UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________
Form 10-Q
|
þ
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT
OF 1934
|
|
|
For the
quarterly period ended March 31,
2009
|
||
|
or
|
||
|
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT
OF 1934
|
|
|
For the transition period
from to
|
||
Commission File Number
001-33303
_____________________
TARGA RESOURCES PARTNERS
LP
(Exact name of
registrant as specified in its charter)
|
Delaware
(State
or other jurisdiction of
incorporation
or organization)
|
65-1295427
(I.R.S.
Employer
Identification
No.)
|
|
|
1000
Louisiana, Suite 4300, Houston, Texas
(Address of
principal executive offices)
|
77002
(Zip
Code)
|
Registrant’s 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 has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes o No o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
|
Large
accelerated filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Smaller
reporting company o
|
|||
|
(Do
not check if a smaller reporting
company)
|
||||||
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act) Yes o No þ
There
were 34,684,000 Common Units, 11,528,231 Subordinated Units and 943,108 General
Partner Units outstanding as of May 1, 2009.
As
generally used in the energy industry and in this Quarterly Report on Form 10-Q
(“Quarterly Report”), the identified terms have the following
meanings:
|
Bbl
|
Barrels
|
||
|
BBtu
|
Billion
British thermal units
|
||
|
Btu
|
British
thermal units, a measure of heating value
|
||
|
/d
|
Per
day
|
||
|
gal
|
Gallons
|
||
|
MBbl
|
Thousand
barrels
|
||
|
MMBtu
|
Million
British thermal units
|
||
|
MMcf
|
Million
cubic feet
|
||
|
NGL(s)
|
Natural
gas liquid(s)
|
||
|
Price
Index Definitions
|
|||
|
IF-HSC
|
Inside
FERC Gas Market Report, Houston Ship Channel/Beaumont,
Texas
|
||
|
IF-NGPL
MC
|
Inside
FERC Gas Market Report, Natural Gas Pipeline,
Mid-Continent
|
||
|
IF-Waha
|
Inside
FERC Gas Market Report, West Texas Waha
|
||
|
NY-HH
|
NYMEX,
Henry Hub Natural Gas
|
||
|
NY-WTI
|
NYMEX,
West Texas Intermediate Crude Oil
|
||
|
OPIS-MB
|
Oil
Price Information Service, Mont Belvieu, Texas
|
||
As used in this Quarterly Report,
unless the context otherwise requires, “we,” “us”, “our,” the “Partnership” and
similar terms refer to Targa Resources Partners LP, together with its
consolidated subsidiaries.
Cautionary Statement About
Forward-Looking Statements
Targa
Resources Partners LP’s (together with its subsidiaries) reports, filings and
other public announcements may from time to time contain statements that do
not directly or exclusively relate to historical facts. Such statements are
“forward-looking statements” within the meaning of the Private Securities
Litigation Reform Act of 1995. You can typically identify forward-looking
statements by the use of forward-looking words, such as “may,” “could,”
“project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,”
“forecast” and other similar words.
All
statements that are not statements of historical facts, including statements
regarding our future financial position, business strategy,
budgets, projected costs and plans and objectives of management for future
operations, are forward-looking statements.
These
forward-looking statements reflect our intentions, plans, expectations,
assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our
control. Important factors that could cause actual results to differ materially
from the expectations expressed or implied in the forward-looking
statements include known and unknown risks. These risks and
uncertainties, many of which are beyond our control, include, but
are not limited to the risks set forth in “Item 1A. Risk Factors” as
well as the following:
|
|
·
|
our
ability to access the debt and equity markets, which will depend on
general market conditions and the credit ratings for our debt
obligations;
|
|
|
·
|
the
amount of collateral required to be posted from time to time in our
transactions;
|
|
|
·
|
our
success in risk management activities, including the use of derivative
financial instruments to hedge commodity and interest rate
risks;
|
|
|
·
|
the
level of creditworthiness of counterparties to
transactions;
|
|
|
·
|
changes
in laws and regulations, particularly with regard to taxes, safety and
protection of the environment;
|
|
|
·
|
the
timing and extent of changes in natural gas, natural gas liquids and other
commodity prices, interest rates and demand for our
services;
|
|
|
·
|
weather
and other natural phenomena;
|
|
|
·
|
industry
changes, including the impact of consolidations and changes in
competition;
|
|
|
·
|
our
ability to obtain necessary licenses, permits and other
approvals;
|
|
|
·
|
the
level and success of natural gas drilling around our assets and our
success in connecting natural gas supplies to our gathering and
processing systems and NGL supplies to our logistics and marketing
facilities;
|
|
|
·
|
our
ability to grow through acquisitions or internal growth projects and the
successful integration and future performance of such
assets;
|
|
|
·
|
general
economic, market and business conditions;
and
|
|
|
·
|
the
risks described elsewhere in this Quarterly Report on Form 10-Q and our
Annual Report on Form 10-K for the year ended December 31,
2008.
|
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 this Quarterly Report and our Annual Report on Form 10-K for the
year ended December 31, 2008. 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.
|
Item 1.
|
Financial
Statements
|
|
TARGA RESOURCES PARTNERS LP
|
||||||||
|
CONSOLIDATED
BALANCE SHEETS
|
||||||||
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(Unaudited)
|
||||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 62,310 | $ | 81,768 | ||||
|
Receivables
from third parties
|
37,551 | 58,355 | ||||||
|
Receivables
from affiliated companies
|
37,289 | 22,295 | ||||||
|
Assets
from risk management activities
|
90,796 | 91,816 | ||||||
|
Other
current assets
|
884 | 1,276 | ||||||
|
Total
current assets
|
228,830 | 255,510 | ||||||
|
Property,
plant and equipment, at cost
|
1,500,457 | 1,492,726 | ||||||
|
Accumulated
depreciation
|
(267,236 | ) | (248,389 | ) | ||||
|
Property,
plant and equipment, net
|
1,233,221 | 1,244,337 | ||||||
|
Long-term
assets from risk management activities
|
63,339 | 68,296 | ||||||
|
Other
assets
|
13,196 | 12,763 | ||||||
|
Total
assets
|
$ | 1,538,586 | $ | 1,580,906 | ||||
|
LIABILITIES
AND PARTNERS' CAPITAL
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$ | 5,868 | $ | 8,649 | ||||
|
Accrued
liabilities
|
61,062 | 86,191 | ||||||
|
Liabilities
from risk management activities
|
12,259 | 11,664 | ||||||
|
Total
current liabilities
|
79,189 | 106,504 | ||||||
|
Long-term
debt
|
696,845 | 696,845 | ||||||
|
Long
term liabilities from risk management activities
|
16,250 | 9,679 | ||||||
|
Deferred
income taxes
|
2,259 | 1,959 | ||||||
|
Other
long-term liabilities
|
3,649 | 3,555 | ||||||
|
Commitments
and contingencies (see Note 10)
|
||||||||
|
Partners'
capital:
|
||||||||
|
Common
unitholders (34,684,000 and 34,652,000 units issued and
|
||||||||
|
outstanding
as of March 31, 2009 and December 31, 2008)
|
749,054 | 769,921 | ||||||
|
Subordinated
unitholders (11,528,231 units issued and outstanding as of
|
||||||||
|
March
31, 2009 and December 31, 2008)
|
(92,153 | ) | (85,185 | ) | ||||
|
General
partner (943,108 and 942,455 units issued and outstanding as
of
|
||||||||
|
March
31, 2009 and December 31, 2008)
|
4,991 | 5,556 | ||||||
|
Accumulated
other comprehensive income
|
78,502 | 72,072 | ||||||
|
Total
partners' capital
|
740,394 | 762,364 | ||||||
|
Total
liabilities and partners' capital
|
$ | 1,538,586 | $ | 1,580,906 | ||||
|
See
notes to consolidated financial statements
|
||||||||
|
TARGA RESOURCES PARTNERS LP
|
||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
||||||||
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(Unaudited)
|
||||||||
|
(In
thousands, except per unit amounts)
|
||||||||
|
Revenues
from third parties
|
$ | 105,832 | $ | 195,072 | ||||
|
Revenues
from affiliates
|
133,202 | 316,997 | ||||||
|
Total
operating revenues
|
239,034 | 512,069 | ||||||
|
Costs
and expenses:
|
||||||||
|
Product
purchases from third parties
|
153,426 | 375,625 | ||||||
|
Product
purchases from affiliates
|
41,138 | 66,525 | ||||||
|
Operating
expenses
|
12,903 | 12,570 | ||||||
|
Depreciation
and amortization expense
|
18,878 | 18,248 | ||||||
|
General
and administrative expense
|
5,321 | 5,201 | ||||||
|
Gain
on sale of assets
|
- | (74 | ) | |||||
| 231,666 | 478,095 | |||||||
|
Income
from operations
|
7,368 | 33,974 | ||||||
|
Other
income (expense):
|
||||||||
|
Interest
expense, net
|
(9,924 | ) | (8,718 | ) | ||||
|
Other
(see Note 12)
|
726 | 16 | ||||||
|
Income
(loss) before income taxes
|
(1,830 | ) | 25,272 | |||||
|
Deferred
income tax expense (see Note 6)
|
(300 | ) | (337 | ) | ||||
|
Net
income (loss)
|
(2,130 | ) | 24,935 | |||||
|
Net
income attributable to general partner
|
1,890 | 1,846 | ||||||
|
Net
income (loss) available to limited partners
|
$ | (4,020 | ) | $ | 23,089 | |||
|
Basic
and diluted net income (loss) per limited partner unit
|
$ | (0.09 | ) | $ | 0.50 | |||
|
Basic
and diluted average limited partner units outstanding
|
46,205 | 46,165 | ||||||
|
See
notes to consolidated financial statements
|
||||||||
|
TARGA RESOURCES PARTNERS LP
|
||||||||
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
||||||||
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(Unaudited)
|
||||||||
|
(In
thousands)
|
||||||||
|
Net
income (loss)
|
$ | (2,130 | ) | $ | 24,935 | |||
|
Other
comprehensive income (loss):
|
||||||||
|
Commodity
hedges:
|
||||||||
|
Change
in fair value
|
14,254 | (51,784 | ) | |||||
|
Reclassification
adjustment for settled periods
|
(6,611 | ) | 9,997 | |||||
|
Interest
rate hedges:
|
||||||||
|
Change
in fair value
|
(3,735 | ) | (9,435 | ) | ||||
|
Reclassification
adjustment for settled periods
|
2,522 | (233 | ) | |||||
|
Other
comprehensive income (loss)
|
6,430 | (51,455 | ) | |||||
|
Comprehensive
income (loss)
|
$ | 4,300 | $ | (26,520 | ) | |||
|
See
notes to consolidated financial statements
|
||||||||
|
TARGA RESOURCES PARTNERS LP
|
||||||||||||||||||||
|
CONSOLIDATED
STATEMENT OF CHANGES IN PARTNERS' CAPITAL
|
||||||||||||||||||||
|
Partners' Capital
|
Accumulated
|
|||||||||||||||||||
|
Other
|
||||||||||||||||||||
|
Limited Partners
|
General
|
Comprehensive
|
||||||||||||||||||
|
Common
|
Subordinated
|
Partner
|
Income
|
Total
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Balance,
December 31, 2008
|
$ | 769,921 | $ | (85,185 | ) | $ | 5,556 | $ | 72,072 | $ | 762,364 | |||||||||
|
Contributions
|
- | - | 5 | - | 5 | |||||||||||||||
|
Amortization
of equity awards
|
99 | - | - | - | 99 | |||||||||||||||
|
Other
comprehensive income
|
- | - | - | 6,430 | 6,430 | |||||||||||||||
|
Net
income (loss)
|
(3,017 | ) | (1,003 | ) | 1,890 | - | (2,130 | ) | ||||||||||||
|
Distributions
to unitholders
|
(17,949 | ) | (5,965 | ) | (2,460 | ) | - | (26,374 | ) | |||||||||||
|
Balance,
March 31, 2009
|
$ | 749,054 | $ | (92,153 | ) | $ | 4,991 | $ | 78,502 | $ | 740,394 | |||||||||
|
See
notes to consolidated financial statements
|
||||||||||||||||||||
|
TARGA RESOURCES PARTNERS LP
|
||||||||
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(Unaudited)
|
||||||||
|
(In
thousands)
|
||||||||
|
Cash
flows from operating activities
|
||||||||
|
Net
income (loss)
|
$ | (2,130 | ) | $ | 24,935 | |||
|
Adjustments
to reconcile net income (loss) to net cash
|
||||||||
|
provided
by operating activities:
|
||||||||
|
Amortization
in interest expense
|
598 | 402 | ||||||
|
Amortization
in general and administrative expense
|
99 | 41 | ||||||
|
Depreciation
and other amortization expense
|
18,878 | 18,248 | ||||||
|
Accretion
of asset retirement obligations
|
82 | 60 | ||||||
|
Deferred
income tax expense
|
300 | 337 | ||||||
|
Risk
management activities
|
18,511 | 478 | ||||||
|
Gain
on sale of assets
|
- | (74 | ) | |||||
|
Changes
in operating assets and liabilities:
|
||||||||
|
Receivables
and other assets
|
6,202 | (5,279 | ) | |||||
|
Inventory
|
- | (245 | ) | |||||
|
Accounts
payable and other liabilities
|
(20,527 | ) | 13,884 | |||||
|
Net
cash provided by operating activities
|
22,013 | 52,787 | ||||||
|
Cash
flows from investing activities
|
||||||||
|
Additions
to property, plant and equipment
|
(15,102 | ) | (7,381 | ) | ||||
|
Other,
net
|
- | (4,167 | ) | |||||
|
Net
cash used in investing activities
|
(15,102 | ) | (11,548 | ) | ||||
|
Cash
flows from financing activities
|
||||||||
|
Repayments
on credit facility
|
- | (50,000 | ) | |||||
|
Distributions
to unitholders
|
(26,374 | ) | (18,792 | ) | ||||
|
General
partner contributions
|
5 | - | ||||||
|
Net
cash used in financing activities
|
(26,369 | ) | (68,792 | ) | ||||
|
Net
change in cash and cash equivalents
|
(19,458 | ) | (27,553 | ) | ||||
|
Cash
and cash equivalents, beginning of period
|
81,768 | 50,994 | ||||||
|
Cash
and cash equivalents, end of period
|
$ | 62,310 | $ | 23,441 | ||||
|
See
notes to consolidated financial statements
|
||||||||
Targa Resources
Partners LP
Notes to
Consolidated Financial Statements
(Unaudited)
Note
1—Organization and Basis of Presentation
Targa
Resources Partners LP, together with its subsidiaries (“we,” “us,” “our” or the
“Partnership”), is a publicly traded Delaware limited partnership formed on
October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”), a leading
provider of midstream natural gas and NGL services in the United States, to own,
operate, acquire and develop a diversified portfolio of complementary midstream
energy assets. We are engaged in the business of gathering, compressing,
treating, processing and selling natural gas and fractionating and selling
natural gas liquids and NGL products. We currently operate in the Fort Worth
Basin/Bend Arch in North Texas (the “Fort Worth Basin”), the Permian Basin
of West Texas and in Southwest Louisiana.
These
unaudited consolidated financial statements have been prepared in accordance
with accounting principles generally accepted in the United States of America
(“GAAP”) for interim financial information and with the instructions to
Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do
not include all of the information and footnotes required by GAAP for complete
financial statements. The year-end balance sheet data was derived from audited
financial statements, but does not include all disclosures required by GAAP. The
unaudited consolidated financial statements for the three months ended
March 31, 2009 and 2008 include all adjustments, both normal and recurring,
which are, in the opinion of management, necessary for a fair statement of the
results for the interim periods. All significant intercompany balances and
transactions have been eliminated in consolidation. Transactions between us and
other Targa operations have been identified in the unaudited consolidated
financial statements as transactions between affiliates (see Note 5). Our
financial results for the three months ended March 31, 2009 are not necessarily
indicative of the results that may be expected for the full year ending
December 31, 2009. 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, 2008.
Note
2—Accounting Policies and Related Matters
Net income per Limited Partner Unit.
Basic and
diluted net income per limited partner unit is calculated by dividing limited
partners’ interest in net income by the weighted-average number of outstanding
limited partner units during the period.
Unvested
share-based payment awards that contain nonforfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are classified as participating
securities and are included in our computation of basic and diluted net income
per limited partner unit.
Accounting Standards
Codification. It is expected that the “Financial Accounting Standards Board
(“FASB”) Accounting Standards Codification” (the “Codification”) will be
effective on July 1, 2009, officially becoming the single source of
authoritative nongovernmental GAAP, superseding existing FASB, American
Institute of Certified Public Accountants, Emerging Issues Task Force, and
related accounting literature. After that date, only one level of authoritative
GAAP will exist. All other accounting literature will be considered
non-authoritative. The Codification reorganizes the thousands of GAAP
pronouncements into roughly 90 accounting topics and displays them using a
consistent structure. Also included in the Codification is relevant Securities
and Exchange Commission (“SEC”) guidance organized using the same topical
structure in separate sections within the Codification. This will have an impact
on our financial statements since all future references to authoritative
accounting literature will be references in accordance with the
Codification.
Accounting
Pronouncements Recently Adopted
In
September 2006, FASB issued Statement of Financial Accounting Standards (“SFAS”)
157, “Fair Value
Measurements.” SFAS 157 defines fair value, establishes a framework for
measuring fair value and expands disclosures about fair value measurements. SFAS
157 applies to other accounting pronouncements that require or permit fair value
measurements and, accordingly, does not require any new fair value measurements.
SFAS 157 was initially effective as of January 1, 2008, but in February 2008,
FASB delayed the effective date for applying this standard to nonfinancial
assets and nonfinancial liabilities that are recognized or disclosed at fair
value in the financial statements on a nonrecurring basis until periods
beginning after November 15, 2008. We adopted SFAS 157 as of January 1, 2008 for
assets and liabilities within its scope and the impact was not material to our
financial statements. As of January 1, 2009, nonfinancial assets and
nonfinancial liabilities were also required to be measured at fair value. The
adoption of these additional provisions did not have a material impact on our
financial statements. See Note 9.
On
October 10, 2008, FASB issued FASB Staff Position (“FSP”) FAS 157-3, “Determining the Fair Value of a
Financial Asset When the Market for That Asset is Not Active.” FSP FAS
157-3 clarifies the application of SFAS 157 in a market that is not active and
provides factors to take into consideration when determining the fair value of
an asset in an inactive market. FSP FAS 157-3 was effective upon issuance,
including prior periods for which financial statements have not been issued. FSP
FAS 157-3 did not have a material impact on our financial
statements.
In
December 2007, FASB issued SFAS 141R, “Business Combinations.” SFAS 141R requires the
acquiring entity in a business combination to recognize all assets acquired and
liabilities assumed in the transaction, establishes the acquisition-date fair
value as the measurement objective for all assets acquired and liabilities
assumed, and requires the acquirer to disclose certain information related to
the nature and financial effect of the business combination. SFAS 141R also
establishes principles and requirements for how an acquirer recognizes any
noncontrolling interest in the acquiree and the goodwill acquired in a business
combination. SFAS 141R was effective on a prospective basis for business
combinations for which the acquisition date is on or after January 1, 2009. For
any business combination that takes place subsequent to January 1, 2009, SFAS
141R may have a material impact on our financial statements. The nature and
extent of any such impact will depend upon the terms and conditions of the
transaction.
On April
1, 2009 FASB issued FSP FAS 141R-1, “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination that Arise from
Contingencies”. FSP FAS 141R-1 amends and clarifies SFAS 141R to address
application issues on initial recognition and measurement, subsequent
measurement and accounting, and disclosure of assets and liabilities arising
from contingencies in a business combination. This FSP is effective for assets
and liabilities arising from contingencies in business combinations for which
the acquisition date is on or after January 1, 2009. We do not expect any
material financial statement implications relating to the adoption of this
FSP.
In
December 2007, FASB issued SFAS 160, “Noncontrolling Interests in
Consolidated Financial Statements – an amendment of Accounting Research Bulletin
No. 51”. SFAS 160 requires all entities to report noncontrolling
interests in subsidiaries as a separate component of equity in the consolidated
statement of financial position, to clearly identify consolidated net income
attributable to the parent and to the noncontrolling interest on the face of the
consolidated statement of income, and to provide sufficient disclosure that
clearly identifies and distinguishes between the interest of the parent and the
interests of noncontrolling owners. SFAS 160 also establishes accounting and
reporting standards for changes in a parent’s ownership interest and the
valuation of retained noncontrolling equity investments when a subsidiary is
deconsolidated. We adopted SFAS 160 as of January 1, 2009. The adoption of SFAS
did not have a material impact on our financial statements.
We
adopted FASB Emerging Issues Task Force 07-4 (“EITF 07-4”), “Application of the Two - Class
Method under FASB
Statement No. 128, Earnings per Share, to Master Limited Partnership” on
January 1, 2009. Our
adoption of EITF 07-4 required us to retrospectively adjust our earnings per
unit calculation as described in Net income per Limited Partner
Unit above.
We
adopted FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payments Transactions are Participating Securities
(“FSP EITF 03-6-1”) on January 1, 2009. Upon adoption, we were required
to retrospectively adjust our earnings per unit data to conform to the
provisions of FSP EITF 03-6-1. The adoption of FSP EITF 03-6-1 resulted in us
recognizing unvested unit-based payment awards as participating units in our
basic earnings per unit calculation.
Accounting
Pronouncements Recently Issued
On April
9, 2009, FASB issued FSP FAS 157-4, “Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly.” FSP FAS
157-4 relates to determining fair values when there is no active market or where
the price inputs being used represent distressed sales. Specifically, it
reaffirms the need to use judgment to ascertain if a formerly active market has
become inactive and in determining fair values when markets have become
inactive. FSP FAS 157-4 is effective for interim and annual periods ending after
June 15, 2009 and should be applied prospectively. We do not expect any material
financial statement implications relating to our adoption of FSP FAS
157-4.
On April
9, 2009, FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value
of Financial Instruments.” This FSP requires disclosures of fair value
for any financial instruments not currently reflected at fair value on the
balance sheet for all interim periods. This FSP is effective for interim and
annual periods ending after June 15, 2009 and should be applied prospectively.
We do not expect any material financial statement implications relating to the
adoption of this FSP.
Note
3—Property, Plant and Equipment
Property,
plant, and equipment and accumulated depreciation were as follows as of the
dates indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
Natural
gas gathering systems
|
$ | 1,170,877 | $ | 1,161,942 | ||||
|
Processing
and fractionation facilities
|
243,787 | 237,321 | ||||||
|
Other
property, plant, and equipment
|
69,976 | 68,003 | ||||||
|
Construction
in progress
|
15,817 | 25,460 | ||||||
| 1,500,457 | 1,492,726 | |||||||
|
Accumulated
depreciation
|
(267,236 | ) | (248,389 | ) | ||||
| $ | 1,233,221 | $ | 1,244,337 | |||||
Additions
to property, plant and equipment were $7.7 million for the first quarter of
2009. Cash flows from investing activities reflects additions of $15.1 million
for the same period. The difference is the result of settled accruals, which
decreased by $7.4 million during the period.
Note
4—Partner Distributions
Distributions
declared and paid during the three months ended March 31, 2009 and 2008 were as
follows:
|
Distributions Paid
|
Distributions
|
||||||||||||||||||||||||
|
For
the Three
|
Limited Partners
|
General Partner
|
per
limited
|
||||||||||||||||||||||
|
Date Paid
|
Months Ended
|
Common
|
Subordinated
|
Incentive
|
2 | % |
Total
|
partner unit
|
|||||||||||||||||
|
(In
thousands, except per unit amounts)
|
|||||||||||||||||||||||||
|
2009
|
|||||||||||||||||||||||||
|
February
13, 2009
|
December
31, 2008
|
$ | 17,949 | $ | 5,965 | $ | 1,933 | $ | 527 | $ | 26,374 | $ | 0.5175 | ||||||||||||
|
2008
|
|||||||||||||||||||||||||
|
February
14, 2008
|
December
31, 2007
|
13,768 | 4,582 | 66 | 376 | 18,792 | 0.3975 | ||||||||||||||||||
On April
23, 2009, we declared a cash distribution of $0.5175 per unit on our outstanding
common and subordinated units. The distribution will be paid on May 15, 2009 to
unitholders of record on May 6, 2009, for the period January 1, 2009 through
March 31, 2009. The total distribution to be paid is $26.4 million, with $23.9
million to be paid to our common and subordinated unitholders, and $0.5 million
and $1.9 million to be paid to our general partner for its general partner
interest and incentive distribution rights.
Note
5—Related Party Transactions
Relationship with
Targa
We are a
party to various agreements with Targa, our general partner and others that
address (i) the reimbursement of costs incurred on our behalf by our
general partner, (ii) our sales of certain NGLs and NGL products to, and
purchases from, Targa; and (iii) our sales of our natural gas to, and
purchases from, Targa.
The
following table summarizes the sales to and purchases from affiliates of Targa,
payments made or received by Targa on behalf of us and allocations of costs from
Targa. Management believes these transactions are executed on terms that are
fair and reasonable.
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
Sales
to affiliates
|
$ | 133,202 | $ | 316,997 | ||||
|
Purchases
from affiliates
|
41,138 | 66,525 | ||||||
|
Allocations
of general & administrative
|
||||||||
|
expenses
under Omnibus Agreement
|
4,604 | 3,862 | ||||||
|
Net
change in affliate receivable
|
14,994 | 15,262 | ||||||
Relationship
with Bank of America/Merrill Lynch
Bank of
America Corp. (“BofA”) acquired Merrill Lynch & Co. (“Merrill Lynch”) on
January 1, 2009. An affiliate of Merrill Lynch is an equity investor in
Targa Investments., which indirectly owns our general partner.
Financial Services. BofA is a
lender and an administrative agent under our senior secured credit
facility.
Commodity hedges. We
have entered into various commodity derivative transactions with Merrill Lynch
Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. The following table
shows our open commodity derivatives with MLCI as of March 31,
2009:
|
Period
|
Commodity
|
Daily Volumes
|
Average Price
|
Index
|
||||||||
|
Apr
2009 - Dec 2009
|
Natural
gas
|
3,556 |
MMBtu
|
$ | 8.07 |
per
MMBtu
|
IF-Waha
|
|||||
|
Apr
2009 - Dec 2009
|
Natural
gas
|
545 |
MMBtu
|
7.98 |
per
MMBtu
|
NY-HH
|
||||||
|
Jan
2010 - Dec 2010
|
Natural
gas
|
3,289 |
MMBtu
|
7.39 |
per
MMBtu
|
IF-Waha
|
||||||
|
Jan
2010 - Jun 2010
|
Natural
gas
|
497 |
MMBtu
|
8.17 |
per
MMBtu
|
NY-HH
|
||||||
|
|
||||||||||||
|
Apr
2009 - Dec 2009
|
NGL
|
3,000 |
Bbl
|
1.18 |
per
gallon
|
OPIS-MB
|
||||||
|
Apr
2009 - Dec 2009
|
Condensate
|
202 |
Bbl
|
70.60 |
per
barrel
|
NY-WTI
|
||||||
|
Jan
2010 - Dec 2010
|
Condensate
|
181 |
Bbl
|
69.28 |
per
barrel
|
NY-WTI
|
||||||
As of
March 31, 2009, the aggregate fair value of these open positions was
$25.1 million. For the three months ended March 31, 2009 and 2008, we
received from (paid to) MLCI $8.5 million and ($4.1) million to settle
payments due under hedge transactions.
Prior to
BofA’s acquisition of Merrill Lynch, we entered into several interest rate
derivative transactions with BofA. Open positions as of March 31, 2009 consisted
of interest rate swaps and interest rate basis swaps expiring on January 24,
2012. As of March 31, 2009, the aggregate fair value of these positions was a
liability of $2.9 million. Payments to BofA related to settled portions were
$1.0 million for the quarter ended March 31, 2009.
Relationship with Warburg
Pincus
LLC
Two
of the directors of Targa are Managing Directors of Warburg Pincus LLC and are
also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural
gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling
interest in Broad Oak. During the three months ended March 31, 2009 and 2008 we
purchased $1.4 million and less than $0.1 million of product from Broad
Oak.
Note
6—Income Taxes
Our
income tax expense results solely from a tax on modified gross margin imposed on
us by the State of Texas. Current tax expense is computed as 1% of forecasted
positive annual margin as apportioned to Texas. Deferred tax expense is based
upon the rate at which income and expense items attributable to current margin
will become tax benefits or liabilities at some point in the
future. Items contributing to current negative margin create a
deferred tax liability, and we are required to record a deferred tax expense
related to these items. As a result, our current and deferred tax expense does
not correlate with income or loss before income taxes.
Note
7—Long-Term Debt
Our
consolidated debt obligations consisted of the following as of the dates
indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
| Senior unsecured notes, 8¼% fixed rate, due July 1, 2016 | ||||||||
| $ | 209,080 | $ | 209,080 | |||||
|
Senior
secured credit facility, variable rate, due February 14,
2012
|
487,765 | 487,765 | ||||||
|
Total
long-term debt
|
$ | 696,845 | $ | 696,845 | ||||
|
Letters
of credit issued
|
$ | 14,985 | $ | 9,651 | ||||
The
following table shows the range of interest rates paid and weighted-average
interest rate paid on our variable-rate debt obligations during the three months
ended March 31, 2009:
|
Obligation
|
Range of interest rates paid
|
Weighted average interest rate paid
|
||
|
Credit
facility
|
1.3%
to 4.5%
|
2.0%
|
Note
8—Derivative Instruments and Hedging Activities
Our
principal market risks are our exposure to changes in commodity prices,
particularly to the prices of natural gas and NGLs, changes in interest rates,
as well as nonperformance by our counterparties.
Commodity Price Risk. A majority of our revenues
are derived from percent-of-proceeds contracts under which we receive a portion
of the natural gas and/or NGLs or equity volumes, as payment for services. The
prices of natural gas and NGLs are subject to market 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 commodity
derivative transactions designed to mitigate the impact of commodity price
fluctuations on our business. Cash flows from a derivative instrument designated
as hedges are classified in the same category as the cash flows from the item
being hedged.
The
primary purpose of our commodity risk management activities is to hedge our
exposure to commodity price risk and reduce fluctuations in our operating cash
flow despite fluctuations in commodity prices. In an effort to reduce the
variability of our cash flows, as of March 31, 2009, we have hedged the
commodity price associated with a significant portion of our expected natural
gas, NGL and condensate equity volumes for the years 2009 through 2013 by
entering into derivative financial instruments including swaps and purchased
puts (or floors). The percentages of our expected equity volumes that are hedged
decrease over time. With swaps, we typically receive an agreed upon fixed price
for a specified notional quantity of natural gas or NGL and we pay the hedge
counterparty a floating price for that same quantity based upon published index
prices. Since we receive from our customers substantially the same floating
index price from the sale of the underlying physical commodity, these
transactions are designed to effectively lock-in the agreed fixed price in
advance for the volumes hedged. In order to avoid having a greater volume hedged
than our actual equity volumes, we typically limit our use of swaps to hedge the
prices of less than our expected natural gas and NGL equity volumes. We utilize
purchased puts (or floors) to hedge additional expected equity commodity volumes
without creating volumetric risk. Our commodity hedges may expose us to the risk
of financial loss in certain circumstances. Our hedging arrangements provide us
protection on the hedged volumes if market prices decline below the prices at
which these hedges are set. If market 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.
We have
tailored our hedges to generally match the NGL product composition and the NGL
and natural gas delivery points to those of our physical equity volumes. Our NGL
hedges cover baskets of ethane, propane, normal butane, iso-butane and natural
gasoline based upon our expected equity NGL composition. We believe this
strategy avoids uncorrelated risks resulting from employing hedges on crude oil
or other petroleum products as “proxy” hedges of NGL prices. Additionally, our
NGL hedges are based on published index prices for delivery at Mont Belvieu and
our natural gas hedges are based on published index prices for delivery at Waha,
Houston Ship channel and Mid-Continent, which closely approximate our actual NGL
and natural gas delivery points. We hedge a portion of our condensate sales
using crude oil hedges that are based on the NYMEX futures contracts for West
Texas Intermediate light, sweet crude.
Interest Rate Risk. We are exposed to changes
in interest rates, primarily as a result of our variable rate debt under our
credit facility. To the extent that interest rates increase, our interest
expense for our revolving debt will also increase. As of March 31, 2009, we had
borrowings of approximately $487.8 million outstanding under our revolving
credit facility. In an effort to reduce the variability of our cash flows, we
have entered into several interest rate swap and interest rate basis swap
agreements. Under these agreements, which are accounted for as cash flow hedges,
the base interest rate on the specified notional amount of our variable rate
debt is effectively fixed for the term of each agreement and ineffectiveness is
required to be measured each reporting period. The fair values of the
interest rate swap agreements, which are adjusted regularly, have been
aggregated by counterparty for classification in our consolidated balance
sheets. Accordingly, unrealized gains and losses relating to the interest rate
swaps are recorded in accumulated other comprehensive income (“OCI”) until the
interest expense on the related debt is recognized in earnings.
Credit Risk. Our credit exposure related
to commodity derivative instruments is represented by the fair value of
contracts with a net positive fair value to us at the reporting
date. At such times, these outstanding instruments expose us to
credit loss in the event of nonperformance by the counterparties to the
agreements. Should the creditworthiness of one or more of our counterparties
decline, our ability to mitigate nonperformance risk is limited to a
counterparty agreeing to either a voluntary termination and subsequent cash
settlement or a novation of the derivative contract to a third party. In the
event of a counterparty default, we may sustain a loss and our cash receipts
could be negatively impacted.
As of
March 31, 2009, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank
accounted for 68%, 17% and 15% of our counterparty credit exposure related to
commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank
are major financial institutions, each possessing investment grade credit
ratings based upon minimum credit ratings assigned by Standard & Poor’s
Ratings Services, a division of the McGraw-Hill Companies, Inc.
The
following schedules reflect the fair values of derivative instruments in our
financial statements.
|
Asset Derivatives
|
Liability Derivatives
|
|||||||||||||||||
|
Balance
|
Fair Value as of
|
Balance
|
Fair Value as of
|
|||||||||||||||
|
Sheet
|
March
31,
|
December
31,
|
Sheet
|
March
31,
|
December
31,
|
|||||||||||||
|
Location
|
2009
|
2008
|
Location
|
2009
|
2008
|
|||||||||||||
|
(In
thousands)
|
(In
thousands)
|
|||||||||||||||||
|
Derivatives
designated as
|
||||||||||||||||||
|
hedging
instruments under
|
||||||||||||||||||
|
SFAS
133
|
||||||||||||||||||
|
Commodity
contracts
|
Current
assets
|
$ | 86,296 | $ | 88,206 |
Current
liabilities
|
$ | 8 | $ | - | ||||||||
|
Other
assets
|
63,198 | 68,296 |
Other
liabiliites
|
3,940 | 123 | |||||||||||||
|
Interest
rate contracts
|
Current
assets
|
- | - |
Current
liabilities
|
7,686 | 8,020 | ||||||||||||
|
Other
assets
|
- | - |
Other
liabiliites
|
12,165 | 9,556 | |||||||||||||
|
Total
|
149,494 | 156,502 | 23,799 | 17,699 | ||||||||||||||
|
Derivatives
not designated as
|
||||||||||||||||||
|
hedging
instruments under
|
||||||||||||||||||
|
SFAS
133
|
||||||||||||||||||
|
Commodity
contracts
|
Current
assets
|
4,500 | 3,610 |
Current
liabilities
|
4,565 | 3,644 | ||||||||||||
|
Other
assets
|
141 | - |
Other
liabiliites
|
145 | - | |||||||||||||
|
Total
|
4,641 | 3,610 | 4,710 | 3,644 | ||||||||||||||
|
Total
derivatives
|
$ | 154,135 | $ | 160,112 | $ | 28,509 | $ | 21,343 | ||||||||||
|
Amount
of Gain (Loss)
|
||||||||
|
Derivatives
in
|
Recognized
in OCI on
|
|||||||
|
SFAS
133
|
Derivatives (Effective
Portion)
|
|||||||
|
Cash
Flow Hedging
|
Three Months Ended March
31,
|
|||||||
|
Relationships
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
Interest
rate contracts
|
$ | (3,735 | ) | $ | (9,435 | ) | ||
|
Commodity
contracts
|
14,255 | (51,784 | ) | |||||
| $ | 10,520 | $ | (61,219 | ) | ||||
|
Amount
of Gain (Loss)
|
Amount
of Gain (Loss)
|
|||||||||||||||
|
Reclassified
from OCI to
|
Recognized
in Income on
|
|||||||||||||||
|
Location
of Gain (Loss)
|
Income (Effective Portion)
|
Derivatives (Ineffective
Portion)
|
||||||||||||||
|
Reclassified
from
|
Three Months Ended March
31,
|
Three Months Ended March
31,
|
||||||||||||||
|
OCI into Income
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
(In
thousands)
|
(In
thousands)
|
|||||||||||||||
|
Interest
expense, net
|
$ | (2,522 | ) | $ | 233 | $ | - | $ | - | |||||||
|
Revenues
|
6,238 | (9,997 | ) | 373 | - | |||||||||||
| $ | 3,716 | $ | (9,764 | ) | $ | 373 | $ | - | ||||||||
As of December 31,
2008, OCI consisted of $89.6 million of unrealized net gains on commodity
hedges, and $17.6 million of unrealized net losses on interest rate
hedges.
As of March 31,
2009, OCI consisted of $97.3 million of deferred net gains on commodity
hedges and $18.8 million of unrealized net losses on interest rate hedges.
Unrealized net gains of $60.1 million on commodity hedges and unrealized
net losses of $8.2 million on interest rate hedges recorded in OCI are
expected to be reclassified to revenues from third parties and interest expense
during the next twelve months.
During
2008 and 2009, we terminated certain commodity and interest rate hedges. Losses
deferred in OCI will be amortized to revenues and interest expense when the
hedged forecasted transactions occur. As of March 31, 2009 the remaining loss
amortization of terminated hedges will be recognized over the following
periods:
|
Commodity Hedges
|
Interest
Rate
|
|||||||||||||||
|
Natural Gas
|
NGL
|
Total
|
Hedges
|
|||||||||||||
|
(In
thousands)
|
||||||||||||||||
|
Remainder
of 2009
|
$ | (3,134 | ) | $ | (16,488 | ) | $ | (19,622 | ) | $ | (1,784 | ) | ||||
|
2010
|
(3,016 | ) | (24,865 | ) | (27,881 | ) | (2,278 | ) | ||||||||
|
2011
|
- | (139 | ) | (139 | ) | (760 | ) | |||||||||
|
2012
|
- | (254 | ) | (254 | ) | (34 | ) | |||||||||
| $ | (6,150 | ) | $ | (41,746 | ) | $ | (47,896 | ) | $ | (4,856 | ) | |||||
The fair
value of our derivative instruments, depending on the type of instrument, are
determined by the use of present value methods and standard option valuation
models with assumptions about commodity price risk and interest rate risk based
on those observed in underlying markets.
As of
March 31, 2009, we had the following commodity hedge arrangements which
will settle during the years ending December 31, 2009 through 2013 (except
as indicated otherwise, the 2009 volumes reflect daily volumes for the period
from April 1, 2009 through December 31, 2009):
Natural
Gas
|
Instrument
|
Avg.
Price
|
MMBtu per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/MMBtu
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
IF-HSC
|
7.39 | 1,966 | - | - | - | - | $ | 1,743 | ||||||||||||||||||||
| 1,966 | - | - | - | - | |||||||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
9.18 | 6,256 | - | - | - | - | 9,410 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
8.86 | - | 5,685 | - | - | - | 7,089 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
7.34 | - | - | 2,750 | - | - | 1,286 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
7.18 | - | - | - | 2,750 | - | 789 | |||||||||||||||||||||
| 6,256 | 5,685 | 2,750 | 2,750 | - | |||||||||||||||||||||||||
|
Swap
|
IF-Waha
|
7.79 | 9,936 | - | - | - | - | 10,910 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.53 | - | 11,709 | - | - | - | 4,715 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.10 | - | - | 11,250 | - | - | 145 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.30 | - | - | - | 7,250 | - | (326 | ) | ||||||||||||||||||||
|
Swap
|
IF-Waha
|
5.59 | - | - | - | - | 4,000 | (1,478 | ) | ||||||||||||||||||||
| 9,936 | 11,709 | 11,250 | 7,250 | 4,000 | |||||||||||||||||||||||||
|
Total
Swaps
|
18,158 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
|
Floor
|
IF-NGPL
MC
|
6.55 | 850 | - | - | - | - | 710 | |||||||||||||||||||||
| 850 | - | - | - | - | |||||||||||||||||||||||||
|
Floor
|
IF-Waha
|
6.55 | 565 | - | - | - | - | 459 | |||||||||||||||||||||
| 565 | - | - | - | - | |||||||||||||||||||||||||
|
Total
Floors
|
1,415 | - | - | - | - | ||||||||||||||||||||||||
|
Total
Sales
|
19,573 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
| $ | 35,452 | ||||||||||||||||||||||||||||
NGLs
|
Instrument
|
Avg.
Price
|
Barrels per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/gal
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
OPIS-MB
|
1.32 | 6,248 | - | - | - | - | $ | 48,006 | ||||||||||||||||||||
|
Swap
|
OPIS-MB
|
1.27 | - | 4,809 | - | - | - | 40,659 | |||||||||||||||||||||
|
Swap
|
OPIS-MB
|
0.92 | - | - | 3,400 | - | - | 9,420 | |||||||||||||||||||||
|
Swap
|
OPIS-MB
|
0.92 | - | - | - | 2,700 | - | 6,197 | |||||||||||||||||||||
|
Total
Swaps
|
6,248 | 4,809 | 3,400 | 2,700 | - | ||||||||||||||||||||||||
|
Floor
|
OPIS-MB
|
1.44 | - | - | 199 | - | - | 1,935 | |||||||||||||||||||||
|
Floor
|
OPIS-MB
|
1.43 | - | - | - | 231 | - | 2,089 | |||||||||||||||||||||
|
Total
Floors
|
- | - | 199 | 231 | - | ||||||||||||||||||||||||
|
Total
Sales
|
6,248 | 4,809 | 3,599 | 2,931 | - | ||||||||||||||||||||||||
| $ | 108,306 | ||||||||||||||||||||||||||||
Condensate
|
Instrument
|
Avg.
Price
|
Barrels per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/Bbl
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
NY-WTI
|
69.00 | 322 | - | - | - | - | $ | 1,153 | ||||||||||||||||||||
|
Swap
|
NY-WTI
|
68.10 | - | 301 | - | - | - | 518 | |||||||||||||||||||||
|
Total
Swaps
|
322 | 301 | - | - | - | ||||||||||||||||||||||||
|
Floor
|
NY-WTI
|
60.00 | 50 | - | - | - | - | 117 | |||||||||||||||||||||
|
Total
Floors
|
50 | - | - | - | - | ||||||||||||||||||||||||
|
Total
Sales
|
372 | 301 | - | - | - | ||||||||||||||||||||||||
| $ | 1,788 | ||||||||||||||||||||||||||||
Customer
Hedges
As of
March 31, 2009, we had the following commodity derivative contracts
directly related to short-term fixed price arrangements elected by certain
customers in various natural gas purchase and sale agreements, which have been
marked to market through earnings:
|
Period
|
Commodity
|
Instrument Type
|
Daily Volume
|
Average Price
|
Index
|
Fair Value
|
|||||||||||
|
(In
thousands)
|
|||||||||||||||||
|
Purchases
|
|||||||||||||||||
|
Apr
2009 - Dec 2009
|
Natural
gas
|
Swap
|
5,891 |
MMBtu
|
$ | 6.71 |
per
MMBtu
|
NY-HH
|
$ | (4,436 | ) | ||||||
|
Jan
2010 - Jun 2010
|
Natural
gas
|
Swap
|
663 |
MMBtu
|
8.03 |
per
MMBtu
|
NY-HH
|
(273 | ) | ||||||||
|
Sales
|
|||||||||||||||||
|
Apr
2009 - Dec 2009
|
Natural
gas
|
Fixed
price sale
|
5,891 |
MMBtu
|
6.71 |
per
MMBtu
|
NY-HH
|
4,373 | |||||||||
|
Jan
2010 - Jun 2010
|
Natural
gas
|
Fixed
price sale
|
663 |
MMBtu
|
8.03 |
per
MMBtu
|
NY-HH
|
267 | |||||||||
| $ | (69 | ) | |||||||||||||||
Interest Rate Hedges
Our
consolidated variable rate indebtedness accrues interest at a base rate plus an
applicable margin. Our interest rate hedges effectively fix the base rate on the
indicated notional amount of borrowings for the indicated periods:
|
Period
|
Fixed Rate
|
Notional Amount
|
Fair Value
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Remainder
of 2009
|
3.68%
|
$ | 300 |
million
|
$ | (5,896 | ) | |||||
|
2010
|
3.67%
|
300 |
million
|
(6,712 | ) | |||||||
|
2011
|
3.48%
|
300 |
million
|
(4,211 | ) | |||||||
|
2012
|
3.40%
|
300 |
million
|
(1,969 | ) | |||||||
|
2013
|
3.39%
|
300 |
million
|
(962 | ) | |||||||
|
1/1
- 4/24/2014
|
3.39%
|
300 |
million
|
(101 | ) | |||||||
| $ | (19,851 | ) | ||||||||||
If
interest rates decline below the rate hedged, we would incur more interest
expense than in the absence of hedges.
See Note
5 and Note 9 for additional disclosures related to derivative instruments and
hedging activities.
Note
9—Fair Value Measurements
We
classify our assets and liabilities measured at fair value on a recurring and
nonrecurring basis using a three-tier fair value hierarchy, which prioritizes
the inputs used in measuring fair value. These tiers include: Level 1, defined
as observable inputs such as quoted prices in active markets; Level 2, defined
as inputs other than quoted prices in active markets that are either directly or
indirectly observable; and Level 3, defined as unobservable inputs in which
little or no market data exists, therefore requiring us to develop our own
assumptions.
The
following table sets forth, by level within the fair value hierarchy, our
financial assets and liabilities measured at fair value on a recurring basis as
of March 31, 2009. These financial assets and liabilities are classified in
their entirety based on the lowest level of input that is significant to the
fair value measurement. Our assessment of the significance of a particular input
to the fair value measurement requires judgment, and may affect the valuation of
the fair value assets and liabilities and their placement within the fair value
hierarchy levels.
|
Total
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
|
(In
thousands)
|
||||||||||||||||
|
Assets
from commodity derivative contracts
|
$ | 154,135 | $ | - | $ | 45,829 | $ | 108,306 | ||||||||
|
Total
assets
|
$ | 154,135 | $ | - | $ | 45,829 | $ | 108,306 | ||||||||
|
Liabilities
from commodity derivative contracts
|
$ | 8,658 | $ | - | $ | 8,658 | $ | - | ||||||||
|
Liabilities
from interest rate derivatives
|
19,851 | - | 19,851 | - | ||||||||||||
|
Total
liabilities
|
$ | 28,509 | $ | - | $ | 28,509 | $ | - | ||||||||
The
following table sets forth a reconciliation of the changes in the fair value of
our financial instruments classified as Level 3 in the fair value
hierarchy:
|
Commodity
Derivative Contracts
|
||||
|
(In
thousands)
|
||||
|
Balance,
December 31, 2008
|
$ | 123,304 | ||
|
Unrealized
losses included in OCI
|
(31,710 | ) | ||
|
Settlements
|
16,712 | |||
|
Balance,
March 31, 2009
|
$ | 108,306 | ||
No
unrealized gains or losses relating to assets and liabilities still held as of
March 31, 2009 were included in our consolidated statement of
operations.
Our
nonfinancial assets and liabilities measured at fair value on a nonrecurring
basis during the three months ended March 31, 2009 were not
significant.
Note
10—Commitments and Contingencies
Environmental
For
environmental matters, we record liabilities when remedial efforts are probable
and the costs are reasonably estimated in accordance with the American Institute
of Certified Public Accountants Statement of Position 96-1, “Environmental Remediation
Liabilities.” Environmental reserves do not reflect management’s
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.
Our
environmental liability, primarily for ground water assessment and remediation,
was less than $0.1 million as of March 31,
2009.
Legal
Proceeding
On
December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District
Court of Harris County, Texas against several defendants, including Targa
Resources, Inc. and three other Targa entities and private equity funds
affiliated with Warburg Pincus LLC, seeking damages from the defendants. The
suit alleges that Targa and private equity funds affiliated with Warburg Pincus
LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to have had to purchase the
SAOU System from ConocoPhillips and (ii) prospective business relations of WTG.
WTG claims the alleged interference resulted from Targa’s competition to
purchase the ConocoPhillips’ assets and its successful acquisition of those
assets in 2004. On October 2, 2007, the District Court granted defendants’
motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider
and for a new trial was overruled. On January 2, 2008, WTG filed a notice of
appeal. On February 3, 2009, the parties presented oral arguments and the appeal
is pending before the 14th Court of Appeals in Houston, Texas. We are
contesting WTG’s appeal, but can give no assurances regarding the outcome of the
proceeding. Targa has agreed to indemnify us for any claim or liability arising
out of the WTG suit.
Note
11—Accounting for Unit-Based Compensation
Our
general partner has adopted a long-term incentive plan (“the Plan”) for
employees, consultants and directors of the general partner and its
affiliates who perform services for us. The following table summarizes our
unit-based awards for the period indicated:
|
Three
|
||||
|
Months
Ended
|
||||
|
March 31, 2009
|
||||
|
Outstanding
at beginning of period
|
26,664 | |||
|
Granted
|
32,000 | |||
|
Vested
|
(10,672 | ) | ||
|
Forfeited
|
- | |||
|
Outstanding
at end of period
|
47,992 | |||
|
Weighted
average grant date fair value per share
|
$ | 12.88 | ||
Non-Employee
Director Grants
In
January 2009, our general partner awarded 32,000 of our restricted common
units (4,000 restricted common units to each of our non-management directors and
to each of Targa Resources Investments Inc.’s independent directors), which
will settle with the delivery of common units and are subject to three-year
vesting, without performance condition, and will vest ratably on each
anniversary of the grant date.
Compensation
expense on the restricted common units is recognized on a straight-line basis
over the vesting period. The fair value of an award of restricted common units
is measured on the grant date using the market price of a common unit on such
date. For each of the three months ended March 31, 2009 and 2008, we
recognized compensation expense of less than $0.1 million related to
equity-based awards. The remaining fair value of $0.4 million will be recognized
in expense over a weighted average period of approximately two
years.
Note
12—Sale of Bankruptcy Claim
In 2008,
we terminated certain derivative contracts with Lehman Brothers Commodity
Services, Inc. and filed a claim with the U.S. Bankruptcy Court. During the
first quarter, we sold our bankruptcy claim for $0.7 million and recognized the
proceeds as other income.
Item 2. Management’s Discussion and Analysis of
Financial Condition and Results of Operations
The following discussion analyzes
our financial condition and results of operations. You should read the following
discussion of our financial condition and results of operations in conjunction
with our consolidated financial statements and notes included elsewhere in this
Quarterly Report on Form 10-Q and in our consolidated financial statements
and notes thereto included in our Annual Report on Form 10-K for the year
ended December 31, 2008.
Overview
We are a
Delaware limited partnership formed by Targa to own, operate, acquire and
develop a diversified portfolio of complementary midstream energy assets. We are
engaged in the business of gathering, compressing, treating, processing and
selling natural gas and fractionating and selling NGLs and NGL products. We
currently operate in the Fort Worth Basin/Bend Arch in North Texas, the
Permian Basin in West Texas and in Southwest Louisiana.
We are
owned 98% by our limited partners and 2% by our general partner, Targa Resources
GP LLC, an indirect, wholly-owned subsidiary of Targa. Our limited partner
common units are publicly traded on The NASDAQ Stock Market LLC under the symbol
“NGLS.”
Our Operations
We sell
the majority of our processed natural gas, NGLs and high-pressure condensate to
Targa at market-based rates pursuant to natural gas, NGL and condensate purchase
agreements. Low-pressure condensate is sold to third parties. For a more
complete description of these arrangements, see “Item 13. Certain Relationships and Related
Transactions, and Director Independence” in our Annual
Report on Form 10-K for the year ended December 31,
2008.
Recently
Issued Pronouncements
See Note
2 of the Notes to Consolidated Financial Statements included in Item 1 of this
Quarterly Report.
Results of
Operations
The
following table and discussion relate to the three months ended March 31,
2009 and 2008 and is a summary of our results of operations for the
periods:
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions, except operating and price data)
|
||||||||
|
Revenues
|
$ | 239.0 | $ | 512.1 | ||||
|
Product
purchases
|
194.5 | 442.2 | ||||||
|
Operating
expenses
|
12.9 | 12.6 | ||||||
|
Depreciation
and amortization expense
|
18.9 | 18.2 | ||||||
|
General
and administrative expense
|
5.3 | 5.2 | ||||||
|
Income
from operations
|
7.4 | 33.9 | ||||||
|
Interest
expense, net
|
(9.9 | ) | (8.7 | ) | ||||
|
Deferred
income tax expense
|
(0.3 | ) | (0.3 | ) | ||||
|
Other
|
0.7 | - | ||||||
|
Net
income (loss)
|
$ | (2.1 | ) | $ | 24.9 | |||
|
Financial
and operating data:
|
||||||||
|
Financial
data:
|
||||||||
|
Operating
margin (1)
|
$ | 31.6 | $ | 57.3 | ||||
|
Adjusted
EBITDA (2)
|
45.5 | 52.6 | ||||||
|
Distributable
cash flow (3)
|
33.6 | 39.9 | ||||||
|
Operating
data:
|
||||||||
|
Gathering
throughput, MMcf/d (4)
|
||||||||
|
LOU
System
|
145.7 | 196.1 | ||||||
|
SAOU
System
|
101.7 | 97.8 | ||||||
|
North
Texas System
|
182.0 | 169.0 | ||||||
| 429.4 | 462.9 | |||||||
|
Plant
natural gas inlet, MMcf/d (5)(6)
|
||||||||
|
LOU
System
|
140.6 | 185.1 | ||||||
|
SAOU
System
|
91.4 | 90.4 | ||||||
|
North
Texas System
|
176.2 | 162.3 | ||||||
| 408.2 | 437.8 | |||||||
|
Gross
NGL production, MBbl/d
|
||||||||
|
LOU
System
|
7.6 | 10.9 | ||||||
|
SAOU
System
|
14.3 | 14.1 | ||||||
|
North
Texas System
|
19.7 | 19.4 | ||||||
| 41.6 | 44.4 | |||||||
|
Natural
gas sales, BBtu/d (6)
|
355.1 | 418.4 | ||||||
|
NGL
sales, MBbl/d
|
37.2 | 38.0 | ||||||
|
Condensate
sales, MBbl/d
|
3.4 | 3.7 | ||||||
|
Average
realized prices:
|
||||||||
|
Natural
Gas, $/MMBtu
|
4.56 | 8.02 | ||||||
|
NGL,
$/gal
|
0.55 | 1.21 | ||||||
|
Condensate,
$/ Bbl
|
41.13 | 85.59 | ||||||
|
|
(1)
|
Operating
margin is revenues less product purchases and operating expense. See
“Non-GAAP Financial Measures.”
|
|
|
(2)
|
Adjusted
EBITDA is net income before interest, income taxes, depreciation and
amortization and non-cash gain or loss related to derivative instruments.
See “Non-GAAP Financial
Measures.”
|
|
|
(3)
|
Distributable
Cash Flow is net income plus depreciation and amortization and deferred
taxes, adjusted for losses on mark-to-market derivative contracts, less
maintenance capital expenditures. See “Non-GAAP Financial
Measures.”
|
|
|
(4)
|
Gathering
throughput represents the volume of natural gas gathered and passed
through natural gas gathering pipelines from connections to producing
wells and central delivery points.
|
|
|
(5)
|
Plant
natural gas inlet represents the volume of natural gas passing through the
meter located at the inlet of a natural gas processing
plant.
|
|
|
(6)
|
Plant
inlet volumes include producer take-in-kind, while natural gas sales
exclude producer take-in-kind
volumes.
|
Three
Months Ended March 31, 2009 Compared to Three Months Ended March 31,
2008
Our
revenues decreased by $273.1 million, or 53%, to $239.0 million for
2009 compared to $512.1 million for 2008. The decrease is primarily due
to:
|
|
·
|
a
decrease attributable to commodity prices of $216.6 million,
comprising decreases in natural gas, NGL and condensate revenues of
$110.4 million, $92.6 million and $13.6
million;
|
|
|
·
|
a
decrease attributable to commodity sales volume of $57.0 million
comprising decreases in natural gas, NGL and condensate revenues of
$49.0 million, $5.4 million and $2.6 million;
and
|
|
|
·
|
an
increase in other revenues of $0.5 million, primarily from
miscellaneous processing
activities.
|
Our
average realized prices for natural gas decreased by $3.46 per MMBtu, or 43%, to
$4.56 per MMBtu for 2009 compared to $8.02 per MMBtu for 2008. Our average
realized price for NGLs decreased by $0.66 per gallon, or 55%, to $0.55 per
gallon for 2009 compared to $1.21 per gallon for 2008. Our average realized
price for condensate decreased by $44.46 per barrel, or 52%, to $41.13 per
barrel for 2009 compared to $85.59 per barrel for 2008.
Our
natural gas sales volumes decreased by 63.3 BBtu/d, or 15%, to 355.1 BBtu/d for
2009 compared to 418.4 BBtu/d for 2008. The decrease in natural gas sales is
primarily the result of a decrease in demand by our industrial customers and a
decrease in sales of gas purchased from affiliates for resale.
Our NGL
sales volumes decreased by 0.8 MBbl/d, or 2%, to 37.2 MBbl/d for 2009
compared to 38.0 MBbl/d for 2008 primarily due to lower plant
inlets.
Our
condensate sales volumes decreased by 0.3 MBbl/d, or 8%, to 3.4 MBbl/d
for 2009 compared to 3.7 MBbl/d for 2008.
Our
product purchases decreased by $247.7 million, or 56%, to
$194.5 million for 2009 compared to $442.2 million for 2008. The
decrease in product purchase cost reflects lower commodity pricing and purchases
of wellhead volumes.
Our
operating expenses increased by $0.3 million, or 2%, to $12.9 million
for 2009 compared to $12.6 million for 2008. The increase in operating
expenses was primarily the result of an increase in compensation and benefit
costs and utility expenses.
Our
general and administrative expenses increased by $0.1 million, or 2%, to
$5.3 million for 2009 compared to $5.2 million for 2008. For
additional information regarding our allocation of general and administrative
costs, see “Item 13. Certain Relationships and Related
Transactions, and Director Independence — Omnibus Agreement” in
our Annual Report on Form 10-K for the year ended December 31, 2008.
Liquidity and Capital
Resources
Our
ability to finance our operations, including to fund capital expenditures
and acquisitions, to meet our indebtedness obligations, to refinance our
indebtedness or to meet our collateral requirements depends on our ability to
generate cash in the future. Our ability to generate cash is subject to a number
of factors, some of which are beyond our control, including weather, commodity
prices, particularly for natural gas and NGLs, and our ongoing efforts to manage
operating costs and maintenance capital expenditures. See “Item 1A. Risk
Factors” in this Quarterly Report and our Annual Report on Form 10-K for the
year ended December 31, 2008.
Our main
sources of liquidity and capital resources are internally generated cash flow
from operations, a senior secured credit facility with both uncommitted and
committed availability and access to both the debt and equity capital markets.
The credit markets are undergoing significant volatility. Many financial
institutions have liquidity concerns, prompting government intervention to
mitigate pressure on the credit markets. Our exposure to the current credit
crisis includes our revolving credit facility, cash investments and counterparty
performance risks. Continued volatility in the capital markets may increase
costs associated with issuing debt instruments due to increased spreads over
relevant interest rate benchmarks and affect our ability to access those
markets.
Current
market conditions also elevate the concern over counterparty risks related to
our commodity derivative contracts and trade credit. We have substantially all
of our commodity derivatives with major financial institutions. Should any of
these financial counterparties not perform, we may not realize the benefit of
some of our hedges under lower commodity prices which could have a materially
adverse effect on our operations. We sell a significant portion of our natural
gas and condensate to a variety of purchasers. Non-performance by a trade
creditor could result in losses.
Crude oil
and natural gas prices are also volatile and in the case of natural gas have
declined significantly during the quarter, continuing downward since the end of
the quarter. In a continuing effort to reduce the volatility of our cash flows,
we have periodically entered into commodity derivative contracts for a portion
of our estimated equity volumes through 2013 (see Note 8 of the Notes to
Consolidated Financial Statements included in Item 1 of this Quarterly
Report).The current market conditions may also impact our ability to enter into
future commodity derivative contracts. In the event of a global recession,
commodity prices may stay depressed or decrease further thereby causing a
prolonged downturn, which could reduce our operating margins and cash flow from
operations.
At this
point, we do not believe our liquidity has been materially affected by the
current credit crisis and we do not expect our liquidity to be materially
impacted in the near future. We will continue to monitor our liquidity and the
capital markets. Additionally, we will continue to monitor events and
circumstances surrounding each of our lenders under our senior secured credit
facility. To date, other than a default by an affiliate of Lehman Brothers
(“Lehman”) on a borrowing request in October 2008, we have not experienced any
material disruptions in our ability to access our senior secured credit
facility. However, we cannot predict with any certainty the impact to us of
any further disruptions in the credit environment. See “Item 1A. Risk
Factors” in this Quarterly Report and our Annual Report on Form 10-K for
the year ended December 31, 2008.
Historically,
our cash generated from operations has been sufficient to finance our operating
expenditures and fund most of our maintenance and expansion capital
expenditures, with remaining amounts being distributed to our
unitholders.
We
believe that cash generated from these sources will be sufficient to meet our
short-term working capital requirements, much of our long-term capital
expenditure requirements and our minimum quarterly cash distributions for at
least the next year.
We intend
to make cash distributions to our unitholders and our general partner at least
at the minimum quarterly distribution rate of $0.3375 per common unit per
quarter ($1.35 per common unit on an annualized basis). Due to our cash
distribution policy, we expect that we will distribute to our unitholders most
of the cash generated by our operations. As a result, we expect that we will
rely upon external financing sources, including other debt and common unit
issuances, to fund our acquisition and expansion capital expenditures. See
Note 7 of the Notes to Consolidated Financial Statements included in Item 1
of this Quarterly Report.
Working
Capital. Working capital is the amount by which current assets
exceed current liabilities. Our working capital requirements are primarily
driven by changes in accounts receivable and accounts payable. These changes are
impacted by changes in the prices of commodities that we buy and sell. In
general, our working capital requirements increase in periods of rising
commodity prices and decrease in periods of declining commodity prices. However,
our working capital needs do not necessarily change at the same rate as
commodity prices because both accounts receivable and accounts payable are
impacted by the same commodity prices. In addition, the timing of payments
received from our customers or paid to our suppliers can also cause fluctuations
in working capital because we settle with most of our larger suppliers and
customers on a monthly basis and often near the end of the month. We expect that
our future working capital requirements will be impacted by these same
factors.
As of
March 31, 2009, we had working capital of $149.6 million, including a
net short-term asset for commodity and interest rate derivatives of
$78.5 million. We record the fair value of all derivative instruments on
the balance sheet. Our hedge agreements provide for monthly settlement
(quarterly for interest rate swaps) based on the differential between the
agreement price and published commodity price and interest rate indexes. Cash
received from physical sales of commodities and cash paid for interest will be
based on actual market prices and interest rates and will generally offset any
gains or losses realized on the derivative instruments. Our derivative contracts
do not have margin requirements or collateral provisions that could require
funding prior to the scheduled cash settlement date.
Excluding
derivatives, our working capital surplus was $71.1 million as of
March 31, 2009. See “Item 3. Quantitative and Qualitative Disclosures
about Market Risk” in this Quarterly Report and our Annual Report on
Form 10-K for the year ended December 31, 2008.
Contractual
Obligations. Except for changes in the ordinary course of our
business, our contractual obligations have not changed materially from
those reported in our Annual Report on Form 10-K for the year ended
December 31, 2008.
Available
Credit. As of March 31, 2009, we had approximately
$337 million in capacity available under our senior secured credit
facility, after giving effect to $487.8 million in outstanding borrowings,
the issuance of $15.0 million of letters of credit and the effect of the
Lehman default.
Cash Flow. Net
cash provided by or used in operating activities, investing activities and
financing activities for the three months ended March 31, 2009 and 2008
were as follows:
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Net
cash provided by (used in):
|
||||||||
|
Operating
activities
|
$ | 22.0 | $ | 52.8 | ||||
|
Investing
activities
|
(15.1 | ) | (11.5 | ) | ||||
|
Financing
activities
|
(26.4 | ) | (68.8 | ) | ||||
Net cash
provided by operating activities decreased by $30.8 million, or 58%, for
the three months ended March 31, 2009 compared to the three months ended
March 31, 2008, primarily attributable to changes in working capital during
the respective periods.
Net cash
used in investing activities for the three months ended March 31,
2009 increased $3.6 million, or 31%, compared to the three months
ended March 31, 2008 due primarily to an increase in cash payments for
additions to property, plant and equipment.
Net cash
used in financing activities decreased $42.4 million, or 62%, for the three
months ended March 31, 2009 compared to the three months ended
March 31, 2008, due to repayments on the credit facility in 2008, partially
offset by increased distributions in 2009.
Capital
Requirements. The midstream energy business can be capital
intensive, requiring significant investment to maintain and upgrade existing
operations. A portion of the cost of constructing new gathering lines to connect
to our gathering system is paid for by the natural gas producer. However, we
expect to continue to incur significant expenditures through the remainder of
2009 related to the expansion of our natural gas gathering and processing
infrastructure.
We
categorize our capital expenditures as either: (i) maintenance expenditures
or (ii) expansion expenditures. Maintenance expenditures are those
expenditures that are necessary to maintain the service capability of our
existing assets including the replacement of system components and equipment
which is worn, obsolete or completing its useful life, the addition of new
sources of natural gas supply to our systems to replace natural gas production
declines and expenditures to remain in compliance with environmental laws and
regulations. Expansion expenditures improve the service capability of the
existing assets, extend asset useful lives, increase capacities from existing
levels, add capabilities, reduce costs or enhance revenues.
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Capital
expenditures:
|
||||||||
|
Expansion
|
$ | 5.1 | $ | 3.0 | ||||
|
Maintenance
|
2.6 | 4.4 | ||||||
| $ | 7.7 | $ | 7.4 | |||||
Additions
to property, plant and equipment were $7.7 million for the first quarter of
2009. Cash flows from investing activities reflects additions of $15.1 million
for the same period. The difference is the result of settled accruals, which
decreased by $7.4 million during the period.
We
estimate that our total capital expenditures for 2009 will be approximately
$55 million. Given our objective of growth through acquisitions, expansions
of existing assets and other internal growth projects, we anticipate that we
will invest significant amounts of capital to grow and acquire assets. Expansion
capital expenditures may vary significantly based on investment
opportunities.
We expect
to fund future capital expenditures with funds generated from our operations,
borrowings under our senior secured credit facility, the issuance of additional
partnership units and debt offerings.
Non-GAAP Financial
Measures
For a
complete discussion of the measures that management uses to evaluate our
operations, see “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations — How We Evaluate our Operations” in
our Annual Report on Form 10-K for the year ended December 31, 2008.
The following tables reconcile the non-GAAP financial measures used by
management to their most directly comparable GAAP measures for the three months
ended March 31, 2009 and 2008:
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Reconciliation
of net cash provided by operating activities to Adjusted
EBITDA:
|
||||||||
|
Net
cash provided by operating activities
|
$ | 22.0 | $ | 52.8 | ||||
|
Interest
expense, net (1)
|
9.3 | 8.3 | ||||||
|
Changes
in operating working capital which used (provided) cash:
|
||||||||
|
Accounts
receivable and other assets
|
(6.3 | ) | 5.4 | |||||
|
Accounts
payable and other liabilities
|
20.5 | (13.9 | ) | |||||
|
Adjusted
EBITDA
|
$ | 45.5 | $ | 52.6 | ||||
_____________
(1) Net
of amortization of debt issuance costs of $0.6 million and $0.4 million for the
three months ended March 31, 2009 and 2008.
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Reconciliation
of net income (loss) to Adjusted EBITDA:
|
||||||||
|
Net
income (loss)
|
$ | (2.1 | ) | $ | 24.9 | |||
|
Add:
|
||||||||
|
Interest
expense, net
|
9.9 | 8.7 | ||||||
|
Deferred
income tax expense
|
0.3 | 0.3 | ||||||
|
Depreciation
and amortization expense
|
18.9 | 18.2 | ||||||
|
Non-cash
loss related to derivatives
|
18.5 | 0.5 | ||||||
|
Adjusted
EBITDA
|
$ | 45.5 | $ | 52.6 | ||||
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Reconciliation
of net income (loss) to operating margin:
|
||||||||
|
Net
income (loss)
|
$ | (2.1 | ) | $ | 24.9 | |||
|
Add:
|
||||||||
|
Depreciation
and amortization expense
|
18.9 | 18.2 | ||||||
|
Deferred
income tax expense
|
0.3 | 0.3 | ||||||
|
Interest
expense, net
|
9.9 | 8.7 | ||||||
|
General
and administrative and other expense
|
4.6 | 5.2 | ||||||
|
Operating
margin
|
$ | 31.6 | $ | 57.3 | ||||
|
Three Months Ended March
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Reconciliation
of net income (loss)
|
(In
millions)
|
|||||||
|
to
"distributable cash flow":
|
||||||||
|
Net
income (loss)
|
$ | (2.1 | ) | $ | 24.9 | |||
|
Depreciation
and amortization expense
|
18.9 | 18.2 | ||||||
|
Deferred
income tax expense
|
0.3 | 0.3 | ||||||
|
Amortization
in interest expense
|
0.6 | 0.4 | ||||||
|
Non-cash
loss related to derivatives
|
18.5 | 0.5 | ||||||
|
Maintenance
capital expenditures
|
(2.6 | ) | (4.4 | ) | ||||
|
Distributable
cash flow
|
$ | 33.6 | $ | 39.9 | ||||
Item
3. Quantitative and Qualitative Disclosures about
Market Risk
For an
in-depth discussion of market risks, see “Item 7A. Quantitative and
Qualitative Disclosures about Market Risk” in our Annual Report on
Form 10-K for the year ended December 31, 2008.
Our
principal market risks are our exposure to changes in commodity prices,
particularly to the prices of natural gas and NGLs (including the impact of
reduced commodity prices on oil and gas drilling levels), changes in interest
rates, as well as nonperformance risk by our derivative counterparties. We do
not use risk sensitive instruments for trading purposes.
Commodity Price Risk. A majority of our revenues
are derived from percent-of-proceeds contracts under which we receive a portion
of the natural gas and/or NGLs or equity volumes, as payment for services. The
prices of natural gas and NGLs are subject to fluctuations in response to
changes in supply, demand, market uncertainty and a variety of additional
factors beyond our control. We monitor these risks and enter into commodity
derivative transactions designed to mitigate the impact of commodity price
fluctuations on our business. Cash flows from a derivative instrument designated
as hedge are classified in the same category as the cash flows from the item
being hedged. For an in-depth discussion of our hedging strategies, see
Item “7A. Quantitative and Qualitative Disclosures about Market
Risk—Commodity Price Risk” in our Annual Report on Form 10-K for the year
ended December 31, 2008.
Our
payment obligations in connection with substantially all of these hedging
transactions, and any additional credit exposure due to a rise in natural gas
and NGL prices relative to the fixed prices set forth in the hedges, are secured
by a first priority lien in the collateral securing our senior secured
indebtedness that ranks equal in right of payment with liens granted in favor of
our senior secured lenders. As long as this first priority lien is in effect, we
expect to have no obligation to post cash, letters of credit or other additional
collateral to secure these hedges at any time even if our counterparty’s
exposure to our credit increases over the term of the hedge as a result of
higher commodity prices or because there has been a change in our
creditworthiness. A purchased put (or floor) transaction does not create credit
exposure to us for our counterparties.
We have
entered into hedging arrangements for a portion of our forecasted equity
volumes. Floor volumes and floor pricing are based solely on purchased puts (or
floors). As of March 31, 2009, we had the following open commodity
derivative positions which will settle during 2009 through 2013 (except as
indicated otherwise, the 2009 volumes reflect daily volumes for the period from
April 1, 2009 through December 31, 2009):
Natural
Gas
|
Instrument
|
Avg.
Price
|
MMBtu per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/MMBtu
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
IF-HSC
|
7.39 | 1,966 | - | - | - | - | $ | 1,743 | ||||||||||||||||||||
| 1,966 | - | - | - | - | |||||||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
9.18 | 6,256 | - | - | - | - | 9,410 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
8.86 | - | 5,685 | - | - | - | 7,089 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
7.34 | - | - | 2,750 | - | - | 1,286 | |||||||||||||||||||||
|
Swap
|
IF-NGPL
MC
|
7.18 | - | - | - | 2,750 | - | 789 | |||||||||||||||||||||
| 6,256 | 5,685 | 2,750 | 2,750 | - | |||||||||||||||||||||||||
|
Swap
|
IF-Waha
|
7.79 | 9,936 | - | - | - | - | 10,910 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.53 | - | 11,709 | - | - | - | 4,715 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.10 | - | - | 11,250 | - | - | 145 | |||||||||||||||||||||
|
Swap
|
IF-Waha
|
6.30 | - | - | - | 7,250 | - | (326 | ) | ||||||||||||||||||||
|
Swap
|
IF-Waha
|
5.59 | - | - | - | - | 4,000 | (1,478 | ) | ||||||||||||||||||||
| 9,936 | 11,709 | 11,250 | 7,250 | 4,000 | |||||||||||||||||||||||||
|
Total
Swaps
|
18,158 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
|
Floor
|
IF-NGPL
MC
|
6.55 | 850 | - | - | - | - | 710 | |||||||||||||||||||||
| 850 | - | - | - | - | |||||||||||||||||||||||||
|
Floor
|
IF-Waha
|
6.55 | 565 | - | - | - | - | 459 | |||||||||||||||||||||
| 565 | - | - | - | - | |||||||||||||||||||||||||
|
Total
Floors
|
1,415 | - | - | - | - | ||||||||||||||||||||||||
|
Total
Sales
|
19,573 | 17,394 | 14,000 | 10,000 | 4,000 | ||||||||||||||||||||||||
| $ | 35,452 | ||||||||||||||||||||||||||||
NGLs
|
Instrument
|
Avg.
Price
|
Barrels per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/gal
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
OPIS-MB
|
1.32 | 6,248 | - | - | - | - | $ | 48,006 | ||||||||||||||||||||
|
Swap
|
OPIS-MB
|
1.27 | - | 4,809 | - | - | - | 40,659 | |||||||||||||||||||||
|
Swap
|
OPIS-MB
|
0.92 | - | - | 3,400 | - | - | 9,420 | |||||||||||||||||||||
|
Swap
|
OPIS-MB
|
0.92 | - | - | - | 2,700 | - | 6,197 | |||||||||||||||||||||
|
Total
Swaps
|
6,248 | 4,809 | 3,400 | 2,700 | - | ||||||||||||||||||||||||
|
Floor
|
OPIS-MB
|
1.44 | - | - | 199 | - | - | 1,935 | |||||||||||||||||||||
|
Floor
|
OPIS-MB
|
1.43 | - | - | - | 231 | - | 2,089 | |||||||||||||||||||||
|
Total
Floors
|
- | - | 199 | 231 | - | ||||||||||||||||||||||||
|
Total
Sales
|
6,248 | 4,809 | 3,599 | 2,931 | - | ||||||||||||||||||||||||
| $ | 108,306 | ||||||||||||||||||||||||||||
Condensate
|
Instrument
|
Avg.
Price
|
Barrels per day
|
|||||||||||||||||||||||||||
|
Type
|
Index
|
$/Bbl
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
|||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||||||||
|
Sales
|
|||||||||||||||||||||||||||||
|
Swap
|
NY-WTI
|
69.00 | 322 | - | - | - | - | $ | 1,153 | ||||||||||||||||||||
|
Swap
|
NY-WTI
|
68.10 | - | 301 | - | - | - | 518 | |||||||||||||||||||||
|
Total
Swaps
|
322 | 301 | - | - | - | ||||||||||||||||||||||||
|
Floor
|
NY-WTI
|
60.00 | 50 | - | - | - | - | 117 | |||||||||||||||||||||
|
Total
Floors
|
50 | - | - | - | - | ||||||||||||||||||||||||
|
Total
Sales
|
372 | 301 | - | - | - | ||||||||||||||||||||||||
| $ | 1,788 | ||||||||||||||||||||||||||||
Interest Rate Risk. We are exposed to changes
in interest rates, primarily as a result of our variable rate debt under our
credit facility. To the extent that interest rates increase, our interest
expense for our revolving debt will also increase. As of March 31, 2009, we had
borrowings of approximately $487.8 million outstanding under our revolving
credit facility. In an effort to reduce the variability of our cash flows, we
have entered into several interest rate swap and interest rate basis swap
agreements. Under these agreements, which are accounted for as cash flow hedges,
the base interest rate on the specified notional amount of our variable rate
debt is effectively fixed for the term of each agreement and ineffectiveness is
required to be measured each reporting period. The fair values of the
interest rate swap agreements, which are adjusted regularly, have been
aggregated by counterparty for classification in our consolidated balance
sheets. Accordingly, unrealized gains and losses relating to the interest rate
swaps are recorded in OCI until the interest expense on the related debt is
recognized in earnings.
As of
March 31, 2009, we had $487.8 million outstanding under our senior
secured credit facility, with interest accruing at a base rate plus an
applicable margin. In order to mitigate the risk of changes in cash flows
attributable to changes in market interest rates we have entered into interest
rate swaps and basis swaps that effectively fix the base rate on
$300 million in borrowings as shown below:
|
Period
|
Fixed Rate
|
Notional Amount
|
Fair Value
|
||||||||||
|
(In
thousands)
|
|||||||||||||
|
Remainder
of 2009
|
3.68
|
% | $ | 300 |
million
|
$ | (5,896 | ) | |||||
|
2010
|
3.67 | % | 300 |
million
|
(6,712 | ) | |||||||
|
2011
|
3.48 | % | 300 |
million
|
(4,211 | ) | |||||||
|
2012
|
3.40 | % | 300 |
million
|
(1,969 | ) | |||||||
|
2013
|
3.39 | % | 300 |
million
|
(962 | ) | |||||||
|
1/1
- 4/24/2014
|
3.39 | % | 300 |
million
|
(101 | ) | |||||||
| $ | (19,851 | ) | |||||||||||
We have
designated all interest rate swaps and interest rate basis swaps as cash flow
hedges. Accordingly, unrealized gains and losses relating to the swaps are
deferred in OCI until interest expense on the related debt is recognized in
earnings. A hypothetical increase of 100 basis points in the underlying
interest rate, after taking into account our interest rate swaps and interest
rate basis swaps, would increase our annual interest expense by
$1.9 million.
Credit Risk. We are subject
to risk of losses resulting from nonpayment or nonperformance by our customers
and derivative counterparties.
We
monitor the creditworthiness of customers to whom we grant credit and establish
credit limits in accordance with our credit policy. A portion of our revenues
are derived from companies in the domestic natural gas, NGL and petrochemical
industries. This concentration could impact our overall exposure to credit risk
since these customers may be impacted by similar economic or other conditions.
To help reduce our credit risk, we evaluate our counterparties’ financial
condition and, where appropriate, negotiate netting agreements. We generally do
not require collateral for our accounts receivable; however, in certain
circumstances we will call for prepayment, require automatic debit agreements or
obtain collateral to minimize our potential exposure to defaults.
Our
credit exposure related to commodity derivative instruments is represented by
the fair value of contracts with a net positive fair value to us at the
reporting date. At such times, these outstanding instruments expose us to credit
loss in the event of nonperformance by the counterparties to the agreements.
Should the creditworthiness of one or more of our counterparties decline, our
ability to mitigate nonperformance risk is limited to a counterparty agreeing to
either a voluntary termination and subsequent cash settlement or a novation of
the derivative contract to a third party. In the event of a counterparty
default, we may sustain a loss and our cash receipts could be negatively
impacted.
As of
March 31, 2009, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank
accounted for 68%, 17% and 15% of our counterparty credit exposure related to
commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank
are major financial institutions, each possessing investment grade credit
ratings based upon minimum credit ratings assigned by Standard & Poor’s
Ratings Services, a division of the McGraw-Hill Companies, Inc.
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.
There has
been no change in our internal control over financial reporting during the three
months ended March 31, 2009 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
Item
1. Legal Proceedings
The
information required for this item is provided in Note 10—Commitments and
Contingencies, under the heading “Legal Proceeding” included in the Notes to
Consolidated Financial Statements included under Part I, Item 1, which
is incorporated by reference into this item.
Item
1A. Risk
Factors
For an
in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our
Annual Report on Form 10-K for the year ended December 31, 2008. 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:
A
recent determination that emissions of carbon dioxide and other “greenhouse
gases” present an endangerment to public health could result in regulatory
initiatives that increase our costs of doing business and the costs of our
services.
On April
17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of
its finding and determination that emissions of carbon dioxide, methane, and
other “greenhouse gases” (“GHGs”) presented an endangerment to human health and
the environment, because emissions of such gases contribute to warming of the
earth’s atmosphere. The finding and determination allows the EPA to
begin regulating GHG emissions under existing provisions of the Clean Air
Act. Although the EPA may take several years to adopt and impose
regulations limiting GHG emissions, any limitation on GHG emissions from our
natural gas–fired compressor stations and processing facilities or from the
combustion of natural gas or natural gas liquids that we produce could increase
our costs of doing business and/or increase the cost and reduce demand for our
services. In addition, the U.S. Congress and various states are
currently considering legislation that may impose national or regional caps on
GHG emissions and may require major sources of GHG emissions to purchase
“allowances” that would permit such sources to continue to emit
GHGs. Such legislation could require us to obtain allowances to
offset emissions of GHGs that result from the combustion of natural gas or
natural gas liquids we produce. As an alternative to a “cap and
trade” program, it is possible that Congress or individual states could
implement carbon tax programs. Any such regulatory initiatives
adopted by EPA or legislation adopted by Congress or the states could increase
our costs of doing business and/or increase the cost and reduce demand for our
services.
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.
Item
6. Exhibits
Exhibit Index
|
Exhibit Number
|
Description
|
|
3.1
|
Certificate
of Limited Partnership of Targa Resources Partners LP (incorporated by
reference to Exhibit 3.2 to Targa Resources Partners LP’s
Registration Statement on Form S-1 filed November 16, 2006
(File No. 333-138747)).
|
|
3.2
|
Certificate
of Formation of Targa Resources GP LLC (incorporated by reference to
Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement
on Form S-1/A filed January 19, 2007 (File
No. 333-138747)).
|
|
3.3
|
Agreement
of Limited Partnership of Targa Resources Partners LP (incorporated by
reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual
Report on Form 10-K filed April 2, 2007 (File
No. 001-33303)).
|
|
3.4
|
First
Amended and Restated Agreement of Limited Partnership of Targa Resources
Partners LP (incorporated by reference to Exhibit 3.1 to Targa
Resources Partners LP’s current report on Form 8-K filed
February 16, 2007 (File No. 001-33303)).
|
|
3.5
|
Amendment
No. 1, dated May 13, 2008, to the First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.5 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File
No. 001-33303)).
|
|
3.6
|
Limited
Liability Company Agreement of Targa Resources GP LLC (incorporated by
reference to Exhibit 3.4 to Targa Resources Partners LP’s
Registration Statement on Form S-1/A filed January 19, 2007
(File No. 333-138747)).
|
|
4.1
|
Specimen
Unit Certificate representing common units (incorporated by reference to
Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K
filed April 2, 2007 (File No. 001-33303)).
|
|
4.2
|
Indenture
dated June 18, 2008, among Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the Guarantors named therein and U.S. Bank
National Association (incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008
(File No. 001-33303)).
|
|
4.3
|
Registration
Rights Agreement dated June 18, 2008, among Targa Resources Partners LP,
Targa Resources Partners Finance Corporation, the Guarantors named therein
and the initial purchasers named therein (incorporated by reference to
Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K
filed June 18, 2008 (File No. 001-33303)).
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1*
|
|
|
32.2*
|
|
|
* Filed
herewith
|
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: May
8, 2009
Exhibit Index
|
Exhibit Number
|
Description
|
|
3.1
|
Certificate
of Limited Partnership of Targa Resources Partners LP (incorporated by
reference to Exhibit 3.2 to Targa Resources Partners LP’s
Registration Statement on Form S-1 filed November 16, 2006
(File No. 333-138747)).
|
|
3.2
|
Certificate
of Formation of Targa Resources GP LLC (incorporated by reference to
Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement
on Form S-1/A filed January 19, 2007 (File
No. 333-138747)).
|
|
3.3
|
Agreement
of Limited Partnership of Targa Resources Partners LP (incorporated by
reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual
Report on Form 10-K filed April 2, 2007 (File
No. 001-33303)).
|
|
3.4
|
First
Amended and Restated Agreement of Limited Partnership of Targa Resources
Partners LP (incorporated by reference to Exhibit 3.1 to Targa
Resources Partners LP’s current report on Form 8-K filed
February 16, 2007 (File No. 001-33303)).
|
|
3.5
|
Amendment
No. 1, dated May 13, 2008, to the First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.5 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File
No. 001-33303)).
|
|
3.6
|
Limited
Liability Company Agreement of Targa Resources GP LLC (incorporated by
reference to Exhibit 3.4 to Targa Resources Partners LP’s
Registration Statement on Form S-1/A filed January 19, 2007
(File No. 333-138747)).
|
|
4.1
|
Specimen
Unit Certificate representing common units (incorporated by reference to
Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K
filed April 2, 2007 (File No. 001-33303)).
|
|
4.2
|
Indenture
dated June 18, 2008, among Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the Guarantors named therein and U.S. Bank
National Association (incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008
(File No. 001-33303)).
|
|
4.3
|
Registration
Rights Agreement dated June 18, 2008, among Targa Resources Partners LP,
Targa Resources Partners Finance Corporation, the Guarantors named therein
and the initial purchasers named therein (incorporated by reference to
Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K
filed June 18, 2008 (File No. 001-33303)).
|
|
31.1*
|
Certification
of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
31.2*
|
Certification
of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.
|
|
32.1*
|
Certification
of the Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
32.2*
|
Certification
of the Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
* Filed
herewith
|
37
CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT
TO RULE 13A-14(A)/15D-14(A) OF THE SECURITIES EXCHANGE ACT OF
1934
I, Rene
R. Joyce, certify that:
|
1.
|
I
have reviewed this Quarterly Report on Form 10-Q 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
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-(f) for the registrant and
have:
|
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
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 registrant’s 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 registrant’s internal control
over financial reporting.
|
Date: May
8, 2009
By: /s/ Rene
R. Joyce e
Name:
Rene R. Joyce
Title:
Chief Executive Officer of Targa Resources GP LLC,
the
general partner of Targa Resources Partners LP
(Principal
Executive Officer)
CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT
TO RULE 13A-14(A)/15D-14(A) OF THE SECURITIES EXCHANGE ACT OF
1934
I,
Jeffrey J. McParland, certify that:
|
1.
|
I
have reviewed this Quarterly Report on Form 10-Q 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
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-(f) for the registrant and
have:
|
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
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 registrant’s 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 registrant’s internal control
over financial reporting.
|
Date: May
8, 2009
By: /s/ Jeffrey
J. McParland .
Name:
Jeffrey J. McParland
Title:
Executive Vice President, Chief Financial Officer
of Targa
Resources GP LLC, the general partner of
Targa
Resources Partners LP
(Principal
Financial Officer)
CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT
TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
In
connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP
(the “Partnership”) for the three months ended March 31, 2009 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.
By: /s/ Rene
R. Joyce e
Name:
Rene R. Joyce
Title:
Chief Executive Officer of Targa Resources GP LLC,
the
general partner of
Targa
Resources Partners LP
Date: May
8, 2009
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.
CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT
TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
In
connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP
(the “Partnership”) for the three months ended March 31, 2009 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, Chief Financial Officer
of Targa
Resources GP LLC, the general partner of
Targa
Resources Partners LP
Date: May
8, 2009
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.