Attached files
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8-K - FORM 8-K AS OF 09/30/09 - Targa Resources Partners LP | form_8k.htm |
Exhibit
99.1
As
generally used in the energy industry and in this report, the identified terms
have the following meanings:
Bbl
|
Barrels
|
Btu
|
British
thermal units, a measure of heating value
|
gal
|
Gallons
|
MMBtu
|
Million
British thermal units
|
NGL(s)
|
Natural
gas liquid(s)
|
Price
Index Definitions
|
|
IF-CGT
|
Inside
FERC Gas Market Report, Columbia Gulf Transmission,
Louisiana
|
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
|
1
TARGA
RESOURCES GP LLC
|
||||
CONSOLIDATED
BALANCE SHEET
|
||||
September 30, 2009
|
||||
(Unaudited)
|
||||
(In
thousands)
|
||||
ASSETS
|
||||
Current
assets:
|
||||
Cash
and cash equivalents
|
$ | 57,766 | ||
Receivables
from third parties
|
251,332 | |||
Inventory
|
42,251 | |||
Assets
from risk management activities
|
48,472 | |||
Other
current assets
|
509 | |||
Total
current assets
|
400,330 | |||
Property,
plant and equipment, at cost
|
2,083,138 | |||
Accumulated
depreciation
|
(392,752 | ) | ||
Property,
plant and equipment, net
|
1,690,386 | |||
Long-term
assets from risk management activities
|
18,860 | |||
Investment
in unconsolidated affiliate
|
17,811 | |||
Other
assets
|
20,931 | |||
Total
assets
|
$ | 2,148,318 | ||
LIABILITIES
AND EQUITY
|
||||
Current
liabilities:
|
||||
Accounts
payable to third parties
|
$ | 123,648 | ||
Accounts
payable to affiliates
|
84,549 | |||
Accrued
liabilities
|
83,730 | |||
Liabilities
from risk management activities
|
10,903 | |||
Total
current liabilities
|
302,830 | |||
Long-term
debt payable to third parties
|
939,424 | |||
Long-term
liabilities from risk management activities
|
15,645 | |||
Deferred
income taxes
|
3,559 | |||
Other
long-term liabilities
|
6,501 | |||
Commitments
and contingencies (Note 12)
|
||||
Equity:
|
||||
Member's
interest
|
9,804 | |||
Accumulated
other comprehensive income
|
187 | |||
Total
member's equity
|
9,991 | |||
Noncontrolling
interest
|
870,368 | |||
Total
equity
|
880,359 | |||
Total
liabilities and equity
|
$ | 2,148,318 | ||
See
notes to consolidated balance sheet
|
2
Targa
Resources GP LLC
Notes to
Consolidated Balance Sheet
(Unaudited)
Except
as noted within the context of each footnote disclosure, the dollar amounts
presented in the tabular data within these footnote disclosures are stated in
thousands of dollars.
Note
1—Organization and Operations
Targa
Resources GP LLC is a Delaware limited liability company formed in October 2006
to become the general partner of Targa Resources Partners LP. Our sole member is
Targa GP Inc., an indirect wholly-owned subsidiary of Targa Resources, Inc.
(“Targa”, or “Parent”). Our primary business purpose is to manage the affairs
and operations of Targa Resources Partners LP.
Unless
the context requires otherwise, references to “we,” “us,” or “our” are intended
to mean and include the business and operations of Targa Resources GP LLC, as
well as its consolidated subsidiaries, which include Targa Resources Partners LP
and its consolidated subsidiaries.
References
to “the Partnership” mean the business and operations of Targa Resources
Partners LP and its consolidated subsidiaries. The Partnership is a publicly
traded Delaware limited partnership, the registered common units of which are
listed on The NASDAQ Stock Market LLC under the ticker symbol “NGLS.” References
to “TRGP” mean Targa Resources GP LLC, individually as the general partner of
the Partnership, and not on a consolidated basis. TRGP has no independent
operations and no material assets outside of its interest in the
Partnership.
On
September 24, 2009, the Partnership acquired Targa’s interests in Targa
Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP
(collectively, the “Downstream Business”) in a transaction among entities under
common control. See Note 4.
This
unaudited consolidated balance sheet has been prepared in accordance with
accounting principles generally accepted in the United States of America
(“GAAP”) for interim financial information. Accordingly, it does not contain all
of the information and footnotes required by GAAP for complete financial
statements. The unaudited consolidated balance sheet as of September 30, 2009
includes all adjustments, both normal and recurring, which are, in the opinion
of management, necessary for the 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 balance sheet as transactions
between affiliates. See Note 14. This unaudited consolidated balance sheet
should be read in conjunction with our consolidated balance sheet and notes
thereto as of December 31, 2008.
Note 2—Basis of Presentation
We
consolidate the accounts of the Partnership and its subsidiaries into our
consolidated balance sheet. Notwithstanding this consolidation, we are not
liable for, and our assets are not available to satisfy, the obligations of the
Partnership and/or its subsidiaries.
We
categorize the midstream natural gas industry into, and describe our business
with the acquisition of the Downstream Business, in, two divisions: (i) Natural
Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and
Marketing. Our NGL Logistics and Marketing division consists of three segments:
(a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale
Marketing.
The
Natural Gas Gathering and Processing segment includes assets used in the
gathering of natural gas produced from oil and gas wells and processing this raw
natural gas into merchantable natural gas by extracting natural gas liquids and
removing impurities. These assets are located in North Texas, Louisiana and the
Permian Basin of West Texas. We are also party to natural gas processing
agreements with third party plants.
3
The
Logistics Assets segment is involved with gathering and storing mixed NGLs and
fractionating, storing, and transporting finished NGLs. These assets are
generally connected to and supplied, in part, by our Natural Gas Gathering and
Processing segment and are predominantly located in Mont Belvieu, Texas and
Western Louisiana.
The NGL
Distribution and Marketing segment markets our own natural gas liquids
production and purchased natural gas liquids products in selected United States
markets.
The
Wholesale Marketing segment includes our refinery services business and
wholesale propane marketing operations. In our refinery services business, we
provide liquefied petroleum gas balancing services, purchase natural gas liquids
products from refinery customers and sell natural gas liquids products to
various customers. Our wholesale propane marketing operations include the sale
of propane and related logistics services to multi-state retailers, independent
retailers and other end-users. Wholesale Marketing operates principally in the
United States, and has a small marketing presence in Canada.
In
preparing the accompanying unaudited consolidated balance sheet, we have
reviewed events that have occurred after September 30, 2009, up until
December 7, 2009, the date of issuance.
Note
3—Accounting Policies and Related Matters
Accounting
Policy Updates/Revisions
Exchanges. Exchanges are
movements of NGL products between parties to satisfy timing and logistical needs
of the parties. Volumes received and delivered under exchange agreements are
recorded as inventory. If the locations of receipt and delivery are in different
markets, a price differential may be billed or owed. The price differential is
recorded as either accounts receivable or accrued liabilities.
Impairment Testing for
Unconsolidated Investments. We evaluate equity method investments (which
include excess cost amounts attributable to tangible or intangible assets) for
impairment when events or changes in circumstances indicate that there is a loss
in value of the investment which is an other than temporary decline. Examples of
such events or changes in circumstances include continuing operating losses of
the investee or long-term negative changes in the investee’s industry. In the
event we determine that the decline in value of an investment is other than
temporary, we record a charge to earnings to adjust the carrying value to fair
value.
Noncontrolling Interest.
Noncontrolling interest represents third party ownership in the net assets of
our consolidated subsidiaries. For financial reporting purposes, the assets and
liabilities of our majority owned subsidiaries are consolidated with those of
our own, with any third party investor’s interest shown as noncontrolling
interest.
Property, Plant and
Equipment. Property, plant and equipment are stated at cost less
accumulated depreciation. Depreciation is computed using the straight-line
method over the estimated useful lives of the assets. The estimated service
lives of our functional asset groups are as follows:
Asset Group
|
Range of Years
|
|
Gas
gathering systems and processing systems
|
15
to 25
|
|
Fractionation,
terminalling and natural gas liquids storage facilities
|
5
to 25
|
|
Transportation
assets
|
10
to 25
|
|
Other
property and equipment
|
3
to 25
|
Accounting
Pronouncements Recently Adopted
On
July 1, 2009, the Financial Accounting Standards Board (“FASB”) issuance of
Statement of Financial Accounting Standards (“SFAS”) 168, “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles—a
replacement of FASB Statement No. 162.” established the FASB Accounting
Standards Codification (“Codification” or “ASC”) as the source of authoritative
GAAP recognized to be
4
applied
by nongovernmental entities. Rules and interpretive releases of the Securities
and Exchange Commission (“SEC”) under authority of federal securities laws are
also sources of authoritative GAAP for SEC registrants. The Codification is
effective for financial statements issued for interim and annual periods ending
after September 15, 2009. On the effective date, the Codification
superseded all then-existing non-SEC accounting and reporting standards. All
other non-grandfathered non-SEC accounting literature not included in the
Codification has become non-authoritative.
Following
the issuance of the Codification, FASB will not issue new standards in the form
of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts.
Instead, it will issue Accounting Standards Updates (“ASU”). FASB will not
consider ASUs as authoritative in their own right. They will serve only to
update the Codification, provide background information about the guidance, and
provide the basis for conclusions on the change(s) in the
Codification.
Fair
Value Measurements
In
September 2006, FASB issued SFAS 157 (ASC 820), “Fair Value Measurements.”
ASC 820 defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements. ASC 820 applies to
other accounting pronouncements that require or permit fair value measurements,
and accordingly, does not require any new fair value measurements. The guidance
in ASC 820 was initially effective as of January 1, 2008, but in February
2008, FASB delayed the effective date for applying the guidance 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 the guidance in ASC 820 as of
January 1, 2008 with respect to financial assets and liabilities within its
scope and the impact was not material to our consolidated balance sheet. 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 consolidated balance sheet. See
Note 11.
In April
2009, FASB issued FASB Staff Position ("FSP") FAS 157-4 (ASC 820), “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.” This update
to ASC 820 provides guidance for 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. We adopted the guidance as of June 30, 2009. There
have been no material consolidated balance sheet implications relating to our
adoption of the guidance.
In April
2009, FASB issued FSP FAS 107-1 and APB 28-1 (ASC 270), “Interim Disclosures about Fair Value
of Financial Instruments.” ASC 270 requires disclosures of fair value for
any financial instruments not currently reflected at fair value on the balance
sheet for all interim periods. We adopted the updated provisions of ASC 270 as
of June 30, 2009. There have been no material consolidated balance sheet
implications relating to this adoption. See Note 13.
Business
Combinations
In
December 2007, FASB issued SFAS 141R (ASC 805), “Business Combinations.” ASC
805 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. ASC 805 also establishes principles and requirements for how an
acquirer recognizes any noncontrolling interest in the acquiree and the goodwill
acquired in a business combination. ASC 805 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, ASC 805 may have a material impact on our consolidated
balance sheet. The nature and extent of any such impact will depend upon the
terms and conditions of the transaction.
In April
2009, FASB issued FSP FAS 141R-1 (ASC 805), “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination that Arise from
Contingencies.” This update to ASC 805 amends and
clarifies
5
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 update is effective for assets and liabilities
arising from contingencies in business combinations for which the acquisition
date is on or after January 1, 2009. There have been no material
consolidated balance sheet implications relating to the adoption of this
update.
Other
In
December 2007, FASB issued SFAS 160 (ASC 810), “Noncontrolling Interests in
Consolidated Financial Statements – an amendment of Accounting Research Bulletin
No. 51.” ASC 810 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. ASC 810 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 ASC 810 as of January 1, 2009. As a result,
additional disclosures have been provided.
In March
2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF
07-4 (ASC 260), “Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships.” ASC 260 provides guidance as to
how a master limited partnership (“MLP”) should allocate and present earnings
per unit using the two-class method when the MLP’s partnership agreement
contains incentive distribution rights. Under the two-class method, current
period earnings are allocated to the partners according to the distribution
formula for available cash set forth in the MLP’s partnership agreement. Our
adoption of this guidance on January 1, 2009, did not impact our
consolidated balance sheet.
In May
2009, FASB issued SFAS 165 (ASC 855), “Subsequent Events.” ASC 855
establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued. ASC 855 sets forth (1) the period after the
balance sheet date during which management of a reporting entity should evaluate
events or transactions that may occur for potential recognition or disclosure in
the financial statements, (2) the circumstances under which an entity
should recognize events or transactions occurring after the balance sheet date
in its financial statements, and (3) the disclosures that an entity should
make about events or transactions that occurred after the balance sheet date.
ASC 855 is effective for interim and annual periods ended after June 15,
2009 and should be applied prospectively. The adoption of ASC 855 did not have a
material impact to our consolidated balance sheet.
The FASB
has issued ASUs 2009-01 through 2009-15, which are either technical corrections
of the Codification and/or do not apply to us.
In June
2009, the SEC Staff issued Staff Accounting Bulletin (“SAB”) 112. SAB 112 amends
or rescinds portions of the SEC staff’s interpretive guidance included in the
Staff Accounting Bulletin Series in order to make the relevant interpretive
guidance consistent with ASC 805 and ASC 810. The adoption of SAB 112 did not
have a material impact on our consolidated balance sheet.
Note
4—Acquisition of Downstream Business
On
September 24, 2009, the Partnership acquired Targa’s interests in the
Downstream Business for $530 million. Consideration to Targa comprised
$397.5 million in cash and the issuance to Targa of 174,033 general partner
units and 8,527,615 common units. The form of the transaction reflected in our
consolidated financial statements was:
|
·
|
Targa
contributed the Downstream Business to the Partnership. On the
contribution date, the Downstream Business’ affiliate indebtedness payable
to Targa was $530 million. Prior to the contribution,
$287.3 million of the Downstream Business’ affiliated indebtedness
was settled through a capital contribution from
Targa.
|
6
|
·
|
The
Partnership repaid the affiliate indebtedness with:
(i) $397.5 million in cash; (ii) 174,033 in general partner
units with an agreed-upon value of $2.7 million; and
(iii) 8,527,615 in common units with an agreed-upon value of
$129.8 million.
|
The
Partnership’s acquisition of the Downstream Business has been accounted for as a
transfer of net assets between entities under common control.
Note
5—Property, Plant and Equipment
Property,
plant, and equipment and accumulated depreciation were as follows as of
September 30,
2009:
Natural
gas gathering systems
|
$ | 1,216,457 | ||
Processing
and fractionation facilities
|
403,038 | |||
Terminalling
and natural gas liquids storage facilities
|
236,978 | |||
Transportation
assets
|
150,658 | |||
Other
property, plant, and equipment
|
16,410 | |||
Land
|
49,770 | |||
Construction
in progress
|
9,827 | |||
2,083,138 | ||||
Accumulated
depreciation
|
(392,752 | ) | ||
$ | 1,690,386 |
Note
6—Investment in Unconsolidated Affiliate
As of
September 30, 2009 our unconsolidated investment consisted of a 38.75%
ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that
fractionates natural gas liquids on the Gulf Coast.
Our
equity in the net assets of GCF exceeded our acquisition date investment account
by $5.2 million.
Note
7—Long-Term Debt
Our
consolidated debt obligations consisted of the following as of
September 30, 2009:
Senior
secured revolving credit facility, variable rate, due February
2012
|
$ | 510,483 | ||
Senior
unsecured notes, 8¼% fixed rate, due July 2016
|
209,080 | |||
Senior
unsecured notes, 11¼% fixed
rate, due July 2017 (1)
|
219,861 | |||
Total
long-term debt
|
$ | 939,424 | ||
Letters
of credit issued
|
$ | 58,844 |
_____________
|
(1)
|
The
carrying amount of the notes includes $11.4 million of unamortized
original
|
issue
discount.
11¼%
Senior Unsecured Notes due July 15, 2017
On
July 6, 2009, the Partnership completed the private placement under Rule
144A and Regulation S of the Securities Act of 1933 of $250 million in
aggregate principal amount of 11¼% senior notes due 2017 (the
“11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face
amount, resulting in gross proceeds of $237.4 million. Proceeds from the
11¼% Notes were used to repay borrowings under the Partnership’s credit
facility.
7
The
11¼% Notes:
|
·
|
are
the Partnership’s unsecured senior
obligations;
|
|
·
|
rank
pari passu in
right of payment with the Partnership’s existing and future senior
indebtedness, including indebtedness under its credit
facility;
|
|
·
|
are
senior in right of payment to any of the Partnership’s future subordinated
indebtedness; and
|
|
·
|
are
unconditionally guaranteed by the
Partnership.
|
The
11¼% Notes are effectively subordinated to all secured indebtedness under
the Partnership’s credit agreement, which is secured by substantially all of the
Partnership’s assets, to the extent of the value of the collateral securing that
indebtedness.
Interest
on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable
semi-annually in arrears on January 15 and July 15, commencing on
January 15, 2010. Interest is computed on the basis of a 360-day year
comprising twelve 30-day months.
At any
time prior to July 15, 2012, the Partnership may on any one or more
occasions redeem up to 35% of the aggregate principal amount of the
11¼% Notes with the net cash proceeds of certain equity offerings by the
Partnership at a redemption price of 111.25% of the principal amount, plus
accrued and unpaid interest to the redemption date, provided that:
(1) at
least 65% of the aggregate principal amount of the 11¼% Notes (excluding
11¼% Notes held by the Partnership) remains outstanding immediately after
the occurrence of such redemption; and
(2) the
redemption occurs within 90 days of the date of the closing of such equity
offering.
Prior to
July 15, 2013, the Partnership may also redeem all or a part of the
11¼% Notes at a redemption price equal to 100% of the principal amount of
the 11¼% Notes redeemed plus the applicable premium as defined in the
indenture agreement as of, and accrued and unpaid interest to, the date of
redemption.
On or
after July 15, 2013, the Partnership may redeem all or a part of the
11¼% Notes at the redemption prices set forth below (expressed as
percentages of principal amount) plus accrued and unpaid interest on the
11¼% Notes redeemed, if redeemed during the twelve-month period beginning
on July 15 of each year indicated below:
Year
|
Percentage
|
|||
2013
|
105.625% | |||
2014
|
102.813% | |||
2015
and thereafter
|
100.000% |
The
11¼% Notes are subject to a registration rights agreement dated as of
July 6, 2009. Under the registration rights agreement, the Partnership is
required to file by July 9, 2010 a registration statement with respect to
any 11¼% Notes that are not freely transferable without volume restrictions
by holders of the 11¼% Notes that are not the Partnership’s affiliates. If
the Partnership fails to do so, additional interest will accrue on the principal
amount of the 11¼% Notes. The Partnership has determined that the payment
of additional interest is not probable. As a result, the Partnership has not
recorded a liability for any contingent obligation. Any subsequent accrual of a
liability under this registration rights agreement will be charged to earnings
as interest expense.
11¼%
Notes Repurchases
During
the third quarter of 2009, we repurchased $18.7 million face value ($17.8
million carrying value, net of issue discount) of our 1¼% Notes for $18.9
million plus accrued interest of $0.3 million.
8
Commitment
Increase
On
July 29, 2009, the Partnership executed a Commitment Increase Supplement
(the “Supplement”) to the Partnership’s existing senior secured credit facility.
The Supplement increased the commitments under the Partnership’s credit facility
by $127.5 million, bringing the total commitments to $977.5 million.
The Partnership may request additional commitments under its credit facility of
up to $22.5 million, which would increase the total commitments under the
credit facility to $1 billion.
Note
8—Accounting for Unit-Based Compensation
We have
adopted a long-term incentive plan (“the Plan”) for employees, consultants and
directors of us and our affiliates who perform services for the Partnership. In
general, restricted unit awards will settle with the delivery of common units
and are subject to three-years vesting, without a performance condition, and
will vest ratably on each anniversary of the grant date. The following table
summarizes information regarding our restricted unit awards for the nine months
ended September 30, 2009:
Outstanding
at beginning of period
|
26,664 | |||
Granted
|
32,000 | |||
Vested
|
(10,672 | ) | ||
Outstanding
at end of period
|
47,992 | |||
Weighted
average grant date fair value per share
|
$ | 12.88 |
Note
9—Equity
As of
September 30, 2009, member’s equity consisted of the capital account of
Targa GP Inc. and its proportionate share of the accumulated other comprehensive
income (“OCI”) of the Partnership.
Noncontrolling
interest represents third-party and Targa ownership interests in the
Partnership. As of September 30, 2009, the components of noncontrolling
interest were:
Non-affiliate
public unitholders
|
$ | 840,324 | ||
Targa
Resources, Inc.
|
20,870 | |||
Accumulated
other comprehensive income
|
9,174 | |||
Noncontrolling
interest
|
$ | 870,368 |
Unit
Offering
On
August 12, 2009, the Partnership completed a unit offering under its shelf
registration statement of 6.9 million common units representing limited
partner interests in the Partnership at a price of $15.70 per common unit. Net
proceeds generated by the offering were $105.3 million, after deducting
underwriting discounts, commissions and estimated offering expenses, and
including TRGP’s proportionate capital contribution of $2.2 million. The
proceeds were used to reduce borrowings of the Partnership’s credit facility by
$103.5 million.
Units
Issued Relating to Acquisition
On
September 24, 2009, the Partnership acquired Targa’s interests in the
Downstream Business for $530 million. Consideration to Targa comprised
$397.5 million in cash and the issuance to Targa of 174,033 general partner
units and 8,527,615 common units. See Note 4.
9
Note
10—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 the Partnership’s 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 the
Partnership enters into commodity derivative transactions designed to mitigate
the impact of commodity price fluctuations. Cash flows from a derivative
instrument designated as a hedge are classified in the same category as the cash
flows from the item being hedged.
The
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 September 30, 2009, the Partnership
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, the Partnership typically receives an agreed
upon fixed price for a specified notional quantity of natural gas or NGL and it
pays the hedge counterparty a floating price for that same quantity based upon
published index prices. Since the Partnership receives from its 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 the Partnership’s expected natural gas
and NGL equity volumes. The Partnership utilizes purchased puts (or floors) to
hedge additional expected equity commodity volumes without creating volumetric
risk. The Partnership’s commodity hedges may expose us to the risk of financial
loss in certain circumstances. The Partnership’s 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 the
Partnership has hedged, we will receive less revenue on the hedged volumes than
we would receive in the absence of hedges.
We have
tailored the Partnership’s hedges to generally match the NGL product composition
and the NGL and natural gas delivery points to those of its physical equity
volumes. The Partnership’s NGL hedges cover baskets of ethane, propane, normal
butane, iso-butane and natural gasoline based upon its 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, the Partnership’s NGL hedges are based on published
index prices for delivery at Mont Belvieu and its natural gas hedges are based
on published index prices for delivery at Columbia Gulf, Houston Ship Channel,
Mid-Continent and Waha, which closely approximate its actual NGL and natural gas
delivery points. The Partnership hedges a portion of its condensate sales using
crude oil hedges that are based on the NYMEX futures contracts for West Texas
Intermediate light, sweet crude.
Interest Rate Risk. We are
exposed to changes in interest rates, primarily as a result of variable rate
borrowings under the Partnership’s senior secured revolving credit facility. To
the extent that interest rates increase, interest expense for the Partnership’s
revolving debt will also increase. As of September 30, 2009, the
Partnership had borrowings of $510.5 million outstanding under its senior
secured revolving credit facility. In an effort to reduce the variability of its
cash flows, the Partnership 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 the
Partnership’s 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 sheet. Accordingly, unrealized gains and losses relating to
our portion of the interest rate swaps are recorded in 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 the Partnership at the
reporting date. At such times, these outstanding
10
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 the Partnership’s
counterparties decline, its 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
September 30, 2009, affiliates of Goldman Sachs, Bank of America (“BofA”)
and Barclays Bank accounted for 81%, 10% and 7% of our exposure related to the
Partnership’s counterparties regarding credit commodity derivative instruments.
Goldman Sachs, BofA 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.
The
following schedules reflect the fair values of derivative instruments in our
consolidated balance sheet:
Asset Derivatives
|
Liability Derivatives
|
|||||||||
Balance
|
Fair
Value as of
|
Balance
|
Fair
Value as of
|
|||||||
Sheet
|
September
30,
|
Sheet
|
September
30,
|
|||||||
Location
|
2009
|
Location
|
2009
|
|||||||
Derivatives designated as hedging instruments
under ASC 815
|
||||||||||
Commodity
contracts
|
Current
assets
|
$ | 46,508 |
Current
liabilities
|
$ | 1,383 | ||||
Long
term assets
|
18,575 |
Long
term liabilities
|
9,415 | |||||||
Interest
rate contracts
|
Current
assets
|
- |
Current
liabilities
|
7,876 | ||||||
Long
term assets
|
- |
Long
term liabilities
|
6,230 | |||||||
Total
derivatives designated
|
||||||||||
as
hedging instruments
|
65,083 | 24,904 | ||||||||
Derivatives not designated as hedging instruments
under ASC 815
|
||||||||||
Commodity
contracts
|
Current
assets
|
1,964 |
Current
liabilities
|
1,644 | ||||||
Long
term assets
|
285 |
Long
term liabilities
|
- | |||||||
Total
derivatives not designated
|
||||||||||
as
hedging instruments
|
2,249 | 1,644 | ||||||||
Total
derivatives
|
$ | 67,332 | $ | 26,548 | ||||||
As of
September 30, 2009, TRGP’s proportionate share of OCI consisted of
$0.4 million of unrealized net gains on commodity hedges and
$0.2 million of unrealized net losses on interest rate hedges.
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.
11
As of
September 30, 2009, the Partnership had the following commodity derivative
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 October 1, 2009 through December 31,
2009):
Natural
Gas
Instrument
|
Avg.
Price
|
MMBtu per day
|
||||||||||||||||||||||||||||
Type
|
Index
|
$/MMBtu
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
||||||||||||||||||||||
Sales
|
||||||||||||||||||||||||||||||
Swap
|
IF-HSC
|
7.39 | 1,966 | - | - | - | - | $ | 500 | |||||||||||||||||||||
Swap
|
IF-NGPL
MC
|
9.18 | 6,256 | - | - | - | - | 2,675 | ||||||||||||||||||||||
Swap
|
IF-NGPL
MC
|
8.86 | - | 5,685 | - | - | - | 6,169 | ||||||||||||||||||||||
Swap
|
IF-NGPL
MC
|
7.34 | - | - | 2,750 | - | - | 898 | ||||||||||||||||||||||
Swap
|
IF-NGPL
MC
|
7.18 | - | - | - | 2,750 | - | 605 | ||||||||||||||||||||||
6,256 | 5,685 | 2,750 | 2,750 | - | ||||||||||||||||||||||||||
Swap
|
IF-Waha
|
7.79 | 9,936 | - | - | - | - | 2,999 | ||||||||||||||||||||||
Swap
|
IF-Waha
|
6.53 | - | 11,709 | - | - | - | 2,630 | ||||||||||||||||||||||
Swap
|
IF-Waha
|
6.10 | - | - | 11,250 | - | - | (1,553 | ) | |||||||||||||||||||||
Swap
|
IF-Waha
|
6.30 | - | - | - | 7,250 | - | (584 | ) | |||||||||||||||||||||
Swap
|
IF-Waha
|
5.59 | - | - | - | - | 4,000 | (1,251 | ) | |||||||||||||||||||||
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 | - | - | - | - | 114 | ||||||||||||||||||||||
Floor
|
IF-Waha
|
6.55 | 565 | - | - | - | - | 77 | ||||||||||||||||||||||
Total
Floors
|
1,415 | - | - | - | - | |||||||||||||||||||||||||
Total
Sales
|
19,573 | 17,394 | 14,000 | 10,000 | 4,000 | |||||||||||||||||||||||||
Basis
Swap Oct 09-May 2011, Rec IF-CGT, Pay NYMEX less $0.11, 20,000
MMBtu/d
|
586 | |||||||||||||||||||||||||||||
Fuel
cost swap Oct 2009-May2011, Rec IF-CGT, Pay $5.96, 226
MMbtu/d
|
18 | |||||||||||||||||||||||||||||
$ | 13,883 |
12
NGLs
Instrument
|
Avg.
Price
|
Barrels per day
|
||||||||||||||||||||||||||||
Type
|
Index
|
$/gal
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
||||||||||||||||||||||
Sales
|
||||||||||||||||||||||||||||||
Swap
|
OPIS-MB
|
1.32 | 6,248 | - | - | - | - | $ | 10,931 | |||||||||||||||||||||
Swap
|
OPIS-MB
|
1.23 | - | 5,209 | - | - | - | 28,074 | ||||||||||||||||||||||
Swap
|
OPIS-MB
|
0.89 | - | - | 3,800 | - | - | 48 | ||||||||||||||||||||||
Swap
|
OPIS-MB
|
0.92 | - | - | - | 2,700 | - | 1,071 | ||||||||||||||||||||||
Total
Swaps
|
6,248 | 5,209 | 3,800 | 2,700 | - | |||||||||||||||||||||||||
Floor
|
OPIS-MB
|
1.44 | - | - | 199 | - | - | 1,454 | ||||||||||||||||||||||
Floor
|
OPIS-MB
|
1.43 | - | - | - | 231 | - | 1,755 | ||||||||||||||||||||||
Total
Floors
|
- | - | 199 | 231 | - | |||||||||||||||||||||||||
Total
Sales
|
6,248 | 5,209 | 3,999 | 2,931 | - | |||||||||||||||||||||||||
$ | 43,333 |
Condensate
Instrument
|
Avg.
Price
|
Barrels per day
|
||||||||||||||||||||||||||||
Type
|
Index
|
$/Bbl
|
2009
|
2010
|
2011
|
2012
|
2013
|
Fair Value
|
||||||||||||||||||||||
Sales
|
||||||||||||||||||||||||||||||
Swap
|
NY-WTI
|
69.00 | 322 | - | - | - | - | $ | (61 | ) | ||||||||||||||||||||
Swap
|
NY-WTI
|
68.04 | - | 401 | - | - | - | (913 | ) | |||||||||||||||||||||
Swap
|
NY-WTI
|
71.00 | - | - | 200 | - | - | (446 | ) | |||||||||||||||||||||
Swap
|
NY-WTI
|
72.60 | - | - | - | 200 | - | (449 | ) | |||||||||||||||||||||
Swap
|
NY-WTI
|
74.00 | - | - | - | - | 200 | (459 | ) | |||||||||||||||||||||
Total
Swaps
|
322 | 401 | 200 | 200 | 200 | |||||||||||||||||||||||||
Floor
|
NY-WTI
|
60.00 | 50 | - | - | - | - | 3 | ||||||||||||||||||||||
Total
Floors
|
50 | - | - | - | - | |||||||||||||||||||||||||
Total
Sales
|
372 | 401 | 200 | 200 | 200 | |||||||||||||||||||||||||
$ | (2,325 | ) |
13
Customer
Hedges
As of
September 30, 2009, the Partnership 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
|
||||||||||||||
Purchases
|
||||||||||||||||||||
Oct
2009 - Dec 2009
|
Natural
gas
|
Swap
|
2,935 |
MMBtu
|
$ | 9.15 |
per
MMBtu
|
NY-HH
|
$ | (1,189 | ) | |||||||||
Jan
2010 - Jun 2010
|
Natural
gas
|
Swap
|
663 |
MMBtu
|
8.03 |
per
MMBtu
|
NY-HH
|
(247 | ) | |||||||||||
Sales
|
||||||||||||||||||||
Oct
2009 - Dec 2009
|
Natural
gas
|
Fixed
price sale
|
2,935 |
MMBtu
|
9.15 |
per
MMBtu
|
NY-HH
|
1,188 | ||||||||||||
Jan
2010 - Jun 2010
|
Natural
gas
|
Fixed
price sale
|
663 |
MMBtu
|
8.03 |
per
MMBtu
|
NY-HH
|
247 | ||||||||||||
$ | (1 | ) |
Interest
Rate Hedges
The
Partnership’s consolidated variable rate indebtedness accrues interest at a base
rate plus an applicable margin. The Partnership’s 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
|
||||||||||
Remainder
of 2009
|
3.66 | % | $ | 300 |
million
|
$ | (647 | ) | |||||
2010
|
3.66 | % | 300 |
million
|
(9,166 | ) | |||||||
2011
|
3.41 | % | 300 |
million
|
(4,566 | ) | |||||||
2012
|
3.39 | % | 300 |
million
|
(913 | ) | |||||||
2013
|
3.39 | % | 300 |
million
|
569 | ||||||||
01/01-4/24/2014
|
3.39 | % | 300 |
million
|
617 | ||||||||
$ | (14,106 | ) |
We have
designated all interest rate swaps and interest rate basis swaps as cash flow
hedges.
See
Notes 11 and 14 for additional disclosures related to derivative
instruments and hedging activities.
Note
11—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 September 30, 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.
14
Total
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Assets
from commodity derivative contracts
|
$ | 67,332 | $ | - | $ | 67,332 | $ | - | ||||||||
Total
assets
|
$ | 67,332 | $ | - | $ | 67,332 | $ | - | ||||||||
Liabilities
from commodity derivative contracts
|
$ | 12,442 | $ | - | $ | 12,442 | $ | - | ||||||||
Liabilities
from interest rate derivatives
|
14,106 | - | 14,106 | - | ||||||||||||
Total
liabilities
|
$ | 26,548 | $ | - | $ | 26,548 | $ | - |
The
following table sets forth a reconciliation of the changes in the fair value of
our financial instruments classified as Level 3 in the fair value
hierarchy:
Commodity
Derivative Contracts
|
||||
Balance,
December 31, 2008
|
$ | 123,304 | ||
Unrealized
gains (losses) included in OCI
|
(26,557 | ) | ||
Settlements
|
(31,392 | ) | ||
Transfers
out of Level 3
|
(65,355 | ) | ||
Balance,
September 30, 2009
|
$ | - |
During
the third quarter of 2009, we reclassified our NGL derivative contracts from
Level 3 (unobservable inputs in which little or no market data exists) to
Level 2 as we were able to obtain directly observable inputs other than
quoted prices in active markets.
Our
nonfinancial assets and liabilities measured at fair value on a nonrecurring
basis as of September 30, 2009 were not significant.
Note
12—Commitments and Contingencies
Environmental
For
environmental matters, we record liabilities when remedial efforts are probable
and the costs can be reasonably estimated. Environmental reserves do not reflect
management’s assessment of 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.
We do not
have a reserve for environmental expenses as of September 30,
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.
15
Note
13—Fair Value of Financial Instruments
The
estimated fair values of our assets and liabilities classified as financial
instruments have been determined using available market information and
valuation methodologies described below. Considerable judgment is required in
interpreting market data to develop the estimates of fair value. The use of
different market assumptions or valuation methodologies may have a material
effect on the estimated fair value amounts.
The
carrying value of the credit facility approximates its fair value, as its
interest rate is based on prevailing market rates. The fair value of the senior
unsecured notes is based on quoted market prices based on trades of such
debt.
The
carrying values of items comprising current assets and current liabilities
approximate fair values due to the short-term maturities of these instruments.
Derivative financial instruments included in our consolidated balance sheet are
stated at fair value. The carrying amounts and fair values of our other
financial instruments are as follows as of September 30, 2009:
Carrying
|
Fair
|
|||||||
Amount
|
Value
|
|||||||
Senior
unsecured notes, 8¼% fixed rate
|
$ | 209,080 | $ | 193,922 | ||||
Senior
unsecured notes, 11¼% fixed rate (1)
|
219,861 | 242,266 |
______________
|
(1)
|
The
carrying amount of the notes includes $11.4 million of
unamortized
|
original
issue discount as of September 30, 2009.
Note
14—Related Party Transactions
Relationship
with Targa
We are a
party to various agreements with Targa and others that address (i) the
reimbursement of costs incurred on the Partnership’s behalf by TRGP,
(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.
Relationship
with Bank of America
An
affiliate of BofA is an equity investor in Targa Resources Investments Inc.,
which indirectly owns TRGP.
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 BofA. The
following table shows our open commodity derivatives with BofA as of
September 30, 2009:
Period
|
Commodity
|
Daily Volumes
|
Average Price
|
Index
|
||||||||||
Oct
2009 - Dec 2009
|
Natural
gas
|
3,556 |
MMBtu
|
$ | 8.07 |
per
MMBtu
|
IF-Waha
|
|||||||
Oct
2009 - Dec 2009
|
Natural
gas
|
652 |
MMBtu
|
8.35 |
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
|
||||||||
Oct
2009 - Dec 2009
|
NGL
|
3,000 |
Bbl
|
1.18 |
per
gallon
|
OPIS-MB
|
||||||||
Oct
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
September 30, 2009, the aggregate fair value of these open positions was
$6.0 million.
16
We have
entered into several interest rate derivative transactions with BofA. Open
positions as of September 30, 2009 consisted of interest rate swaps and
interest rate basis swaps expiring on April 24, 2014. As of
September 30, 2009, the aggregate fair value of these positions was a
liability of $2.7 million.
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. As of September 30, 2009, our payable balance with Broad Oak was
$0.8 million.
Note 15—Segment
Information
We
categorize the midstream natural gas industry into, and describe our business
in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and
(ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division
consists of three segments: (a) Logistics Assets, (b) NGL Distribution and
Marketing and (c) Wholesale Marketing.
The
Natural Gas Gathering and Processing segment includes assets used in the
gathering of natural gas produced from oil and gas wells and processing this raw
natural gas into merchantable natural gas by extracting natural gas liquids and
removing impurities. These assets are located in North Texas, Louisiana and the
Permian Basin of West Texas. The Partnership is also party to natural gas
processing agreements with third party plants.
The
Logistics Assets segment is involved with gathering and storing mixed NGLs and
fractionating, storing, and transporting finished NGLs. These assets are
generally connected to and supplied, in part, by our Natural Gas Gathering and
Processing segment and are predominantly located in Mont Belvieu, Texas and
Western Louisiana.
The
NGL Distribution and Marketing segment markets our own natural gas liquids
production and purchased natural gas liquids products in selected United States
markets.
The
Wholesale Marketing segment includes our refinery services business and
wholesale propane marketing operations. In our refinery services business, we
provide liquefied petroleum gas balancing services, purchase natural gas liquids
products from refinery customers and sell natural gas liquids products to
various customers. Our wholesale propane marketing operations include the sale
of propane and related logistics services to multi-state retailers, independent
retailers and other end-users. Wholesale Marketing operates principally in the
United States, and has a small marketing presence in Canada.
The
“Eliminations and Other” column in the following tables includes corporate level
consolidation adjustments as of and for the nine months ended September 30,
2009:
Natural Gas Gathering and
Processing
|
Logistics
Assets
|
NGL
Distribution
and
Marketing
|
Wholesale Marketing
|
Eliminations
and Other
|
Total
|
|||||||||||||||||||
Identifiable
assets
|
$ | 1,309,344 | $ | 490,481 | $ | 234,716 | $ | 70,630 | $ | 43,147 | $ | 2,148,318 | ||||||||||||
Unconsolidated
investments
|
- | 17,811 | - | - | - | 17,811 | ||||||||||||||||||
Capital
expenditures
|
21,341 | 15,853 | - | - | - | 37,194 |
17