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, 2007
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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, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer o Accelerated
filer o Non-accelerated
filer þ
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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 19,336,000 Common Units, 11,528,231 Subordinated
Units and 629,555 General Partner Units outstanding as of
August 1, 2007.
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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BBtu
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Billion British thermal units
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Btu
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British thermal unit, 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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Bbl
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Barrels
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MBbl
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Thousand barrels
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Mcf
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Thousand cubic feet
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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
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Natural gas liquids
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Price Index
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Definitions
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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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MB-OPIS
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Oil Price Information Service,
Mont Belvieu, Texas
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NY-WTI
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NYMEX, West Texas Intermediate
Crude Oil
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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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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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2
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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 elsewhere in this quarterly report and under
Item 1A. Risk Factors in our Annual Report on
Form 10-K
for the year ended December 31, 2006.
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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 under the heading Risk Factors in our Annual
Report on
Form 10-K
for the year ended December 31, 2006 and elsewhere in this
Quarterly Report. Except as may be required by applicable law,
we undertake no obligation to publicly update or advise of any
change in any forward-looking statement, whether as a result of
new information, future events or otherwise.
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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Consolidated
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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2007
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2006
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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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9,361
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$
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Receivables from third parties
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|
1,195
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1,310
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Receivables from affiliated
companies
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50,701
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Assets from risk management
activities
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7,616
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17,250
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Other
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|
483
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Total current assets
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69,356
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18,560
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Property, plant and equipment, at
cost
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1,139,723
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1,129,210
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Accumulated depreciation
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(93,586
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)
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(65,102
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)
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Property, plant and equipment, net
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1,046,137
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1,064,108
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Long-term assets from risk
management activities
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4,462
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15,541
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Other long-term assets
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3,860
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17,612
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Total assets
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$
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1,123,815
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$
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1,115,821
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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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4,252
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$
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2,789
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Accrued liabilities
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33,983
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28,832
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Current maturities of debt
allocated from Parent
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281,083
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Liabilities from risk management
activities
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6,874
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Total current liabilities
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45,109
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312,704
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Long-term debt allocated from
Parent
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582,877
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Long-term debt
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294,500
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Long-term liabilities from risk
management activities
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11,550
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96
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Other long-term liabilities
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1,763
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1,684
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Deferred income tax liability
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3,197
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2,844
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Commitments and contingencies
(Note 9)
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Partners capital:
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Common unitholders
(19,336,000 units issued and outstanding at June 30,
2007)
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378,208
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Subordinated unitholders
(11,528,231 units issued and outstanding at June 30,
2007)
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376,673
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General partner
(629,555 units issued and outstanding at June 30, 2007)
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20,571
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Accumulated other comprehensive
income (loss)
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(7,756
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)
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30,843
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Net parent investment
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184,773
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Total partners capital
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767,696
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215,616
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Total liabilities and
partners capital
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$
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1,123,815
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$
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1,115,821
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See notes to unaudited consolidated financial statements
4
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months
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Three Months
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Six Months
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Six Months
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Ended
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Ended
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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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June 30,
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June 30,
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2007
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2006
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2007
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2006
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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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4,300
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|
$
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2,871
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$
|
10,384
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$
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4,728
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Revenues from affiliates
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|
|
102,103
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|
|
|
89,802
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|
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|
189,612
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|
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184,196
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|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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Total operating revenues
|
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106,403
|
|
|
|
92,673
|
|
|
|
199,996
|
|
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188,924
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Costs and expenses:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Product purchases from third
parties
|
|
|
74,306
|
|
|
|
64,657
|
|
|
|
137,751
|
|
|
|
132,350
|
|
Product purchases from affiliates
|
|
|
271
|
|
|
|
227
|
|
|
|
514
|
|
|
|
400
|
|
Operating expenses, excluding
DD&A
|
|
|
6,065
|
|
|
|
5,599
|
|
|
|
12,033
|
|
|
|
11,543
|
|
Depreciation and amortization
expense
|
|
|
14,289
|
|
|
|
13,719
|
|
|
|
28,484
|
|
|
|
27,439
|
|
General and administrative expense
|
|
|
1,953
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|
|
|
1,667
|
|
|
|
3,531
|
|
|
|
3,255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,884
|
|
|
|
85,869
|
|
|
|
182,313
|
|
|
|
174,987
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|
|
|
|
|
|
|
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|
|
|
|
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|
|
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Income from operations
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|
|
9,519
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|
|
|
6,804
|
|
|
|
17,683
|
|
|
|
13,937
|
|
Other expense:
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|
|
|
|
|
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|
|
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|
|
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Interest expense, net
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|
|
5,154
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|
|
|
|
|
|
|
7,859
|
|
|
|
|
|
Interest expense from affiliates,
net
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|
|
|
|
|
|
|
|
|
|
9,827
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|
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Interest expense allocated from
Parent
|
|
|
|
|
|
|
18,302
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|
|
|
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|
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|
35,663
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
4,365
|
|
|
|
(11,498
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)
|
|
|
(3
|
)
|
|
|
(21,726
|
)
|
Deferred income tax expense
|
|
|
327
|
|
|
|
1,454
|
|
|
|
665
|
|
|
|
1,454
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4,038
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|
|
$
|
(12,952
|
)
|
|
$
|
(668
|
)
|
|
$
|
(23,180
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)
|
|
|
|
|
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|
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|
|
|
|
|
|
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Allocation of net income (loss)
for the three and six months ended June 30, 2007:
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Net loss attributable to the
period from January 1, 2007 to February 13, 2007
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$
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$
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(6,861
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)
|
|
|
|
|
Net income attributable to the
period from February 14, 2007 to June 30, 2007
|
|
|
4,038
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|
|
|
|
|
|
|
6,193
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4,038
|
|
|
|
|
|
|
$
|
(668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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General partner interest in net
income for the period from February 14, 2007 to
June 30, 2007
|
|
$
|
81
|
|
|
|
|
|
|
$
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Common and subordinated
unitholders interest in net income for the period from
February 14, 2007 to June 30, 2007
|
|
$
|
3,957
|
|
|
|
|
|
|
$
|
6,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common and
subordinated unit
|
|
$
|
0.13
|
|
|
|
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common and
subordinated unit
|
|
$
|
0.13
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|
|
|
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and
subordinated units outstanding
|
|
|
30,848
|
|
|
|
|
|
|
|
30,848
|
|
|
|
|
|
Diluted average number of common
and subordinated units outstanding
|
|
|
30,855
|
|
|
|
|
|
|
|
30,854
|
|
|
|
|
|
See notes to unaudited consolidated financial statements
5
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Six Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
4,038
|
|
|
$
|
(12,952
|
)
|
|
$
|
(668
|
)
|
|
$
|
(23,180
|
)
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of commodity
hedges
|
|
|
(7,440
|
)
|
|
|
12,007
|
|
|
|
(33,335
|
)
|
|
|
12,007
|
|
Reclassification adjustment for
settled periods
|
|
|
(1,004
|
)
|
|
|
|
|
|
|
(5,000
|
)
|
|
|
|
|
Related income taxes
|
|
|
8
|
|
|
|
|
|
|
|
311
|
|
|
|
|
|
Interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest
rate swaps
|
|
|
|
|
|
|
593
|
|
|
|
(575
|
)
|
|
|
1,559
|
|
Reclassification adjustment for
settled periods
|
|
|
|
|
|
|
(36
|
)
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
|
(8,436
|
)
|
|
|
12,564
|
|
|
|
(38,599
|
)
|
|
|
13,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
$
|
(4,398
|
)
|
|
$
|
(388
|
)
|
|
$
|
(39,267
|
)
|
|
$
|
(9,611
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated financial statements
6
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENT OF CHANGES IN PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Partners Capital
|
|
|
|
|
|
|
Net Parent
|
|
|
Comprehensive
|
|
|
Limited Partners
|
|
|
General
|
|
|
|
|
|
|
Investment
|
|
|
Income
|
|
|
Common
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Total
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Balance at December 31,
2006
|
|
$
|
184,773
|
|
|
$
|
30,843
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
215,616
|
|
Net loss attributable to the
period from January 1, 2007 through February 13, 2007
|
|
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,861
|
)
|
Other contributions
|
|
|
218,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218,993
|
|
Book value of net assets
contributed by Targa Resources, Inc. to the Partnership
|
|
|
(396,905
|
)
|
|
|
|
|
|
|
|
|
|
|
376,351
|
|
|
|
20,554
|
|
|
|
|
|
Issuance of units to public
(including underwriter over-allotment), net of offering and
other costs
|
|
|
|
|
|
|
|
|
|
|
377,593
|
|
|
|
|
|
|
|
|
|
|
|
377,593
|
|
Non-cash compensation
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
Other comprehensive loss
|
|
|
|
|
|
|
(38,599
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,599
|
)
|
Net income attributable to the
period from February 14, 2007 to June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
3,802
|
|
|
|
2,267
|
|
|
|
124
|
|
|
|
6,193
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
|
(3,263
|
)
|
|
|
(1,945
|
)
|
|
|
(107
|
)
|
|
|
(5,315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30,
2007
|
|
$
|
|
|
|
$
|
(7,756
|
)
|
|
$
|
378,208
|
|
|
$
|
376,673
|
|
|
$
|
20,571
|
|
|
$
|
767,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated financial statements
7
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30, 2007
|
|
|
June 30, 2006
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating
activities
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(668
|
)
|
|
$
|
(23,180
|
)
|
Adjustments to reconcile net loss
to net cash provided by operating activities
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
28,484
|
|
|
|
27,439
|
|
Accretion of asset retirement
obligations
|
|
|
79
|
|
|
|
72
|
|
Amortization of debt issue costs
|
|
|
305
|
|
|
|
2,570
|
|
Noncash compensation
|
|
|
76
|
|
|
|
|
|
Gain (loss) on sale of assets
|
|
|
1
|
|
|
|
(15
|
)
|
Deferred income tax expense
|
|
|
665
|
|
|
|
1,454
|
|
Risk management activities
|
|
|
130
|
|
|
|
|
|
Changes in operating assets and
liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(11,730
|
)
|
|
|
409
|
|
Inventory
|
|
|
|
|
|
|
824
|
|
Other
|
|
|
(503
|
)
|
|
|
630
|
|
Accounts payable
|
|
|
1,463
|
|
|
|
933
|
|
Accrued liabilities
|
|
|
5,151
|
|
|
|
(7,754
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
23,453
|
|
|
|
3,382
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities
|
|
|
|
|
|
|
|
|
Purchases of property, plant and
equipment
|
|
|
(10,515
|
)
|
|
|
(11,225
|
)
|
Other
|
|
|
1
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(10,514
|
)
|
|
|
(11,161
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities
|
|
|
|
|
|
|
|
|
Proceeds from initial public
offering
|
|
|
380,768
|
|
|
|
|
|
Costs incurred in connection with
initial public offering
|
|
|
(3,175
|
)
|
|
|
|
|
Distributions
|
|
|
(5,315
|
)
|
|
|
|
|
Proceeds from borrowings under
credit facility
|
|
|
342,500
|
|
|
|
|
|
Costs incurred in connection with
financing arrangements
|
|
|
(4,145
|
)
|
|
|
|
|
Repayments of loans:
|
|
|
|
|
|
|
|
|
Affiliated
|
|
|
(665,692
|
)
|
|
|
|
|
Credit facility
|
|
|
(48,000
|
)
|
|
|
|
|
Deemed parent contributions
(distributions)
|
|
|
(519
|
)
|
|
|
7,779
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
(3,578
|
)
|
|
|
7,779
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents,
beginning of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of
period
|
|
$
|
9,361
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow
information:
|
|
|
|
|
|
|
|
|
Net settlement of allocated
indebtedness and debt issue costs
|
|
$
|
846,348
|
|
|
$
|
|
|
Net contribution of affiliated
indebtedness
|
|
|
(665,692
|
)
|
|
|
|
|
Net contribution of affiliated
receivables
|
|
|
38,856
|
|
|
|
|
|
Noncash long-term debt allocation
of payments from Parent
|
|
|
|
|
|
|
2,466
|
|
See notes to unaudited consolidated financial statements
8
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
|
|
Note 1
|
Description
of Business and Basis of Presentation
|
Targa Resources Partners LP (the Partnership,
we, our, us), a Delaware
limited partnership formed in October 2006, currently operates
two wholly-owned natural gas processing plants and an extensive
network of integrated gathering pipelines that serve a 14 county
natural gas producing region in the Fort Worth Basin in
North Central Texas (the North Texas System). The
natural gas processing facilities comprise the Chico processing
and fractionating facilities and the Shackelford processing
facility.
We closed our initial public offering (IPO) of
19,320,000 common units (including 2,520,000 common units sold
pursuant to the full exercise by the underwriters of their
option to purchase additional common units) at a price of $21.00
per unit on February 14, 2007. Proceeds from the IPO were
approximately $377.6 million, net of offering costs.
Concurrent with the IPO, Targa Resources, Inc.
(Targa) contributed its interest in Targa North
Texas GP LLC and Targa North Texas LP (TNT LP) to
us. In return, Targa indirectly received a 2% general
partnership interest in us (629,555 General Partner Units),
incentive distribution rights and a 36.6% limited partnership
interest in us (11,528,231 Subordinated Units). Our general
partner is Targa Resources GP LLC (TR GP), a wholly
owned subsidiary of Targa. See Note 3 for information
related to the distribution rights of the common and
subordinated unitholders and the incentive distribution rights
held by the general partner.
The accompanying unaudited consolidated financial statements of
the Partnership include historical cost-basis accounts of the
assets of TNT LP, or the North Texas System, contributed to us
by Targa in connection with the IPO for the periods prior to
February 14, 2007, the closing date of the
Partnerships IPO, and include charges from Targa for
direct costs and allocations of indirect corporate overhead and
the results of contracts in force at that time. Management
believes that the allocation methods are reasonable, and that
the allocations are representative of costs that would have been
incurred on a stand-alone basis. Both the Partnership and TNT LP
are considered entities under common control as
defined under accounting principles generally accepted in the
United States of America (GAAP) and, as such, the
transfer between entities of the assets and liabilities and
operations has been recorded in a manner similar to that
required for a pooling of interests, whereby the recorded assets
and liabilities of TNT LP are carried forward to the
consolidated partnership at their historical amounts. The
Partnership as used herein refers to the consolidated financial
results and operations for the North Texas System from its
inception through its contribution to us and to the Partnership
thereafter.
On February 14, 2007 the Partnership borrowed
$342.5 million through its credit facility, and
concurrently repaid $48.0 million under its credit facility
with the proceeds from the 2,520,000 common units sold pursuant
to the full exercise by the underwriters of their option to
purchase additional common units. The net proceeds of
$294.5 million from this borrowing, together with
approximately $371.2 million of available cash from the IPO
(after payment of offering and debt issue costs and necessary
operating cash reserve balances), were also used to repay
affiliate indebtedness that was contributed to the Partnership
as part of TNT LP. See Note 6 for information related to
our credit facility.
Targa directs our business operations through its ownership and
control of our general partner. Targa and its affiliates
employees provide administrative support to us and operate our
assets.
These unaudited consolidated financial statements have been
prepared in accordance with GAAP for interim financial
information and with the instructions to
Form 10-Q
and Article 10 of
Regulation S-X.
Accordingly, they do not include all of the information and
footnotes required by GAAP for complete financial statements.
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, 2007 and 2006 include all adjustments, both normal
and recurring, which are, in the opinion of management,
necessary for a fair presentation of the results for the interim
periods. All significant intercompany balances and transactions
have been eliminated in consolidation. Transactions
9
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
between us and other Targa operations have been identified in
the unaudited consolidated financial statements as transactions
between affiliates (see Note 5). Financial results for the
Partnership for the three and six months ended June 30,
2007 are not necessarily indicative of the results that may be
expected for the full year ended December 31, 2007. 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, 2006.
|
|
Note 2
|
Accounting
Policies
|
Asset Retirement Obligations. The Partnership
accounts for asset retirement obligations (AROs)
using Statement of Financial Accounting Standards
(SFAS) 143, Accounting for Asset Retirement
Obligations, as interpreted by Financial
Interpretation FIN 47, Accounting for
Conditional Asset Retirement Obligations. Asset
retirement obligations are legal obligations associated with the
retirement of tangible long-lived assets that result from the
assets acquisition, construction, development
and/or
normal operation. An ARO is initially measured at its estimated
fair value. Upon initial recognition of an ARO, an entity
records an increase to the carrying amount of the related
long-lived asset and an offsetting ARO liability. The
consolidated cost of the asset and the capitalized asset
retirement obligation is depreciated using a systematic and
rational allocation method over the period during which the
long-lived asset is expected to provide benefits. After the
initial period of ARO recognition, the ARO will change as a
result of either the passage of time or revisions to the
original estimates of either the amounts of estimated cash flows
or their timing. Changes due to the passage of time increase the
carrying amount of the liability because there are fewer periods
remaining from the initial measurement date until the settlement
date; therefore, the present values of the discounted future
settlement amount increases. These changes are recorded as a
period cost called accretion expense. Upon settlement, AROs will
be extinguished by the entity at either the recorded amount or
the entity will recognize a gain or loss on the difference
between the recorded amount and the actual settlement cost.
The changes in our aggregate asset retirement obligations are as
follows (in thousands):
|
|
|
|
|
Balance as of December 31,
2006
|
|
$
|
1,684
|
|
Liabilities incurred
|
|
|
|
|
Change in estimate
|
|
|
|
|
Accretion expense
|
|
|
79
|
|
|
|
|
|
|
Balance as of June 30, 2007
|
|
$
|
1,763
|
|
|
|
|
|
|
Cash and Cash Equivalents. Targa operates a
centralized cash management system whereby excess cash from most
of its subsidiaries, held in separate bank accounts, is swept to
a centralized account. Cash distributions are deemed to have
occurred through partners capital, and are reflected as an
adjustment to partners capital. Prior to February 14,
2007, the cash accounts of the Partnership were part of
Targas centralized cash management system. After this
date, the Partnership maintains its own cash management system.
For the period from January 1, 2007 through
February 13, 2007, deemed net capital distributions from
the Partnership were $0.5 million.
Comprehensive Income. Comprehensive income
includes net income and other comprehensive income, which
includes unrealized gains and losses on derivative instruments
that are designated as hedges.
Debt Issue Costs. Costs incurred in connection
with the issuance of long-term debt are capitalized and charged
to interest expense over the term of the related debt.
Environmental Liabilities. Liabilities for
loss contingencies, including environmental remediation costs
arising from claims, assessments, litigation, fines, and
penalties and other sources are charged to expense when
10
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
it is probable that a liability has been incurred and the amount
of the assessment
and/or
remediation can be reasonably estimated.
Impairment of Long-Lived Assets. Management
reviews property, plant and equipment for impairment whenever
events or changes in circumstances indicate that the carrying
amount of such assets may not be recoverable. The carrying
amount is deemed not recoverable if it exceeds the undiscounted
sum of the cash flows expected to result from the use and
eventual disposition of the asset. Estimates of expected future
cash flows represent managements best estimate based on
reasonable and supportable assumptions. If the carrying amount
is not recoverable, the impairment loss is measured as the
excess of the assets carrying value over its fair value.
Management assesses the fair value of long-lived assets using
commonly accepted techniques, and may use more than one method,
including, but not limited to, recent third party comparable
sales, internally developed discounted cash flow analysis and
analysis from outside advisors.
Income Taxes. The Partnership is not subject
to federal income taxes. As a result, our earnings or losses for
federal income tax purposes are included in the tax returns of
our individual partners. In May 2006, Texas adopted a margin
tax, consisting generally of a 1% tax on the amount by which
total revenues exceed cost of goods sold. Accordingly, we have
estimated our liability for this tax and it is presently
recorded as a deferred tax liability.
We adopted the provisions of FIN 48 Accounting for
Uncertainty in Income Taxes on January 1, 2007.
FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. Based on our evaluation, we have determined that
there are no significant uncertain tax positions requiring
recognition in our financial statements at the date of adoption
or at June 30, 2007. There are no unrecognized tax benefits
that, if recognized, would affect the effective rate, and there
are no unrecognized tax benefits that are reasonably expected to
increase or decrease in the next twelve months. We file tax
returns in the U.S. Federal and State of Texas
jurisdictions, and are open to federal and state income tax
examinations for years 2006 forward. Presently, no income tax
examinations are underway, and none have been announced. No
potential interest or penalties were recognized at June 30,
2007.
Inventory Imbalance. Quantities of natural gas
and/or
natural gas liquids (NGL) over-delivered or
under-delivered related to operational balancing agreements are
recorded monthly as inventory or as a payable using weighted
average prices at the time the imbalance was created. Monthly,
inventory imbalances receivable are valued at the lower of cost
or market; inventory imbalances payable are valued at
replacement cost. These imbalances are typically settled in the
following month with deliveries of natural gas or NGL. Certain
contracts require cash settlement of imbalances on a current
basis. Under these contracts, imbalance cash-outs are recorded
as a sale or purchase of natural gas, as appropriate.
Net Income per Limited Partner Unit. Emerging
Issues Task Force (EITF) Issue
03-6,
Participating Securities and the Two-Class Method
Under FASB Statement No. 128 addresses the
computation of earnings per share by entities that have issued
securities other than common stock that contractually entitle
the holder to participate in dividends and earnings of the
entity when, and if, it declares dividends on its securities.
EITF 03-6
requires that securities that meet the definition of a
participating security 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.
11
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
EITF 03-6
does not impact the Partnerships overall net income or
other financial results; however, in periods in which aggregate
net income exceeds the Partnerships aggregate
distributions for such period, it will have the impact of
reducing net income per limited partner unit. This result occurs
as a larger portion of the Partnerships aggregate
earnings, as if distributed, is allocated to the incentive
distribution rights of the general partner, even though the
Partnership makes distributions on the basis of available cash
and not earnings. In periods in which the Partnerships
aggregate net income does not exceed its aggregate distributions
for such period,
EITF 03-6
does not have any impact on the Partnerships calculation
of earnings per limited partner unit.
Price Risk Management (Hedging). The
Partnership accounts for derivative instruments in accordance
with SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under
SFAS 133, all derivative instruments not qualifying for the
normal purchases and normal sales exception are recorded on the
balance sheet at fair value. If a derivative does not qualify as
a hedge or is not designated as a hedge, the gain or loss on the
derivative is recognized currently in earnings. If a derivative
qualifies for hedge accounting and is designated as a hedge, the
effective portion of the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(OCI), a component of partners capital, and
reclassified to earnings when the forecasted transaction occurs.
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.
The relationship between the hedging instrument and the hedged
item must be highly effective in achieving the offset of changes
in cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. Hedge
accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to
cash flow hedges for which hedge accounting has been
discontinued remain deferred until the forecasted transaction
occurs. If it is probable that a hedged forecasted transaction
will not occur, deferred gains or losses on the hedging
instrument are reclassified to earnings immediately.
The Partnerships policy is to formally document all
relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedged item,
the nature of the risk being hedged and the manner in which the
hedging instruments effectiveness will be assessed. At the
inception of the hedge and on an ongoing basis, the Partnership
assesses whether the derivatives used in hedging transactions
are highly effective in offsetting changes in cash flows of
hedged items. Hedge effectiveness is measured on a quarterly
basis. Any ineffective portion of the unrealized gain or loss is
reclassified to earnings in the current period.
Property, Plant and Equipment. Property,
plant, and equipment are stated at cost less accumulated
depreciation. Depreciation is computed using the straight-line
method over the estimated useful lives of the assets. The
estimated service lives of the Partnerships functional
asset groups are as follows:
|
|
|
|
|
Asset Group
|
|
Range of Years
|
|
|
Natural gas gathering systems and
processing facilities
|
|
|
15 to 25
|
|
Office and miscellaneous equipment
|
|
|
3 to 7
|
|
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures to refurbish assets that extend the
useful lives or prevent environmental contamination are
capitalized and depreciated over the remaining useful life of
the asset. Upon disposition or retirement of property, plant,
and equipment, any gain or loss is charged to operations.
Revenue Recognition. The Partnerships
primary types of sales and service activities reported as
operating revenues include:
|
|
|
|
|
sales of natural gas, NGL and condensate; and
|
|
|
|
natural gas processing, from which we generate revenues through
the compression, gathering, treating, and processing of natural
gas.
|
12
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
The Partnership recognizes revenues when all of the following
criteria are met: (1) persuasive evidence of an exchange
arrangement exists, if applicable, (2) delivery has
occurred or services have been rendered, (3) the price is
fixed or determinable and (4) collectibility is reasonably
assured.
For processing services, the Partnership receives either fees or
a percentage of commodities as payment for these services,
depending on the type of contract. Under percent-of-proceeds
contracts, the Partnership is paid for its services by keeping a
percentage of the NGL extracted and the residue gas resulting
from processing natural gas. In percent-of-proceeds
arrangements, the Partnership remits either a percentage of the
proceeds received from the sales of residue gas and NGL or a
percentage of the residue gas or NGL at the tailgate of the
plant to the producer. Under the terms of percent-of-proceeds
and similar contracts, the Partnership may purchase the
producers share of the processed commodities for resale or
deliver the commodities to the producer at the tailgate of the
plant. Percent-of-value and percent-of-liquids contracts are
variations on this arrangement. Under keep-whole contracts, the
Partnership keeps the NGL extracted and returns to the producer
volumes of residue gas containing an equivalent Btu content as
the unprocessed natural gas that was delivered to the
Partnership. Natural gas or NGL that the Partnership receives
for services or purchase for resale are in turn sold and
recognized in accordance with the criteria outlined above. Under
fee-based contracts, the Partnership receives a fee based on
throughput volumes.
The Partnership generally reports revenues gross in the
consolidated statements of operations, in accordance with
EITF 99-19,
Reporting Revenue Gross as a Principal versus Net as an
Agent. Except for fee-based contracts, the Partnership
acts as the principal in the transactions where we receive
commodities, take title to the natural gas and NGL, and incur
the risks and rewards of ownership.
Segment Information. SFAS 131,
Disclosures about Segments of an Enterprise and Related
Information, establishes standards for reporting
information about operating segments. The Partnership operates
in one segment only, the natural gas gathering and processing
segment.
Use of Estimates. The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the period.
Estimates and judgments are based on information available at
the time such estimates and judgments are made. Adjustments made
with respect to the use of these estimates and judgments often
relate to information not previously available. Uncertainties
with respect to such estimates and judgments are inherent in the
preparation of financial statements. Estimates and judgments are
used in, among other things, (1) estimating unbilled
revenues and operating and general and administrative costs
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
tangible and intangible assets for possible impairment,
(4) estimating the useful lives of assets and
(5) determining amounts to accrue for contingencies,
guarantees and indemnifications. Actual results could differ
materially from estimated amounts.
Recent
Accounting Pronouncements.
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS 157, Fair Value
Measurements. SFAS 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and
expands disclosures about fair value measurements. SFAS 157
applies under other accounting pronouncements that require or
permit fair value measurements, the FASB having previously
concluded in those accounting pronouncements that fair value is
the relevant measurement attribute. Accordingly, SFAS 157
does not require any new fair value measurements. SFAS 157
is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods
within those fiscal years. We have not yet determined the impact
this new accounting standard will have on our financial
statements.
13
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
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, which is effective for fiscal years
beginning after November 15, 2007, with early adoption
permitted. 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. We are currently reviewing this new
accounting standard and the impact, if any, it will have on our
financial statements.
|
|
Note 3
|
Partnership
Equity and Distributions
|
General. The partnership agreement requires
that, within 45 days after the end of each quarter, we
distribute all of our Available Cash (defined below) to
unitholders of record on the applicable record date, as
determined by the general partner.
Definition of Available Cash. Available Cash,
for any quarter, consists of all cash and cash equivalents on
hand on the date of determination of available cash for that
quarter:
|
|
|
|
|
less the amount of cash reserves established by the general
partner to:
|
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to the unitholders and to the
general partner for any one or more of the next four quarters.
|
General Partner Interest and Incentive Distribution
Rights. The general partner is initially entitled
to 2% of all quarterly distributions that we make prior to our
liquidation. This general partner interest is represented by
629,555 general partner units. The general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its current general partner
interest. The general partners initial 2% interest in
these distributions will be reduced if we issue additional units
in the future and the general partner does not contribute a
proportionate amount of capital to us to maintain its 2% general
partner interest.
The incentive distribution rights held by the general partner
entitle it to receive an increasing share of Available Cash when
pre-defined distribution targets are achieved. The general
partners incentive distribution rights are not reduced if
we issue additional units in the future and the general partner
does not contribute a proportionate amount of capital to us to
maintain its 2% general partner interest. Please read the
Distributions of Available Cash during the Subordination Period
and Distributions of Available Cash after the Subordination
Period sections below for more details about the distribution
targets and their impact on the general partners incentive
distribution rights.
Subordinated Units. All of the subordinated
units are held by Targa GP Inc. and Targa LP Inc. The
partnership agreement provides that, during the subordination
period, the common units have the right to receive distributions
of Available Cash each quarter in an amount equal to $0.3375 per
common unit, or the Minimum Quarterly Distribution,
plus any arrearages in the payment of the Minimum Quarterly
Distribution on the common units from prior quarters, before any
distributions of Available Cash may be made on the subordinated
units. These units are deemed subordinated because
for a period of time, referred to as the subordination period,
the subordinated units will not be entitled to receive any
distributions until the common units have received the Minimum
Quarterly Distribution plus any arrearages from prior quarters.
Furthermore, no arrearages will be paid on the subordinated
units. The practical effect of the subordinated units is to
increase the likelihood that during the subordination period
there will be Available Cash to be distributed on the common
units. The subordination period will end, and the subordinated
units will convert to common units, on a one for one basis, when
certain distribution requirements, as defined in the partnership
agreement, have been met. The earliest date at which the
subordination period may end is April 2008.
14
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
Distributions of Available Cash during the Subordination
Period. Based on the general partners
initial 2% ownership percentage, the partnership agreement
requires that we make distributions of Available Cash from
operating surplus for any quarter during the subordination
period in the following manner:
|
|
|
|
|
first, 98% to the common unitholders, and 2% to the
general partner, pro rata, until we distribute for each
outstanding common unit an amount equal to the Minimum Quarterly
Distribution for that quarter;
|
|
|
|
second, 98% to the common unitholders, and 2% to the
general partner, pro rata, until we distribute for each
outstanding common unit an amount equal to any arrearages in
payment of the Minimum Quarterly Distribution on the common
units for any prior quarters during the subordination period;
|
|
|
|
third, 98% to the subordinated unitholders, and 2% to the
general partner, pro rata, until we distribute for each
subordinated unit an amount equal to the Minimum Quarterly
Distribution for that quarter;
|
|
|
|
fourth, 98% to all unitholders, and 2% to the general
partner, pro rata, until each unitholder receives a total of
$0.3881 per unit for that quarter (the First Target
Distribution);
|
|
|
|
fifth, 85% to all unitholders, and 15% to the general
partner, pro rata, until each unitholder receives a total of
$0.4219 per unit for that quarter (the Second Target
Distribution);
|
|
|
|
sixth, 75% to all unitholders, and 25% to the general
partner, pro rata, until each unitholder receives a total of
$0.50625 per unit for that quarter (the Third Target
Distribution); and
|
|
|
|
thereafter, 50% to all unitholders, and 50% to the
general partner pro rata, (the Fourth Target Distribution).
|
Distributions of Available Cash after the Subordination
Period. The partnership agreement requires that
we make distributions of Available Cash from operating surplus
for any quarter after the subordination period in the following
manner:
|
|
|
|
|
first, 98% to all unitholders, and 2% to the general
partner, pro rata, until each unitholder receives a total of
$0.3881 per unit for that quarter;
|
|
|
|
second, 85% to all unitholders, and 15% to the general
partner, pro rata, until each unitholder receives a total of
$0.4219 per unit for that quarter;
|
|
|
|
third, 75% to all unitholders, and 25% to the general
partner, pro rata, until each unitholder receives a total of
$0.50625 per unit for that quarter; and
|
|
|
|
thereafter, 50% to all unitholders, and 50% to the
general partner, pro rata.
|
|
|
Note 4
|
Net
Income per Limited Partner Unit
|
The Partnerships 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. 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, by the weighted average
number of outstanding limited partner units during the period.
Basic earnings per unit is computed by dividing net earnings
attributable to unitholders by the weighted average number of
units outstanding during each period. However, because our IPO
was completed on February 14, 2007, the number of units
issued following the IPO is utilized for the 2007 period
presented. Diluted earnings per unit reflects the potential
dilution of common equivalent units that could occur if
securities or other contracts to issue common units were
exercised or converted into common units.
Due to the timing of our IPO, a pro-rated distribution for the
first quarter of 2007 of $0.16875 per common unit was approved
by the Board of Directors of our general partner on
April 23, 2007. On May 15,
15
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
2007, we paid this distribution (approximately
$5.3 million) to unitholders of record as of the close of
business on May 3, 2007.
The following table illustrates the Partnerships
calculation of net income per limited and subordinated partner
unit for the three and six months ended June 30, 2007 (in
thousands, except unit and per unit information):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Feb. 14, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
Ended
|
|
|
|
June 30, 2007
|
|
|
June 30, 2006
|
|
|
June 30, 2007
|
|
|
June 30, 2007
|
|
|
Feb. 13, 2007
|
|
|
June 30, 2006
|
|
|
Revenues from third parties
|
|
$
|
4,300
|
|
|
$
|
2,871
|
|
|
$
|
10,384
|
|
|
$
|
6,449
|
|
|
$
|
3,935
|
|
|
$
|
4,728
|
|
Revenues from affiliates
|
|
|
102,103
|
|
|
|
89,802
|
|
|
|
189,612
|
|
|
|
151,443
|
|
|
|
38,169
|
|
|
|
184,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106,403
|
|
|
|
92,673
|
|
|
|
199,996
|
|
|
|
157,892
|
|
|
|
42,104
|
|
|
|
188,924
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases
|
|
|
74,577
|
|
|
|
64,884
|
|
|
|
138,265
|
|
|
|
109,570
|
|
|
|
28,695
|
|
|
|
132,750
|
|
Operating expenses, excluding
DD&A
|
|
|
6,065
|
|
|
|
5,599
|
|
|
|
12,033
|
|
|
|
9,217
|
|
|
|
2,816
|
|
|
|
11,543
|
|
Depreciation and amortization
expense
|
|
|
14,289
|
|
|
|
13,719
|
|
|
|
28,484
|
|
|
|
21,559
|
|
|
|
6,925
|
|
|
|
27,439
|
|
General and administrative expense
|
|
|
1,953
|
|
|
|
1,667
|
|
|
|
3,531
|
|
|
|
2,829
|
|
|
|
702
|
|
|
|
3,255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,884
|
|
|
|
85,869
|
|
|
|
182,313
|
|
|
|
143,175
|
|
|
|
39,138
|
|
|
|
174,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
9,519
|
|
|
|
6,804
|
|
|
|
17,683
|
|
|
|
14,717
|
|
|
|
2,966
|
|
|
|
13,937
|
|
Other expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
5,154
|
|
|
|
|
|
|
|
7,859
|
|
|
|
7,859
|
|
|
|
|
|
|
|
|
|
Interest expense from affiliate, net
|
|
|
|
|
|
|
|
|
|
|
9,827
|
|
|
|
|
|
|
|
9,827
|
|
|
|
|
|
Interest expense allocated from
Parent
|
|
|
|
|
|
|
18,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
4,365
|
|
|
|
(11,498
|
)
|
|
|
(3
|
)
|
|
|
6,858
|
|
|
|
(6,861
|
)
|
|
|
(21,726
|
)
|
Deferred income tax expense
|
|
|
327
|
|
|
|
1,454
|
|
|
|
665
|
|
|
|
665
|
|
|
|
|
|
|
|
1,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4,038
|
|
|
$
|
(12,952
|
)
|
|
$
|
(668
|
)
|
|
$
|
6,193
|
|
|
$
|
(6,861
|
)
|
|
$
|
(23,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in net
income
|
|
$
|
81
|
|
|
|
|
|
|
$
|
(6,737
|
)
|
|
$
|
124
|
|
|
$
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and
subordinated unitholders
|
|
$
|
3,957
|
|
|
|
|
|
|
$
|
6,069
|
|
|
$
|
6,069
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common and
subordinated unit
|
|
$
|
0.13
|
|
|
|
|
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common and
subordinated unit
|
|
$
|
0.13
|
|
|
|
|
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and
subordinated units outstanding
|
|
|
30,848
|
|
|
|
|
|
|
|
30,848
|
|
|
|
30,848
|
|
|
|
|
|
|
|
|
|
Restrictive equivalents
|
|
|
7
|
|
|
|
|
|
|
|
6
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted average number of common
and subordinated units outstanding
|
|
|
30,855
|
|
|
|
|
|
|
|
30,854
|
|
|
|
30,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The calculation of basic and diluted net income per common and
subordinated unit are the same for all periods presented as
distributable cash flow was greater than net income for those
periods.
16
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
|
|
Note 5
|
Related-Party
Transactions
|
Targa
Resources, Inc.
On February 14, 2007, we entered into an Omnibus Agreement
with Targa, our general partner and others that addressed the
reimbursement of our general partner for costs incurred on our
behalf and indemnification matters. Any or all of the provisions
of the Omnibus Agreement, other than the indemnification
provisions described in Note 9, are terminable by Targa at
its option if our general partner is removed without cause and
units held by our general partner and its affiliates are not
voted in favor of that removal. The Omnibus Agreement will also
terminate in the event of a change of control of us or our
general partner.
Reimbursement
of Operating and General and Administrative Expense
Under the Omnibus Agreement, we reimburse Targa for the payment
of certain operating expenses, including compensation and
benefits of operating personnel, and for the provision of
various general and administrative services for our benefit with
respect to the assets contributed to us in connection with our
IPO. Specifically, we reimburse Targa for the following expenses:
|
|
|
|
|
general and administrative expenses, which are capped at
$5 million annually for three years, subject to increases
based on increases in the Consumer Price Index and subject to
further increases in connection with expansions of our
operations through the acquisition or construction of new assets
or businesses with the concurrence of our conflicts committee;
thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement; and
|
|
|
|
operations and certain direct expenses, which are not subject to
the $5 million cap for general and administrative expenses.
|
Pursuant to these arrangements, Targa performs centralized
corporate functions for us, such as legal, accounting, treasury,
insurance, risk management, health, safety and environmental,
information technology, human resources, credit, payroll,
internal audit, taxes, engineering and marketing. We reimburse
Targa for the direct expenses to provide these services as well
as other direct expenses it incurs on our behalf, such as
compensation of operational personnel performing services for
our benefit and the cost of their employee benefits, including
401(k), pension and health insurance benefits.
Sales to and purchases from affiliates. The
Partnership routinely conducts business with other subsidiaries
of Targa. The related transactions result primarily from
purchases and sales of natural gas and NGL. Prior to
February 14, 2007, all of the Partnerships
expenditures were paid through Targa, resulting in inter-company
transactions. Prior to February 14, 2007, settlement of
these inter-company transactions was through adjustments to
partners capital accounts. Effective February 14,
2007, these transactions are settled monthly in cash.
NGL and Condensate Purchase Agreement. In
connection with our IPO which closed on February 14, 2007,
we entered into an NGL and high pressure condensate purchase
agreement with Targa Liquids Marketing and Trade
(TLMT) which has an initial term of 15 years
and will automatically extend for a term of five years, unless
the agreement is otherwise terminated by either party, pursuant
to which (i) we are obligated to sell all volumes of NGL
(other than high-pressure condensate) that we own or control to
TLMT and (ii) we have the right to sell to TLMT or third
parties the volumes of high-pressure condensate that we own or
control, in each case at a price based on the prevailing market
price less transportation, fractionation and certain other fees.
Furthermore, either party may elect to terminate the agreement
if either party ceases to be an affiliate of Targa.
Natural Gas Purchase Agreement. In connection
with our IPO which closed on February 14, 2007, we entered
into a natural gas purchase agreement with Targa Gas Marketing
LLC (TGM) at a price based on
17
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
TGMs sale price for such natural gas, less TGMs
costs and expenses associated therewith. This agreement has an
initial term of 15 years and will automatically extend for
a term of five years, unless the agreement is otherwise
terminated by either party. Furthermore, either party may elect
to terminate the agreement if either party ceases to be an
affiliate of Targa.
Allocation of costs. The employees supporting
the Partnerships operations are employees of Targa. The
Partnerships financial statements include costs allocated
to it by Targa for centralized general and administrative
services performed by Targa, as well as depreciation of assets
utilized by Targas centralized general and administrative
functions. Costs allocated to the Partnership were based on
identification of Targas resources which directly benefit
the Partnership and its proportionate share of costs based on
the Partnerships estimated usage of shared resources and
functions. All of the allocations are based on assumptions that
management believes are reasonable; however, these allocations
are not necessarily indicative of the costs and expenses that
would have resulted if the Partnership had been operated as a
stand-alone entity. Prior to February 14, 2007, these
allocations were not settled in cash, but were settled through
an adjustment to partners capital accounts. Effective
February 14, 2007, all intercompany accounts are settled
monthly in cash.
Allocations of long-term debt, debt issue costs, interest
rate swaps and interest expense. Prior to
January 1, 2007, the Partnerships financial
statements included long-term debt, debt issue costs, interest
rate swaps and interest expense allocated from Targa. The
allocations were calculated in a manner similar to Targas
purchase price allocation related to its acquisition of Dynegy
Midstream Services, Limited Partnership (the DMS
Acquisition) and were based on the fair value of acquired
tangible assets plus related net working capital and
unconsolidated equity interests. These allocations were not
settled in cash. Settlement of these allocations occurred
through adjustments to partners capital. On
January 1, 2007, the allocated debt, debt issue costs and
interest rate swaps were settled through a deemed partner
contribution of $846.3 million.
18
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Feb. 14, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
Ended
|
|
|
|
June 30, 2007
|
|
|
June 30, 2007
|
|
|
Feb. 13, 2007
|
|
|
June 30, 2006
|
|
|
|
(In thousands)
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to affiliates
|
|
$
|
(189,612
|
)
|
|
$
|
(151,443
|
)
|
|
$
|
(38,169
|
)
|
|
$
|
(184,196
|
)
|
Purchases from affiliates
|
|
|
514
|
|
|
|
437
|
|
|
|
77
|
|
|
|
400
|
|
Allocations of general &
administrative expenses pre IPO
|
|
|
702
|
|
|
|
|
|
|
|
702
|
|
|
|
3,255
|
|
Allocations of general &
administrative expenses under Omnibus Agreement
|
|
|
2,829
|
|
|
|
2,829
|
|
|
|
|
|
|
|
|
|
Allocated interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,663
|
|
Affiliate interest
|
|
|
9,838
|
|
|
|
|
|
|
|
9,838
|
|
|
|
|
|
Receivable from affiliates to be
settled in cash
|
|
|
50,701
|
|
|
|
50,701
|
|
|
|
|
|
|
|
|
|
Payments made by the Parent
|
|
|
124,509
|
|
|
|
97,476
|
|
|
|
27,033
|
|
|
|
150,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(519
|
)
|
|
$
|
|
|
|
|
(519
|
)
|
|
|
5,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net settlement of allocated
indebtedness and debt issue costs
|
|
|
|
|
|
|
|
|
|
$
|
846,348
|
|
|
$
|
|
|
Net contribution of affiliated
indebtedness
|
|
|
|
|
|
|
|
|
|
|
(665,692
|
)
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
38,856
|
|
|
|
2,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
219,512
|
|
|
|
2,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
218,993
|
|
|
$
|
7,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
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, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
Instrument Type
|
|
Daily Volumes
|
|
Average Price
|
|
Index
|
|
Jul 2007 Dec 2007
|
|
|
Natural gas
|
|
|
Swap
|
|
4,200 MMBtu
|
|
$
|
9
|
.14 per MMBtu
|
|
IF-Waha
|
Jan 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 2007 Dec 2007
|
|
|
NGL
|
|
|
Swap
|
|
500 Bbl
|
|
|
37
|
.80 per Bbl
|
|
OPIS-MB
|
Jan 2008 Dec 2008
|
|
|
NGL
|
|
|
Swap
|
|
375 Bbl
|
|
|
36
|
.75 per Bbl
|
|
OPIS-MB
|
Jan 2009 Dec 2009
|
|
|
NGL
|
|
|
Swap
|
|
300 Bbl
|
|
|
35
|
.39 per Bbl
|
|
OPIS-MB
|
Jul 2007 Dec 2007
|
|
|
Condensate
|
|
|
Swap
|
|
319 Bbl
|
|
|
75
|
.27 per Bbl
|
|
NY-WTI
|
Jan 2008 Dec 2008
|
|
|
Condensate
|
|
|
Swap
|
|
264 Bbl
|
|
|
72
|
.66 per Bbl
|
|
NY-WTI
|
Jan 2009 Dec 2009
|
|
|
Condensate
|
|
|
Swap
|
|
202 Bbl
|
|
|
70
|
.60 per Bbl
|
|
NY-WTI
|
Jan 2010 Dec 2010
|
|
|
Condensate
|
|
|
Swap
|
|
181 Bbl
|
|
|
69
|
.28 per Bbl
|
|
NY-WTI
|
In October 2005, Targa completed the DMS acquisition. A
substantial portion of the acquisition was financed through
borrowings. Following the acquisition, a significant portion of
Targas acquisition borrowings were allocated to the North
Texas System, resulting in approximately $868.9 million of
allocated indebtedness and corresponding levels of interest
expense. The entity holding the North Texas System provided a
guarantee of this indebtedness. This indebtedness was also
secured by a collateral interest in both the equity of the
entity holding the North Texas System as well as its assets.
On January 1, 2007, Targa contributed to us affiliated
indebtedness related to the North Texas System of approximately
$904.5 million (including accrued interest of
$88.3 million computed at 10% per anum). The Partnership
recorded approximately $9.8 million in interest expense
associated with this affiliated debt for the period from
January 1, 2007 through February 13, 2007. On
February 14, 2007, Targa contributed its interest in Targa
North Texas GP LLC and Targa North Texas LP to us.
The stated 10% interest rate in the formal debt arrangement is
not indicative of prevailing external rates of interest
including that incurred under our credit facility which is
secured by substantially all of our assets. On a pro forma
basis, at prevailing interest rates the affiliated interest
expense for the period from January 1, 2007 to
February 13, 2007 would have been reduced by
$3.0 million. The pro forma interest expense adjustment has
been calculated by applying the weighted average rate of 6.9%
that we incurred under our revolving credit facility to the
affiliate debt balance for the period from January 1, 2007
to February 13, 2007.
On February 14, 2007, we entered into a credit agreement
which provides for a five-year $500 million revolving
credit facility with a syndicate of financial institutions. The
revolving credit facility bears interest at the
Partnerships option, at the higher of the lenders
prime rate or the federal funds rate plus 0.5%, plus an
applicable margin ranging from 0% to 1.25% dependent on the
Partnerships total leverage ratio, or LIBOR plus an
applicable margin ranging from 1.0% to 2.25% dependent on the
Partnerships total leverage ratio. The
20
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
Partnership initially borrowed $342.5 million under its
credit facility, and concurrently repaid $48.0 million
under its credit facility with the proceeds from the 2,520,000
common units sold pursuant to the full exercise by the
underwriters of their option to purchase additional common
units. The net proceeds of $294.5 million from this
borrowing, together with approximately $371.2 million of
available cash from the IPO (after payment of offering and debt
issue costs and necessary operating cash reserve balances), were
used to repay approximately $665.7 million of affiliate
indebtedness. In connection with our IPO, the guarantee of
indebtedness from the entity holding the North Texas System was
terminated, the collateral interest was released and the
remaining affiliate indebtedness was retired and treated as a
capital contribution to the Partnership. Our credit facility is
secured by substantially all of our assets. Our weighted average
interest rate on outstanding borrowings under our credit
facility for the period from February 14, 2007 to
June 30, 2007 was 6.9%.
The credit agreement restricts our ability to make distributions
of available cash to unitholders if we are in any default or an
event of default (as defined in the credit agreement) exists.
The credit agreement requires us to maintain a leverage ratio
(the ratio of consolidated indebtedness to our consolidated
EBITDA, as defined in the credit agreement) of no more than 5.75
to 1.00, as of June 30, 2007; and no more than 5.00 to 1.00
on the last day of any fiscal quarter ending on or after
September 30, 2007. The credit agreement also requires us
to maintain an interest coverage ratio (the ratio of our
consolidated EBITDA to our consolidated interest expense, as
defined in the credit agreement) of no less than 2.25 to 1.00
determined as of the last day of each quarter for the
four-fiscal quarter period ending on the date of determination.
In addition, the credit agreement contains various covenants
that may limit, among other things, our ability to:
|
|
|
|
|
incur indebtedness;
|
|
|
|
grant liens; and
|
|
|
|
engage in transactions with affiliates.
|
The credit facility matures on February 14, 2012, at which
time all unpaid principal and interest is due.
As of June 30, 2007, we had approximately
$205.5 million available under our revolving credit
facility, after giving effect to our outstanding borrowings.
|
|
Note 7
|
Derivative
Instruments and Hedging Activities
|
At June 30, 2007 and December 31, 2006, OCI included
$7.8 million of unrealized net losses and
$30.5 million ($30.2 million, net of tax) of
unrealized net gains, respectively, on commodity hedges. 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 and credited to
income as revenues. There were no settlements of commodity
hedges during the first six months of 2006. There were no
adjustments for hedge ineffectiveness during the first six
months of 2007 or 2006.
At December 31, 2006, OCI also included $0.6 million
of unrealized gains on interest rate hedges allocated from
Targa. In connection with our IPO, all allocated debt was repaid
or retired, and the associated allocated interest rate swaps
were also retired. For the three and six months ended
June 30, 2006, deferred net gains (losses) on interest rate
hedges of $36,000 and ($3,000) were reclassified from OCI to net
interest expense. There were no adjustments for hedge
ineffectiveness during the first six months of 2007 or 2006.
At June 30, 2007, deferred net gains of $35,000 on
commodity hedges recorded in OCI are expected to be reclassified
to earnings during the next twelve months.
21
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
At June 30, 2007, we had the following hedge arrangements
for the six months ended December 31, 2007 and the years
ended December 31, 2008 thru 2012:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/MMBtu
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
IF-NGPL MC
|
|
$
|
8.56
|
|
|
|
8,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,975
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.43
|
|
|
|
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,644
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.02
|
|
|
|
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
340
|
|
Swap
|
|
IF-NGPL MC
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(713
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(181
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,152
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
4,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-Waha
|
|
|
8.73
|
|
|
|
5,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,836
|
|
Swap
|
|
IF-Waha
|
|
|
8.53
|
|
|
|
|
|
|
|
4,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,102
|
|
Swap
|
|
IF-Waha
|
|
|
7.96
|
|
|
|
|
|
|
|
|
|
|
|
4,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(177
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,809
|
|
|
|
|
|
|
|
|
|
|
|
(659
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,250
|
|
|
|
|
|
|
|
(200
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,250
|
|
|
|
(136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,460
|
|
|
|
4,657
|
|
|
|
4,196
|
|
|
|
3,809
|
|
|
|
2,250
|
|
|
|
2,250
|
|
|
|
1,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
13,612
|
|
|
|
11,621
|
|
|
|
10,452
|
|
|
|
9,494
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
6,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.45
|
|
|
|
520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
520
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-Waha
|
|
|
6.70
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
Floor
|
|
IF-Waha
|
|
|
6.85
|
|
|
|
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168
|
|
Floor
|
|
IF-Waha
|
|
|
6.55
|
|
|
|
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
350
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
870
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
NGL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/gal
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
|
OPIS-MB
|
|
|
$
|
0.96
|
|
|
|
3,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,375
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.93
|
|
|
|
|
|
|
|
2,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,136
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.89
|
|
|
|
|
|
|
|
|
|
|
|
2,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,863
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,157
|
|
|
|
|
|
|
|
|
|
|
|
(1,718
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,250
|
|
|
|
|
|
|
|
(262
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
750
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,416
|
|
|
|
2,909
|
|
|
|
2,547
|
|
|
|
2,157
|
|
|
|
1,250
|
|
|
|
750
|
|
|
$
|
(13,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/Bbl
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
|
NY-WTI
|
|
|
$
|
72.82
|
|
|
|
439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
126
|
|
Swap
|
|
|
NY-WTI
|
|
|
|
70.68
|
|
|
|
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(223
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
69.00
|
|
|
|
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(356
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
439
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(727
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
58.60
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.50
|
|
|
|
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.00
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
464
|
|
|
|
439
|
|
|
|
372
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
$
|
(621
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 revenues on
the hedged volumes than we would receive in the absence of
hedges.
We are not a taxable entity for U.S. federal income tax
purposes. Taxes on our net income are generally borne by our
unitholders through allocations of taxable income pursuant to
the partnership agreement. In May 2006, Texas substantially
revised its tax rules and imposed a new tax based on modified
gross margin, beginning in 2007. Pursuant to the guidance of
SFAS 109, Accounting for Income Taxes,
we have accounted for this tax as an income tax. Our income tax
expense of $0.3 million and $0.7 million for the three
and six months ended June 30, 2007, was computed by
applying a 1.0% state income tax rate to taxable margin, as
defined in the Texas statute.
23
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
|
|
Note 9
|
Commitments
and Contingencies
|
Environmental
For environmental matters, the Partnership records 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 IPO.
Our environmental liability was $0.3 million at
June 30, 2007, primarily for ground water assessment and
remediation.
Under the Omnibus Agreement described in Note 5, Targa has
indemnified us for three years from February 14, 2007,
against certain potential environmental claims, losses and
expenses associated with the operation of the North Texas System
and occurring before such date that were not reserved on the
books of the North Texas System. Targas maximum liability
for this indemnification obligation will not exceed
$10.0 million and Targa will not have any obligation under
this indemnification until our aggregate losses exceed $250,000.
We have indemnified Targa against environmental liabilities
related to the North Texas System arising or occurring after
February 14, 2007.
Litigation
Summary
The Partnership is not a party to any legal proceeding other
than legal proceedings arising in the ordinary course of its
business. The Partnership is a party to various administrative
and regulatory proceedings that have arisen in the ordinary
course of its business which are not expected to have a material
adverse effect upon our future financial position, results of
operations or cash flows.
Casualty
or Other Risks
Targa maintains coverage in various insurance programs on our
behalf, which provides us with property damage, business
interruption and other coverages which are customary for the
nature and scope of our operations.
Management believes that Targa has adequate insurance coverage,
although insurance will not cover every type of interruption
that might occur. As a result of insurance market conditions,
premiums and deductibles for certain insurance policies have
increased substantially, and in some instances, certain
insurance may become unavailable, or available for only reduced
amounts of coverage. As a result, Targa may not be able to renew
existing insurance policies or procure other desirable insurance
on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were
not fully insured, it could have a material impact on our
consolidated financial position and results of operations. In
addition, the proceeds of any such insurance may not be paid in
a timely manner and may be insufficient if such an event were to
occur. Any event that interrupts the revenues generated by us,
or which causes us to make significant expenditures not covered
by insurance, could reduce our ability to meet our financial
obligations.
A portion of the insurance costs described above is allocated to
us by Targa through the allocation methodology as prescribed in
the Omnibus Agreement described in Note 5.
Under the Omnibus Agreement, Targa has also indemnified us for
losses attributable to rights-of-way, certain consents or
governmental permits, pre-closing litigation relating to the
North Texas System and income
24
Targa
Resources Partners LP
Notes to
Consolidated Financial Statements
(Continued)
taxes attributable to pre-closing operations that were not
reserved on the books of the North Texas System as of
February 14, 2007. Targa does not have any obligation under
these indemnifications until our aggregate losses exceed
$250,000. We have indemnified Targa for all losses attributable
to the post-closing operations of the North Texas System.
Targas obligations under this additional indemnification
will survive for three years from February 14, 2007, except
that the indemnification for income tax liabilities will
terminate upon the expiration of the applicable statutes of
limitations.
|
|
Note 10
|
Employees
and Equity Compensation Plans
|
We do not directly employ any of the persons responsible for
managing our business, nor do we have a compensation committee.
Any compensation decisions that are required to be made by our
general partner, TR GP, are made by its board of directors.
All of our executive officers are employees of Targa Resources
LLC, a wholly-owned subsidiary of Targa. All of the outstanding
equity of Targa is held indirectly by Targa Resources
Investments Inc. (Targa Investments). Our
reimbursement for the compensation of executive officers is
based on Targas methodology used for allocating general
and administration expenses during a period pursuant to the
terms of, and subject to the limitations contained in, the
Omnibus Agreement.
Equity
Compensation Plans.
Our general partner has adopted a long-term incentive plan
(LTIP) for employees, consultants and directors of
our general partner and its affiliates who perform services for
us, including officers, directors and employees of Targa. The
LTIP provides for the grant of restricted units, phantom units,
unit options and substitute awards, and with respect to unit
options and phantom units, the grant of distribution equivalent
rights (DERs). Under the LTIP, up to
1.68 million common units may be delivered pursuant to
awards under the LTIP. The LTIP is administered by the board of
directors of Targa Resources GP LLC, and may be delegated to the
compensation committee of the board of directors of our general
partner if one is established. Subject to applicable vesting
criteria, a DER entitles the grantee to a cash payment equal to
cash distributions paid on an outstanding common unit. Upon
vesting, certain of the awards may be settled in common units or
equivalent cash at the election of our general partner. For the
three and six months ended June 30, 2007, we recognized
compensation expense of approximately $85,000 and $115,000
related to the LTIP, respectively.
In connection with our IPO in February 2007, we made
equity-based awards to each of our non-management and
independent directors under our LTIP. We also made equity-based
awards to each of the non-management and independent directors
of Targa Investments. The awards were determined by Targa
Investments and were ratified by the board of directors of our
general partner. Each of our independent and non-management
directors and the independent and non-management directors of
Targa Investments received an initial award of 2,000 restricted
units, for a total of 16,000 restricted units. The awards to
these independent and non-management directors consist of
restricted units and will settle with the delivery of common
units. All of these awards are subject to three-year vesting,
without a performance condition, and will vest ratably on each
anniversary of the grant. For the three months ended
June 30, 2007 and for the period from commencement of
Partnership operations (February 14, 2007) through
June 30, 2007, we recognized compensation expense of
approximately $60,000 and $76,000 related to the equity-based
awards, respectively. We estimate that the remaining fair value
of $0.3 million will be recognized in expense over the next
32 months.
|
|
Note 11
|
Subsequent
Event
|
On July 23, 2007, our general partner approved a quarterly
distribution of available cash of $0.3375 per unit
(approximately $10.6 million), for the quarter ended
June 30, 2007, payable on August 14, 2007 to
unitholders of record as of the close of business on
August 2, 2007.
25
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
On February 14, 2007 we completed our initial public
offering, or IPO, of common units. In the IPO, we issued
19,320,000 common units (including 2,520,000 common units sold
pursuant to the full exercise by the underwriters of their
option to purchase additional common units) representing limited
partner interests in us at a price of $21.00 per unit. We used
the net proceeds of the IPO to pay expenses related to the IPO
and our credit facility, for necessary operating cash reserve
balances and to repay approximately $371.2 million of our
outstanding affiliate indebtedness. Upon completion of the IPO,
we had 19,320,000 common units, 11,528,231 subordinated units,
and 629,555 general partner units outstanding.
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 Annual Report on
Form 10-K
for the year ended December 31, 2006. The historical
financial statements included in this item reflect the results
of operations of the assets contributed to us by Targa in
connection with our IPO (the North Texas System). As
used in this report, unless we indicate otherwise, the terms
Partnership, our, we,
us and similar terms refer to Targa Resources
Partners LP, together with our subsidiaries, including Targa
North Texas LP (TNT LP). The Partnership as used
herein refers to the consolidated financial results and
operations of TNT LP from its inception through its contribution
to us, and to the Partnership thereafter. The term
Targa refers to Targa Resources, Inc. and its
subsidiaries and affiliates (other than us).
Overview
We are a Delaware limited partnership formed in October 2006 by
Targa to own, operate, acquire and develop a diversified
portfolio of complementary midstream energy assets. On
February 14, 2007, Targa contributed to us the entities
holding the North Texas System. The North Texas System consists
of two wholly-owned natural gas processing plants and an
extensive network of integrated gathering pipelines that serve a
14-county natural gas producing region in the Fort Worth
Basin in North Central Texas. This producing region includes
production from the Barnett Shale formation and production from
shallower formations including the Bend Conglomerate, Caddo,
Atoka, Marble Falls, and other Pennsylvanian and upper
Mississippian formations (referred to as the other
Fort Worth Basin formations). The natural gas
processing plants consist of the Chico processing and
fractionation facilities and the Shackelford processing facility.
The unaudited consolidated financial statements of the
Partnership include historical cost-basis accounts of TNT LP
(the North Texas System) for the periods prior to
February 14, 2007, the closing date of the
Partnerships IPO, and include charges from Targa for
direct costs and allocations of indirect corporate overhead and
the results of contracts in force at that time. Management
believes that the allocation methods are reasonable. Both the
Partnership and TNT LP are considered entities under
common control as defined under accounting principles
generally accepted in the United States of America
(GAAP) and, as such, the transfer between entities
of the assets and liabilities and operations has been recorded
in a manner similar to that required for a pooling of interests,
whereby the recorded assets and liabilities of TNT LP are
carried forward to the consolidated partnership at their
recorded amounts.
Factors
That Significantly Affect Our Results
Our results of operations are substantially impacted by changes
in commodity prices as well as increases and decreases in the
volume of natural gas that we gather and transport through our
pipeline systems, which we refer to as throughput volume.
Throughput volumes and capacity utilization rates generally are
driven by wellhead production, our competitive position on a
regional basis and more broadly by prices and demand for natural
gas and NGL.
Our processing contract arrangements can have a significant
impact on our profitability. We process natural gas under a
combination of percent-of-proceeds contracts (representing
approximately 97% of our gathered natural gas volumes) and
keep-whole contracts (representing approximately 3% of our
gathered natural gas volumes), each of which exposes us to
commodity price risk. We attempt to mitigate this risk through
hedging activities which can materially impact our results of
operations. Please see Item 7A.
26
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk in our Annual Report on
Form 10-K
for the year ended December 31, 2006.
Actual contract terms are based upon a variety of factors,
including natural gas quality, geographic location, the
competitive commodity and pricing environment at the time the
contract is executed and customer requirements. Our gathering
and processing contract mix and, accordingly, our exposure to
natural gas and NGL prices may change as a result of producer
preferences, competition, changes in production as wells decline
at different rates or are added, our expansion into regions
where different types of contracts are more common and other
market factors. For a more complete discussion of the types of
contracts under which we process natural gas, please see
Item 1. Business Midstream Industry Overview in
our Annual Report on
Form 10-K
for the year ended December 31, 2006.
Upon the closing of our IPO, Targa contributed to us the assets,
liabilities and operations reflected in the historical financial
statements. The historical financial statements of the
Partnership include certain items that will not materially
impact our future results of operations and liquidity and do not
fully reflect a number of other items that will materially
impact future results of operations and liquidity, including the
items described below:
Affiliate Indebtedness and Borrowings. At
December 31, 2006, affiliate indebtedness consisted of
borrowings incurred by Targa and allocated to us for financial
reporting purposes. A substantial portion of Targas
October 31, 2005 acquisition of Dynegy Inc.s interest
in Dynegy Midstream Services, Limited Partnership (the DMS
Acquisition) was financed through borrowings. A
significant portion of Targas acquisition borrowings were
allocated to the Partnership, resulting in approximately
$868.9 million of allocated indebtedness as of
December 31, 2006 and corresponding levels of interest
expense. TNT LP, the entity holding the North Texas System,
provided a guarantee of the indebtedness. The indebtedness was
also secured by a collateral interest in both the equity of TNT
LP as well as its assets.
On January 1, 2007 the allocated debt was extinguished
through a deemed capital contribution by Targa and affiliate
indebtedness of $904.5 million (including accrued interest
of $88.3 million) related to the North Texas System was
contributed to us.
On February 14, 2007, we borrowed $342.5 million under
our credit facility and concurrently repaid $48.0 million
under our credit facility with proceeds from the 2,520,000
common units sold pursuant to the full exercise by the
underwriters of their option to purchase additional common
units. The net proceeds of $294.5 million from this
borrowing, together with approximately $371.2 million of
available cash from the IPO (after payment of offering and debt
issuance costs and necessary operating cash reserves balances)
were used to repay $665.7 million of affiliate
indebtedness. Immediately before closing of the IPO, the
remaining affiliate indebtedness in excess of
$665.7 million was retired through a capital contribution
to us. In connection with the IPO, our guarantee of Targas
indebtedness was terminated and the collateral interest was
released.
Hedging Activities. In an effort to reduce the
variability of our cash flows, we have hedged the commodity
price associated with a portion of our expected natural gas, NGL
and condensate equity volumes for the years 2007 through 2012 by
entering into derivative financial instruments including swaps
and purchased puts (or floors). With these arrangements, we have
attempted to mitigate our exposure to commodity price movements
with respect to our forecasted volumes for this period. For
additional information regarding our hedging activities, please
see Item 7A. Quantitative and Qualitative Disclosures about
Market Risk Commodity Price Risk in our Annual
Report on
Form 10-K
for the year ended December 31, 2006.
General and Administrative Expenses. The
Partnership recognized general and administrative expenses as a
result of allocations from the consolidated general and
administrative expenses of Targa. On February 14, 2007 the
Partnership entered into the Omnibus Agreement with Targa
pursuant to which our allocated general and administrative
expenses are capped at $5 million per year for three years,
subject to adjustment. In addition to these allocated general
and administrative expenses, we expect to incur incremental
general and administrative expenses as a result of operating as
a separate publicly held
27
limited partnership. These direct, incremental general and
administrative expenses which are expected to be approximately
$2.5 million annually, are not subject to the cap contained
in the Omnibus Agreement and include costs associated with
annual and quarterly reports to unitholders, tax return and
Schedule K-1
preparation and distribution, incremental independent auditor
fees, registrar and transfer agent fees and independent director
compensation. These incremental general and administrative
expenditures are not reflected in the historical financial
statements of the Partnership. For a more complete description
of this agreement, please 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, 2006.
Working Capital Adjustments. In the historical
financial statements of the North Texas System, all intercompany
transactions, including commodity sales and expense
reimbursements, were not cash settled with Targa, but were
recorded as an adjustment to parent equity on the balance sheet.
The primary intercompany transactions between Targa and the
Partnership were natural gas and NGL sales, the provision of
operations and maintenance activities and the provision of
general and administrative services. Accordingly, the working
capital of the Partnership did not reflect any affiliate
accounts receivable for intercompany commodity sales or
affiliate accounts payable for the personnel and services
provided by or paid for by the applicable parent on behalf of
the Partnership. Subsequent to February 14, 2007, all
transactions with Targa and its affiliates are cash settled on a
monthly basis.
Distributions to our Unitholders. We intend to
make cash distributions to our unitholders and our general
partner at an initial 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, the North Texas System has largely relied on
internally generated cash flows for these purposes. Due to the
timing of our IPO, a pro-rated distribution for the first
quarter of 2007 of $0.16875 per common unit was approved by the
Board of Directors of our general partner on April 23, 2007
and paid on May 15, 2007 to unitholders of record as of the
close of the business on May 3, 2007. For the second
quarter of 2007, a distribution to unitholders of $0.3375 per
common unit was approved by the Board of Directors of our
general partner on July 23, 2007. This distribution is
payable on August 14, 2007 to unitholders of record as of
the close of business on August 2, 2007.
Our
Operations
Our results of operations are determined primarily by the
volumes of natural gas gathered, compressed, treated, processed,
transported and sold through our gathering, processing and
pipeline systems; the volumes of NGL and residue natural gas
sold; and the level of natural gas and NGL prices. We generate
our revenues and our operating margins principally under
percent-of-proceeds contractual arrangements. Under these
arrangements, we generally gather natural gas from producers at
the wellhead or central delivery points, transport the wellhead
natural gas through our gathering system, treat and process the
natural gas, and then sell the resulting residue natural gas and
NGL at index prices based on published index market prices. We
remit to the producers either an agreed upon percentage of
recovered volumes or the actual proceeds that we receive from
our sales of the residue natural gas and NGL or an agreed upon
percentage of the proceeds based on index related prices for the
natural gas and NGL. Under these types of arrangements, our
revenues correlate directly with the price of natural gas and
NGL. For the three and six months ended June 30, 2007 and
2006, our percent-of-proceeds activities accounted for
approximately 97% of our natural gas throughput volumes. The
balance of our throughput volumes are processed under wellhead
purchases and keep-whole contractual arrangements.
Our Chico facility includes an NGL fractionator with the
capacity to fractionate up to 11,500 Bbl/d of the raw NGL
mix that results from the processing of natural gas at Chico.
This fractionation capability allows Chico to deliver either raw
NGL mix to Mont Belvieu primarily through Chevrons WTLPG
Pipeline or separated NGL products to local and other markets
via truck.
28
We sell all of our processed natural gas, NGL 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 Chico System Market Access in our Annual
Report on
Form 10-K
for the year ended December 31, 2006.
How We
Evaluate Our Operations
Our profitability is a function of the difference between the
revenues we receive from our operations, including revenues from
the natural gas, NGL and condensate we sell, and the costs
associated with conducting our operations, including the costs
of wellhead natural gas that we purchase as well as operating
and general and administrative costs. Because commodity price
movements tend to impact both revenues and costs, increases or
decreases in our revenues alone are not necessarily indicative
of increases or decreases in our profitability. Our contract
portfolio, the prevailing pricing environment for natural gas
and NGL, and the natural gas and NGL throughput on our system
are important factors in determining our profitability. Our
profitability is also affected by the NGL content in gathered
wellhead natural gas, demand for our products and changes in our
customer mix.
Our management uses a variety of financial and operational
measurements to analyze our performance. These measurements
include the following: (1) throughput volumes, facility
efficiencies and fuel consumption, (2) operating margin,
(3) operating expenses, (4) general and administrative
expenses, (5) EBITDA and (6) distributable cash flow.
Throughput Volumes, Facility Efficiencies and Fuel
Consumption. Our profitability is impacted by our
ability to add new sources of natural gas supply to offset the
natural decline of existing volumes from natural gas wells that
are connected to our systems. This is achieved by connecting new
wells as well as by capturing supplies currently gathered by
third-parties. In addition, we seek to increase operating
margins by limiting volume losses and reducing fuel consumption
by increasing compression efficiency. With our gathering
systems extensive use of remote monitoring capabilities,
we monitor the volumes of natural gas received at the wellhead
or central delivery points along our gathering systems, the
volume of natural gas received at our processing plant inlets
and the volumes of NGL and residue natural gas recovered by our
processing plants. This information is tracked through our
processing plants to determine customer settlements and helps us
increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we
measure the difference between the volume of natural gas
received at the wellhead or central delivery points on our
gathering systems and the volume received at the inlet of our
processing plants as an indicator of fuel consumption and line
loss. We also track the difference between the volume of natural
gas received at the inlet of the processing plant and the NGL
and residue gas produced at the outlet of such plants to monitor
the fuel consumption and recoveries of the facilities. These
volume, recovery and fuel consumption measurements are an
important part of our operational efficiency analysis.
Operating Margin. We review our performance
based on the non-generally accepted accounting principle
(non-GAAP) financial measure of operating margin. We
define operating margin as total operating revenues, which
consist of natural gas and NGL sales plus service fee revenues,
less product purchases, which consist primarily of producer
payments and other natural gas purchases, and operating
expenses. Natural gas and NGL sales revenues includes settlement
gains and losses on commodity hedges. Our operating margin is
impacted by volumes and commodity prices as well as by our
contract mix and hedging program, which are described in more
detail below. We view our operating margin as an important
performance measure of the core profitability of our operations.
We review our operating margin monthly for consistency and trend
analysis.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our
29
results as reported under GAAP. Because operating margin
excludes some, but not all, items that affect net income and is
defined differently by different companies in our industry, our
definition of operating margin may not be comparable to
similarly titled measures of other companies, thereby
diminishing its utility.
We compensate for the limitations of operating margin as an
analytical tool by reviewing the comparable GAAP measure,
understanding the differences between the measures and
incorporating these learnings into our decision-making processes.
Operating Expenses. Operating expenses are
costs associated with the operation of a specific asset. Direct
labor, ad valorem taxes, repair and maintenance, utilities and
contract services compose the most significant portion of our
operating expenses. These expenses generally remain relatively
stable independent of the volumes through our systems but
fluctuate depending on the scope of the activities performed
during a specific period.
EBITDA. EBITDA is another non-GAAP financial
measure that is used by us. We define EBITDA as net income
before interest, income taxes, depreciation and amortization.
EBITDA is used as a supplemental financial measure by us and by
external users of our financial statements such as investors,
commercial banks and others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
|
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|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
The economic substance behind our use of EBITDA is to measure
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness, and make distributions
to our investors.
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies.
We compensate for the limitations of EBITDA as an analytical
tool by reviewing the comparable GAAP measures, understanding
the differences between the measures and incorporating these
learnings into our decision-making processes.
30
Reconciliation
of Non-GAAP Measures
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Six Months
|
|
|
Six Months
|
|
|
|
Three Months
|
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|
Three Months
|
|
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Ended
|
|
|
Ended
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
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June 30,
|
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|
June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Reconciliation of
EBITDA to net cash provided by (used in) operating
activities:
|
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|
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|
|
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Net cash provided by (used in)
operating activities
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$
|
(2.0
|
)
|
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$
|
4.5
|
|
|
$
|
23.5
|
|
|
$
|
3.4
|
|
Allocated interest expense from
parent(1)
|
|
|
|
|
|
|
17.0
|
|
|
|
|
|
|
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33.1
|
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Interest expense, net(1)
|
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5.0
|
|
|
|
|
|
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17.4
|
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|
|
|
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Changes in operating working
capital which used (provided) cash:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Accounts receivable
|
|
|
21.8
|
|
|
|
|
|
|
|
11.7
|
|
|
|
(0.4
|
)
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Accounts payable and accrued
liabilities
|
|
|
(1.3
|
)
|
|
|
(0.6
|
)
|
|
|
(6.6
|
)
|
|
|
6.8
|
|
Other, including changes in
noncurrent assets and liabilities
|
|
|
0.3
|
|
|
|
(0.4
|
)
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0.2
|
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
23.8
|
|
|
$
|
20.5
|
|
|
$
|
46.2
|
|
|
$
|
41.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
EBITDA to net income (loss):
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Net income (loss )
|
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$
|
4.0
|
|
|
$
|
(13.0
|
)
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|
$
|
(0.7
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)
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|
$
|
(23.2
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)
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Add:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Allocated interest expense, net
|
|
|
|
|
|
|
18.3
|
|
|
|
|
|
|
|
35.7
|
|
Interest expense, net
|
|
|
5.2
|
|
|
|
|
|
|
|
17.7
|
|
|
|
|
|
Deferred income tax expense
|
|
|
0.3
|
|
|
|
1.5
|
|
|
|
0.7
|
|
|
|
1.5
|
|
Depreciation and amortization
expense
|
|
|
14.3
|
|
|
|
13.7
|
|
|
|
28.5
|
|
|
|
27.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
23.8
|
|
|
$
|
20.5
|
|
|
$
|
46.2
|
|
|
$
|
41.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
operating margin to net income (loss):
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4.0
|
|
|
$
|
(13.0
|
)
|
|
$
|
(0.7
|
)
|
|
$
|
(23.2
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)
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Add:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
14.3
|
|
|
|
13.7
|
|
|
|
28.5
|
|
|
|
27.4
|
|
Deferred income tax expense
|
|
|
0.3
|
|
|
|
1.5
|
|
|
|
0.7
|
|
|
|
1.5
|
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated interest expense, net
|
|
|
|
|
|
|
18.3
|
|
|
|
|
|
|
|
35.7
|
|
Interest expense, net
|
|
|
5.2
|
|
|
|
|
|
|
|
17.7
|
|
|
|
|
|
General and administrative expense
|
|
|
1.9
|
|
|
|
1.7
|
|
|
|
3.5
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
25.7
|
|
|
$
|
22.2
|
|
|
$
|
49.7
|
|
|
$
|
44.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of amortization of debt issuance costs of $0.2 million
and $0.3 million for the three and six months ended
June 30, 2007 and $1.3 million and $2.6 million
for the three and six months ended June 30, 2006. |
Distributable Cash Flow. Distributable cash
flow is a significant performance metric used by us and by
external users of our financial statements, such as investors,
commercial banks, research analysts and others to compare basic
cash flows generated by us (prior to the establishment of any
retained cash reserves by our general partner) to the cash
distributions we expect to pay our unitholders. Using this
metric, management can quickly compute the coverage ratio of
estimated cash flows to planned cash distributions.
Distributable cash flow is also an important non-GAAP financial
measure for our unitholders since it serves as an indicator of
31
our success in providing a cash return on investment.
Specifically, this financial measure indicates to investors
whether or not we are generating cash flow at a level that can
sustain or support an increase in our quarterly distribution
rates. Distributable cash flow is also a quantitative standard
used throughout the investment community with respect to
publicly-traded partnerships and limited liability companies
because the value of a unit of such an entity is generally
determined by the units yield (which in turn is based on
the amount of cash distributions the entity pays to a
unitholder).
The economic substance behind our use of distributable cash flow
is to measure the ability of our assets to generate cash flow
sufficient to make distributions to our investors.
The GAAP measure most directly comparable to distributable cash
flow is net income. Our non-GAAP measure of distributable cash
flow should not be considered as an alternative to GAAP net
income. Distributable cash flow is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider distributable cash flow
in isolation or as a substitute for analysis of our results as
reported under GAAP. Because distributable cash flow excludes
some, but not all, items that affect net income and is defined
differently by different companies in our industry, our
definition of distributable cash flow may not be compatible to
similarly titled measures of other companies, thereby
diminishing its utility.
We compensate for the limitations of distributable cash flow as
an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into our decision making processes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
|
Three
|
|
|
Six
|
|
|
Six
|
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
Months Ended
|
|
|
|
June 30, 2007
|
|
|
June 30, 2006
|
|
|
June 30, 2007
|
|
|
June 30, 2006
|
|
|
|
(In millions)
|
|
|
|
(Unaudited)
|
|
|
Reconciliation of
Distributable cash flow to net income
(loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4.0
|
|
|
$
|
(13.0
|
)
|
|
$
|
(0.7
|
)
|
|
$
|
(23.2
|
)
|
Depreciation and amortization
expense
|
|
|
14.3
|
|
|
|
13.7
|
|
|
|
28.5
|
|
|
|
27.4
|
|
Deferred income tax expense
|
|
|
0.3
|
|
|
|
1.5
|
|
|
|
0.7
|
|
|
|
1.5
|
|
Amortization of debt issue costs
|
|
|
0.2
|
|
|
|
1.3
|
|
|
|
0.3
|
|
|
|
2.6
|
|
Maintenance capital expenditures
|
|
|
(2.6
|
)
|
|
|
(2.8
|
)
|
|
|
(5.3
|
)
|
|
|
(6.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow
|
|
$
|
16.2
|
|
|
$
|
0.7
|
|
|
$
|
23.5
|
|
|
$
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Critical
Accounting Policies and Estimates
There have been no significant changes to our critical
accounting policies and estimates since year-end. 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, 2006.
32
Results
of Operations
The following table and discussion relate to the three and six
months ended June 30, 2007 and 2006 and is a summary of our
results of operations for the periods then ended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Six Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions of dollars, except operating and price data)
|
|
|
Revenues
|
|
$
|
106.4
|
|
|
$
|
92.7
|
|
|
$
|
200.0
|
|
|
$
|
188.9
|
|
Product purchases
|
|
|
74.7
|
|
|
|
64.9
|
|
|
|
138.3
|
|
|
|
132.8
|
|
Operating expense, excluding
DD&A
|
|
|
6.0
|
|
|
|
5.6
|
|
|
|
12.0
|
|
|
|
11.5
|
|
Depreciation and amortization
expense
|
|
|
14.3
|
|
|
|
13.7
|
|
|
|
28.5
|
|
|
|
27.4
|
|
General and administrative expense
|
|
|
1.9
|
|
|
|
1.7
|
|
|
|
3.5
|
|
|
|
3.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
9.5
|
|
|
|
6.8
|
|
|
|
17.7
|
|
|
|
13.9
|
|
Interest expense, net
|
|
|
5.2
|
|
|
|
18.3
|
|
|
|
17.7
|
|
|
|
35.7
|
|
Deferred income tax expense (1)
|
|
|
0.3
|
|
|
|
1.5
|
|
|
|
0.7
|
|
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4.0
|
|
|
$
|
(13.0
|
)
|
|
$
|
(0.7
|
)
|
|
$
|
(23.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(2)
|
|
$
|
25.7
|
|
|
$
|
22.2
|
|
|
$
|
49.7
|
|
|
$
|
44.6
|
|
EBITDA(3)
|
|
$
|
23.8
|
|
|
$
|
20.5
|
|
|
$
|
46.2
|
|
|
$
|
41.3
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput, MMcf/d(4)
|
|
|
166.4
|
|
|
|
166.8
|
|
|
|
166.3
|
|
|
|
167.3
|
|
Plant natural gas inlet,
MMcf/d(5)(6)
|
|
|
160.4
|
|
|
|
160.3
|
|
|
|
160.0
|
|
|
|
160.4
|
|
Gross NGL production, MBbl/d
|
|
|
18.4
|
|
|
|
18.5
|
|
|
|
17.3
|
|
|
|
18.7
|
|
Natural gas sales, BBtu/d(6)
|
|
|
73.8
|
|
|
|
74.8
|
|
|
|
75.9
|
|
|
|
74.4
|
|
NGL sales, MBbl/d
|
|
|
13.9
|
|
|
|
13.9
|
|
|
|
13.0
|
|
|
|
13.9
|
|
Condensate sales, MBbl/d
|
|
|
1.9
|
|
|
|
1.6
|
|
|
|
1.9
|
|
|
|
1.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
6.67
|
|
|
$
|
5.51
|
|
|
$
|
6.46
|
|
|
$
|
6.28
|
|
Impact of hedging
|
|
|
0.36
|
|
|
|
|
|
|
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
7.03
|
|
|
$
|
5.51
|
|
|
$
|
6.84
|
|
|
$
|
6.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL, per gal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
0.95
|
|
|
$
|
0.89
|
|
|
$
|
0.88
|
|
|
$
|
0.84
|
|
Impact of hedging
|
|
|
(0.03
|
)
|
|
|
|
|
|
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
0.92
|
|
|
$
|
0.89
|
|
|
$
|
0.87
|
|
|
$
|
0.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate, per Bbl
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
54.88
|
|
|
$
|
53.57
|
|
|
$
|
50.39
|
|
|
$
|
51.87
|
|
Impact of hedging
|
|
|
1.80
|
|
|
|
|
|
|
|
2.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
56.68
|
|
|
$
|
53.57
|
|
|
$
|
52.97
|
|
|
$
|
51.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In May 2006, Texas adopted a margin tax effective
January 1, 2007, consisting of a 1% tax on the amount by
which total revenues exceed cost of goods sold. The amount
presented represents our estimated liability for this tax. |
|
(2) |
|
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures Operating Margin
included in this Item 2. |
33
|
|
|
(3) |
|
EBITDA is net income before interest, income taxes, depreciation
and amortization. Please see Non-GAAP Financial
Measures EBITDA, included in this Item 2. |
|
(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 natural gas inlet volumes include producer
take-in-kind,
while natural gas sales exclude producer
take-in-kind
volumes. |
Comparison
of Three Months Ended June 30, 2007 to Three Months Ended
June 30, 2006
Our revenues increased $13.7 million, or 15%, to
$106.4 million for the three months ended June 30,
2007 compared to $92.7 million for the three months ended
June 30, 2006. The increase is primarily due to:
|
|
|
|
|
a net increase attributable to commodity sales volume of
$0.9 million, consisting of an increase in condensate
revenues of $1.4 million, offset by a decrease in natural
gas revenues of $0.5 million.
|
|
|
|
an increase attributable to commodity prices of
$12.2 million, consisting of increases in natural gas, NGL
and condensate revenues of $10.2 million, $1.5 million
and $0.5 million, respectively.
|
|
|
|
an increase in revenues from fee based processing activities of
$0.6 million.
|
Average realized prices for natural gas increased by $1.52 per
MMBtu (including a $0.36 increase related to hedging), or 28%,
to $7.03 per MMBtu for the three months ended June 30, 2007
compared to $5.51 per MMBtu for the three months ended
June 30, 2006. The average realized price for NGL increased
by $0.03 per gallon (net of a $0.03 decrease related to
hedging), or 3%, to $0.92 per gallon for the three months ended
June 30, 2007 compared to $0.89 per gallon for the three
months ended June 30, 2006. The average realized price for
condensate increased by $3.11 per Bbl (including a $1.80
increase related to hedging), or 6%, to $56.68 per Bbl for the
three months ended June 30, 2007 compared to $53.57 per Bbl
for the three months ended June 30, 2006.
Natural gas sales volumes decreased by 1.0 BBtu/d, to 73.8
BBtu/d for the three months ended June 30, 2007 compared to
74.8 BBtu/d for the three months ended June 30, 2006. NGL
sales volumes were flat at 13.9 MBbl/d for the three months
ended June 30, 2007 and June 30, 2006. Condensate
sales volumes increased by 0.3 MBbl/d, or 19%, to
1.9 MBbl/d for the three months ended June 30, 2007
compared to 1.6 MBbl/d for the three months ended
June 30, 2006. The volumetric difference in condensate is
primarily the result of unseasonable wet weather and cooler
temperatures and their impact on recoveries.
Product purchases increased by $9.8 million, or 15%, to
$74.7 million for the three months ended June 30, 2007
compared to $64.9 million for the three months ended
June 30, 2006. For the three months ended June 30,
2007 and 2006, product purchases were 70% of total revenues for
both periods.
Operating expenses increased by $0.4 million, or 7%, to
$6.0 million for the three months ended June 30, 2007
compared to $5.6 million for the three months ended
June 30, 2006.
Depreciation and amortization expense increased by
$0.6 million, or 4%, to $14.3 million for the three
months ended June 30, 2007 compared to $13.7 million
for the three months ended June 30, 2006. The increase is
due to the higher carrying value of property, plant and
equipment as a result of capital spending in the last six months
of 2006 and the first six months of 2007.
General and administrative expense increased by
$0.2 million, or 12%, to $1.9 million for the three
months ended June 30, 2007 compared to $1.7 million
for the three months ended June 30, 2006. For the three
months ended June 30, 2007, general and administrative
expenses were limited by the $5 million annual cap on
general and administrative expense under the Omnibus Agreement.
For this period, our general and administrative expense
allocation was approximately $1.4 million. For additional
information regarding our allocation of general and
administrative costs, please see Item 13. Certain
Relationships and Related
34
Transactions, and Director Independence Omnibus
Agreement in our Annual Report on
Form 10-K
for the year ended December 31, 2006.
Interest expense recorded for the three months ended
June 30, 2007 was $5.2 million, which reflects the
interest costs associated with borrowings under our revolving
credit facility. The decrease in interest expense for the three
months ended June 30, 2007 of $13.1 million, or 72%,
from $18.3 million for the three months ended June 30,
2006 is due to the repayment of affiliate indebtedness with the
proceeds of our IPO and borrowings under our credit facility.
The remainder of the affiliate debt was treated as contributed
capital by our general and limited partners in conjunction with
our IPO.
The Partnership is not subject to Federal income taxes. As a
result, the earnings or losses for federal income tax purposes
are includable in the tax returns of the individual partners. In
May 2006, Texas adopted a margin tax consisting of a 1% tax on
the amount by which total revenues exceeds cost of goods.
Accordingly, we have estimated our liability for this tax.
Comparison
of Six Months Ended June 30, 2007 to Six Months Ended
June 30, 2006
Our revenues increased $11.1 million, or 6%, to
$200.0 million for the six months ended June 30, 2007
compared to $188.9 million for the six months ended
June 30, 2006. The increase is primarily due to:
|
|
|
|
|
a net decrease attributable to commodity sales volume of
$1.3 million, consisting of increases in natural gas and
condensate revenues of $1.7 million and $2.7 million,
respectively, offset by a decrease in NGL revenues of
$5.7 million.
|
|
|
|
an increase attributable to commodity prices of
$11.1 million, consisting of increases in natural gas, NGL
and condensate revenues of $7.7 million, $3.0 million
and $0.4 million, respectively.
|
|
|
|
an increase in revenues from fee based processing activities of
$1.3 million.
|
Average realized prices for natural gas increased by $0.56 per
MMBtu (including a $0.38 increase related to hedging), or 9%, to
$6.84 per MMBtu for the six months ended June 30, 2007
compared to $6.28 per MMBtu for the six months ended
June 30, 2006. The average realized price for NGL increased
by $0.03 per gallon (net of a $0.01 decrease related to
hedging), or 4%, to $0.87 per gallon for the six months ended
June 30, 2007 compared to $0.84 per gallon for the six
months ended June 30, 2006. The average realized price for
condensate increased by $1.10 per Bbl (including a $2.58
increase related to hedging), or 2%, to $52.97 per Bbl for the
six months ended June 30, 2007 compared to $51.87 per Bbl
for the six months ended June 30, 2006.
Natural gas sales volumes increased by 1.5 BBtu/d, or 2%, to
75.9 BBtu/d for the six months ended June 30, 2007 compared
to 74.4 BBtu/d for the six months ended June 30, 2006.
Volumes for the six months ended June 30, 2007 were also
negatively impacted by unseasonable wet weather which limited
our ability to complete connections to new wells. NGL sales
volumes decreased by 0.9 MBbl/d, or 6%, to 13.0 MBbl/d
for the six months ended June 30, 2007 compared to
13.9 MBbl/d for the six months ended June 30, 2006.
Some of the new production connected to the Chico plant
increased the average carbon dioxide
(CO2)
content, requiring the plant to expand the
CO2
treating capabilities by putting an existing
CO2
treater back into operation. The treater had to be refurbished,
and was not operational until April 2007. Until that time, the
plant rejected ethane to allow the increased
CO2
to pass thru the plant into the residue gas to keep the NGL
product on specification. For the six months ended June 30,
2007, these changes in operations resulted in decreased NGL
recoveries compared to the six months ended June 30, 2006.
Condensate sales volumes increased by 0.3 MBbl/d, or 19%,
to 1.9 MBbl/d for the six months ended June 30, 2007
compared to 1.6 MBbl/d for the six months ended
June 30, 2006.
Product purchases increased by $5.5 million, or 4%, to
$138.3 million for the six months ended June 30, 2007
compared to $132.8 million for the six months ended
June 30, 2006. For the six months ended June 30, 2007
and 2006, product purchases were 69% and 70% of total revenues,
respectively. The increase in product
35
purchases for the six months ended June 30, 2007
corresponds with the increase in revenues for the same period.
Operating expenses increased by $0.5 million, or 4%, to
$12.0 million for the six months ended June 30, 2007
compared to $11.5 million for the six months ended
June 30, 2006.
Depreciation and amortization expense increased by
$1.1 million, or 4%, to $28.5 million for the six
months ended June 30, 2007 compared to $27.4 million
for the six months ended June 30, 2006. The increase is due
to the higher carrying value of property, plant and equipment as
a result of capital spending in the last six months of 2006 and
the first six months of 2007.
General and administrative expense increased by
$0.2 million, or 6%, to $3.5 million for the six
months ended June 30, 2007 compared to $3.3 million
for the six months ended June 30, 2006. For the period from
February 14, 2007 through June 30, 2007, general and
administrative expenses were limited by the $5 million
annual cap on general and administrative expense under the
Omnibus Agreement. For this period, our general and
administrative expense allocation was approximately
$1.9 million. For additional information regarding our
allocation of general and administrative costs, please 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, 2006.
Interest expense recorded for the six months ended June 30,
2007 was $17.7 million, which reflects pre-IPO interest
expense of $9.8 million on debt contributed to us for the
period from January 1, 2007 though February 13, 2007
and $7.9 million in interest expense for the period from
February 14, 2007 through June 30, 2007, reflecting
the interest costs associated with borrowings under our
revolving credit facility. The decrease in interest expense for
the six months ended June 30, 2007 of $18.0 million,
or 50%, from $35.7 million for the six months ended
June 30, 2006 is due to the repayment of affiliate
indebtedness with the proceeds of our IPO offset by borrowings
under our credit facility.
The Partnership is not subject to Federal income taxes. As a
result, the earnings or losses for federal income tax purposes
are includable in the tax returns of the individual partners. In
May 2006, Texas adopted a margin tax consisting of a 1% tax on
the amount by which total revenues exceed cost of goods.
Accordingly, we have estimated our liability for this tax.
Liquidity
and Capital Resources
Our ability to finance our operations, including funding capital
expenditures and acquisitions, to meet our indebtedness
obligations, to refinance our indebtedness 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
NGL, operating costs and maintenance capital expenditures.
Please see Item 1A. Risk Factors in our Annual Report on
Form 10-K
for the year ended December 31, 2006.
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. Our cash receipts were deposited into
centralized cash management accounts that were maintained by
Targa and all cash disbursements were made from these accounts.
Thus, historically, our financial statements have reflected no
cash balances. Cash transactions handled by Targa for us were
reflected as adjustments to partners equity. Following our
IPO, we maintain our own cash management system, which is
managed by Targa.
We expect our sources of liquidity to include:
|
|
|
|
|
cash generated from operations;
|
|
|
|
borrowings under our revolving credit facility;
|
|
|
|
issuance of additional partnership units; and
|
|
|
|
debt offerings.
|
36
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 quarterly cash
distributions for at least the next year.
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 by 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.
Description of Credit Agreement. On
February 14, 2007, we entered into a credit agreement which
provides for a five-year $500 million revolving credit
facility. The revolving credit facility bears interest at the
Partnerships option, at the higher of the lenders
prime rate or the federal funds rate plus 0.5%, plus an
applicable margin ranging from 0% to 1.25% dependent on the
Partnerships total leverage ratio, or LIBOR plus an
applicable margin ranging from 1.0% to 2.25% dependent on the
Partnerships total leverage ratio. We borrowed
$342.5 million under our credit facility and concurrently
repaid $48.0 million under our credit facility with
proceeds from the 2,520,000 common units sold pursuant to the
full exercise by the underwriters of their option to purchase
additional common units. The net proceeds of $294.5 million
from this borrowing, together with approximately
$371.2 million of net proceeds from the IPO (after payment
of offering costs, debt issuance costs and necessary operating
cash reserve balances), were used to repay approximately
$665.7 million of affiliate indebtedness. There have been
no additional borrowings as of June 30, 2007 under our
revolving credit facility.
The credit agreement restricts our ability to make distributions
of available cash to unitholders if we are in any default or an
event of default (as defined in the credit agreement) exists.
The credit agreement requires us to maintain a leverage ratio
(the ratio of consolidated indebtedness to our consolidated
EBITDA, as defined in the credit agreement) of no more than 5.75
to 1.00, as of June 30, 2007, subject to certain
adjustments. We are also required to maintain a leverage ratio
of no more than 5.00 to 1.00 on the last day of any fiscal
quarter ending on or after September 30, 2007. The credit
agreement also requires us to maintain an interest coverage
ratio (the ratio of our consolidated EBITDA to our consolidated
interest expense, as defined in the credit agreement) of no less
than 2.25 to 1.00 determined as of the last day of each quarter
for the four-fiscal quarter period ending on the date of
determination. In addition, the credit agreement contains
various covenants that may limit, among other things, our
ability to:
|
|
|
|
|
incur indebtedness,
|
|
|
|
grant liens, and
|
|
|
|
engage in transactions with affiliates.
|
Any subsequent replacement of our credit agreement or any new
indebtedness could have similar or greater restrictions. As of
June 30, 2007, we had approximately $205.5 million
available under the credit agreement, after giving effect to our
outstanding borrowings.
37
Contractual
Obligations
Our contractual obligations changed due to the repayment of
affiliated debt and the borrowings under our credit facility. A
summary of our remaining contractual obligations as it relates
to our debt as of June 30, 2007 is presented in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
|
Contractual Obligations
|
|
Total
|
|
|
of 2007
|
|
|
2008-2009
|
|
|
2010-2011
|
|
|
2012
|
|
|
|
(In millions)
|
|
|
Debt obligations
|
|
$
|
294.5
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
294.5
|
|
Interest on debt obligations(1)
|
|
|
95.3
|
|
|
|
10.3
|
|
|
|
41.2
|
|
|
|
41.2
|
|
|
|
2.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
389.8
|
|
|
$
|
10.3
|
|
|
$
|
41.2
|
|
|
$
|
41.2
|
|
|
$
|
297.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Represents interest expense on the Partnerships revolving
credit facility using an average interest rate of 7%.
|
Cash
Flow
Net cash provided by or used in operating activities, investing
activities and financing activities for the six months ended
June 30, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
Six Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Net cash provided by operating
activities
|
|
$
|
23.5
|
|
|
$
|
3.4
|
|
Net cash used in investing
activities
|
|
|
(10.5
|
)
|
|
|
(11.2
|
)
|
Net cash provided by (used in)
financing activities
|
|
|
(3.6
|
)
|
|
|
7.8
|
|
Operating Activities. Net cash provided by
operating activities was $23.5 million for the six months
ended June 30, 2007 compared to $3.4 million for the
six months ended June 30, 2006. The $20.1 million
increase was attributable to a lower net loss for the six months
ended June 30, 2007, adjusted for non-cash charges and cash
settlement of operational transactions, including affiliate
transactions, subsequent to our IPO. Prior to the IPO, our
operational transactions were settled through an adjustment to
partners capital. Please see the Liquidity and Capital
Resources section of this MD&A.
Investing Activities. Net cash used in
investing activities was $10.5 million for the six months
ended June 30, 2007 compared to $11.2 million for the
six months ended June 30, 2006. The $0.7 million, or
6%, decrease was primarily attributable to a $1.0 million
decrease in capital spending related to maintenance
expenditures. We categorize our capital expenditures as either:
(i) maintenance expenditures or (ii) growth
expenditures. Maintenance capital expenditures are those
expenditures that are necessary to maintain the base levels of
production, including the replacement of system components and
equipment which is worn, obsolete or completing its useful life,
the addition of new sources of natural gas supply to our systems
to replace natural gas production declines and expenditures to
remain in compliance with environmental laws and regulations.
Growth capital expenditures improve the service capability of
the existing assets, extend asset useful lives, increase
capacities from existing levels, reduce costs or enhance
revenues. The table below outlines our capital expenditures for
the six months ended June 30, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Feb. 14, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
Six Months Ended
|
|
|
|
June 30, 2007
|
|
|
June 30, 2007
|
|
|
Feb. 14, 2007
|
|
|
June 30, 2006
|
|
|
|
(In millions)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Growth
|
|
$
|
5.2
|
|
|
$
|
3.5
|
|
|
$
|
1.7
|
|
|
$
|
4.9
|
|
Maintenance
|
|
|
5.3
|
|
|
|
3.8
|
|
|
|
1.5
|
|
|
|
6.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10.5
|
|
|
$
|
7.3
|
|
|
$
|
3.2
|
|
|
$
|
11.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
Financing Activities. Net cash provided by
financing activities for the six months ended June 30, 2007
primarily reflects the proceeds from our IPO, borrowings under
our credit facility, and deemed parent contributions prior to
the IPO, offset by payments of debt, and the payment of offering
costs and debt issuance costs on our credit facility. Net cash
provided by financing activities for the six months ended
June 30, 2006 represents the contribution to us by Targa of
the net cash required for principal and interest on allocated
parent debt.
Capital Requirements. The midstream energy
business is capital intensive, requiring significant investment
to maintain and upgrade existing operations. A significant
portion of the cost of constructing new gathering lines to
connect to our gathering system is generally paid for by the
natural gas producer. However, we expect to make significant
expenditures during the next year for the construction of
additional natural gas gathering and processing infrastructure.
We expect to fund future capital expenditures with funds
generated from our operations, borrowings under our credit
facility, the issuance of additional partnership units and debt
offerings.
Recent
Accounting Pronouncements
The accounting standard-setting bodies have recently issued the
following accounting guidelines that will or may affect our
future financial statements:
|
|
|
|
|
SFAS 157, Fair Value Measurements, and
|
|
|
|
SFAS 159, Fair Value Option for Financial Assets
and Financial Liabilities Including an amendment of
FASB Statement No. 115.
|
For additional information regarding these recent accounting
developments and others that may affect our future financial
statements, see Note 2 of the Notes to Consolidated
Financial Statements included in Item 1 of this Quarterly
Report.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
For an in-depth discussion of market risks, please see
Item 7A. Quantitative and Qualitative Disclosure about
Market Risk in our Annual Report on
Form 10-K
for the year ended December 31, 2006.
Our principal market risks are our exposure to changes in
commodity prices, particularly to the prices of natural gas and
NGL, changes in interest rates, as well as nonperformance by our
customers. We do not use risk sensitive instruments for trading
purposes.
Commodity
Price Risk
Substantially all of our revenues are derived from
percent-of-proceeds contracts under which we receive a portion
of the natural gas
and/or NGL,
or equity volumes, as payment for services. The prices of
natural gas and NGL 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, please see Item 7A. Quantitative and
Qualitative Disclosure about Market Risk Commodity
Price Risk Hedging Strategies in our Annual Report
on
Form 10-K
for the year ended December 31, 2006.
39
For the three and six months ended June 30, 2007, net
hedging activities increased our operating revenues by
$1.0 million and $5.0 million, respectively. We had no
hedge settlements during the first six months of 2006. At
June 30, 2007, we had the following open commodity
derivative positions designated as cash flow hedges:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/MMBtu
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
IF-NGPL MC
|
|
$
|
8.56
|
|
|
|
8,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,975
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.43
|
|
|
|
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,644
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.02
|
|
|
|
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
340
|
|
Swap
|
|
IF-NGPL MC
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(713
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(181
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,152
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
4,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-Waha
|
|
|
8.73
|
|
|
|
5,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,836
|
|
Swap
|
|
IF-Waha
|
|
|
8.53
|
|
|
|
|
|
|
|
4,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,102
|
|
Swap
|
|
IF-Waha
|
|
|
7.96
|
|
|
|
|
|
|
|
|
|
|
|
4,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(177
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,809
|
|
|
|
|
|
|
|
|
|
|
|
(659
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,250
|
|
|
|
|
|
|
|
(200
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,250
|
|
|
|
(136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,460
|
|
|
|
4,657
|
|
|
|
4,196
|
|
|
|
3,809
|
|
|
|
2,250
|
|
|
|
2,250
|
|
|
|
1,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
13,612
|
|
|
|
11,621
|
|
|
|
10,452
|
|
|
|
9,494
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
6,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.45
|
|
|
|
520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
520
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-Waha
|
|
|
6.70
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
Floor
|
|
IF-Waha
|
|
|
6.85
|
|
|
|
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168
|
|
Floor
|
|
IF-Waha
|
|
|
6.55
|
|
|
|
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
350
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
870
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
NGL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/gal
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
OPIS-MB
|
|
$
|
0.96
|
|
|
|
3,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,375
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.93
|
|
|
|
|
|
|
|
2,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,136
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.89
|
|
|
|
|
|
|
|
|
|
|
|
2,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,863
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,157
|
|
|
|
|
|
|
|
|
|
|
|
(1,718
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,250
|
|
|
|
|
|
|
|
(262
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
750
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,416
|
|
|
|
2,909
|
|
|
|
2,547
|
|
|
|
2,157
|
|
|
|
1,250
|
|
|
|
750
|
|
|
$
|
(13,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/Bbl
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Swap
|
|
NY-WTI
|
|
$
|
72.82
|
|
|
|
439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
126
|
|
Swap
|
|
NY-WTI
|
|
|
70.68
|
|
|
|
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(223
|
)
|
Swap
|
|
NY-WTI
|
|
|
69.00
|
|
|
|
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(356
|
)
|
Swap
|
|
NY-WTI
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
439
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(727
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
NY-WTI
|
|
|
58.60
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Floor
|
|
NY-WTI
|
|
|
60.50
|
|
|
|
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48
|
|
Floor
|
|
NY-WTI
|
|
|
60.00
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
25
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
464
|
|
|
|
439
|
|
|
|
372
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
$
|
(621
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Interest
Rate Risk
We are exposed to changes in interest rates, as a result of our
variable rate debt under our credit facility that we entered
into on February 14, 2007. This $500 million revolving
credit facility had outstanding borrowings of
$294.5 million as of June 30, 2007. A hypothetical
100 basis point increase in the underlying interest rate
would increase our annual interest expense by $2.9 million.
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 connection with our IPO,
we entered into natural gas, NGL and condensate purchase
agreements with Targa pursuant to which Targa will purchase all
of our natural gas, NGL and high-pressure condensate for terms
of 15 years. We also entered into an Omnibus Agreement with
Targa which addresses, among other things, the provision of
general and administrative and operating services to us. As of
October 2006, Moodys and Standard & Poors
assigned Targa corporate credit ratings of B1 and B+,
respectively, which are speculative ratings. The ratings have
not been changed as of June 30, 2007. A speculative rating
signifies a higher risk that Targa will default on its
41
obligations, including its obligations to us, than does an
investment grade rating. 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 4.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
Our management, under the supervision of and with the
participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the 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.
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
The information required for this item is provided in
Note 9, Commitments and Contingencies, under the heading
Litigation Summary 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, please see
Item 1A. Risk Factors in our
Form 10-K
for the year ended December 31, 2006. 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 adopted certain valuation methodologies that may
result in a shift of income, gain, loss and deduction between
the general partner and the unitholders. The IRS may challenge
this treatment, which could adversely affect the value of the
common units.
When we issue additional units or engage in certain other
transactions, we determine the fair market value of our assets
and allocate any unrealized gain or loss attributable to our
assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, under our current valuation methods,
subsequent purchasers of common units may have a greater portion
of their Internal Revenue Code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated
to our intangible assets. The IRS may challenge our valuation
methods, or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of income, gain, loss and deduction between the
general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
42
|
|
Item 2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
Not applicable.
|
|
Item 3.
|
Defaults
Upon Senior Securities
|
Not applicable.
|
|
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 the Partnership, incorporated by reference to
Exhibit 3.2 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
3
|
.2
|
|
Certificate of Formation of Targa
Resources GP LLC, incorporated by reference to Exhibit 3.3
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
3
|
.3
|
|
Agreement of Limited Partnership
of Targa Resources Partners LP, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
3
|
.4
|
|
First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP,
dated February 14, 2007, incorporated by reference to
Exhibit 3.1 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
4
|
.1
|
|
Specimen Unit Certificate
representing common units, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
10
|
.1
|
|
Credit Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, as Borrower, Bank of America, N.A., as Administrative Agent,
Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch
Capital, Royal Bank of Canada and The Royal Bank of Scotland
PLC, as Co-Documentation Agents, and the other lenders party
thereto, incorporated by reference to Exhibit 10.1 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.2
|
|
Contribution, Conveyance and
Assumption Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, Targa Resources Operating LP, Targa
Resources GP LLC, Targa Resources Operating GP LLC, Targa GP
Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North
Texas GP LLC and Targa North Texas LP, incorporated by reference
to Exhibit 10.2 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.3
|
|
Omnibus Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources, Inc., Targa Resources LLC and Targa
Resources GP LLC, incorporated by reference to Exhibit 10.3
to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.4
|
|
Targa Resources Partners Long-Term
Incentive Plan, incorporated by reference to Exhibit 10.2
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.5
|
|
Targa Resources Investments Inc.
Long-Term Incentive Plan, incorporated by reference to
Exhibit 10.9 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.6
|
|
Form of Restricted Unit Grant
Agreement, incorporated by reference to Exhibit 10.2 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
|
|
10
|
.7
|
|
Form of Performance Unit Grant
Agreement, incorporated by reference to Exhibit 10.3 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
|
43
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.8
|
|
Gas Gathering and Purchase
Agreement by and between Burlington Resources Oil &
Gas Company LP, Burlington Resources Trading Inc. and Targa
Midstream Services Limited Partnership (portions of this exhibit
have been omitted pursuant to a request for confidential
treatment), incorporated by reference to Exhibit 10.5 to
the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.9
|
|
Natural Gas Purchase Agreement
with Targa Gas Marketing LLC, incorporated by reference to
Exhibit 10.6 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.10
|
|
NGL and Condensate Purchase
Agreement with Targa Liquids Marketing and Trade, incorporated
by reference to Exhibit 10.7 to the Partnerships
Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.11
|
|
Targa Resources Partners LP
Indemnification Agreement for Barry R. Pearl dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
10
|
.12
|
|
Targa Resources Partners LP
Indemnification Agreement for Robert B. Evans dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
10
|
.13
|
|
Targa Resources Partners LP
Indemnification Agreement for William D. Sullivan dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
* 31
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
* 31
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
* 32
|
.10
|
|
Certification of 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
|
.20
|
|
Certification of Chief Executive
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
44
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
Targa Resources Partners LP
(Registrant)
|
|
|
|
By:
|
Targa Resources GP LLC,
|
its general partner
|
|
|
|
By:
|
/s/ John
Robert Sparger
|
John Robert Sparger
Senior Vice President and Chief Accounting Officer
(Authorized signatory and Principal Accounting Officer)
Date: August 14, 2007
45
Exhibit Index
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Certificate of Limited Partnership
of the Partnership, incorporated by reference to
Exhibit 3.2 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
3
|
.2
|
|
Certificate of Formation of Targa
Resources GP LLC, incorporated by reference to Exhibit 3.3
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
3
|
.3
|
|
Agreement of Limited Partnership
of Targa Resources Partners LP, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
3
|
.4
|
|
First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP,
dated February 14, 2007, incorporated by reference to
Exhibit 3.1 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
4
|
.1
|
|
Specimen Unit Certificate
representing common units, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
10
|
.1
|
|
Credit Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, as Borrower, Bank of America, N.A., as Administrative Agent,
Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch
Capital, Royal Bank of Canada and The Royal Bank of Scotland
PLC, as Co-Documentation Agents, and the other lenders party
thereto, incorporated by reference to Exhibit 10.1 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.2
|
|
Contribution, Conveyance and
Assumption Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, Targa Resources Operating LP, Targa
Resources GP LLC, Targa Resources Operating GP LLC, Targa GP
Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North
Texas GP LLC and Targa North Texas LP, incorporated by reference
to Exhibit 10.2 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.3
|
|
Omnibus Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources, Inc., Targa Resources LLC and Targa
Resources GP LLC, incorporated by reference to Exhibit 10.3
to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
|
|
10
|
.4
|
|
Targa Resources Partners Long-Term
Incentive Plan, incorporated by reference to Exhibit 10.2
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.5
|
|
Targa Resources Investments Inc.
Long-Term Incentive Plan, incorporated by reference to
Exhibit 10.9 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.6
|
|
Form of Restricted Unit Grant
Agreement, incorporated by reference to Exhibit 10.2 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
|
|
10
|
.7
|
|
Form of Performance Unit Grant
Agreement, incorporated by reference to Exhibit 10.3 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
|
|
10
|
.8
|
|
Gas Gathering and Purchase
Agreement by and between Burlington Resources Oil &
Gas Company LP, Burlington Resources Trading Inc. and Targa
Midstream Services Limited Partnership (portions of this exhibit
have been omitted pursuant to a request for confidential
treatment), incorporated by reference to Exhibit 10.5 to
the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.9
|
|
Natural Gas Purchase Agreement
with Targa Gas Marketing LLC, incorporated by reference to
Exhibit 10.6 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.10
|
|
NGL and Condensate Purchase
Agreement with Targa Liquids Marketing and Trade, incorporated
by reference to Exhibit 10.7 to the Partnerships
Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
|
|
10
|
.11
|
|
Targa Resources Partners LP
Indemnification Agreement for Barry R. Pearl dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
46
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.12
|
|
Targa Resources Partners LP
Indemnification Agreement for Robert B. Evans dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
10
|
.13
|
|
Targa Resources Partners LP
Indemnification Agreement for William D. Sullivan dated
February 14, 2007, incorporated by reference to
Exhibit 3.3 to the Annual report on
Form 10-K
for the Year Ended December 31, 2006.
|
|
* 31
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
* 31
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
* 32
|
.10
|
|
Certification of 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
|
.20
|
|
Certification of Chief Executive
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
47
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, 2007 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)
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) 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
(c) Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an
Annual Report) 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.
Name: Rene R. Joyce
|
|
|
|
Title:
|
Chief Executive Officer of Targa Resources GP, LLC,
the general partner of Targa Resources Partners LP
(Principal Executive Officer)
|
Date: August 14, 2007
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, 2007 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)
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) 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
(c) Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an
Annual Report) 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.
|
|
|
|
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)
|
Date: August 14, 2007
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, 2007 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, the general partner of the
Partnership, 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.
Name: Rene R. Joyce
|
|
|
|
Title:
|
Chief Executive Officer of Targa Resources GP LLC,
the general partner of the Partnership
|
Date: August 14, 2007
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, 2007 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, the general partner of the
Partnership, 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.
|
|
|
|
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 the Partnership
|
Date: August 14, 2007
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.