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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K/A
(AMENDMENT NO. 5)
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): September 30, 2004
ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 1-14323 76-0568219
(State or Other Jurisdiction of (Commission File Number) (I.R.S. Employer
Incorporation or Organization) Identification No.)
2727 NORTH LOOP WEST, HOUSTON, TEXAS 77008-1044
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, including Area Code: (713) 880-6500
Check the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant under any of the
following provisions (see General Instruction A.2. below):
[ ] Written communications pursuant to Rule 425 under the Securities Act
(17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act
(17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange
Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange
Act (17 CFR 240.13e-4(c))
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EXPLANATORY NOTE
The purpose of this Amendment No. 5 is to amend the Current Report on
Form 8-K filed by Enterprise Products Partners L.P. ("Enterprise") on September
30, 2004, as amended by Amendment No. 1 thereto filed on October 5, 2004,
Amendment No. 2 thereto filed on October 18, 2004, Amendment No. 3 thereto filed
on December 3, 2004 and Amendment No. 4 thereto filed on December 6, 2004 (the
"Existing 8-K") to (i) remove the unaudited condensed consolidated financial
statements of GulfTerra Energy Partners, L.P. at September 30, 2004 and December
31, 2003 and for the three and nine months ended September 30, 2004 and 2003
contained in Amendment No. 3 to the Existing 8-K, and (ii) file the unaudited
condensed financial statements of GulfTerra Energy Partners, L.P. at September
30, 2004 and for the six months ended June 30, 2004, the three months ended
September 30, 2004, the nine months total September 30, 2004, and the three
months and the nine months ended September 30, 2003 under Item 9.01(a). In
accordance with Rule 12b-15, Item 9.01 is restated in its entirety, as amended.
There is no change to Items 1.01, 2.01, 2.03, 5.02, 5.03 or 7.01 as set forth in
the Existing 8-K.
ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS.
(a) FINANCIAL STATEMENTS OF BUSINESSES ACQUIRED.
1. The Consolidated Financial Statements of GulfTerra Energy
Partners, L.P. as of December 31, 2003 and 2002 and for
the three year period ended December 31, 2003 and
independent auditors' report are contained in Enterprise's
Current Report on Form 8-K filed with the Commission on
April 20, 2004 and are incorporated herein by reference.
2. The Financial Statements of Poseidon Oil Pipeline Company,
L.L.C. as of December 31, 2003 and 2002 and for the three
year period ended December 31, 2003 and independent
auditors' report are contained in Enterprise's Current
Report on Form 8-K filed with the Commission on April 20,
2004 and are incorporated herein by reference.
3. The Combined Financial Statements of El Paso Hydrocarbons,
L.P. and El Paso NGL Marketing Company, L.P. as of
December 31, 2003 and 2002 and for the three year period
ended December 31, 2003 and independent auditors' report
are contained in Enterprise's Current Report on Form 8-K
filed with the Commission on April 16, 2004 and are
incorporated herein by reference.
4. The Unaudited Consolidated Financial Statements of
GulfTerra Energy Partners, L.P. at June 30, 2004 and
December 31, 2003 and for the six months ended June 30,
2004 and 2003 are contained in Enterprise's Current Report
on Form 8-K filed with the Commission on September 17,
2004 and are incorporated herein by reference.
5. The Unaudited Combined Financial Statements of El Paso
Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P.
at June 30, 2004 and December 31, 2003 and for the six
months ended June 30, 2004 and 2003 are contained in
Enterprise's Current Report on Form 8-K filed with the
Commission on August 11, 2004 and are incorporated herein
by reference.
6. The Unaudited Condensed Consolidated Financial Statements
of GulfTerra Energy Partners, L.P. at September 30, 2004
and for the six months ended June 30, 2004, the three
months ended September 30, 2004, the nine months total
September 30, 2004, and the three months and the nine
months ended September 30, 2003 (filed herewith as Annex A
to this Current Report on Form 8-K/A).
2
(b) PRO FORMA FINANCIAL INFORMATION.
1. The Unaudited Pro Forma Condensed Consolidated Financial
Statements of Enterprise Products Partners L.P. at and for
the six months ended June 30, 2004 and for the year ended
December 31, 2003 are contained in Enterprise's Current
Report on Form 8-K filed with the Commission on September
27, 2004 and are incorporated herein by reference.
2. The Unaudited Pro Forma Condensed Consolidated Financial
Statements of Enterprise Products Partners L.P. at and for
the nine months ended September 30, 2004 and for the year
ended December 31, 2003 are contained in Enterprise's
Current Report on Form 8-K/A (Amendment No. 4) filed with
the Commission on December 6, 2004 and are incorporated
herein by reference.
(c) EXHIBITS.
Exhibit No. Description
----------- ------------
2.1 Merger Agreement, dated as of December 15, 2003, by
and among Enterprise Products Partners L.P.,
Enterprise Products GP, LLC, Enterprise Products
Management LLC, GulfTerra Energy Partners, L.P. and
GulfTerra Energy Company, L.L.C. (incorporated by
reference to Exhibit 2.1 to Enterprise's Current
Report on Form 8-K filed with the Commission on
December 15, 2003).
2.2 Parent Company Agreement, dated as of December 15,
2003, by and among Enterprise Products Partners L.P.,
Enterprise Products GP, LLC, Enterprise Products GTM,
LLC, El Paso Corporation, Sabine River Investors I,
L.L.C., Sabine River Investors II, L.L.C., El Paso
EPN Investments, L.L.C. and GulfTerra GP Holding
Company (incorporated by reference to Exhibit 2.2 to
Enterprise's Current Report on Form 8-K filed with
the Commission on
December 15, 2003).
2.3 Second Amended and Restated Limited Liability Company
Agreement of GulfTerra Energy Company, L.L.C.,
adopted by GulfTerra GP Holding Company, a Delaware
corporation, and Enterprise Products GTM, LLC, a
Delaware limited liability company, as of December
15, 2003, (incorporated by reference to Exhibit 2.3
to Enterprise's Current Report on Form
8-K filed with the Commission on December 15, 2003).
2.4 Purchase and Sale Agreement (Gas Plants), dated
as of December 15, 2003, by and between El Paso
Corporation, El Paso Field Services Management, Inc.,
El Paso Transmission, L.L.C., El Paso Field Services
Holding Company and Enterprise Products Operating
L.P. (incorporated by reference to Exhibit 2.4 to
Enterprise's Current Report on Form 8-K filed with
the Commission on December 15, 2003).
2.5 Amendment No. 1 to Parent Company Agreement, dated
as of April 19, 2004, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products GTM, LLC, El Paso Corporation,
Sabine River Investors I, L.L.C., Sabine River
Investors II, L.L.C., El Paso EPN Investments, L.L.C.
and GulfTerra GP Holding Company (incorporated by
reference to Exhibit 2.1 to Enterprise's Current
Report on Form 8-K filed with the Commission on April
21, 2004).
2.6 Amendment No. 1 to Merger Agreement, dated as of
August 31, 2004, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC,
Enterprise Products Management LLC, GulfTerra Energy
Partners, L.P. and GulfTerra Energy Company, L.L.C.
(incorporated by reference to Exhibit 2.1 to
Enterprise's Current Report on Form 8-K filed with
the Commission on September 7, 2004).
3
3.1* Second Amended and Restated Limited Liability Company
Agreement of Enterprise Products GP, LLC, among
Duncan Family Interests, Inc., Dan Duncan LLC, and
GulfTerra GP Holding Company dated September 30,
2004.
4.1* Exchange and Registration Rights Agreement, dated as
of September 30, 2004, among GulfTerra GP Holding
Company, Enterprise Products GP, LLC and Enterprise
Products Partners L.P.
4.2* Performance Guaranty dated as of September 30, 2004,
by DFI Delaware Holdings L.P. in favor of GulfTerra
GP Holding Company (with respect to the obligations
of Enterprise Products GP, LLC under Exhibit 4.1,
above).
4.3* Registration Rights Agreement, dated as of September
30, 2004, between El Paso Corporation and Enterprise
Products Partners L.P.
4.4** Assumption Agreement dated as of September 30, 2004
between Enterprise Products Partners L.P. and
GulfTerra Energy Partners, L.P. relating to the
assumption by Enterprise of GulfTerra's obligations
under the GulfTerra Series F2 Convertible Units.
4.5 Statement of Rights, Privileges and Limitations of
Series F Convertible Units, included as Annex A to
Third Amendment to the Second Amended and Restated
Agreement of Limited Partnership of GulfTerra Energy
Partners, L.P., dated May 16, 2003 (incorporated by
reference to Exhibit 3.B.3 to Current Report on Form
8-K of GulfTerra Energy Partners, L.P., file no.
001-11680, filed with the Commission on May 19,
2003).
4.6 Unitholder Agreement between GulfTerra Energy
Partners, L.P. and Fletcher International, Inc. dated
May 16, 2003 (incorporated by reference to Exhibit
4.L to Current Report on Form 8-K of GulfTerra Energy
Partners, L.P., file no. 001-11680, filed with the
Commission on May 19, 2003).
10.1*** Letter Agreement dated September 30, 2004, among
Enterprise Products Partners L.P., GulfTerra Energy
Partners, L.P. and Bart Heijermans.
10.2 1998 Omnibus Compensation Plan of GulfTerra Energy
Partners, L.P., Amended and Restated as of January 1,
1999 (incorporated by reference to Exhibit 10.9 to
Form 10-K for the year ended December 31, 1998 of
GulfTerra Energy Partners, L.P., file no. 001-11680);
Amendment No. 1, dated as of December 1, 1999
(incorporated by reference to Exhibit 10.8.1 to Form
10-Q for the quarter ended June 30, 2000 of GulfTerra
Energy Partners, L.P., file no. 001-116800);
Amendment No. 2 dated as of May 15, 2003
(incorporated by reference to Exhibit 10.M.1 to Form
10-Q for the quarter ended June 30, 2003 of GulfTerra
Energy Partners, L.P., file no. 001-11680).
10.3 1998 Enterprise Products Long-Term Incentive Plan
(Amended and Restated as of April 8, 2004)
(incorporated by reference to Appendix B to
Enterprise's Notice of Written Consent dated April
22, 2004, filed with the Commission on April 22,
2004).
99.1* Press release dated September 30, 2004.
------------
* Filed with original Current Report on Form 8-K.
** Filed with Amendment No. 1 to Current Report on Form 8-K.
*** Filed with Amendment No. 2 to Current Report on Form 8-K.
4
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this Report to be signed on its behalf by the
undersigned hereunto duly authorized.
ENTERPRISE PRODUCTS PARTNERS L.P.
By: Enterprise Products GP, LLC,
its General Partner
Date: December 23, 2004 By: /s/ Michael J. Knesek
--------------------------------------------
Name: Michael J. Knesek
Title: Vice President, Controller and
Principal Accounting Officer of
Enterprise Products GP, LLC
Signature Page
GULFTERRA ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
AT SEPTEMBER 30, 2004 AND
FOR THE SIX MONTHS ENDED JUNE 30, 2004, THREE MONTHS ENDED SEPTEMBER 30, 2004,
NINE MONTHS TOTAL SEPTEMBER 30, 2004, AND THE THREE AND
NINE MONTHS ENDED SEPTEMBER 30, 2003
A-1
GULFTERRA ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
SEPTEMBER 30,
2004 (1)
-------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 40,453
Accounts receivable, net of allowance for doubtful accounts of
$4.2 million at September 30, 2004 156,997
Affiliated note receivable
Other current assets 32,055
----------
Total current assets 229,505
PROPERTY, PLANT, AND EQUIPMENT, NET 2,926,861
INTANGIBLE ASSETS 3,080
INVESTMENTS IN UNCONSOLIDATED AFFILIATES 210,742
OTHER ASSETS 26,101
----------
Total $3,396,289
==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of debt $ 5,000
Accounts payable 133,407
Accrued interest 26,361
Other current liabilities 35,045
----------
Total current liabilities 199,813
LONG-TERM DEBT 1,878,456
OTHER LONG-TERM LIABILITIES 42,384
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST (12)
PARTNERS' EQUITY:
Common units (60,638,989 units outstanding at September 30, 2004) 929,110
Series C units (10,937,500 units outstanding at September 30, 2004) 333,063
General partner 13,475
----------
Total Partners' Equity 1,275,648
----------
Total $3,396,289
==========
--------------------------------------------------------------------------------
(1) The September 30, 2004 amounts do not reflect any pro forma impacts of the
merger, repayments of debt, changes in ownership of our common unitholders
or any other purchase accounting-related adjustments to be made by
Enterprise in connection with the merger - see Note 2.
See Notes to Unaudited Condensed Consolidated Financial Statements.
A-2
GULFTERRA ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL ------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
---------------------------------------- ------------------------
2004 (1) 2003
------------------------------------- -----------------------
OPERATING REVENUES $ 445,557 $ 231,165 $ 676,722 $ 213,831 $ 680,957
--------- --------- --------- --------- ---------
OPERATING EXPENSES
Cost of natural gas and other products 124,522 61,651 186,173 64,277 240,415
Operation and maintenance 100,463 64,361 164,824 51,221 140,416
Depreciation, depletion and amortization 52,303 28,994 81,297 25,218 73,761
Gain on sale of long-lived assets (24) (12) (36) (18,964) (18,707)
--------- --------- --------- --------- ---------
Total operating expenses 277,264 154,994 432,258 121,752 435,885
--------- --------- --------- --------- ---------
OPERATING INCOME 168,293 76,171 244,464 92,079 245,072
--------- --------- --------- --------- ---------
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES 5,466 2,101 7,567 3,195 9,498
--------- --------- --------- --------- ---------
Minority interest income (expense) 12 1,813 1,825 (889) (969)
Other income 284 188 472 250 942
Interest and debt expense 54,727 27,951 82,678 33,197 99,521
Loss due to early redemptions of debt 16,285 16,285 1,225 4,987
--------- --------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE 103,043 52,322 155,365 60,213 150,035
Cumulative effect of accounting change 1,690
--------- --------- --------- --------- ---------
NET INCOME $ 103,043 $ 52,322 $ 155,365 $ 60,213 $ 151,725
========= ========= ========= ========= =========
ALLOCATION OF NET INCOME TO:
Series B unitholders $ 4,018 $ 11,792
========= =========
General partner:
Income before cumulative effect of accounting change $ 42,549 $ 21,550 $ 64,099 $ 18,031 $ 48,747
Cumulative effect of accounting change 17
--------- --------- --------- --------- ---------
Total allocation to general partner $ 42,549 $ 21,550 $ 64,099 $ 18,031 $ 48,764
========= ========= ========= ========= =========
Common unitholders:
Income before cumulative effect of accounting change $ 51,087 $ 26,044 $ 77,131 $ 31,337 $ 72,951
Cumulative effect of accounting change 1,340
--------- --------- --------- --------- ---------
Total allocation to common unitholders $ 51,087 $ 26,044 $ 77,131 $ 31,337 $ 74,291
========= ========= ========= ========= =========
Series C unitholders:
Income before cumulative effect of accounting change $ 9,407 $ 4,728 $ 14,135 $ 6,827 $ 16,545
Cumulative effect of accounting change 333
--------- --------- --------- --------- ---------
Total allocation to Series C unitholders $ 9,407 $ 4,728 $ 14,135 $ 6,827 $ 16,878
========= ========= ========= ========= =========
EARNINGS PER UNIT:
Basic income per unit before cumulative effect of
accounting change $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.54
Cumulative effect of accounting change, per unit (basic) 0.03
--------- --------- --------- --------- ---------
Basic net income per unit $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.57
========= ========= ========= ========= =========
Diluted income per unit before cumulative effect of
accounting change $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.53
Cumulative effect of accounting change, per unit (diluted) 0.03
--------- --------- --------- --------- ---------
Diluted net income per unit $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.56
========= ========= ========= ========= =========
--------------------------------------------------------------------------------
(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of
the merger, repayments of debt, changes in ownership of our common
unitholders or any other purchase accounting-related adjustments to be made
by Enterprise in connection with the merger - see Note 2.
See Notes to Unaudited Condensed Consolidated Financial Statements.
A-3
GULFTERRA ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
SIX MONTHS THREE MONTHS NINE MONTHS NINE MONTHS
ENDED ENDED TOTAL ENDED
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
---------------------------------------------- -------------
2004 (1) 2003
---------------------------------------------- -------------
OPERATING ACTIVITIES
Net income $ 103,043 $ 52,322 $ 155,365 $ 151,725
Adjustments to reconcile net income to cash flows provided by
operating activities:
Cumulative effect of accounting change (1,690)
Depreciation, depletion and amortization in operating
expenses 52,303 28,994 81,297 73,761
Amortization of debt issuance costs, premiums and discounts 2,651 1,209 3,860 5,977
Equity in income of unconsolidated affiliates (5,466) (2,101) (7,567) (9,498)
Distributions received from unconsolidated affiliates 1,450 750 2,200 11,390
Gain on sale of long-lived assets (24) (12) (36) (18,707)
Loss due to write-off of unamortized debt issuance costs 3,884 3,884 4,987
Other noncash items 6,352 533 6,885 2,910
Net effect of changes in operating accounts (27,961) 4,186 (23,775) (11,500)
----------- ----------- ----------- -----------
Cash provided by operating activities 136,232 85,881 222,113 209,355
----------- ----------- ----------- -----------
INVESTING ACTIVITIES
Capital expenditures (86,107) (31,418) (117,525) (246,295)
Proceeds from sale of assets 197 278 475 77,448
Investments in unconsolidated affiliates (17,947) (2,419) (20,366) (33,879)
Proceeds from sale of equity investments 1,342
----------- ----------- ----------- -----------
Cash used in investing activities (103,857) (33,559) (137,416) (201,384)
----------- ----------- ----------- -----------
FINANCING ACTIVITIES
Borrowings under debt agreements, net of debt issuance costs 586,531 59,958 646,489 835,537
Repayments of debt (522,585) (60,000) (582,585) (861,000)
Distributions paid to partners (142,317) (72,067) (214,384) (167,974)
Distributions paid to minority interests (642)
Contribution from general partner 480 98 578 4
Net proceeds from issuance of common units, Series F
convertible units and conversion of Series F
convertible units 48,536 34,324 82,860 208,949
Unit option buyout (7,627) (7,627)
----------- ----------- ----------- -----------
Cash provided by (used in) financing activities (29,355) (45,314) (74,669) 14,874
----------- ----------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 3,020 7,008 10,028 22,845
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 30,425 33,445 30,425 36,099
----------- ----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 33,445 $ 40,453 $ 40,453 $ 58,944
=========== =========== =========== ===========
Schedule of non-cash financing activities:
Investment in Cameron Highway Oil Pipeline Company
joint venture $ 50,836
===========
Redemption of Series B preference units contributed
from our general partner $ 1,986
===========
--------------------------------------------------------------------------------
(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of
the merger, repayments of debt, changes in ownership of our common
unitholders or any other purchase accounting-related adjustments to be made
by Enterprise in connection with the merger - see Note 2.
See Notes to Unaudited Condensed Consolidated Financial Statements.
A-4
GULFTERRA ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS
(DOLLARS IN THOUSANDS)
COMPREHENSIVE INCOME
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL ------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
------------------------------------------ ------------------------
2004 (1) 2003
------------------------------------------ ------------------------
Net income $ 103,043 $ 52,322 $ 155,365 $ 60,213 $ 151,725
Other comprehensive income (loss) (2,172) 7,923 5,751 8,094 2,651
--------- --------- --------- ---------- ---------
Total comprehensive income $ 100,871 $ 60,245 $ 161,116 $ 68,307 $ 154,376
========= ========= ========= ========== =========
ACCUMULATED OTHER COMPREHENSIVE LOSS
SIX MONTHS THREE MONTHS
JUNE 30, SEPTEMBER 30,
-------------------------- NINE MONTHS
2004 (1) TOTAL
-------------------------- -----------
Beginning balance $ (9,027) $ (11,199) $ (9,027)
Unrealized mark-to-market losses on cash flow hedges
arising during period (10,716) (225) (10,941)
Reclassification adjustments for changes in initial value
of derivative instruments to settlement date 8,544 8,148 16,692
----------- ---------- -----------
Ending balance $ (11,199) $ (3,276) $ (3,276)
=========== ========== ===========
Accumulated other comprehensive loss allocated to:
Common units' interest $ (9,305) $ (2,670) $ (2,670)
=========== ========== ===========
Series C units' interest $ (1,742) $ (533) $ (533)
=========== ========== ===========
General partner's interests $ (152) $ (73) $ (73)
=========== ========== ===========
--------------------------------------------------------------------------------
(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of
the merger, repayments of debt, changes in ownership of our common
unitholders or any other purchase accounting-related adjustments to be made
by Enterprise in connection with the merger - see Note 2.
See Notes to Unaudited Condensed Consolidated Financial Statements.
A-5
GULFTERRA ENERGY PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
We are a Delaware limited partnership established in 1993 for
the purpose of providing midstream energy services, including gathering,
transportation, fractionation, storage and other related activities, for
producers of natural gas and oil, onshore and offshore in the Gulf of Mexico.
Our general partner is GulfTerra Energy Company, L.L.C. ("GulfTerra GP"), a
Delaware limited liability company - see Note 2. References to "us", "we",
"our", or "GulfTerra" are intended to mean the consolidated business and
operations of GulfTerra Energy Partners, L.P. References to "El Paso" refer to
El Paso Corporation, its subsidiaries and affiliates.
On September 30, 2004, we completed our merger with Enterprise
Products Partners L.P. ("Enterprise"). For additional information regarding the
merger, see Note 2. Unless otherwise disclosed, these unaudited condensed
consolidated financial statements do not reflect any pro forma impacts of the
merger, repayments of debt - see Note 4, changes in ownership of our common
unitholders, purchase accounting-related adjustments or any other adjustments to
be made by Enterprise in connection with the merger. Effective September 30,
2004, most of our then outstanding limited partner interests were converted to
Enterprise limited partner interests pursuant to the merger. Those limited
partner interests that were not converted into Enterprise limited partner
interests were purchased by Enterprise from El Paso for cash immediately prior
to the merger. As a result of the merger, we ceased as being a publicly-traded
company subject to the filing requirements of the Securities and Exchange
Commission ("SEC").
In the opinion of GulfTerra, the accompanying unaudited
condensed consolidated financial statements include all adjustments consisting
of normal recurring accruals necessary for a fair presentation. Although we
believe the disclosures in these financial statements are adequate to make the
information presented not misleading, certain information and footnote
disclosures normally included in annual financial statements prepared in
accordance with accounting principles generally accepted in the United States of
America have been condensed or omitted pursuant to the rules and regulations of
the SEC.
The results of operations for the six months ended June 30,
2004, the three months ended September 30, 2004 or the total for the nine months
ended September 30, 2004 are not necessarily indicative of the results to be
expected for the full year.
Dollar amounts presented in the tabular data within these
footnote disclosures are stated in thousands of dollars, unless otherwise
stated.
Certain reclassifications have been made to the prior year's
financial statements to conform to the current year presentation. Typhoon Oil
Pipeline, a wholly-owned subsidiary, has transportation agreements with BHP
Billiton and ChevronTexaco which provide that Typhoon Oil purchase the oil
produced at the inlet of its pipeline for an index price less an amount that
compensates Typhoon Oil for transportation services. At the outlet of its
pipeline, Typhoon Oil resells this oil back to these producers at the same index
price. As disclosed in our 2003 annual report on Form 10-K, as amended, we now
record revenue from these buy/sell transactions upon delivery of the oil based
on the net amount billed to the producers. For the three and nine months ended
September 30, 2003, we reduced by $69.8 million and $191.7 million our revenues
and cost of natural gas and other products to conform to the current period
presentation. This revision had no effect on operating income, net income or
partners' equity.
With respect to our Texas intrastate pipeline system, which we
acquired in April 2002, we had previously used the pre-acquisition accounting
methodology for the cash settlement of natural gas imbalance receivables, which
included the cash settlement amounts as a component of operating revenues and
cost of natural gas and other products. However, effective January 1, 2004, we
have conformed our accounting for cash settlements on that system to the same
method we use to account for imbalance receivable settlements on our other
systems, which method accounts for these types of cash settlements as an
adjustment to cost of natural gas and other products. We have determined that
this revision is not material to our previously reported financial statements.
Accordingly, we have not revised our previously filed financial statements to
reflect this change in methodology.
A-6
Accounting for stock-based compensation
Under the terms of the merger agreement with Enterprise, we
were obligated to repurchase, before the effective time of the merger, all
outstanding employee and director unit options that had not been exercised or
otherwise cancelled. As a result, we had no outstanding unit options at
September 30, 2004. Historically, we used the intrinsic value method established
in Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock
Issued to Employees, to value unit options issued to directors of our general
partner. We used the provisions of Statement of Financial Accounting Standards
("SFAS") No. 123, Accounting for Stock-Based Compensation, to account for all of
our other equity-based compensation programs. The costs associated with our unit
options accounted for under APB No. 25 had no impact on net income for the six
months ended June 30, 2004, the three months ended September 30, 2004 and the
three and nine months ended September 30, 2003, as these options had an exercise
price equal to the market value of the underlying common units on the date of
grant. Historical compensation expense amounts associated with our unit options
accounted for under SFAS No. 123 are shown in the following table.
If compensation expense had been determined by applying the
fair value method in SFAS No. 123 to all of our grants, our net income allocated
to common unitholders and net income per common unit would have approximated the
pro forma amounts below (dollars in thousands, except per unit amounts). As a
result of applying SFAS No. 123 to all unit options, there was no difference
between our historical and pro forma earnings per unit amounts.
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL ------------ -----------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
----------------------------------------- -------------------------
2004 2003
----------------------------------------- -------------------------
Net income as reported $ 103,043 $ 52,322 $ 155,365 $ 60,213 $ 151,725
Add: Equity-based compensation expense included
in reported net income using SFAS No. 123 267 142 409 404 1,083
Less: Pro forma equity-based compensation expense determined
using the fair value method as if all unit options
were accounted for under SFAS No. 123 (300) (142) (442) (406) (1,126)
--------- --------- --------- --------- ---------
Pro forma net income $ 103,010 $ 52,322 $ 155,332 $ 60,211 $ 151,682
========= ========= ========= ========= =========
Pro forma net income allocated to common unitholders $ 51,054 $ 26,044 $ 77,098 $ 31,335 $ 74,248
========= ========= ========= ========= =========
Earnings per common unit:
Basic, as reported and pro forma $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.57
========= ========= ========= ========= =========
Diluted, as reported and pro forma $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.56
========= ========= ========= ========= =========
Inventory
In June 2004, we purchased pipeline inventory, consisting of
parts and materials, from El Paso -see Note 8. This inventory is included on our
unaudited condensed consolidated balance sheet as of September 30, 2004, in
other current assets. We use the average cost method to account for our
inventory and we value our inventory at the lower of its cost or market value.
Consolidation of variable interest entities
During the first quarter of 2004, we adopted the provisions of
Financial Accounting Standards Board Interpretation ("FIN") No. 46,
Consolidation of Variable Interest Entities, an Interpretation of Accounting
Research Bulletin ("ARB") No. 51, as replaced by FIN No. 46-R. This
interpretation defines a variable interest entity as a
A-7
legal entity whose equity owners do not have sufficient equity at risk and/or a
controlling financial interest in the entity and excludes certain joint ventures
of other entities that meet the characteristics of a business. Our adoption of
FIN No. 46 had no effect on our reported results or financial position.
Two-class method of computing earnings per common unit
During the second quarter of 2004, we adopted the provisions
of Emerging Issues Task Force ("EITF") 03-6, Participating Securities and the
Two-Class Method under SFAS No. 128. EITF 03-6 requires the use of the two-class
method of determining basic earnings per unit. Under the two-class method,
distributions to equity owners are subtracted from earnings, and any remaining
earnings would be allocated to the various classes of owners in proportion to
their right to receive distributions as if those earnings had been distributed.
The total of distributions to each class of owner plus the amount allocated to
each class would be used to compute earnings per unit for that class. Because
our distributions to owners exceeded earnings during the periods presented, as
has historically been the case, the two-class method did not produce any change
in result from the way we have traditionally computed earnings per unit. As a
result, the adoption of this standard had no effect on our earnings per unit
calculation for the six months ended June 30, 2004, the three months ended
September 30, 2004 and the three and nine months ended September 30, 2003.
2. MERGER WITH ENTERPRISE AND RELATED TRANSACTIONS
General description of merger
On September 30, 2004, Enterprise and GulfTerra completed the
merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra
being the surviving entity thereof (the "GulfTerra Merger"). Unless otherwise
disclosed, these unaudited condensed consolidated financial statements do not
reflect any pro forma impacts of the GulfTerra Merger, repayments of debt - see
Note 4, changes in ownership of our common unitholders, purchase
accounting-related adjustments or any other adjustments to be made by Enterprise
in connection with the GulfTerra Merger.
The aggregate value of the total consideration Enterprise paid
or issued to complete the GulfTerra Merger was approximately $3.8 billion.
Pursuant to the merger agreements, the GulfTerra Merger occurred in several
interrelated transactions as described below.
o Step One. On December 15, 2003, Enterprise purchased a 50%
membership interest in our general partner, GulfTerra GP, from
El Paso for $425 million in cash. As a result of Step One of
the merger, GulfTerra GP was owned 50% by Enterprise and 50%
by El Paso.
o Step Two. On September 30, 2004, the GulfTerra Merger was
consummated and GulfTerra and GulfTerra GP became wholly-owned
subsidiaries of Enterprise. Step Two of the merger included
the following transactions:
o Immediately prior to closing the GulfTerra Merger,
the general partner of Enterprise ("Enterprise GP")
acquired El Paso's remaining 50% membership interest
in GulfTerra GP for $370 million in cash paid to El
Paso and the issuance of a 9.9% membership interest
in Enterprise GP to El Paso. Subsequently, Enterprise
GP contributed this 50% membership interest in
GulfTerra GP to Enterprise.
o Immediately prior to closing the GulfTerra Merger,
Enterprise paid $500 million in cash to El Paso for
our 10,937,500 outstanding Series C units and
2,876,620 of our common units. After giving effect to
this purchase, our remaining 57,762,369 common units
were converted into 104,549,823 Enterprise common
units using a conversion ratio of 1.81 Enterprise
common units for each GulfTerra common unit
outstanding.
A-8
Enterprise's assumption of Series F2 convertible unit
obligations
Upon completion of the GulfTerra Merger, Enterprise assumed
our obligations associated with the outstanding Series F2 convertible units. As
a result, the 80 Series F2 convertible units outstanding at the merger date were
converted into rights to receive Enterprise common units. The number Enterprise
common units and the price per unit were adjusted based on the 1.81 conversion
ratio. For additional information regarding the Series F convertible units, see
Note 6.
Repayment of certain GulfTerra debt in connection with the
merger
In connection with the closing of our merger with Enterprise
on September 30, 2004, we repaid, in full, the amounts outstanding under our
revolving credit facility and senior secured term loans using funds contributed
by Enterprise - see Note 4. The closing of our merger with Enterprise
constituted a change of control, and thus a default, under our credit
agreements. In order to avoid the default, Enterprise will contribute $961.7
million to us at closing on September 30, 2004, which we will use to fully repay
our outstanding obligations and related interest of $1.2 million under these
agreements. All such contributions and repayments are not reflected in our
September 30, 2004 unaudited condensed consolidated financial statements. For
additional information regarding our remaining debt obligations, see Note 4.
Tender offers for GulfTerra notes in connection with the
merger
On August 4, 2004, in anticipation of completing the merger,
Enterprise commenced four cash tender offers to purchase any and all of our
outstanding senior and senior subordinated notes having a total outstanding
principal amount of approximately $921.5 million. In connection with the tender
offers, we executed supplements to the indentures governing these notes that
eliminated certain restrictive covenants and default provisions contained in
those indentures.
Substantially all of our notes ($915 million of $921.5
million) were tendered pursuant to the tender offers. On October 5, 2004,
Enterprise purchased the notes for a total price of approximately $1.1 billion,
which included $27 million related to consent payments. The following table
shows our four senior debt obligations affected, including the principal amount
of each series of notes tendered, as well as the payment made by Enterprise to
complete the tender offers.
CASH PAYMENTS MADE BY ENTERPRISE
PRINCIPAL --------------------------------------------
AMOUNT ACCRUED TENDER TOTAL
DESCRIPTION TENDERED INTEREST PRICE (1) PRICE
----------- ---------- ---------- ---------- ----------
8.50% Senior Subordinated Notes due 2010
(Represents 98.2% of principal amount outstanding) $ 212,057 $ 6,209 $ 246,366 $ 252,575
10.625% Senior Subordinated Notes due 2012
(Represents 99.9% of principal amount outstanding) 133,916 4,901 167,612 172,513
8.50% Senior Subordinated Notes due 2011
(Represents 99.5% of principal amount outstanding) 319,823 9,364 359,379 368,743
6.25% Senior Notes due 2010
(Represents 99.7% of principal amount outstanding) 249,250 5,366 274,073 279,439
---------- ---------- ---------- ----------
Totals $ 915,046 $ 25,840 $1,047,430 $1,073,270
========== ========== ========== ==========
--------------------------------------------------------------------------------
(1) Tender price includes consent payment of $30 per $1,000 principal amount
tendered.
For additional information regarding our senior and senior
subordinated notes, see Note 4.
A-9
OTHER MERGER-RELATED TRANSACTIONS
Prior to our merger with Enterprise, we determined that it was
in our and our unitholders' best interest to offer selected employees of El Paso
incentives to continue to focus on the business of the partnership during the
merger process. We accounted for the cost of these incentives under the
provisions of SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. In March 2004, we recorded a liability and a related
deferred charge of $4.3 million, which was reflected in other current
liabilities and other current assets on our balance sheets. Our liability was
estimated based upon the number of employees accepting the offer and the
discounted amount they were expected to be paid. During the six months ended
June 30, 2004 and the three months ended September 30, 2004, we recorded $2.8
million and $1.5 million of amortization expense associated with these
incentives.
Additionally, pursuant to the terms of the engagement letter,
we agreed to pay UBS Securities ("UBS") $10.3 million for advisory fees related
to our merger with Enterprise. In the first quarter of 2004, we paid UBS $3.5
million upon receiving a fairness opinion related to the merger, and the
remaining $6.8 million was paid on September 30, 2004.
Furthermore, during the three months ended September 30, 2004,
we recognized a merger-related expense of $4.9 million associated with our
repurchase of the outstanding unit options prior to closing the merger with
Enterprise. Under the merger agreement with Enterprise, we were obligated to
repurchase, at reasonable prices and before the effective time of the merger,
all outstanding employee and director unit options that had not been exercised
or otherwise cancelled. Approximately 1,000,000 common unit options were
outstanding at the merger date, which we repurchased for approximately $13
million. For the unit options accounted for under the provisions of SFAS No.
123, the purchase price recorded had two components. The purchase price paid up
to the fair value of the options as of the valuation date was recorded as the
repurchase of an equity instrument. The payment above that fair value amount was
recorded as compensation expense. For our unit options accounted for under APB
No. 25, the amount paid up to the intrinsic value of the options repurchased was
also accounted for as the repurchase of an equity instrument, with any amount
paid in excess of the intrinsic value recorded as compensation expense.
Lastly, during the six months ended June 30, 2004 and the
three months ended September 30, 2004, we recognized additional merger-related
expenses primarily for legal and audit fees totaling $1.5 million and $1.1
million. All of our merger-related costs are included in operation and
maintenance expenses on our unaudited condensed consolidated statements of
income and are allocated across all of our operating segments.
3. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consisted of the following
at the dates indicated:
SEPTEMBER 30,
2004
-------------
Property, plant and equipment, at cost
Pipelines $2,880,523
Platforms and facilities 165,179
Processing plants 317,638
Oil and natural gas properties 131,166
Storage facilities 337,023
Construction-in-progress 45,005
----------
3,876,534
Less accumulated depreciation, depletion and amortization 949,673
----------
Total property, plant and equipment, net $2,926,861
==========
The values shown in the table above do not reflect any
purchase accounting-related adjustments recorded by Enterprise as a result of
the GulfTerra Merger - see Note 2.
A-10
4. DEBT OBLIGATIONS
Prior to the September 30, 2004 debt repayments and subsequent
tender offer payments, both in connection with the merger - see Note 2, our debt
consisted of the following at the dates indicated:
SEPTEMBER 30,
2004
-------------
Borrowings under:
Revolving Credit Facility (1) $ 462,000
Senior Secured Term Loans (1) 498,500
Senior Notes, 6.25% fixed-rate, due June 2010 (2) 250,000
Senior Subordinated Notes, 10.375% fixed-rate, due June 2009 (3)
Senior Subordinated Notes, 8.50% fixed-rate, due June 2010 (2,4) 215,915
Senior Subordinated Notes, 8.50% fixed-rate, due June 2011 (2) 321,600
Senior Subordinated Notes, 10.625% fixed-rate, due Dec. 2012 (2) 134,000
-----------
Total principal amount 1,882,015
Other, including unamortized premiums and discounts 1,441
-----------
Subtotal long-term debt 1,883,456
Less current maturities of debt (5,000)
-----------
Long-term debt $ 1,878,456
===========
--------------------------------------------------------------------------------
(1) In connection with closing the merger, Enterprise contributed
approximately $962 million to us on September 30, 2004 to repay in full
the $960.5 million in principal amount due under these debt agreements,
plus $1.2 million of related accrued interest - see Note 2.
(2) On October 5, 2004, $915 million of these senior note obligations were
tendered to Enterprise pursuant to its tender offers made in connection
with the merger - see Note 2.
(3) In June 2004, we redeemed, at a premium, all of our 10.375% Senior
Subordinated Notes due 2009.
(4) In April 2004, we redeemed, at a premium, approximately $39.1 million of
our 8.5% Senior Subordinated Notes due June 2010.
After giving effect to the September 30, 2004 debt repayments
and subsequent tender offer payments, both in connection with the merger - see
Note 2, our debt consisted of the following at the dates indicated:
OCTOBER 5, SEPTEMBER 30,
2004 2004
----------- -------------
Borrowings under:
Revolving Credit Facility $ 462,000
Senior Secured Term Loans 498,500
Senior Notes, 6.25% fixed-rate, due June 2010 $ 750 250,000
Senior Subordinated Notes, 10.375% fixed-rate, due June 2009
Senior Subordinated Notes, 8.50% fixed-rate, due June 2010 3,858 215,915
Senior Subordinated Notes, 8.50% fixed-rate, due June 2011 1,777 321,600
Senior Subordinated Notes, 10.625% fixed-rate, due Dec. 2012 84 134,000
---------- ----------
6,469 1,882,015
Other, including unamortized premiums and discounts 1,441
---------- ----------
6,469 1,883,456
Less current maturities of debt (5,000)
---------- ----------
$ 6,469 $1,878,456
========== ==========
A-11
PARENT-SUBSIDIARY GUARANTOR RELATIONSHIPS
After giving effect to the completion of Enterprise's tender offers on
October 5, 2004 -see Note 2, we have $6.5 million in senior and senior
subordinated notes outstanding. These obligations are jointly, severally, fully
and unconditionally guaranteed by us and each of our subsidiaries, excluding our
unrestricted subsidiaries.
DEBT MATURITIES
After giving effect to the completion of Enterprise's tender offers on
October 5, 2004 - see Note 2, aggregate maturities of the principal amounts of
long-term debt are none for the remainder of 2004 and in each of the years 2005
through 2008 and $6.5 million in total after 2008.
INFORMATION REGARDING VARIABLE INTEREST RATES PAID
On September 30, 2004, and prior to the merger-related repayment, we
had $462 million outstanding under our revolving credit facility at an average
interest rate of 3.82%. On September 30, 2004, and prior to the merger-related
repayment, we had $498.5 million outstanding under our senior secured term loans
at an average interest rate of 4.07%.
LOSS DUE TO EARLY REDEMPTIONS OF DEBT
We recognized losses associated with early redemptions of debt as
follows:
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL --------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
------------------------------------------- --------------------------
2004 2003
------------------------------------------- --------------------------
Loss due to payment of redemption premiums $12,401 $12,401
Loss due to write-off of unamortized debt
issuance costs 3,884 3,884 $1,225 $4,987
------- ------- ------ ------
$16,285 $16,285 $1,225 $4,987
======= ======= ====== ======
JOINT VENTURE DEBT OBLIGATIONS
We have ownership interests in three joint ventures having long-term
debt obligations: Cameron Highway Oil Pipeline Company ("Cameron Highway");
Deepwater Gateway, L.L.C. ("Deepwater Gateway"); and Poseidon Oil Pipeline
Company, L.L.C. ("Poseidon"). The following table shows (i) our ownership
interest in each entity at September 30, 2004, (ii) total long-term debt
obligations (including current maturities) of each unconsolidated affiliate on
that date (on a 100% basis to the joint venture), and (iii) the estimated
corresponding scheduled maturities of such long-term debt.
SCHEDULED MATURITIES OF LONG-TERM DEBT
OUR --------------------------------------------------------------
OWNERSHIP AFTER
INTEREST TOTAL 2004 2005 2006 2007 2008 2008
--------------------------------------------------------------------------------------
Cameron Highway (1) 50.0% $ 297,000 $ 16,250 $ 32,500 $ 156,250 $ 92,000
Deepwater Gateway 50.0% 149,500 $ 5,500 $ 22,000 22,000 22,000 22,000 56,000
Poseidon (2) 36.0% 116,000 116,000
--------- -------- -------- -------- -------- --------- --------
Total $ 562,500 $ 5,500 $ 22,000 $ 38,250 $ 54,500 $ 294,250 $148,000
========= ======== ======== ======== ======== ========= ========
-------------------------------------------------------------------------------
(1) Cameron Highway has a total borrowing capacity under its project loan
facility of $325 million. The scheduled maturities for Cameron Highway
assume that the construction loan is or will be converted into a term loan
on June 30, 2005 and the scheduled repayments will begin on September 30,
2006.
(2) Poseidon has a total borrowing capacity of $170 million under its revolving
credit facility.
A-12
At September 30, 2004, long-term debt for Cameron Highway consisted of
$197 million outstanding under a variable-rate construction loan and $100
million of senior secured notes. Cameron Highway has a borrowing capacity of
$225 million under its construction loan. At September 30, 2004, the average
variable interest rate charged under Cameron Highway's construction loan
agreement was 4.97%. The interest rate on Cameron Highway's senior secured notes
is 3.25% over the rate on 10-year U.S. treasury securities, which at September
30, 2004 was 7.4%.
At September 30, 2004, long-term debt for Deepwater Gateway consisted
of $149.5 million due under a project finance loan used to fund a portion of the
construction costs of the Marco Polo tension leg platform ("TLP") and related
facilities. Construction of the Marco Polo TLP was completed during the first
quarter of 2004, and in June 2004, Deepwater Gateway converted the project
finance loan into a term loan which matures in June 2009. At September 30, 2004,
the average variable interest rate charged under Deepwater Gateway's term loan
was 3.6%.
At September 30, 2004, long-term debt for Poseidon consisted of $116
million due under a revolving credit facility, which matures in January 2008. At
September 30, 2004, the average variable interest rate charged under Poseidon's
credit agreement was 3.7%.
5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
We own interests in various related businesses that are accounted for
using the equity method. In general, we use the equity method of accounting for
an investment in which we own 20% to 50% of its outstanding ownership interests
and exercise significant influence over its operating and financial policies.
Our investments in unconsolidated affiliates totaled $210.7 million at September
30, 2004.
The following table shows our equity in income of unconsolidated
affiliates for the periods indicated:
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL -------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
----------------------------------------- -------------------------
2004 2003
----------------------------------------- -------------------------
Cameron Highway (1) $ (57) $ (57)
Coyote 1,118 $ 577 1,695 $ 516 $ 1,771
Deepwater Gateway (2) 1,209 3,111 4,320
Poseidon 3,226 2,127 5,353 1,797 6,845
Other (3) (30) (3,714) (3,744) 882 882
------- ------- ------- ------- -------
Total $ 5,466 $ 2,101 $ 7,567 $ 3,195 $ 9,498
======= ======= ======= ======= =======
(1) Cameron Highway is a development stage company at September 30, 2004;
therefore, there are no operating revenues or expenses. Since its formation
in June 2003, it has incurred organizational expenses and received interest
income. In September 2004, construction of the Cameron Highway oil pipeline
system was completed and we anticipate that operations will begin during the
fourth quarter of 2004 or the first quarter of 2005.
(2) The Marco Polo TLP, which is owned by Deepwater Gateway, was installed in
the first quarter of 2004. First production and thus volumetric payments
started in July 2004. In April 2004, Deepwater Gateway began receiving
monthly demand payments of $2.1 million. Prior to the installation of this
platform, Deepwater Gateway was a development stage company; therefore,
there were no operating revenues or operating expenses.
(3) The 2004 period includes a $3.7 million loss associated with our write-off
of a note receivable from El Paso we received in connection with the sale of
our interest in Copper Eagle Gas Storage, L.L.C. ("Copper Eagle") to El Paso
in August 2003. The 2003 period includes a $0.9 million gain we initially
recorded on the sale of our interest in Cooper Eagle to El Paso. See Note 8
for additional information regarding this related party transaction.
A-13
The following table presents unaudited summarized income statement
information for our current unconsolidated affiliates from which we have
recorded equity earnings (for the periods indicated, on a 100% basis).
SIX MONTHS ENDED THREE MONTHS ENDED
----------------------------------------------- ------------------------------------------------
JUNE 30, 2004 SEPTEMBER 30, 2004
----------------------------------------------- ------------------------------------------------
NET NET
REVENUES INCOME (LOSS) REVENUES INCOME (LOSS)
----------------------------------------------- ------------------------------------------------
Cameron Highway $ (298) $ (290)
Deepwater Gateway $ 6,300 2,800 $ 9,598 6,124
Poseidon 18,116 8,780 9,399 6,193
Coyote 3,600 2,244 1,800 1,137
NINE MONTHS TOTAL
-----------------------------------------------
SEPTEMBER 30,2004
-----------------------------------------------
NET
REVENUES INCOME (LOSS)
-------------------- --- ----------------------
Cameron Highway $ (588)
Deepwater Gateway $ 15,898 8,924
Poseidon 27,515 14,973
Coyote 5,400 3,381
THREE MONTHS ENDED NINE MONTHS ENDED
----------------------------------------------- ------------------------------------------------
SEPTEMBER 30, 2003 SEPTEMBER 30, 2003
----------------------------------------------- ------------------------------------------------
NET NET
REVENUES INCOME REVENUES INCOME
----------------------------------------------- ------------------------------------------------
Cameron Highway
Deepwater Gateway $ 14 $ 32
Poseidon $ 9,425 5,278 $ 32,632 19,356
Coyote 1,800 1,014 5,625 3,524
6. PARTNERS' CAPITAL
On September 30, 2004, we completed our merger with Enterprise - see
Note 2. These unaudited condensed consolidated financial statements do not
reflect any changes in ownership of our common unitholders as a result of the
merger. Effective September 30, 2004, most of our then outstanding limited
partner interests were converted to Enterprise limited partner interests
pursuant to the merger. Those limited partner interests that were not converted
into Enterprise limited partner interests were purchased by Enterprise from El
Paso for cash immediately prior to the merger. As a result of the merger, we
ceased as being a publicly-traded company subject to the filing requirements of
the SEC.
During the first nine months of 2004 we received net proceeds of
approximately $78.3 million from the conversion of 80 Series F1 convertible
units into 2,061,109 common units (45 Series F1 convertible units were converted
into 1,146,418 common units with proceeds paid to us of $45 million during the
first six months of 2004). As a result of these conversions in 2004, all of the
Series F1 convertible units were converted into GulfTerra common units by the
holder prior to our merger with Enterprise. On the merger closing date,
Enterprise assumed our obligations associated with the outstanding Series F2
convertible units.
A-14
The following table reflects our cash distribution history for the nine
months ended September 30, 2004 (dollars in millions, except per unit amounts):
COMMON COMMON SERIES C GENERAL
MONTH PAID UNIT UNITHOLDERS UNITHOLDERS PARTNER
---------- ---------- ----------- ----------- -----------
February $ 0.71 $ 41.5 $ 7.8 $ 21.3
May $ 0.71 $ 42.4 $ 7.8 $ 21.7
August $ 0.71 $ 42.6 $ 7.8 $ 21.7
7. EARNINGS PER COMMON UNIT
The following table sets forth the computation of basic and diluted
earnings per common unit (dollars in thousands, except per unit amounts):
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED TOTAL ---------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
------------------------------------------- ---------------------------
2004 2003
------------------------------------------- ---------------------------
Numerator:
Numerator for basic earnings per common unit:
Income before cumulative effect of
accounting change $51,087 $26,044 $77,131 $31,337 $72,951
Cumulative effect of accounting change 1,340
------- ------- ------- ------- -------
$51,087 $26,044 $77,131 $31,337 $74,291
======= ======= ======= ======= =======
Denominator:
Denominator for basic earnings per common unit:
weighted-average common units 59,298 59,946 59,515 50,072 47,388
Effect of dilutive securities:
Unit options 244 270 139
Restricted units 23 26 26 14 11
Series F convertible units 1 1 29 115
------- ------- ------- ------- -------
Denominator for diluted earnings per common unit:
Adjusted for weighted-average common units 59,566 59,972 59,542 50,385 47,653
======= ======= ======= ======= =======
Basic earnings per common unit
Income before cumulative effect of accounting
change $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.54
Cumulative effect of accounting change 0.03
------- ------- ------- ------- -------
$ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.57
======= ======= ======= ======= =======
Diluted earnings per common unit
Income before cumulative effect of accounting
change $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.53
Cumulative effect of accounting change 0.03
------- ------- ------- ------- -------
$ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.56
======= ======= ======= ======= =======
A-15
8. RELATED PARTY TRANSACTIONS
For the nine months ended September 30, 2004, there were no
changes to our related party relationships. Prior to our merger with
Enterprise, our largest related party was our parent company, El Paso. As a
result of our merger with Enterprise, El Paso is no longer classified as a
related party to us.
Revenues received from related parties for the six months
ended June 30, 2004 and the three months ended September 30, 2004, were
approximately 17 percent and 16 percent of our total revenue. Revenues received
from related parties for the three and nine months ended September 30, 2003,
were approximately 12 percent and 13 percent of our total revenue.
Our transactions with related parties and affiliates are as follows:
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED ENDED ---------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
----------------------------------------- ---------------------------
2004 2003
----------------------------------------- ---------------------------
Revenues received from related parties:
Natural gas pipelines and plants $ 43,513 $ 21,107 $ 64,620 $ 18,054 $ 67,068
Oil and NGL logistics 30,247 15,250 45,497 6,842 22,686
-------- -------- -------- -------- --------
Total $ 73,760 $ 36,357 $110,117 $ 24,896 $ 89,754
======== ======== ======== ======== ========
Expenses paid to related parties:
Cost of natural gas and other products $ 16,011 $ 4,046 $ 20,057 $ 6,191 $ 26,988
Operation and maintenance 45,665 23,501 69,166 22,229 68,039
-------- -------- -------- -------- --------
Total $ 61,676 $ 27,547 $ 89,223 $ 28,420 $ 95,027
======== ======== ======== ======== ========
Reimbursements received from related parties:
Operation and maintenance $ 1,629 $ 707 $ 2,336 $ 659 $ 1,860
======== ======== ======== ======== ========
The following table provides summary data categorized by our related
parties:
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED ENDED ---------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
----------------------------------------- ---------------------------
2004 2003
----------------------------------------- ---------------------------
Revenues received from related parties:
El Paso $ 73,146 $ 35,977 $109,123 $ 24,986 $ 89,754
Enterprise 614 380 994
-------- -------- -------- -------- --------
Total $ 73,760 $ 36,357 $110,117 $ 24,986 $ 89,754
======== ======== ======== ======== ========
Cost of natural gas and other products paid
to related parties:
El Paso $ 16,011 $ 4,046 $ 20,057 $ 6,191 $ 26,988
======== ======== ======== ======== ========
Operation and maintenance expenses paid to
related parties:
El Paso $ 45,443 $ 23,389 $ 68,832 $ 22,120 $ 67,723
Unconsolidated affiliates 222 112 334 109 316
-------- -------- -------- -------- --------
Total $ 45,665 $ 23,501 $ 69,166 $ 22,229 $ 68,039
======== ======== ======== ======== ========
Reimbursements received from related parties:
Unconsolidated affiliates $ 1,629 $ 707 $ 2,336 $ 659 $ 1,860
======== ======== ======== ======== ========
A-16
Our accounts receivable due from related parties consisted of the
following as of:
SEPTEMBER 30,
2004
-------------
El Paso $18,512
Enterprise 279
Unconsolidated affiliates 8,496
-------
Total $27,287
=======
Our accounts payable due to related parties consisted of the following
as of:
SEPTEMBER 30,
2004
-------------
El Paso $35,167
Unconsolidated Subsidiaries 3,830
-------
Total $38,997
=======
Other matters
Petal. In September 2003, we entered into a nonbinding letter
of intent with El Paso, regarding the proposed development and sale of a natural
gas storage cavern, and the proposed sale of an undivided interest in a related
pipeline and other facilities related to that natural gas storage cavern. In
June 2004, we and El Paso terminated the letter of intent and we announced that
we would hold a nonbinding open season to determine market interest for up to
5.0 Bcf of firm natural gas storage capacity, and up to 500,000 MMBtu/d of firm
transportation on the Petal pipeline, all available in the third quarter of
2007.
Copper Eagle. In August 2003, a majority-owned subsidiary of
ours sold its interest in Copper Eagle Gas Storage, L.L.C. ("Copper Eagle") to
El Paso. Copper Eagle is developing a natural gas storage project located
outside of Phoenix, Arizona. Under the original sale agreement with El Paso, we
had the right to receive $6.2 million of the sale proceeds, including a note
receivable for $4.9 million that was to be paid quarterly beginning in January
2004 and ending in October 2004. As of September 30, 2004, we had received
principal payments totaling $1.3 million from El Paso related to the note
receivable. Prior to the sale, we accounted for our investment in Copper Eagle
using the equity method.
The proposed natural gas storage project has received strong
local opposition by developers and residents due to the close proximity to
residential communities. Further, the storage facilities will be near the Luke
Air Force Base and the Arizona legislature recently reached a resolution which
prohibits the development of a hydrocarbon storage facility within a nine mile
range of an air force base or airport. As a result of these developments, we
have changed our view on the probability that the Copper Eagle natural gas
storage project will actually be developed and we wrote-off the remaining $3.7
million note receivable from El Paso as uncollectible during the third quarter
of 2004. The write-off was recorded as a reduction to equity in income of
unconsolidated affiliates - see Note 5. In addition, we reduced our minority
interest balance by $1.8 million and recognized minority interest income of $1.8
million, which reflects the portion of the write-off allocated to the minority
interest owner of our subsidiary.
Indemnifications. In addition to the related party
transactions discussed above, pursuant to the terms of many of the purchase and
sale agreements we have entered into with various entities controlled directly
or indirectly by El Paso, we have been indemnified for potential future
liabilities, expenses and capital requirements above a negotiated threshold.
Some of our agreements obligate certain indirect subsidiaries of El Paso to pay
for capital costs related to maintaining assets which were acquired by us, if
such costs exceed negotiated thresholds. We have not made any claims during the
nine months ended September 30, 2004 or 2003. However, for the full year of
2003, we made claims for approximately $5 million of costs incurred during the
year ended December 31, 2003, as costs exceeded the established thresholds for
2003.
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Wilson storage operating lease commitment. In connection with
our April 2002 purchase of the EPN Holding assets from El Paso, we obtained a
long-term operating lease commitment related to the Wilson natural gas storage
facility, which is operated by one of our direct subsidiaries. From the
acquisition date until the second quarter of 2004, El Paso guaranteed our direct
subsidiary's payment and performance under this commitment. In the second
quarter of 2004, El Paso was released from the guarantee and, thus, we now are
solely liable for our direct subsidiary's payment and performance under this
operating lease agreement.
9. COMMITMENTS AND CONTINGENCIES
LITIGATION
We are sometimes named as a defendant in litigation relating
to our normal business operations. Although we insure against various business
risks, to the extent management believes it is prudent, there is no assurance
that the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from legal proceedings as a result of
ordinary business activity. Management is not aware of any significant
litigation, pending or threatened, that would have a significant adverse effect
on our financial position or results of operations.
ENVIRONMENTAL
Environmental costs for remediation are accrued at their
undiscounted estimated amounts based on known remediation requirements. Such
accruals are based on management's best estimate of the ultimate costs to
remediate a given site and take into account the likely effects of inflation and
other societal and economic factors, including estimated associated legal costs.
We expense amounts for clean up of existing environmental contamination caused
by past operations which do not benefit future periods. We expense or capitalize
expenditures for ongoing compliance with environmental regulations that relate
to past or current operations as appropriate. As of September 30, 2004, we had
an environmental liability initially estimated at $21 million, which is included
in other long-term liabilities on our unaudited condensed consolidated balance
sheet, for remediation costs expected to be incurred over time associated with
mercury gas meters.
While the outcome of our outstanding environmental matters
cannot be predicted with certainty, based on the information known to date and
our existing accruals, we do not expect the ultimate resolution of these matters
to have a material adverse effect on our financial position, results of
operations or cash flows. It is possible that new information or future
developments could require us to reassess our potential exposure related to
environmental matters. We may incur significant costs and liabilities in order
to comply with existing laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws and regulations and
claims for damage to property, employees, other persons and the environment
resulting from our current or past operations, could result in substantial costs
and liabilities in the future. As this information becomes available, or
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our current
reserves are adequate.
JOINT VENTURES
We conduct a portion of our activities through joint venture
business arrangements formed to construct, operate and finance the development
of our onshore and offshore midstream energy businesses. We are obligated to
make our proportionate share of additional capital contributions to our joint
ventures only to the extent that they are unable to satisfy their obligations
from other sources including proceeds from credit arrangements. Examples of this
type of business arrangement include our equity method investments in Cameron
Highway, Deepwater Gateway and Poseidon.
A-18
OTHER COMMITMENTS
Long-term debt-related commitments. We have long-term payment
obligations under our senior and senior subordinated notes. See Note 4 for a
description of these debt obligations.
Operating lease commitments. We lease certain storage
facilities located in Texas (one natural gas facility and two NGL facilities).
At September 30, 2004, the future minimum lease payments associated with these
operating lease commitments are as follows: $0.4 million, 2004; $7 million,
2005; $7 million, 2006; $5.8 million, 2007; $3.2 million, 2008; and $1.8 million
thereafter.
10. ACCOUNTING FOR HEDGING ACTIVITIES
A majority of our commodity purchases and sales, which relate
to sales of oil and natural gas associated with our production operations,
purchases and sales of natural gas associated with pipeline operations, sales of
natural gas liquids ("NGL") and purchases or sales of gas associated with our
processing plants and our gathering activities, are at spot market or forward
market prices. We use futures, forward contracts, and swaps to limit our
exposure to fluctuations in the commodity markets and allow for a fixed cash
flow stream from these activities.
In February and August 2003, we entered into derivative
financial instruments to hedge our exposure during 2004 to changes in natural
gas prices relating to gathering activities in the San Juan Basin. In September
2004, we settled the open San Juan natural gas hedges for October, November and
December 2004, prior to their expiration date and prior to our merger with
Enterprise. The derivatives were financial swaps on 30,000 MMBtu per day whereby
we received an average fixed price of $4.23 per MMBtu and paid a floating price
based on the San Juan index. As a result of our early settlement of the open San
Juan natural gas hedges, we paid the counterparties, J. Aaron and Company and
UBS Energy LLC, $2.5 million during the third quarter of 2004. The derivatives
were marked to fair value just prior to settlement and the loss on the
settlement was recorded in accumulated other comprehensive income and will be
reclassified to earnings in the periods that the previously hedged transaction
would have occurred.
In September 2004 and prior to our merger with Enterprise, we
entered into a derivative financial instrument to hedge our exposure during
November 2004 through March 2005 to changes in natural gas prices relating to
gathering activities in the San Juan Basin. The derivative is a financial swap
on 40,000 MMBtu per day whereby we receive a fixed price of $6.71 per MMBtu and
pay a floating price based on the San Juan index. As of September 30, 2004, the
fair value of this cash flow hedge was a liability of $0.7 million, as the
market price at this date was higher than the hedge price. As a result of our
merger with Enterprise on September 30, 2004, Enterprise assumed the liability
associated with the hedge. We are accounting for this derivative as a cash flow
hedge under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities. No ineffectiveness exists in this hedging relationship because all
purchase and sales prices are based on the same index and volumes as the hedge
transaction. The counterparty for the San Juan hedge activity is UBS Energy LLC.
We do not require collateral or anticipate non-performance by this counterparty.
During 2003, we entered into derivative financial instruments
to hedge a portion of our business' exposure to changes in NGL prices during
2004. We entered into financial swaps for 6,000 barrels per day for the period
from August 2003 to September 2004. The average fixed price received was $0.47
per gallon for 2004 while we paid a monthly average floating price based on the
Oil Pricing Information Service average price for each month. In September 2004,
these cash flow hedges expired and for the six months ended June 30, 2004 and
the three months ended September 30, 2004, we reclassified approximately $4.6
million and $5.2 million of unrealized losses from accumulated other
comprehensive income to earnings. These reclassifications are included in our
natural gas pipelines and plants segment. No ineffectiveness exists in this
hedging relationship because all purchase and sales prices are based on the same
index and volumes as the hedge transaction.
In connection with our GulfTerra Intrastate Alabama
operations, we had fixed price contracts with specific customers for the sale of
predetermined volumes of natural gas for delivery over established periods of
time. We entered into cash flow hedges in 2003 to offset the risk of increasing
natural gas prices. For January and February 2004, we contracted to purchase
20,000 MMBtu and for March 2004, we contracted to purchase 15,000 MMBtu. The
average fixed price paid during 2004 was $5.28 per MMBtu while we received a
floating price based on the
A-19
Southern Natural Pipeline index as published by the periodical "Inside FERC". In
March 2004, these cash flow hedges expired and we reclassified a gain of
approximately $45 thousand from accumulated other comprehensive income to
earnings. This reclassification is included in our natural gas pipelines and
plants segment. No ineffectiveness existed in this hedging relationship because
all purchase and sale prices were based on the same index and volumes as the
hedge transaction.
In July 2003, to achieve a more balanced mix of fixed rate
debt and variable rate debt, we entered into an eight-year interest rate swap
agreement to provide for a floating interest rate on $250 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we paid the
counterparty a LIBOR based interest rate plus a spread of 4.20% and received a
fixed rate of 8 1/2%. We accounted for this derivative as a fair value hedge
under SFAS No. 133. In March 2004, we terminated our fixed to floating interest
rate swap with our counterparty. The value of the transaction at termination was
zero and as such neither we, nor our counterparty, were required to make any
payments. Also, neither we, nor our counterparty, have any future obligations
under this transaction.
We estimate the entire $3.3 million of unrealized losses
included in accumulated other comprehensive income at September 30, 2004, will
be reclassified from accumulated other comprehensive income as a reduction to
earnings over the next six months. When our derivative financial instruments are
settled, the related amount in accumulated other comprehensive income is
recorded in the income statement in operating revenues, cost of natural gas and
other products, or interest and debt expense, depending on the item being
hedged. The effect of reclassifying these amounts to the income statement line
items is recording our earnings for the period related to the hedged items at
the "hedged price" under the derivative financial instruments.
11. BUSINESS SEGMENT INFORMATION
Historically, we have segregated our business activities into
four distinct operating segments: Natural gas pipelines and plants; Oil and NGL
logistics; Natural gas storage; and Platform services. Each of our segments are
business units that offer different services and products that are managed
separately since each segment's operations required different technology and
marketing strategies.
Prior our merger with Enterprise, we used performance cash
flows to (i) evaluate the performance of our business segments, (ii) determine
how resources would be allocated among the segments and (iii) develop strategic
plans for our overall business. We defined performance cash flows as earnings
before interest, depreciation and amortization and other adjustments.
Historically, our lenders and equity investors viewed our performance cash flows
measure as an indication of our ability to generate sufficient cash to meet debt
obligations or to pay distributions to partners. In addition, this non-GAAP
measure was useful to investors because it allowed them to evaluate the
effectiveness of our business segments from an operational perspective,
exclusive of the costs to finance those activities and depreciation and
amortization (neither of which are directly relevant to the efficiency of those
operations). Performance cash flows may not be comparable to measurements used
by other companies and should not be used a substitute for net income or other
performance measures. In this context and for transition purposes only, we have
presented performance cash flows as our measure of segment earnings for the six
months ended June 30, 2004, the three months ended September 30, 2004 and the
three and nine months ended September 30, 2003. Beginning October 1, 2004, we
will conform our non-GAAP financial measures to those used by Enterprise.
A-20
Information by segment, together with reconciliations to the consolidated
totals, is presented in the following table:
NATURAL GAS OIL AND NATURAL
PIPELINES & NGL GAS PLATFORM NON-SEGMENT
PLANTS LOGISTICS STORAGE SERVICES ACTIVITY(1) TOTAL
----------- ---------- ---------- ---------- ----------- ----------
SIX MONTHS ENDED JUNE 30, 2004
Revenue from external customers $ 364,493 $ 35,005 $ 24,193 $ 12,932 $ 8,934 $ 445,557
Intersegment revenue 64 1,164 (1,228)
Equity in income of unconsolidated affiliates 1,118 3,169 (30) 1,209 5,466
Performance cash flows 165,917 20,720 16,782 12,179
Assets 2,344,760 464,228 317,221 175,161 84,721 3,386,091
THREE MONTHS ENDED SEPTEMBER 30, 2004
Revenue from external customers $ 188,567 $ 20,871 $ 11,129 $ 6,772 $ 3,826 $ 231,165
Intersegment revenue 26 566 (592)
Equity in income of unconsolidated affiliates 576 2,126 (3,713) 3,112 2,101
Performance cash flows 79,655 13,021 5,806 5,471
Assets 2,360,943 471,399 301,894 176,734 85,319 3,396,289
NINE MONTHS TOTAL SEPTEMBER 30, 2004
Revenue from external customers $ 553,060 $ 55,876 $ 35,322 $ 19,704 $ 12,760 $ 676,722
Intersegment revenue 90 1,730 (1,820)
Equity in income of unconsolidated affiliates 1,694 5,295 (3,743) 4,321 7,567
Performance cash flows 245,572 33,741 22,588 17,650
Assets 2,360,943 471,399 301,894 176,734 85,319 3,396,289
THREE MONTHS ENDED SEPTEMBER 30, 2003
Revenue from external customers (2) $ 180,879 $ 13,205 $ 10,252 $ 5,185 $ 4,310 $ 213,831
Intersegment revenue 29 600 (629)
Equity in income of unconsolidated affiliates 516 1,797 882 3,195
Performance cash flows 80,002 26,782 7,518 4,885
Assets 2,227,900 444,253 314,192 163,000 132,424 3,281,769
NINE MONTHS ENDED SEPTEMBER 30, 2003
Revenue from external customers (2) $ 577,585 $ 41,182 $ 32,729 $ 15,668 $ 13,793 $ 680,957
Intersegment revenue 97 278 2,004 (2,379)
Equity in income of unconsolidated affiliates 1,771 6,845 882 9,498
Performance cash flows 236,223 51,279 22,587 15,397
Assets 2,227,900 444,253 314,192 163,000 132,424 3,281,769
-------------------------------------------------------------------------------
(1) Represents predominantly our oil and natural gas production activities as
well as intersegment eliminations. Our intersegment revenues, along with our
intersegment operating expenses, consist of normal course of business-type
transactions between our operating segments. We record an intersegment revenue
elimination, which is the only elimination included in the "Non-Segment
Activity" column, to remove intersegment transactions.
(2) Revenue from external customers for our Oil and NGL Logistics segment has
been reduced by $69.8 million and $191.7 million for the quarter and nine months
ended September 30, 2003 to reflect the revision of Typhoon Oil Pipeline's
revenues and cost of natural gas and other products to conform to the current
period presentation - see Note 1.
A-21
A reconciliation of our segment performance cash flows to our
consolidated net income is as follows:
THREE MONTHS NINE MONTHS
SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED
ENDED ENDED ENDED ---------------------------
JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
------------------------------------------- ---------------------------
2004 2003
------------------------------------------- ---------------------------
Natural gas pipelines and plants $ 165,917 $ 79,655 $ 245,572 $ 80,002 $ 236,223
Oil and NGL logistics 20,720 13,021 33,741 26,782 51,279
Natural gas storage 16,782 5,806 22,588 7,518 22,587
Platform services 12,179 5,471 17,650 4,885 15,397
--------- --------- --------- --------- ---------
Segment performance cash flows 215,598 103,953 319,551 119,187 325,486
Plus: Other, non-segment results 8,692 2,150 10,842 3,640 11,917
Equity in income of unconsolidated
affiliates 5,466 2,101 7,567 3,195 9,498
Cumulative effect of accounting change 1,690
Less: Interest and debt expense 54,727 27,951 82,678 33,197 99,521
Loss due to early redemptions of debt 16,285 16,285 1,225 4,987
Depreciation, depletion and amortization 52,303 28,994 81,297 25,218 73,761
Distributions received from unconsolidated
affiliates 1,450 750 2,200 3,160 11,390
Minority interest (12) (1,813) (1,825) 889 969
Net cash payment received from El Paso 1,960 1,960 2,120 6,238
--------- --------- --------- --------- ---------
Net income $ 103,043 $ 52,322 $ 155,365 $ 60,213 $ 151,725
========= ========= ========= ========= =========
A-22