
their most directly comparable GAAP measures for the three and
six months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Reconciliation of Adjusted EBITDA to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
46.6
|
|
|
$
|
25.3
|
|
|
$
|
99.4
|
|
|
$
|
68.9
|
|
Allocated interest expense from parent(1)
|
|
|
|
|
|
|
2.4
|
|
|
|
|
|
|
|
15.2
|
|
Interest expense, net(1)
|
|
|
7.5
|
|
|
|
5.2
|
|
|
|
15.8
|
|
|
|
7.9
|
|
Changes in operating working capital which used (provided) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and other
|
|
|
43.5
|
|
|
|
25.0
|
|
|
|
48.9
|
|
|
|
7.9
|
|
Accounts payable
|
|
|
(1.1
|
)
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
(2.6
|
)
|
Accrued liabilities
|
|
|
(41.0
|
)
|
|
|
(12.6
|
)
|
|
|
(56.0
|
)
|
|
|
(12.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
55.5
|
|
|
$
|
45.5
|
|
|
$
|
108.2
|
|
|
$
|
84.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to net income
(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
28.2
|
|
|
$
|
13.8
|
|
|
$
|
53.1
|
|
|
$
|
3.2
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated interest expense, net
|
|
|
|
|
|
|
2.7
|
|
|
|
|
|
|
|
16.2
|
|
Interest expense, net
|
|
|
8.0
|
|
|
|
5.2
|
|
|
|
16.7
|
|
|
|
7.9
|
|
Deferred income tax expense
|
|
|
0.4
|
|
|
|
0.3
|
|
|
|
0.7
|
|
|
|
0.7
|
|
Depreciation and amortization expense
|
|
|
18.4
|
|
|
|
17.6
|
|
|
|
36.7
|
|
|
|
35.7
|
|
Risk Management Activities
|
|
|
0.5
|
|
|
|
5.9
|
|
|
|
1.0
|
|
|
|
21.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
55.5
|
|
|
$
|
45.5
|
|
|
$
|
108.2
|
|
|
$
|
84.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of operating margin to net income
(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
28.2
|
|
|
$
|
13.8
|
|
|
$
|
53.1
|
|
|
$
|
3.2
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
18.4
|
|
|
|
17.6
|
|
|
|
36.7
|
|
|
|
35.7
|
|
Deferred income tax expense
|
|
|
0.4
|
|
|
|
0.3
|
|
|
|
0.7
|
|
|
|
0.7
|
|
Allocated interest expense, net
|
|
|
|
|
|
|
2.7
|
|
|
|
|
|
|
|
16.2
|
|
Interest expense, net
|
|
|
8.0
|
|
|
|
5.2
|
|
|
|
16.7
|
|
|
|
7.9
|
|
Non-cash gain related to derivative instruments
|
|
|
|
|
|
|
6.1
|
|
|
|
|
|
|
|
21.0
|
|
General and administrative and other expense
|
|
|
5.7
|
|
|
|
4.4
|
|
|
|
10.9
|
|
|
|
7.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
60.7
|
|
|
$
|
50.1
|
|
|
$
|
118.1
|
|
|
$
|
92.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of amortization of debt issue costs of $0.5 million and
$0.9 million for the three and six months June 30,
2008 and $0.3 million and $1.0 million for the three
and six months ended June 30, 2007. |
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
|
(In millions)
|
|
|
Reconciliation of distributable cash flow to
net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
28.2
|
|
|
$
|
13.8
|
|
|
$
|
53.1
|
|
|
$
|
3.2
|
|
Depreciation and amortization expense
|
|
|
18.4
|
|
|
|
17.6
|
|
|
|
36.7
|
|
|
|
35.7
|
|
Deferred income tax expense
|
|
|
0.4
|
|
|
|
0.3
|
|
|
|
0.7
|
|
|
|
0.7
|
|
Amortization of debt issue costs
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
0.9
|
|
|
|
1.0
|
|
Loss on mark-to-market derivative instruments
|
|
|
|
|
|
|
6.1
|
|
|
|
|
|
|
|
21.0
|
|
Maintenance capital expenditures
|
|
|
(7.4
|
)
|
|
|
(5.1
|
)
|
|
|
(11.8
|
)
|
|
|
(10.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
40.1
|
|
|
$
|
33.0
|
|
|
$
|
79.6
|
|
|
$
|
51.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Distributable cash flow for the three and six months ended
June 30, 2007 reflects allocated interest from Parent of
$2.7 million and $16.2 million, respectively. |
Below is a reconciliation of net income (loss) as reported and
distributable cash flow which excludes the results of operations
of the North Texas System and the SAOU and LOU Systems prior to
their ownership by the Partnership.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2007
|
|
|
|
|
|
|
Pre-Acquisition
|
|
|
Post Acquisition
|
|
|
|
|
|
|
SAOU-LOU
|
|
|
North Texas
|
|
|
|
|
|
|
|
|
|
Jan 1, 2007 to
|
|
|
Jan 1, 2007 to
|
|
|
|
|
|
|
TRP LP
|
|
|
June 30, 2007
|
|
|
Feb 13, 2007
|
|
|
TRP LP
|
|
|
|
(In millions)
|
|
|
Net income (loss)
|
|
$
|
3.2
|
|
|
$
|
3.9
|
|
|
$
|
(6.9
|
)
|
|
$
|
6.2
|
|
Depreciation and amortization expense
|
|
|
35.7
|
|
|
|
7.2
|
|
|
|
6.9
|
|
|
|
21.6
|
|
Deferred income tax expense
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
0.7
|
|
Amortization of debt issue costs
|
|
|
1.0
|
|
|
|
0.7
|
|
|
|
|
|
|
|
0.3
|
|
Loss on mark-to-market derivative instruments
|
|
|
21.0
|
|
|
|
21.0
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures
|
|
|
(10.0
|
)
|
|
|
(4.8
|
)
|
|
|
(1.5
|
)
|
|
|
(3.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
51.6
|
|
|
$
|
28.0
|
|
|
$
|
(1.5
|
)
|
|
$
|
25.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
For an in-depth discussion of market risks, see
Item 7A. Quantitative and Qualitative Disclosure
about Market Risk in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Our principal market risks are our exposure to changes in
commodity prices, particularly to the prices of natural gas and
NGLs, changes in interest rates, as well as nonperformance by
our customers. We do not use risk sensitive instruments for
trading purposes.
Commodity Price Risk. A majority of our
revenues are derived from percent-of-proceeds contracts under
which we receive a portion of the natural gas
and/or NGLs,
or equity volumes, as payment for services. The prices of
natural gas and NGLs are subject to fluctuations in response to
changes in supply, demand, market uncertainty and a variety of
additional factors beyond our control. We monitor these risks
and enter into hedging transactions designed to mitigate the
impact of commodity price fluctuations on our business. Cash
flows from a derivative instrument designated as a hedge are
classified in the same category as the cash flows from the item
being hedged. For an in-depth discussion of our hedging
strategies, see Item 7A. Quantitative and Qualitative
Disclosure about Market Risk Commodity Price
Risk in our Annual Report on
Form 10-K
for the year ended December 31, 2007.
Our payment obligations in connection with substantially all of
these hedging transactions, and any additional credit exposure
due to a rise in natural gas and NGL prices relative to the
fixed prices set forth in the
28
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. As long as this first priority lien is in
effect, we expect to have no obligation to post cash, letters of
credit, or other additional collateral to secure these hedges at
any time even if our counterpartys exposure to our credit
increases over the term of the hedge as a result of higher
commodity prices or because there has been a change in our
creditworthiness. A purchased put (or floor) transaction does
not create credit exposure to us for our counterparties.
For the six months ended June 30, 2008, our operating
revenues were decreased by net hedge settlements of
$30.3 million. During 2006 through 2008, we entered into
hedging arrangements for a portion of our forecasted equity
volumes. Floor volumes and floor pricing are based solely on
purchased puts (or floors). As of June 30, 2008, we had the
following open commodity derivative positions (except as
indicated otherwise, the 2008 volumes reflect daily volumes for
the period from July 1, 2008 through December 31,
2008):
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/MMBtu
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Natural Gas Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
NY-HH
|
|
|
|
8.43
|
|
|
|
1,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
IF-HSC
|
|
|
|
8.09
|
|
|
|
2,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,143
|
)
|
Swap
|
|
|
IF-HSC
|
|
|
|
7.39
|
|
|
|
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,236
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,328
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
IF-NGPL MC
|
|
|
|
8.43
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,088
|
)
|
Swap
|
|
|
IF-NGPL MC
|
|
|
|
8.02
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,016
|
)
|
Swap
|
|
|
IF-NGPL MC
|
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(5,536
|
)
|
Swap
|
|
|
IF-NGPL MC
|
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(2,316
|
)
|
Swap
|
|
|
IF-NGPL MC
|
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(2,309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
(21,266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
IF-Waha
|
|
|
|
8.20
|
|
|
|
7,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,101
|
)
|
Swap
|
|
|
IF-Waha
|
|
|
|
7.61
|
|
|
|
|
|
|
|
6,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,380
|
)
|
Swap
|
|
|
IF-Waha
|
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
5,709
|
|
|
|
|
|
|
|
|
|
|
|
(5,699
|
)
|
Swap
|
|
|
IF-Waha
|
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
|
|
|
|
(2,786
|
)
|
Swap
|
|
|
IF-Waha
|
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
(2,924
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,389
|
|
|
|
6,936
|
|
|
|
5,709
|
|
|
|
3,250
|
|
|
|
3,250
|
|
|
|
(25,890
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
16,681
|
|
|
|
15,158
|
|
|
|
11,394
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
(51,277
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
IF-NGPL MC
|
|
|
|
6.55
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Floor
|
|
|
IF-NGPL MC
|
|
|
|
6.55
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
IF-Waha
|
|
|
|
6.85
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Floor
|
|
|
IF-Waha
|
|
|
|
6.55
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(51,228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
NGLs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/gal
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
NGL Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
OPIS-MB
|
|
|
|
1.01
|
|
|
|
7,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(45,341
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.96
|
|
|
|
|
|
|
|
6,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(62,001
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
4,809
|
|
|
|
|
|
|
|
|
|
|
|
(40,124
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,400
|
|
|
|
|
|
|
|
(26,650
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,700
|
|
|
|
(19,612
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
7,095
|
|
|
|
6,248
|
|
|
|
4,809
|
|
|
|
3,400
|
|
|
|
2,700
|
|
|
|
(193,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floors
|
|
|
OPIS-MB
|
|
|
|
1.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
|
|
|
|
|
|
860
|
|
Floors
|
|
|
OPIS-MB
|
|
|
|
1.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
422
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
|
|
422
|
|
|
|
1,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(191,911
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/Bbl
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Condensate Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
NY-WTI
|
|
|
|
67.19
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(4,922
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
69.00
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,937
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(6,821
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(19,680
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.50
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.00
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(19,677
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
Hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
|
Instrument Type
|
|
|
Daily Volume
|
|
|
Average Price
|
|
|
Index
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul 2008 Dec 2008
|
|
|
Natural gas
|
|
|
|
Swap
|
|
|
|
7,043 MMBtu
|
|
|
$
|
12.81 per MMBtu
|
|
|
|
NY-HH
|
|
|
$
|
453
|
|
Jan 2009 Dec 2009
|
|
|
Natural gas
|
|
|
|
Swap
|
|
|
|
658 MMBtu
|
|
|
|
11.95 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
123
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul 2008 Dec 2008
|
|
|
Natural gas
|
|
|
|
Fixed price sale
|
|
|
|
7,043 MMBtu
|
|
|
|
12.81 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
(453
|
)
|
Jan 2009 Dec 2009
|
|
|
Natural gas
|
|
|
|
Fixed price sale
|
|
|
|
658 MMBtu
|
|
|
|
11.95 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These contracts may expose us to the risk of financial loss in
certain circumstances. Our hedging arrangements provide us
protection on the hedged volumes if prices decline below the
prices at which these hedges are set. If prices rise above the
prices at which we have hedged, we will receive less revenue on
the hedged volumes than we would receive in the absence of
hedges.
30
Interest
Rate Risk
We are exposed to changes in interest rates, primarily as a
result of variable rate debt under our senior secured credit
facility. To the extent that interest rates increase, interest
expense on our revolving debt will also increase. As of
June 30, 2008, there were borrowings of approximately
$325 million outstanding under our $850 million senior
secured credit facility and we had the following open interest
rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
|
|
|
|
|
Notional
|
|
Effective Date
|
|
Date
|
|
|
Rate
|
|
|
Amount
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
12/13/2007
|
|
|
01/24/2011
|
|
|
|
4.0775
|
%
|
|
$
|
50,000
|
|
12/18/2007
|
|
|
01/24/2011
|
|
|
|
4.2100
|
%
|
|
|
50,000
|
|
12/21/2007
|
|
|
01/24/2012
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
12/21/2007
|
|
|
01/24/2012
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
01/09/2008
|
|
|
01/24/2012
|
|
|
|
3.6990
|
%
|
|
|
50,000
|
|
01/11/2008
|
|
|
01/24/2012
|
|
|
|
3.6400
|
%
|
|
|
50,000
|
|
Each swap fixes the three month LIBOR rate as indicated for the
specified notional amount outstanding under our senior secured
credit facility over the term of each swap agreement. The fair
value of our outstanding interest rate swaps was a liability of
$0.9 million as of June 30, 2008. We have designated
all interest rate swaps as cash flow hedges. Accordingly,
unrealized gains and losses relating to the interest rate swaps
are recorded in OCI until the interest expense on the related
debt is recognized in earnings. A hypothetical increase of
100 basis points in the underlying interest rate, after
taking into account our interest rate swaps, would increase our
annual interest expense by $250 thousand.
Credit
Risk
We are subject to risk of losses resulting from nonpayment or
nonperformance by our customers. We operate under the Targa
credit policy and closely monitor the creditworthiness of
customers to whom we grant credit and establish credit limits in
accordance with this credit policy. In addition to third party
contracts, we have entered into several agreements with Targa.
For example, we are party to natural gas, NGL and condensate
purchase agreements pursuant to which Targa purchases the
majority of our natural gas, NGLs and high-pressure condensate.
In addition, we are also a party to an omnibus agreement with
Targa which addresses, among other things, the provision of
general and administrative and operating services to us. Any
material nonperformance under the omnibus and purchase
agreements by Targa could materially and adversely impact our
ability to operate and make distributions to our unitholders.
|
|
Item 4T.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
Our management, under the supervision of and with the
participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the effectiveness of our disclosure
controls and procedures, as such term is defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934, as amended (the
Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, our Chief Executive
Officer and Chief Financial Officer have concluded that, as of
the end of such period, our disclosure controls and procedures
were effective at a reasonable assurance level to provide
reasonable assurance that all material information relating to
us required to be included in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and
forms of the Securities and Exchange Commission.
There has been no change in our internal controls over financial
reporting during the three or six months ended June 30,
2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
31
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
The information required for this item is provided in
Note 8, Commitments and Contingencies, under the heading
Litigation included in the notes to the consolidated
financial statements included under Part I, Item 1,
which is incorporated by reference into this item.
For an in-depth discussion of our risk factors, see
Item 1A. Risk Factors in our Annual Report on
Form 10-K
for the year ended December 31, 2007. These risks and
uncertainties are not the only ones facing us and there may be
additional matters that we are unaware of or that we currently
consider immaterial. All of these risks and uncertainties could
adversely affect our business, financial condition
and/or
results of operations, as could the following:
We
have a substantial amount of indebtedness which could adversely
affect our financial position.
We currently have a substantial amount of indebtedness. As of
June 30, 2008 we have approximately $575 million of
total indebtedness outstanding, approximately
$41 million of letters of credit outstanding and
approximately $484 million of additional borrowing capacity
under our senior secured credit facility. Our senior secured
credit facility allows us to request increases in the
commitments under the facility by up to $150 million. We
may also incur additional indebtedness in the future.
Our substantial indebtedness may:
|
|
|
|
|
make it difficult for us to satisfy our financial obligations,
including making scheduled principal and interest payments on
our indebtedness;
|
|
|
|
limit our ability to borrow additional funds for working
capital, capital expenditures, acquisitions or other general
business purposes;
|
|
|
|
limit our ability to use our cash flow or obtain additional
financing for future working capital, capital expenditures,
acquisitions or other general business purposes;
|
|
|
|
require us to use a substantial portion of our cash flow from
operations to make debt service payments;
|
|
|
|
limit our flexibility to plan for, or react to, changes in our
business and industry;
|
|
|
|
place us at a competitive disadvantage compared to our less
leveraged competitors; and
|
|
|
|
increase our vulnerability to the impact of adverse economic and
industry conditions.
|
We
require a significant amount of cash to service our
indebtedness. Our ability to generate cash depends on many
factors beyond our control.
Our ability to make payments on and to refinance our
indebtedness and to fund planned capital expenditures depends on
our ability to generate cash in the future. This, to a certain
extent, is subject to general economic, financial, competitive,
legislative, regulatory and other factors that are beyond our
control. We cannot assure you that we will generate sufficient
cash flow from operations or that future borrowings will be
available to us under our credit agreement or otherwise in an
amount sufficient to enable us to pay our indebtedness or to
fund our other liquidity needs. We may need to refinance all or
a portion of our indebtedness at or before maturity. We cannot
assure you that we will be able to refinance any of our
indebtedness on commercially reasonable terms or at all.
|
|
Item 2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
Not applicable.
|
|
Item 3.
|
Defaults
Upon Senior Securities
|
Not applicable.
32
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
Not applicable.
|
|
Item 5.
|
Other
Information
|
Not applicable.
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Certificate of Limited Partnership of Targa Resources Partners
LP (incorporated by reference to Exhibit 3.2 to Targa
Resources Partners LPs Registration Statement on
Form S-1
filed November 16, 2006 (File
No. 333-138747)).
|
|
3
|
.2
|
|
Certificate of Formation of Targa Resources GP LLC (incorporated
by reference to Exhibit 3.3 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed January 19, 2007
(File No. 333-138747)).
|
|
3
|
.3
|
|
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.3 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007
(File No. 001-33303)).
|
|
3
|
.4
|
|
First Amended and Restated Agreement of Limited Partnership of
Targa Resources Partners LP (incorporated by reference to
Exhibit 3.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
3
|
.5
|
|
Amendment No. 1, dated May 13, 2008, to the First
Amended and Restated Agreement of Limited Partnership of Targa
Resources Partners LP (incorporated by reference to
Exhibit 3.5 to Targa Resources Partners LPs Quarterly
Report on
Form 10-Q
filed May 14, 2008 (File
No. 001-33303)).
|
|
3
|
.6
|
|
Limited Liability Company Agreement of Targa Resources GP LLC
(incorporated by reference to Exhibit 3.4 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed January 19, 2007 (File
No. 333-138747)).
|
|
4
|
.1
|
|
Indenture dated June 18, 2008, among Targa Resources
Partners LP, Targa Resources Partners Finance Corporation, the
Guarantors named therein and U.S. Bank National Association
(incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LPs current report on
Form 8-K
filed June 18, 2008 (File No
001-33303)).
|
|
4
|
.2
|
|
Registration Rights Agreement dated June 18, 2008, among
Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the Guarantors named therein and the initial
purchasers named therein (incorporated by reference to
Exhibit 4.2 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 18, 2008 (File
No. 001-33303)).
|
|
10
|
.1
|
|
Purchase Agreement dated June 12, 2008 among Targa
Resources Partners LP, Targa Resources Partners Finance
Corporation, the Guarantors named therein and the initial
purchasers named therein (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 18, 2008 (File
No. 001-33303)).
|
|
10
|
.2
|
|
Commitment Increase Supplement, dated June 18, 2008, by and
among Targa Resources Partners LP, Bank of America, N.A. and the
other parties signatory thereto (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 24, 2008
(File No. 001-33303)).
|
|
31
|
.1*
|
|
Certification of the Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
31
|
.2*
|
|
Certification of the Chief Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
32
|
.1*
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
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|
32
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.2*
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|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
33
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Targa Resources Partners LP
(Registrant)
By: Targa Resources GP LLC,
its general partner
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|
|
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By:
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/s/ John
Robert Sparger
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John Robert Sparger
Senior Vice President and Chief Accounting Officer
(Authorized signatory and Principal Accounting Officer)
Date: August 11, 2008
34
Exhibit Index
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|
|
|
|
Exhibit
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|
|
Number
|
|
Description
|
|
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3
|
.1
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|
Certificate of Limited Partnership of Targa Resources Partners
LP (incorporated by reference to Exhibit 3.2 to Targa
Resources Partners LPs Registration Statement on
Form S-1
filed November 16, 2006 (File
No. 333-138747)).
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3
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.2
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|
Certificate of Formation of Targa Resources GP LLC (incorporated
by reference to Exhibit 3.3 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed January 19, 2007
(File No. 333-138747)).
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|
3
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.3
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|
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.3 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007
(File No. 001-33303)).
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|
3
|
.4
|
|
First Amended and Restated Agreement of Limited Partnership of
Targa Resources Partners LP (incorporated by reference to
Exhibit 3.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
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3
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.5
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|
Amendment No. 1, dated May 13, 2008, to the First
Amended and Restated Agreement of Limited Partnership of Targa
Resources Partners LP (incorporated by reference to
Exhibit 3.5 to Targa Resources Partners LPs Quarterly
Report on
Form 10-Q
filed May 14, 2008 (File
No. 001-33303)).
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3
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.6
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|
Limited Liability Company Agreement of Targa Resources GP LLC
(incorporated by reference to Exhibit 3.4 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed January 19, 2007 (File
No. 333-138747)).
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4
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.1
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|
Indenture dated June 18, 2008, among Targa Resources
Partners LP, Targa Resources Partners Finance Corporation, the
Guarantors named therein and U.S. Bank National Association
(incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LPs current report on
Form 8-K
filed June 18, 2008 (File No
001-33303)).
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|
4
|
.2
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|
Registration Rights Agreement dated June 18, 2008, among
Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the Guarantors named therein and the initial
purchasers named therein (incorporated by reference to
Exhibit 4.2 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 18, 2008 (File
No. 001-33303)).
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|
10
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.1
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|
Purchase Agreement dated June 12, 2008 among Targa
Resources Partners LP, Targa Resources Partners Finance
Corporation, the Guarantors named therein and the initial
purchasers named therein (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 18, 2008 (File
No. 001-33303)).
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|
10
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.2
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|
Commitment Increase Supplement, dated June 18, 2008, by and
among Targa Resources Partners LP, Bank of America, N.A. and the
other parties signatory thereto (incorporated by reference to
|
|
|
|
|
Exhibit 10.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed June 24, 2008
(File No. 001-33303)).
|
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31
|
.1*
|
|
Certification of the Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
31
|
.2*
|
|
Certification of the Chief Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
32
|
.1*
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
exv31w1
Exhibit 31.1
Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
I, Rene R. Joyce, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended June 30, 2008 of
Targa Resources Partners LP;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15(d)-(f))for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter that has materially
affected, or is reasonably likely to materially affect, the registrants internal control over
financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrants internal control over financial reporting.
Date: August 11, 2008
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By: /s/ Rene R. Joyce
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|
Name:
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|
Rene R. Joyce
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|
|
Title:
|
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Chief Executive Officer of Targa Resources GP LLC, |
|
|
|
|
the general partner of Targa Resources Partners LP |
|
|
|
|
(Principal Executive Officer) |
|
|
exv31w2
Exhibit 31.2
Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
I, Jeffrey J. McParland, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended June 30, 2008 of
Targa Resources Partners LP;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15(d)-(f))for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter that has materially
affected, or is reasonably likely to materially affect, the registrants internal control over
financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrants internal control over financial reporting.
Date: August 11, 2008
|
|
|
|
|
By: /s/ Jeffrey J. McParland
|
|
|
Name:
|
|
Jeffrey J. McParland
|
|
|
Title:
|
|
Executive Vice President and Chief Financial Officer |
|
|
|
|
of Targa Resources GP LLC, |
|
|
|
|
the general partner of Targa Resources Partners LP |
|
|
|
|
(Principal Financial Officer) |
|
|
exv32w1
Exhibit 32.1
CERTIFICATION OF CEO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report on Form 10-Q for the period ended June 30, 2008 of
Targa Resources Partners LP (the Partnership) as filed with the Securities and Exchange
Commission on the date hereof (the Report), Rene R. Joyce, as Chief Executive Officer of Targa
Resources GP LLC, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
Date: August 11, 2008
|
|
|
|
|
By: /s/ Rene R. Joyce
|
|
|
Name:
|
|
Rene R. Joyce
|
|
|
Title:
|
|
Chief Executive Officer of Targa Resources GP LLC, |
|
|
|
|
the general partner of Targa Resources Partners LP |
|
|
|
|
(Principal Executive Officer) |
|
|
A signed original of this written statement required by Section 906, or other document
authenticating, acknowledging, or otherwise adopting the signature that appears in typed form
within the electronic version of this written statement required by Section 906, has been provided
to the Partnership and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request.
exv32w2
Exhibit 32.2
CERTIFICATION OF CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report on Form 10-Q for the period ended June 30, 2008 of
Targa Resources Partners LP (the Partnership) as filed with the Securities and Exchange
Commission on the date hereof (the Report), Jeffrey J. McParland, as Chief Financial Officer of
Targa Resources GP LLC, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
Date: August 11, 2008
|
|
|
|
|
By: /s/ Jeffrey J. McParland
|
|
|
Name:
|
|
Jeffrey J. McParland
|
|
|
Title:
|
|
Executive Vice President and Chief Financial Officer |
|
|
|
|
of Targa Resources GP LLC, |
|
|
|
|
the general partner of Targa Resources Partners LP |
|
|
|
|
(Principal Financial Officer) |
|
|
A signed original of this written statement required by Section 906, or other document
authenticating, acknowledging, or otherwise adopting the signature that appears in typed form
within the electronic version of this written statement required by Section 906, has been provided
to the Partnership and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request.