UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): December 15, 2003
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 (I.R.S. Employer
Incorporation or Organization) File Number) Identification No.)
2727 NORTH LOOP WEST, HOUSTON, TEXAS 77008
(Address of Principal Executive Offices) (Zip Code)
(713) 880-6500
(Registrant's Telephone Number, including Area Code)
EXPLANATORY NOTE
On December 15, 2003, Enterprise Products Partners L.P. ("Enterprise") and
certain of its affiliates, El Paso Corporation ("El Paso") and certain of its
affiliates, and GulfTerra Energy Partners, L.P. ("GulfTerra") and certain of its
affiliates entered into a series of definitive agreements pursuant to which
Enterprise and GulfTerra will merge. The purpose of this Current Report on Form
8-K is to file (1) the consolidated financial statements of GulfTerra as of
December 31, 2003 and 2002 and for the three year period ended December 31,
2003, and (2) the financial statements of Poseidon Oil Pipeline Company, L.L.C.,
an unconsolidated affiliate of GulfTerra, as of December 31, 2003 and 2002 and
for the three year period ended December 31, 2003, pursuant to the requirements
of S-X Rule 3-05(a) and (b), in connection with Enterprise's proposed merger
with GulfTerra. Enterprise is filing these financial statements with this report
so that they will be incorporated by reference in its currently effective
registration statements.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS.
(a) Financial statements of businesses acquired.
1. 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.
2. 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.
1
REPORT OF INDEPENDENT AUDITORS
To the Unitholders of GulfTerra Energy Partners, L.P.
and the Board of Directors and Stockholders of
GulfTerra Energy Company, L.L.C., as General Partner:
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, comprehensive income and changes in
accumulated other comprehensive income (loss), partners' capital and cash flows
present fairly, in all material respects, the financial position of GulfTerra
Energy Partners, L.P. and its subsidiaries (the "Partnership") at December 31,
2003 and 2002, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Partnership's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, the
Partnership has entered into a definitive agreement to merge with Enterprise
Products Partners L.P.
As discussed in Note 1 to the consolidated financial statements, the
Partnership changed its method of accounting for asset retirement obligations
and its reporting for gains or losses resulting from the extinguishment of debt
effective January 1, 2003.
As discussed in Note 1 to the consolidated financial statements, the
Partnership changed its method of accounting for the impairment or disposal of
long lived assets effective January 1, 2002.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 12, 2004
2
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------------
2003 2002 2001
---------- -------- --------
Operating revenues
Natural gas pipelines and plants
Natural gas sales......................................... $ 171,738 $ 85,001 $ 59,701
NGL sales................................................. 121,167 32,978 --
Gathering and transportation.............................. 388,777 194,336 33,849
Processing................................................ 52,988 45,266 7,133
---------- -------- --------
734,670 357,581 100,683
---------- -------- --------
Oil and NGL logistics
Oil sales................................................. 2,231 108 --
Oil transportation........................................ 26,769 8,364 7,082
Fractionation............................................. 22,034 26,356 25,245
NGL storage............................................... 2,816 2,817 --
---------- -------- --------
53,850 37,645 32,327
---------- -------- --------
Platform services........................................... 20,861 16,672 15,385
Natural gas storage......................................... 44,297 28,602 19,373
Other -- oil and natural gas production..................... 17,811 16,890 25,638
---------- -------- --------
871,489 457,390 193,406
---------- -------- --------
Operating expenses
Cost of natural gas and other products.................... 287,157 108,819 51,542
Operation and maintenance................................. 189,702 115,162 33,279
Depreciation, depletion and amortization.................. 98,846 72,126 34,778
Asset impairment charge................................... -- -- 3,921
(Gain) loss on sale of long-lived assets.................. (18,679) 473 11,367
---------- -------- --------
557,026 296,580 134,887
---------- -------- --------
Operating income............................................ 314,463 160,810 58,519
---------- -------- --------
Earnings from unconsolidated affiliates..................... 11,373 13,639 8,449
Minority interest income (expense).......................... (917) 60 (100)
Other income................................................ 1,206 1,537 28,726
Interest and debt expense................................... 127,830 81,060 41,542
Loss due to early redemptions of debt....................... 36,846 2,434 --
---------- -------- --------
Income from continuing operations........................... 161,449 92,552 54,052
Income from discontinued operations......................... -- 5,136 1,097
Cumulative effect of accounting change...................... 1,690 -- --
---------- -------- --------
Net income.................................................. $ 163,139 $ 97,688 $ 55,149
========== ======== ========
See accompanying notes.
3
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME -- (CONTINUED)
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEAR ENDED DECEMBER 31,
---------------------------
2003 2002 2001
------- ------- -------
Income allocation
Series B unitholders...................................... $11,792 $14,688 $17,228
======= ======= =======
General partner
Income from continuing operations...................... $69,414 $42,082 $24,650
Income from discontinued operations.................... -- 51 11
Cumulative effect of accounting change................. 17 -- --
------- ------- -------
$69,431 $42,133 $24,661
======= ======= =======
Common unitholders
Income from continuing operations...................... $65,155 $34,275 $12,174
Income from discontinued operations.................... -- 5,085 1,086
Cumulative effect of accounting change................. 1,340 -- --
------- ------- -------
$66,495 $39,360 $13,260
======= ======= =======
Series C unitholders
Income from continuing operations...................... $15,088 $ 1,507 $ --
Cumulative effect of accounting change................. 333 -- --
------- ------- -------
$15,421 $ 1,507 $ --
======= ======= =======
Basic earnings per common unit
Income from continuing operations......................... $ 1.30 $ 0.80 $ 0.35
Income from discontinued operations....................... -- 0.12 0.03
Cumulative effect of accounting change.................... 0.03 -- --
------- ------- -------
Net income................................................ $ 1.33 $ 0.92 $ 0.38
======= ======= =======
Diluted earnings per common unit
Income from continuing operations......................... $ 1.30 $ 0.80 $ 0.35
Income from discontinued operations....................... -- 0.12 0.03
Cumulative effect of accounting change.................... 0.02 -- --
------- ------- -------
Net income................................................ $ 1.32 $ 0.92 $ 0.38
======= ======= =======
Basic weighted average number of common units outstanding... 49,953 42,814 34,376
======= ======= =======
Diluted weighted average number of common units
outstanding............................................... 50,231 42,814 34,376
======= ======= =======
See accompanying notes.
4
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31,
------------------------
2003 2002
---------- ----------
ASSETS
Current assets
Cash and cash equivalents................................. $ 30,425 $ 36,099
Accounts receivable, net
Trade.................................................. 43,203 90,379
Unbilled trade......................................... 63,067 49,140
Affiliates............................................. 47,965 83,826
Affiliated note receivable................................ 3,768 --
Other current assets...................................... 20,595 3,451
---------- ----------
Total current assets.............................. 209,023 262,895
Property, plant and equipment, net.......................... 2,894,492 2,724,938
Intangible assets........................................... 3,401 3,970
Investments in unconsolidated affiliates.................... 175,747 95,951
Other noncurrent assets..................................... 38,917 43,142
---------- ----------
Total assets...................................... $3,321,580 $3,130,896
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
Accounts payable
Trade.................................................. $ 113,820 $ 120,140
Affiliates............................................. 38,870 86,144
Accrued gas purchase costs................................ 15,443 6,584
Accrued interest.......................................... 11,199 15,028
Current maturities of senior secured term loan............ 3,000 5,000
Other current liabilities................................. 27,035 21,195
---------- ----------
Total current liabilities......................... 209,367 254,091
Revolving credit facility................................... 382,000 491,000
Senior secured term loans, less current maturities.......... 297,000 552,500
Long-term debt.............................................. 1,129,807 857,786
Other noncurrent liabilities................................ 49,043 23,725
---------- ----------
Total liabilities................................. 2,067,217 2,179,102
---------- ----------
Commitments and contingencies
Minority interest........................................... 1,777 1,942
Partners' capital
Limited partners
Series B preference units; 125,392 units in 2002 issued
and outstanding....................................... -- 157,584
Common units; 58,404,649 and 44,030,314 units in 2003
and 2002 issued and outstanding....................... 898,072 433,150
Series C units; 10,937,500 units in 2003 and 2002
issued and outstanding................................ 341,350 350,565
General partner........................................... 13,164 8,553
---------- ----------
Total partners' capital........................... 1,252,586 949,852
---------- ----------
Total liabilities and partners' capital........... $3,321,580 $3,130,896
========== ==========
See accompanying notes.
5
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- ----------- ---------
Cash flows from operating activities
Net income................................................ $ 163,139 $ 97,688 $ 55,149
Less cumulative effect of accounting change............... 1,690 -- --
Less income from discontinued operations.................. -- 5,136 1,097
--------- ----------- ---------
Income from continuing operations......................... 161,449 92,552 54,052
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization............... 98,846 72,126 34,778
Asset impairment charge................................ -- -- 3,921
Distributed earnings of unconsolidated affiliates
Earnings from unconsolidated affiliates.............. (11,373) (13,639) (8,449)
Distributions from unconsolidated affiliates......... 12,140 17,804 35,062
(Gain) loss on sale of long-lived assets............... (18,679) 473 11,367
Loss due to write-off of unamortized debt issuance
costs, premiums and discounts........................ 12,544 2,434 --
Amortization of debt issuance costs.................... 7,498 4,443 3,608
Other noncash items.................................... 3,445 4,429 544
Working capital changes, net of acquisitions and non-cash
transactions
Accounts receivable.................................... 66,441 (167,536) (41,037)
Other current assets................................... (9,762) (12,612) 125
Other noncurrent assets................................ (1,540) 467 (10,379)
Accounts payable....................................... (45,829) 143,553 (672)
Accrued gas purchase costs............................. 8,859 4,223 (2,776)
Accrued interest....................................... (3,829) 9,330 3,574
Other current liabilities.............................. (8,928) 13,086 (235)
Other noncurrent liabilities........................... (3,114) (377) (1,067)
--------- ----------- ---------
Net cash provided by continuing operations................ 268,168 170,756 82,416
Net cash provided by discontinued operations.............. -- 5,244 4,968
--------- ----------- ---------
Net cash provided by operating activities......... 268,168 176,000 87,384
--------- ----------- ---------
Cash flows from investing activities
Development expenditures for oil and natural gas
properties............................................. (145) (1,682) (2,018)
Additions to property, plant and equipment................ (332,019) (202,541) (508,347)
Proceeds from the sale and retirement of assets........... 77,911 5,460 109,126
Additions to investments in unconsolidated affiliates..... (35,536) (38,275) (1,487)
Proceeds from the sale of investments in unconsolidated
affiliates............................................. 1,355 -- --
Repayments on note receivable............................. 1,238 -- --
Cash paid for acquisitions, net of cash acquired.......... (20) (1,164,856) (28,414)
--------- ----------- ---------
Net cash used in investing activities of continuing
operations............................................. (287,216) (1,401,894) (431,140)
Net cash provided by (used in) investing activities of
discontinued operations................................ -- 186,477 (68,560)
--------- ----------- ---------
Net cash used in investing activities............. (287,216) (1,215,417) (499,700)
--------- ----------- ---------
6
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- ----------- ---------
Cash flows from financing activities
Net proceeds from revolving credit facility............... 533,564 366,219 559,994
Repayments of revolving credit facility................... (647,000) (177,000) (581,000)
Net proceeds from GulfTerra Holding term credit
facility............................................... -- 530,136 --
Repayment of GulfTerra Holding term credit facility....... -- (375,000) --
Repayment of GulfTerra Holding term loan.................. (160,000) -- --
Net proceeds from senior secured acquisition term loan.... (23) 233,236 --
Repayment of senior secured acquisition term loan......... (237,500) -- --
Net proceeds from senior secured term loan................ 299,512 156,530 --
Repayment of senior secured term loan..................... (160,000) -- --
Net proceeds from issuance of long-term debt.............. 537,426 423,528 243,032
Repayments of long-term debt.............................. (269,401) -- --
Repayment of Argo term loan............................... -- (95,000) --
Distributions to minority interests....................... (1,242) -- --
Net proceeds from issuance of common units................ 509,010 150,159 286,699
Redemption of Series B preference units................... (155,673) -- (50,000)
Contributions from general partner........................ 3,098 4,095 2,843
Distributions to partners................................. (238,397) (154,468) (106,409)
--------- ----------- ---------
Net cash provided by financing activities of continuing
operations............................................. 13,374 1,062,435 355,159
Net cash provided by (used in) financing activities of
discontinued operations................................ -- (3) 49,960
--------- ----------- ---------
Net cash provided by financing activities......... 13,374 1,062,432 405,119
--------- ----------- ---------
Increase (decrease) in cash and cash equivalents............ (5,674) 23,015 (7,197)
Cash and cash equivalents at beginning of year.............. 36,099 13,084 20,281
--------- ----------- ---------
Cash and cash equivalents at end of year.................... $ 30,425 $ 36,099 $ 13,084
========= =========== =========
See accompanying notes.
7
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)
SERIES B SERIES B
PREFERENCE PREFERENCE SERIES C SERIES C COMMON COMMON GENERAL
UNITS(1) UNITHOLDERS UNITS(2) UNITHOLDERS UNITS UNITHOLDERS PARTNER(3) TOTAL
---------- ----------- -------- ----------- ------ ----------- ---------- ----------
Partners' capital at
January 1, 2001......... 170 $ 175,668 -- $ -- 31,550 $ 132,802 $ 2,601 $ 311,071
Net income(4)............. -- 17,228 -- -- -- 13,260 24,661 55,149
Other comprehensive
loss.................... -- -- -- -- -- (1,259) (13) (1,272)
Issuance of common
units................... -- -- -- -- 8,189 286,699 -- 286,699
Issuance of unit
options................. -- -- -- 2,161 -- 2,161
Redemption of Series B
preference units........ (45) (50,000) -- -- -- -- -- (50,000)
General partner
contribution related to
the issuance of common
units................... -- -- -- -- -- -- 2,843 2,843
Cash distributions........ -- -- -- -- -- (80,903) (25,022) (105,925)
---- --------- ------ -------- ------ --------- -------- ----------
Partners' capital at
December 31, 2001....... 125 $ 142,896 -- $ -- 39,739 $ 352,760 $ 5,070 $ 500,726
Net income(4)............. -- 14,688 -- 1,507 -- 39,360 42,133 97,688
Issuance of Series C
units................... -- -- 10,938 350,000 -- -- -- 350,000
Other comprehensive
loss.................... -- -- -- (942) -- (3,364) (44) (4,350)
Issuance of common
units................... -- -- -- -- 4,291 156,072 -- 156,072
Issuance of unit
options................. -- -- -- -- -- 89 -- 89
General partner
contribution related to
the issuance of Series C
units and common
units................... -- -- -- -- -- -- 4,095 4,095
Cash distributions........ -- -- -- -- -- (111,767) (42,701) (154,468)
---- --------- ------ -------- ------ --------- -------- ----------
Partners' capital at
December 31, 2002....... 125 $ 157,584 10,938 $350,565 44,030 $ 433,150 $ 8,553 $ 949,852
Net income(4)............. -- 11,792 -- 15,421 66,495 69,431 163,139
Other comprehensive
loss.................... -- -- (467) -- (2,865) (73) (3,405)
Issuance of common
units................... -- -- -- -- 14,056 494,812 -- 494,812
Issuance of Series F
units................... -- -- -- -- -- 4,104 -- 4,104
Redemption of unit
options................. -- -- -- -- 319 10,094 -- 10,094
Redemption of Series B
preference units........ (125) (169,376) -- 1,919 -- 9,686 2,098 (155,673)
Issuance of unit options
and restricted units.... 1,687 1,687
General partner
contribution related to
the issuance of common
units................... -- -- -- -- -- -- 3,098 3,098
Receipt of communication
assets.................. -- -- -- 4,100 -- 18,942 233 23,275
Cash distributions........ -- -- -- (30,188) -- (138,033) (70,176) (238,397)
---- --------- ------ -------- ------ --------- -------- ----------
Partners' capital at
December 31, 2003....... -- $ -- 10,938 $341,350 58,405 $ 898,072 $ 13,164 $1,252,586
==== ========= ====== ======== ====== ========= ======== ==========
---------------
(1) In October 2003, we redeemed all of our remaining outstanding Series B
preference units for $156 million.
(2) We issued 10,937,500 of our Series C units to El Paso Corporation for a
value of $350 million in connection with our acquisition of the San Juan
assets. A discussion of this new class of units is included in Note 8.
(3) GulfTerra Energy Company, L.L.C. is our sole general partner and is owned 50
percent by a subsidiary of El Paso Corporation and 50 percent by a
subsidiary of Enterprise Products Partners, L.P.
(4) Income allocation to our general partner includes both its incentive
distributions and its one percent ownership interest.
See accompanying notes.
8
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
COMPREHENSIVE INCOME
YEAR ENDED DECEMBER 31,
----------------------------
2003 2002 2001
-------- ------- -------
Net income............................................. $163,139 $97,688 $55,149
Other comprehensive loss............................... (3,405) (4,350) (1,272)
-------- ------- -------
Total comprehensive income............................. $159,734 $93,338 $53,877
======== ======= =======
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
YEAR ENDED DECEMBER 31,
----------------------------
2003 2002 2001
-------- ------- -------
Beginning balance...................................... $ (5,622) $(1,272) $ --
Unrealized mark-to-market losses on cash flow hedges
arising during period............................. (12,924) (6,428) (1,682)
Reclassification adjustments for changes in initial
value of derivative instruments to settlement
date.............................................. 10,018 1,579 410
Accumulated other comprehensive income (loss) from
investment in unconsolidated affiliate............ (499) 499 --
-------- ------- -------
Ending balance......................................... $ (9,027) $(5,622) $(1,272)
======== ======= =======
See accompanying notes.
9
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
We are a publicly held Delaware master 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. As of December 31, 2003, we had 58,404,649 common units outstanding
representing limited partner interests and 10,937,500 Series C units outstanding
representing non-voting limited partner interests. On that date, the public
owned 48,020,404 common units, or 82.2 percent of our outstanding common units,
and El Paso Corporation, through its subsidiaries, owned 10,384,245 common
units, or 17.8 percent of our outstanding common units, all of our Series C
units and 50 percent of our general partner, which owns our one percent general
partner interest.
In May 2003, we changed our name to GulfTerra Energy Partners, L.P. from El
Paso Energy Partners, L.P. and reorganized our general partner. In connection
with our name change, we also changed the names of several subsidiaries in May
2003, including the following, as listed in the table below.
NEW NAME FORMER NAME
-------- -----------------------------------------
El Paso Energy Partners Finance
GulfTerra Energy Finance Corporation..... Corporation
GulfTerra Arizona Gas, L.L.C............. El Paso Arizona Gas, L.L.C.
GulfTerra Intrastate, L.P................ El Paso Energy Intrastate, L.P.
GulfTerra Texas Pipeline, L.P............ EPGT Texas Pipeline, L.P.
GulfTerra Holding V, L.P................. EPN Holding Company, L.P.
Our sole general partner is GulfTerra Energy Company, L.L.C., a
recently-formed Delaware limited liability company that is owned 50 percent by a
subsidiary of El Paso Corporation and 50 percent by a subsidiary of Enterprise,
a publicly traded master limited partnership. El Paso Corporation (through its
subsidiaries) owned 100 percent of our general partner until October 2003, when
Goldman Sachs acquired a 9.9 percent interest in our general partner. In
December 2003, El Paso Corporation reacquired Goldman Sachs' interest in our
general partner and then sold a 50 percent interest in our general partner to a
subsidiary of Enterprise.
On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs with Enterprise being
the continuing entity. The general partner of the combined partnership will be
jointly owned by affiliates of El Paso Corporation and privately-held Enterprise
Products Company, with each owning a 50-percent interest.
The combined partnership, which will retain the name Enterprise Products
Partners L.P., will serve the largest producing basins of natural gas, crude oil
and NGLs in the U.S., including the Gulf of Mexico, Rocky Mountains, San Juan
Basin, Permian Basin, South Texas, East Texas, Mid-Continent and Louisiana Gulf
Coast basins and, through connections with third-party pipelines, Canada's
western sedimentary basin. The partnership will also serve the largest consuming
regions for natural gas, crude oil and NGLs on the U.S. Gulf Coast.
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We account for investments in companies
where we have the ability to exert significant influence over, but not control
over operating and financial policies, using the equity method of accounting.
Prior to May 2001, our general partner's approximate one percent non-managing
interest in twelve of our subsidiaries represented the minority interest
10
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
in our consolidated financial statements. In May 2001, we purchased our general
partner's one percent non-managing ownership interest in twelve of our
subsidiaries for $8 million. As a result of this acquisition, all of our
subsidiaries, but not our equity investees, are wholly-owned by us.
During part of 2003 and 2002, third parties had minority ownership
interests in Matagorda Island Area Gathering System (MIAGS) and Arizona Gas,
L.L.C. The assets, liabilities and operations of these entities are included in
our consolidated financial statements and we account for the third party
ownership interest as minority interest in our consolidated balance sheets and
as minority interest income (expense) in our consolidated statements of income.
In October 2003, we purchased the remaining 17 percent interest in MIAGS. As a
result, we no longer recognize the third party ownership interest in MIAGS as
minority interests in our consolidated balance sheets or consolidated statements
of income.
Our consolidated financial statements for prior periods include
reclassifications that were made to conform to the current year presentation.
Those reclassifications have no impact on reported net income or partners'
capital. We have reflected the results of operations from our Prince assets
disposition as discontinued operations for the years ended December 31, 2002 and
2001. See Note 2 for a further discussion of our Prince assets disposition.
Use of Estimates
The preparation of our financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and disclosure of contingent assets and liabilities that
exist at the date of our financial statements. While we believe our estimates
are appropriate, actual results can, and often do, differ from those estimates.
Accounting for Regulated Operations
Our HIOS interstate natural gas system and our Petal storage facility are
subject to the jurisdiction of FERC in accordance with the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Each system operates under separate
FERC approved tariffs that establish rates, terms and conditions under which
each system provides services to its customers. Our businesses that are subject
to the regulations and accounting requirements of FERC have followed the
accounting requirements of Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation, which may
differ from the accounting requirements of our non-regulated entities.
Transactions that have been recorded differently as a result of regulatory
accounting requirements include the capitalization of an equity return component
on regulated capital projects.
Under the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligations, which we adopted on January 1, 2003, the cost associated with the
retirement of long-lived assets for regulated entities accounted for under SFAS
No. 71 should be classified as a regulatory liability instead of as a component
of property, plant and equipment. As a result, we reclassified $13.6 million
from property, plant and equipment to a regulatory liability and at December 31,
2003, this balance is included in other noncurrent liabilities in our
consolidated balance sheet. Prior to January 2003, this item was reflected in
accumulated depreciation, depletion and amortization and the balance for this
item at December 31, 2002, was $12.9 million.
When the accounting method followed is required by or allowed by the
regulatory authority for rate-making purposes, the method conforms to the
generally accepted accounting principle (GAAP) of matching costs with the
revenues to which they apply.
11
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Cash and Cash Equivalents
We consider short-term investments with little risk of change in value
because of changes in interest rates and purchased with an original maturity of
less than three months to be cash equivalents.
Allowance for Doubtful Accounts
We have established an allowance for losses on accounts that we believe are
uncollectible. We review collectibility regularly and adjust the allowance as
necessary, primarily under the specific identification method. At December 31,
2003 and 2002, the allowance was $4.0 million and $2.5 million.
Natural Gas Imbalances
Natural gas imbalances result from differences in gas volumes received from
and delivered to our customers and arise when a customer delivers more or less
gas into our pipelines than they take out. These imbalances are settled in kind
through a tracking mechanism, negotiated cash-outs between parties, or are
subject to a cash-out procedure and are valued at prices representing the
estimated value of these imbalances upon settlement. We estimate the value of
our imbalances at prices representing the estimated value of the imbalances upon
settlement. Changes in natural gas prices may impact our valuation. We do not
value our imbalances based on current month-end spot prices because it is not
likely that we would purchase or receive natural gas at that point in time to
settle the imbalance. Natural gas imbalances are reflected in accounts
receivable or accounts payable, as appropriate, in our accompanying consolidated
balance sheets. Our imbalance receivables and imbalance payables were as follows
at December 31 (in thousands):
2003 2002
------- --------
Imbalance Receivables
Trade..................................................... $37,228 $ 88,929
Affiliates................................................ $16,405 $ 15,460
Imbalance Payables
Trade..................................................... $68,446 $104,035
Affiliates................................................ $14,047 $ 22,316
Property, Plant and Equipment
We record our property, plant and equipment at its original cost of
construction or, upon acquisition, the fair value of the asset acquired.
Additionally, we capitalize direct costs, such as labor and materials, and
indirect costs, such as overhead, interest and, in our regulated businesses that
apply the provisions of SFAS No. 71, an equity return component. We also
capitalize the major units of property replacements or improvements and expense
minor items including repair and maintenance costs. In addition, we reduce our
property, plant and equipment balance for any amounts that we receive in the
form of contributions in aid of construction.
For our regulated interstate system and storage facility we use the
composite (group) method to depreciate regulated property, plant and equipment.
Under this method, assets with similar lives and other characteristics are
grouped and depreciated as one asset. We apply the depreciation rate approved in
our tariff to the total cost of the group until its net book value equals its
estimated salvage value. Currently, depreciation rates on our regulated
interstate system and storage facility vary from 1 to 20 percent. Using these
rates, the remaining depreciable lives of these assets range from 1 to 39 years.
12
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our non-regulated gathering pipelines, platforms and related facilities,
processing facilities and equipment, and storage facilities and equipment are
depreciated on a straight-line basis over the estimated useful lives which are
as follows:
Gathering pipelines......................................... 5-40 years
Platforms and facilities.................................... 18-30 years
Processing facilities....................................... 25-30 years
Storage facilities.......................................... 25-30 years
We account for our oil and natural gas exploration and production
activities using the successful efforts method of accounting. Under this method,
costs of successful exploratory wells, developmental wells and acquisitions of
mineral leasehold interests are capitalized. Production, exploratory dry hole
and other exploration costs, including geological and geophysical costs and
delay rentals, are expensed as incurred. Unproved properties are assessed
periodically and any impairment in value is recognized currently as
depreciation, depletion and amortization expense.
Depreciation, depletion and amortization of the capitalized costs of
producing oil and natural gas properties, consisting principally of tangible and
intangible costs incurred in developing a property and costs of productive
leasehold interests, are computed on the unit-of-production method.
Unit-of-production rates are based on annual estimates of remaining proved
developed reserves or proved reserves, as appropriate, for each property.
Estimated dismantlement, restoration and abandonment costs and estimated
residual salvage values are taken into account in determining depreciation
provisions for gathering pipelines, platforms, related facilities and oil and
natural gas properties. At December 31, 2002, accrued abandonment costs were
$24.6 million, of which $6.4 million was related to offshore wells. As discussed
below, we adopted SFAS No. 143 Accounting for Asset Retirement Obligations on
January 1, 2003 and the amounts accrued and capitalized were adjusted to conform
to the provisions of that statement.
Retirements, sales and disposals of assets are recorded by eliminating the
related costs and accumulated depreciation, depletion and amortization of the
disposed assets with any resulting gain or loss reflected in income.
Accounting for Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143. The provisions of this
statement relate primarily to our obligations to plug abandoned offshore wells
that constitute part of our non-segment assets.
Upon our adoption of SFAS No. 143, we recorded (i) a $7.4 million net
increase to property, plant, and equipment, relating to offshore wells,
representing non-current retirement assets, (ii) a $5.7 million increase to
noncurrent liabilities representing retirement obligations, and (iii) a $1.7
million increase to income as a cumulative effect of accounting change. Each
retirement asset is depreciated over the remaining useful life of the long-term
asset with which the retirement liability is associated. An ongoing expense is
recognized for the interest component of the liability due to the changes in the
value of the retirement liability as a result of the passage of time, which we
reflect as a component of depreciation expense in our income statement.
Other than our obligations to plug and abandon wells, we cannot estimate
the costs to retire or remove assets used in our business because we believe the
assets do not have definite lives or we do not have the legal obligation to
abandon or dismantle the assets. We believe that the lives of our assets or the
underlying reserves associated with our assets cannot be estimated. Therefore,
aside from the liability associated with the plugging and abandonment of
offshore wells, we have not recorded liabilities relating to any of our other
assets.
13
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The pro forma income from continuing operations and amounts per common unit
for the years ended December 31, 2002 and 2001, assuming the provisions of SFAS
No. 143 were adopted prior to the earliest period presented, are shown below:
YEARS ENDED
DECEMBER 31,
-----------------
2002 2001
------- -------
Pro forma income from continuing operations................. $93,932 $54,321
======= =======
Pro forma income from continuing operations allocated to
common unitholders........................................ $35,369 $12,446
======= =======
Pro forma basic income from continuing operations per
weighted average common unit.............................. $ 0.83 $ 0.36
======= =======
Pro forma diluted income from continuing operations per
weighted average common unit.............................. $ 0.83 $ 0.36
======= =======
The pro forma amount of our asset retirement obligations at December 31,
2002 and 2001, assuming asset retirement obligations as provided for in SFAS No.
143 were recorded prior to the earliest period presented was $5.7 million and
$5.3 million. Our asset retirement obligation for December 31, 2003, is shown
below.
LIABILITY
BALANCE OTHER LIABILITY BALANCE
AS OF CHANGE IN AS OF
YEAR JANUARY 1 ACCRETION LIABILITY DECEMBER 31
---- --------- --------- --------- -----------------
(IN THOUSANDS)
2003..................................... $5,726 $442 $(246)(1) 5,922
---------------
(1) Abandonment work performed during the year ended December 31, 2003.
Goodwill and Other Intangible Assets
We adopted the provisions of SFAS No. 142 Goodwill and Other Intangible
Assets on January 1, 2002, except for goodwill and intangible assets we acquired
after June 30, 2001 for which we adopted the provisions immediately.
Accordingly, we record identifiable intangible assets we acquire individually or
with a group of other assets at fair value upon acquisition. Identifiable
intangible assets with finite useful lives are amortized to expense over the
estimated useful life of the asset. Identifiable intangible assets with
indefinite useful lives and goodwill are evaluated annually for impairment by
comparison of their carrying amounts with the fair value of the individual
assets. We recognize an impairment loss in income for the amount by which the
carrying value of any identifiable intangible asset or goodwill exceeds the fair
value of the specific assets. As of December 31, 2003 and 2002, we had no
goodwill, other than as described below.
As of December 31, 2003 and 2002, the carrying amount of our equity
investment in Poseidon exceeded the underlying equity in net assets by
approximately $3.0 million. With our adoption of SFAS No. 142 on January 1,
2002, we no longer amortize this excess amount and will test it for impairment
if an event occurs that indicates there may be a loss in value, or at least
annually. Prior to January 1, 2002, we amortized this excess amount using the
straight line method over approximately 30 years. This excess amount is
reflected on our accompanying consolidated balance sheets in investments in
unconsolidated affiliates. Our adoption of this statement did not have a
material impact on our financial position or results of operations.
As part of our acquisition of the EPN Holding assets and the San Juan
assets, we obtained intangible assets representing contractual rights under
dedication and transportation agreements with producers. As of December 31, 2003
and 2002, the value of these intangible assets was approximately $3.4 million
and
14
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$4.0 million and is reflected on our accompanying consolidated balance sheets as
intangible assets. We amortize the intangible assets acquired in the EPN Holding
asset acquisition to expense using the units-of-production method over the
expected lives of the reserves ranging from 26 to 45 years. We amortize the
intangible assets acquired in the San Juan asset acquisition over the life of
the contracts of approximately 4 years.
Impairment and Disposal of Long-Lived Assets
We apply the provisions of SFAS No. 144 Accounting for the Impairment or
Disposal of Long-Lived Assets to account for impairment and disposal of
long-lived assets. Accordingly, we evaluate the recoverability of long-lived
assets when adverse events or changes in circumstances indicate that the
carrying value of an asset or group of assets may not be recoverable. We
determine the recoverability of an asset or group of assets by estimating the
undiscounted cash flows expected to result from the use and eventual disposition
of the asset or group of assets at the lowest level for which separate cash
flows can be measured. If the total of the undiscounted cash flows is less that
the carrying amount for the assets, we estimate the fair value of the asset or
group of assets and recognize the amount by which the carrying value exceeds the
fair value, less cost to sell, as an impairment loss in income from operations
in the period the impairment is determined.
Additionally, as required by SFAS No. 144, we classify long-lived assets to
be disposed of other than by sale (e.g., abandonment, exchange or distribution)
as held and used until the item is abandoned, exchanged or distributed. We
evaluate assets to be disposed of other than by sale for impairment and
recognize a loss for the excess of the carrying value over the fair value.
Long-lived assets to be disposed of through sale recognition meeting specific
criteria are classified as "Held for Sale" and measured at the lower of their
cost or fair value less cost to sell. We report the results of operations of a
component classified as held for sale, including any gain or loss in the
period(s) in which they occur. Upon our adoption of SFAS No. 144, we
reclassified our losses on the sale of long-lived assets of $0.4 million and
$11.4 million for the years ended December 31, 2002 and 2001, into operating
income to conform with the provisions of SFAS No. 144.
We also reclassify the asset or assets as either held for sale or as
discontinued operations, depending on whether they have independently
determinable cash flow and whether we have any continuing involvement.
Capitalization of Interest
Interest and other financing costs are capitalized in connection with
construction and drilling activities as part of the cost of the asset and
amortized over the related asset's estimated useful life.
Debt Issue Costs
Debt issue costs are capitalized and amortized over the life of the related
indebtedness using the effective interest method. Any unamortized debt issue
costs are expensed at the time the related indebtedness is repaid or terminated.
At December 31, 2003 and 2002, the unamortized amount of our debt issue costs
included in other noncurrent assets was $29.2 million and $32.6 million.
Amortization of debt issue costs for the years ended December 31, 2003, 2002 and
2001 were $7.5 million, $4.4 million and $3.6 million and are included in
interest and debt expense on our consolidated statements of income.
Revenue Recognition and Cost of Natural Gas and Other Products
Revenue from gathering and transportation of hydrocarbons is recognized
upon receipt of the hydrocarbons into the pipeline systems. Revenue from
commodity sales is recognized upon delivery. Commodity storage revenues and
platform access revenues consist primarily of fixed fees for capacity
reservation and some of the transportation contracts on our Viosca Knoll system
and our Indian Basin lateral also contain a fixed fee to reserve transportation
capacity. These fixed fees are recognized during the month in
15
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
which the capacity is reserved by the customer, regardless of how much capacity
is actually used. Revenue from processing services, treating services and
fractionation services is recognized in the period the services are provided.
Interruptible revenues from natural gas storage, which are generated by
providing excess storage capacity, are variable in nature and are recognized
when the service is provided. Other revenues generally are recorded when
services have been provided or products have been delivered.
Prior to 2002, our cost of natural gas consisted primarily of natural gas
purchased at GulfTerra Alabama Intrastate for resale. As a result of our
acquisition of the EPN Holding assets and the San Juan assets, we are now
incurring additional costs related to system imbalances and for the purchase of
natural gas as part of our producer services activities. As a convenience for
our producers, we may purchase natural gas from them at the wellhead at an index
price less an amount that compensates us for our gathering services. We then
sell this gas into the open market at points on our system at the same index
price. We reflect these sales in our revenues and the related purchases as cost
of natural gas on the accompanying consolidated statements of income.
Typhoon Oil Pipeline's transportation agreement with BHP and Chevron Texaco
provides 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. Beginning in 2003, we
record revenue from these buy/sell transactions upon delivery of the oil based
on the net amount billed to the producers. We acquired the Typhoon oil pipeline
in November 2002, and for the year ended December 31, 2002, we recorded revenue
based on the gross amount billed to the producers. For the year ended December
31, 2002, we reclassified $10.5 million from cost of natural gas and other
products to revenue to conform to our 2003 presentation. This reclassification
has no effect on operating income, net income or partners' capital.
As of July 1, 2003, HIOS implemented new rates, subject to a refund, and we
established a reserve for our estimate of the refund obligation. We will
continue to review our expected refund obligation as the rate case moves through
the hearing process and may increase or decrease the amounts reserved for refund
obligation as our expectation changes.
Environmental Costs
We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods. We
record liabilities when our environmental assessments indicate that remediation
efforts are probable, and the costs can be reasonably estimated. Estimates of
our liabilities are based on currently available facts, existing technology and
presently enacted laws and regulations taking into consideration the likely
effects of inflation and other societal and economic factors, and include
estimates of associated legal costs. These amounts also consider prior
experience in remediating contaminated sites, other companies' clean-up
experience and data released by the Environmental Protection Agency (EPA) or
other organizations. These estimates are subject to revision in future periods
based on actual costs or new circumstances and are included in our consolidated
balance sheets in other noncurrent liabilities at their undiscounted amounts.
Accounting for Price Risk Management Activities
Our business activities expose us to a variety of risks, including
commodity price risk and interest rate risk. From time to time we engage in
price risk management activities for non-trading purposes to manage market risks
associated with commodities we purchase and sell and interest rates on variable
rate debt. Our price risk management activities involve the use of a variety of
derivative financial instruments, including:
- exchange-traded future contracts that involve cash settlement;
16
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- forward contracts that involve cash settlements or physical delivery of a
commodity; and
- swap contracts that require payments to (or receipts from) counterparties
based on the difference between a fixed and a variable price, or two
variable prices, for a commodity or variable rate debt instrument.
We account for all of our derivative instruments in our consolidated
financial statements under SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. We record all derivatives in our consolidated balance
sheets at their fair value as other assets or other liabilities and classify
them as current or noncurrent based upon their anticipated settlement date.
For those instruments entered into to hedge risk and which qualify as
hedges, we apply the provisions of SFAS No. 133, and the accounting treatment
depends on each instrument's intended use and how it is designated. In addition
to its designation, a hedge must be effective. To be effective, changes in the
value of the derivative or its resulting cash flows must substantially offset
changes in the value or cash flows of the item being hedged.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategies for
undertaking various hedge transactions. All hedging instruments are linked to
the hedged asset, liability, firm commitment or forecasted transaction. We also
assess, both at the inception of the hedge and on an on-going basis, whether the
derivatives that are used in our hedging transactions are highly effective in
offsetting changes in cash flows or fair values of the hedged items. We
discontinue hedge accounting prospectively if we determine that a derivative is
not highly effective as a hedge or if we decide to discontinue the hedging
relationship.
During 2003, 2002 and 2001, we entered into cash flow hedges that qualify
for hedge accounting under SFAS No. 133 treatment. Changes in the fair value of
a derivative designated as a cash flow hedge are recorded in accumulated other
comprehensive income for the portion of the change in value of the derivative
that is effective. The ineffective portion of the derivative is recorded in
earnings in the current period. Classification in the income statement of the
ineffective portion is based on the income classification of the item being
hedged. At the date of the hedged transaction, we reclassify the gains or losses
resulting from the sale, maturity, extinguishment or termination of derivative
instruments designated as hedges from accumulated other comprehensive income to
operating income or interest expense, as appropriate, in our consolidated
statements of income. We classify cash inflows and outflows associated with the
settlement of our derivative transactions as cash flows from operating
activities in our consolidated statements of cash flows.
We also record our ownership percentage of the changes in the fair value of
derivatives of our investments in unconsolidated affiliates in accumulated other
comprehensive income.
We may also purchase and sell instruments to economically hedge price
fluctuations in the commodity markets. These instruments are not documented as
hedges due to their short-term nature, or do not qualify under the provisions of
SFAS No. 133 for hedge accounting due to the terms in the instruments. Where
such derivatives do not qualify, or are not documented, changes in their fair
value are recorded in earnings in the current period.
In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices in the San Juan Basin
in anticipation of our acquisition of the San Juan assets. From August 2002
through our acquisition date, November 27, 2002, we accounted for this
derivative through current earnings since it did not qualify for hedge
accounting under SFAS No. 133. Beginning with the acquisition date in November
2002, we have designated this derivative as a cash flow hedge and are accounting
for it as such under SFAS No. 133.
During the normal course of our business, we may enter into contracts that
qualify as derivatives under the provisions of SFAS No. 133. As a result, we
evaluate our contracts to determine whether derivative
17
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
accounting is appropriate. Contracts that meet the criteria of a derivative and
qualify as "normal purchases" and "normal sales", as those terms are defined in
SFAS No. 133, may be excluded from SFAS No. 133 treatment.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. This statement amends SFAS No.
133 to incorporate several interpretations of the Derivatives Implementation
Group (DIG), and also makes several minor modifications to the definition of a
derivative as it was defined in SFAS No. 133. SFAS No. 149 is effective for
contracts entered into or modified after June 30, 2003. There was no initial
financial statement impact of adopting this standard, although the FASB and DIG
continue to deliberate on the application of the standard to certain derivative
contracts, which may impact our financial statements in the future.
Income Taxes
As of December 31, 2003, neither we nor any of our subsidiaries are taxable
entities. However, the taxable income or loss resulting from our operations will
ultimately be included in the federal and state income tax returns of the
general and limited partners. Individual partners will have different investment
bases depending upon the timing and price of their acquisition of partnership
units. Further, each partner's tax accounting, which is partially dependent upon
his tax position, may differ from the accounting followed in the consolidated
financial statements. Accordingly, there could be significant differences
between each individual partner's tax basis and his share of the net assets
reported in the consolidated financial statements. We do not have access to
information about each individual partner's tax attributes and the aggregate tax
bases cannot be readily determined.
Income (Loss) per Common Unit
Basic income (loss) per common unit excludes dilution and is computed by
dividing net income (loss) attributable to the common unitholders by the
weighted average number of common units outstanding during the period. Diluted
income (loss) per common unit reflects potential dilution and is computed by
dividing net income (loss) attributable to the common unitholders by the
weighted average number of common units outstanding during the period increased
by the number of additional common units that would have been outstanding if the
potentially dilutive units had been issued.
Basic income (loss) per common unit and diluted income (loss) per common
unit are the same for the years ended December 31, 2002 and 2001, as the number
of potentially dilutive units were so small as not to cause the diluted earnings
per unit to be different from the basic earnings per unit.
Comprehensive Income
Our comprehensive income is determined based on net income (loss), adjusted
for changes in accumulated other comprehensive income (loss) from our cash flow
hedging activities associated with our GulfTerra Alabama Intrastate operations,
our Indian Basin processing plant, the San Juan assets and our unconsolidated
affiliate, Poseidon Oil Pipeline Company, L.L.C.
The following table presents our allocation of accumulated other
comprehensive loss as of December 31:
2003 2002 2001
------- ------- -------
Common units' interest.................................. $(7,488) $(4,623) $(1,259)
======= ======= =======
Series C units' interest................................ $(1,409) $ (942) $ --
======= ======= =======
General partner's interest.............................. $ (130) $ (57) $ (13)
======= ======= =======
18
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accounting for Stock-Based Compensation
We use 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 individuals who are on our general partner's current
board of directors and for those grants made prior to El Paso Corporation's
acquisition of our general partner in August 1998 under our Omnibus Plan and
Director Plan. For the years ending December 31, 2003, 2002 and 2001, the cost
of this stock-based compensation had no impact on our net income, as all options
granted had an exercise price equal to the market value of the underlying common
stock on the date of grant. We use the provisions of SFAS No. 123, Accounting
for Stock-Based Compensation, to account for all of our other stock-based
compensation programs.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation Transition and Disclosure. This statement amends SFAS No. 123, to
provide alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements about the
methods of accounting for stock-based employee compensation and the effect of
the method used on reported results. This statement is effective for fiscal
years ending after December 15, 2002. We have decided that we will continue to
use APB No. 25 to value our stock-based compensation issued to individuals who
are on our general partner's current board of directors and for those grants
made prior to El Paso Corporation's acquisition of our general partner in August
1998 and will include data providing the pro forma income effect of using the
fair value method as required by SFAS No. 148. We will continue to use the
provisions of SFAS No. 123 to account for all of our other stock-based
compensation programs.
If compensation expense related to these plans had been determined by
applying the fair value method in SFAS No. 123 our net income allocated to
common unitholders and net income per common unit would have approximated the
pro forma amounts below:
YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 2001
-------- ------- -------
(IN THOUSANDS)
Net income, as reported................................ $163,139 $97,688 $55,149
Add: Stock-based employee compensation expense included
in reported net income............................ 1,489 1,168 367
Less: Stock-based employee compensation expense
determined under fair value based method......... 1,532 1,912 678
-------- ------- -------
Pro forma net income................................... $163,096 $96,944 $54,838
======== ======= =======
Pro forma net income allocated to common unitholders... $ 66,452 $38,616 $12,949
======== ======= =======
Earnings per common unit:
Basic, as reported................................... $ 1.33 $ 0.92 $ 0.38
======== ======= =======
Basic, pro forma..................................... $ 1.33 $ 0.90 $ 0.38
======== ======= =======
Diluted, as reported................................. $ 1.32 $ 0.92 $ 0.38
======== ======= =======
Diluted, pro forma................................... $ 1.32 $ 0.90 $ 0.38
======== ======= =======
The effects of applying SFAS No. 123 in this pro forma disclosure may not
be indicative of future amounts.
Accounting for Debt Extinguishments
In January 2003, we adopted SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
Accordingly, we now evaluate the nature
19
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of any debt extinguishments to determine whether to report any gain or loss
resulting from the early extinguishment of debt as an extraordinary item or as a
component of income from continuing operations.
Accounting for Costs Associated with Exit or Disposal Activities
In January 2003, we adopted SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement impacts any exit or disposal
activities that we initiate after January 1, 2003 and we now recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Our adoption of this pronouncement
did not have an effect on our financial position or results of operations.
Accounting for Guarantees
In accordance with the provisions of Financial Accounting Standards Board
(FASB) Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we record a liability at fair value, or otherwise disclose, certain
guarantees issued after December 31, 2002, that contractually require us to make
payments to a guaranteed party based on the occurrence of certain events. We
have not entered into any material guarantees that would require recognition
under FIN No. 45.
Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
provides guidance on the classification of financial instruments, as equity, as
liabilities, or as both liabilities and equity. The provisions of SFAS No. 150
are effective for all financial instruments entered into or modified after May
31, 2003, and otherwise is effective at the beginning of the first interim
period beginning July 1, 2003. We adopted the provisions of SFAS No. 150 on July
1, 2003, and our adoption had no material impact on our financial statements.
New Accounting Pronouncements Issued But Not Yet Adopted
Consolidation of Variable Interest Entities
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. This interpretation defines
a variable interest entity (VIE) as a legal entity whose equity owners do not
have sufficient equity at risk and/or a controlling financial interest in the
entity. This standard requires a company to consolidate a VIE if it is allocated
a majority of the entity's losses and/or returns, including fees paid by the
entity. In December 2003, the FASB issued FIN 46-R, which amended FIN No. 46, to
extend its effective date until the first quarter of 2004 for all types of
entities except special purpose entities (SPE's). In addition, FIN No. 46-R also
limited the scope of FIN No. 46 to exclude certain joint ventures of other
entities that meet the characteristics of businesses.
We have no SPE's as defined by FIN Nos. 46 and 46-R. We have evaluated our
joint ventures, unconsolidated subsidiaries and other contractual arrangements
that could be considered variable interests or variable interest entities that
were created before February 1, 2003 and have determined that they will not have
a significant effect on our reported results and financial position when we
adopt the provisions of FIN No. 46-R in the first quarter of 2004.
20
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. ACQUISITIONS AND DISPOSITIONS
Merger with Enterprise
On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs. The general partner
of the combined partnership will be jointly owned by affiliates of El Paso
Corporation and privately-held Enterprise Products Company, with each owning a
50-percent interest. The definitive agreements include three transactions, of
which two affect us.
In the first transaction that effects us, which occurred with the signing
of the merger agreement, a wholly owned subsidiary of Enterprise purchased a 50
percent limited-voting interest in our general partner. This interest entitles
Enterprise to half of the cash distributed to our general partner, but does not
allow Enterprise to elect any of our general partner's directors or otherwise
generally participate in our general partner's management of our business.
The second transaction that affects us will occur at the merger date. At
the closing of the merger, each outstanding GulfTerra common unit (other than
those owned by Enterprise) will convert into 1.81 Enterprise common units,
GulfTerra will become a wholly-owned subsidiary of Enterprise, and El Paso
Corporation will acquire a 50 percent interest in Enterprise's general partner
(including the right to elect half of the directors of Enterprise's general
partner). The closing of the merger is subject to the satisfaction of specified
conditions, including obtaining clearance under the Hart-Scott-Rodino Antitrust
Improvement Acts, and the approval of our unitholders and Enterprise's
unitholders. Completion of the merger is expected to occur during the second
half of 2004.
Our merger agreement with Enterprise limits our ability to raise additional
capital prior to the closing of the merger without Enterprise's approval. In
addition, because the closing of the merger will be a change of control, and
thus a default, under our credit facility, we will either repay or amend that
facility prior to the closing. In addition, because the merger closing will
constitute a change of control under our indentures, we will be required to
offer to repurchase our outstanding senior subordinated notes (and possibly our
senior notes) at 101 percent of their principal amount after the closing. In
coordination with Enterprise, we are evaluating alternative financing plans in
preparation for the close of the merger. We and Enterprise can agree on the date
of the merger closing after the receipt of all necessary approvals. We do not
intend to close until appropriate financing is in place.
If the merger agreement is terminated and (1) a business transaction
between us and a third party that conflicts with the merger was proposed and
certain other conditions were met or (2) we materially and willfully violated
our agreement not to solicit transactions that conflict with the merger, then we
will be required to pay Enterprise a termination fee of $112 million. If the
merger agreement is terminated because our unitholders did not approve the
merger and either (1) a possible business transaction involving us but not
involving Enterprise and conflicting with the merger was publicly proposed and
our board of directors publicly and timely reaffirmed its recommendations of the
Enterprise merger or (2) no such possible business transaction was publicly
announced, then we will be required to pay Enterprise a termination fee of $15
million. Enterprise is subject to similar termination fee requirements.
Exchange with El Paso Corporation
In connection with our November 2002 San Juan assets acquisition, El Paso
Corporation retained the obligation to repurchase the Chaco plant from us for
$77 million in October 2021. In October 2003, we released El Paso Corporation
from that obligation in exchange for El Paso Corporation contributing specified
communication assets and other rights to us. The communication assets we
received are used in the operation of our pipeline systems. Prior to the October
2003 exchange, we had access to these assets under our general
21
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and administrative services agreement with El Paso Corporation. We recorded the
communication assets at El Paso Corporation's book value of $23.3 million with
the offset to partners' capital.
As a result of the October 2003 exchange, we revised our estimate for the
depreciable life of the Chaco plant from 19 to 30 years, the estimated remaining
useful life of the Chaco plant. Depreciation expense will decrease approximately
$0.5 million and $2.3 million on a quarter and annual basis.
Cameron Highway Oil Pipeline Company
Refer to Note 3 for a discussion related to our sale of a 50 percent
interest in Cameron Highway Oil Pipeline.
San Juan Assets
In November 2002, we acquired from subsidiaries of El Paso Corporation,
interests in assets we collectively refer to as the San Juan assets, which
consist of the following:
- 100 percent of El Paso Field Services' San Juan Gathering and Processing
Businesses, which include a natural gas gathering system and related
compression facilities, the Rattlesnake Treating Plant, a 50-percent
equity interest in Coyote Gas Treating, L.L.C. which owns the Coyote
natural gas treating facility, and the remaining interests in the Chaco
cryogenic natural gas processing plant we did not already own, all of
which are located in the San Juan Basin of northwest New Mexico and
southwestern Colorado;
- 100 percent of the Typhoon Oil Pipeline assets located in the Deepwater
Trend area of the Gulf of Mexico. Typhoon Oil was placed in service in
July 2001 and provides transportation of oil produced from the Typhoon
field for delivery to a platform in Green Canyon Block 19 with onshore
access through various oil pipelines;
- 100 percent of the Typhoon Gas Pipeline, which was placed in service in
August 2001. Typhoon Gas is also located in the Deepwater Trend area of
the Gulf of Mexico. The pipeline gathers natural gas from the Typhoon
field for redelivery into El Paso Corporation's ANR Patterson System; and
- 100 percent of the Coastal Liquids Partners' NGL Business, consisting of
an integrated set of NGL assets that stretch from the Mexico border near
McAllen, Texas, to Houston, Texas. This business includes a fractionation
facility near Houston, Texas; a truck-loading terminal near McAllen,
Texas, and leased underground NGL storage facilities.
We purchased the San Juan assets for $782 million, $764 million after
adjustments for capital expenditures and actual working capital acquired. During
2003, the total purchase price and net assets acquired decreased $2.4 million
due to post-closing purchase price adjustments related to natural gas
imbalances, NGL in-kind reserves and well loss reserves. We financed the
purchase of these assets with net proceeds from an offering of $200 million of
10 5/8% Senior Subordinated Notes due 2012; borrowings of $237.5 million under
our senior secured acquisition term loan; our issuance, to El Paso Corporation,
of 10,937,500 of our Series C units valued at $32 per unit or $350 million; and
currently available funds. We acquired the San Juan assets because they are
strategically located in active supply development areas and are supported by
long-term contracts that provide us with growing and reliable cash flows
consistent with our stated growth strategy.
In connection with this acquisition, we entered into an agreement with El
Paso Corporation under which El Paso Corporation would have been required,
subject to specified conditions, to repurchase the Chaco plant from us for $77
million in October 2021, at which time we would have had the right to lease the
plant from them for a period of 10 years with the option to renew the lease
annually thereafter. In October 2003, we
22
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
released El Paso Corporation from that repurchase obligation in exchange for El
Paso Corporation contributing communication assets to us.
As a result of our acquisition of the San Juan assets, our financial
results from the operation of the Chaco plant are significantly different from
our results prior to the purchase in the following ways:
- We no longer receive fixed fee revenue of $0.134/Dth for natural gas
processed; rather, from a majority of our customers, we receive a
processing fee of an in-kind portion of the NGL produced from the natural
gas processed. We then sell these NGL and, accordingly, our processing
revenues are affected by changes in the price of NGL.
- We no longer receive revenue for leasing the Chaco plant to El Paso Field
Services.
- We no longer recognize amortization expense relating to our investment in
processing agreement, which we terminated upon completing the
acquisition. This decrease in amortization expense is offset by
additional depreciation expense associated with the acquired assets.
In accordance with our procedures for evaluating and valuing material
acquisitions with El Paso Corporation, our Audit and Conflicts Committee engaged
independent financial advisors. Separate financial advisors delivered fairness
opinions for the acquisition of the San Juan assets and the issuance of the
Series C units. Based on these opinions, our Audit and Conflicts Committee and
the full Board approved these transactions.
The following table summarizes our allocation of the fair values of the
assets acquired and liabilities assumed at November 27, 2002. Our allocation
among the assets acquired is based on the results of an independent third-party
appraisal.
AT
NOVEMBER 27,
2002
--------------
(IN THOUSANDS)
Note receivable............................................. $ 17,100
Property, plant and equipment............................... 763,696
Intangible assets........................................... 470
Investment in unconsolidated affiliate...................... 2,500
--------
Total assets acquired..................................... 783,766
--------
Imbalances payable.......................................... 17,403
Other current liabilities................................... 2,565
--------
Total liabilities assumed................................. 19,968
--------
Net assets acquired.................................... $763,798
========
The acquired intangible assets represent contractual rights we obtained
under dedication and transportation agreements with producers which we are
amortizing to expense over the life of the contracts of approximately 4 years.
We recorded adjustments to the purchase price of approximately $18 million
primarily for capital expenditures and actual working capital acquired.
Our consolidated financial statements include the results of operations of
the San Juan assets from the November 27, 2002 purchase date. We have included
the assets and operating results of the El Paso Field Services' San Juan
Gathering and Processing Businesses and the Typhoon Gas Pipeline in our natural
gas pipelines and plants segment and the assets and operating results of the
Typhoon Oil Pipeline and Coastal Liquids Partners' NGL Business in our oil and
NGL logistics segment from the purchase date. The following
23
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
selected unaudited pro forma financial information presents our consolidated
operating results for the years ended December 31, 2002 and 2001 as if we
acquired the San Juan assets on January 1, 2001:
2002 2001
--------- ---------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
Operating revenues.......................................... $627,191 $427,942
Income from continuing operations........................... $ 88,902 $ 77,219
Income allocated to common unitholders from continuing
operations................................................ $ 25,738 $ 16,687
Basic and diluted net income per unit from continuing
operations................................................ $ 0.60 $ 0.43
The unaudited pro forma financial information presented above is not
necessarily indicative of the results of operations we might have realized had
the transaction been completed at the beginning of the earliest period
presented, nor do they necessarily indicate our consolidated operating results
for any future period.
EPN Holding Assets
In April 2002, we acquired, through a series of related transactions, from
subsidiaries of El Paso Corporation the following midstream assets located in
Texas and New Mexico, which we collectively refer to, for purposes of these
financial statements, as the EPN Holding assets:
- The Waha natural gas gathering and treating system and the Carlsbad
natural gas gathering system which are generally located in the Permian
Basin region of Texas and New Mexico.
- A 50 percent undivided interest in the Channel Pipeline System, an
intrastate natural gas transmission system located along the Gulf Coast
of Texas.
- The TPC Offshore pipeline system, a collection of natural gas gathering
and transmission assets located offshore of Matagorda Bay, Texas,
including the Oyster Lake and MILSP Condensate Separation and
Stabilization facilities and other undivided interests in smaller
pipelines.
- GulfTerra Texas Pipeline, L.P. which owned, among other assets, (i) the
GulfTerra Texas intrastate pipeline system, (ii) the TGP natural gas
lateral pipelines, (iii) the leased natural gas storage facilities
located in Wharton County, Texas generally known as the Wilson Storage
facility, (iv) an 80 percent undivided interest in the East Texas 36 inch
pipeline, (v) a 50 percent undivided interest in the West Texas 30 inch
pipeline, (vi) a 50 percent undivided interest in the North Texas 36 inch
pipeline, (vii) the McMullen County natural gas gathering system, (viii)
the Hidalgo County natural gas gathering system, (ix) a 22 percent
undivided interest in the Bethel-Howard pipeline, and (x) a 75 percent
undivided interest in the Longhorn pipeline.
- El Paso Hub Services L.L.C. which owned certain contract rights and
parcels of real property located in Texas.
- 100 percent of the outstanding joint venture interest in Warwink
Gathering and Treating Company which owned, among other assets, the
Warwink natural gas gathering system located in the Permian Basin region
of Texas and New Mexico.
In conjunction with the acquisition of the above assets, we obtained from
another affiliate of El Paso Corporation, all of the equity interest in El Paso
Indian Basin, L.P. which owned a 42.3 percent undivided, non-operating interest
in the Indian Basin natural gas processing plant and treating facility located
in southeastern New Mexico and the price risk management activities associated
with the plant.
We acquired the EPN Holding assets to provide us with a significant new
source of cash flow, greater diversification of our midstream asset base and to
provide new long term internal growth opportunities in the Texas intrastate
market. We purchased the EPN Holding assets for $750 million, adjusted for the
assumption
24
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of $15 million of net working capital obligations related to natural gas
imbalances resulting in net consideration of $735 million comprised of the
following:
- $420 million of cash;
- $119 million of assumed short-term indebtedness payable to El Paso
Corporation, which we subsequently repaid;
- $6 million in common units; and
- $190 million in assets, comprised of our Prince TLP and our nine percent
overriding royalty interest in the Prince field (see discussion below).
During 2003, the purchase price and net assets acquired increased $17.5
million due to post-closing purchase price adjustments related primarily to a
reduction in natural gas imbalance payables assumed in the transaction.
We entered into a limited recourse credit agreement with a syndicate of
commercial banks to finance substantially all of the cash consideration
associated with this transaction. See Note 6 for additional discussion regarding
the EPN Holding term credit facility.
The following table summarizes our allocation of the fair values of the
assets acquired and liabilities assumed at April 8, 2002. Our allocation among
the assets acquired is based on the results of an independent third-party
appraisal.
AT APRIL 8,
2002
--------------
(IN THOUSANDS)
Current assets.............................................. $ 4,690
Property, plant and equipment............................... 780,648
Intangible assets........................................... 3,500
--------
Total assets acquired..................................... 788,838
--------
Current liabilities......................................... 15,229
Environmental liabilities................................... 21,136
--------
Total liabilities assumed................................. 36,365
--------
Net assets acquired.................................... $752,473
========
The acquired intangible assets represent contractual rights we obtained
under dedication and transportation agreements with producers which we will
amortize to expense using the units-of-production method over the expected lives
of the underlying reserves ranging from 26 to 45 years. Additionally, we assumed
environmental liabilities of $21.1 million for estimated environmental
remediation costs associated with the GulfTerra Texas intrastate pipeline assets
as discussed in Note 11.
Our consolidated financial statements include the results of operations of
the EPN Holding assets from the April 8, 2002 purchase date. We have included
the assets and operating results of the Waha, Carlsbad and Warwink natural gas
gathering systems; the Channel and TPC Offshore pipeline systems; and the
GulfTerra Texas pipeline assets (excluding the Wilson Storage facility) in our
natural gas pipelines and plants segment. Our 42.3 percent ownership interest in
the assets and operating results of the Indian Basin plant are included in our
oil and NGL logistics segment and the Wilson storage facility assets and
operating results are included in our natural gas storage segment. The following
selected unaudited pro forma information depicts our
25
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
consolidated results of operations for the years ended December 31, 2002 and
2001 as if we acquired the EPN Holding assets on January 1, 2001:
2002 2001
--------- ---------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
Operating revenues.......................................... $540,154 $538,095
Income from continuing operations........................... $114,517 $ 81,022
Income allocated to common unitholders from continuing
operations................................................ $ 56,020 $ 38,874
Basic and diluted net income per unit from continuing
operations................................................ $ 1.31 $ 1.13
The unaudited pro forma financial information presented above is not
necessarily indicative of the results of operations we might have realized had
the transaction been completed at the beginning of the earliest period
presented, nor do they necessarily indicate our consolidated operating results
for any future period.
Prince Assets
In connection with our April 2002 acquisition of the EPN Holding assets
from El Paso Corporation, we sold our Prince tension leg platform (TLP) and our
nine percent overriding royalty interest in the Prince Field to subsidiaries of
El Paso Corporation. The results of operations for these assets have been
accounted for as discontinued operations and have been excluded from continuing
operations for all periods in our consolidated statements of income.
Accordingly, the segment results in Note 15 reflect neither the results of
operations for the Prince assets nor the related net assets held for sale. The
Prince TLP was previously included in the platform services segment and related
royalty interest was included in non-segment activity. Included in income from
discontinued operations for the years ended December 31, 2002 and 2001 were
revenues of $7.8 million and $8.8 million attributable to these disposed assets.
In April 2002, we sold the Prince assets for $190 million and recognized a
gain on the sale of $0.4 million during 2002. In conjunction with this
transaction, we repaid the related outstanding $95 million principal balance
under our Argo term loan.
Deepwater Holdings L.L.C. and Chaco Transaction
In October 2001, we acquired the remaining 50 percent interest that we did
not already own in Deepwater Holdings for approximately $81 million, consisting
of $26 million cash and $55 million of assumed indebtedness, and at the
acquisition date also repaid all of Deepwater Holdings' $110 million of
indebtedness. HIOS and East Breaks became indirect wholly-owned assets through
this transaction. In a separate transaction, we acquired interests in the title
holder of, and other interests in the Chaco cryogenic natural gas processing
plant for $198.5 million. The total purchase price was composed of a payment of
$77 million to acquire the plant from the bank group that provided the financing
for the construction of the facility and a payment of $121.5 million to El Paso
Field Services in connection with the execution of a 20-year fee-based
processing agreement relating to the processing capacity of the Chaco plant and
dedication of natural gas gathered by El Paso Field Services to the Chaco plant.
Under the terms of the processing agreement, we received a fixed fee for each
dekatherm of natural gas that we processed at the Chaco plant, and we bore all
costs associated with the plant's ownership and operations. El Paso Field
Services personnel continued to operate the plant. In accordance with the
original construction financing agreements, the Chaco plant was under an
operating lease to El Paso Field Services. El Paso Field Services had the right
to repurchase the Chaco plant at the end of the lease term in October 2002 for
approximately $77 million. We funded both of these transactions by borrowing
from our revolving credit facility. We accounted for these transactions as
purchases and have assigned the purchase price to the net assets acquired based
upon the estimated fair value of the net assets as of the acquisition date. The
operating results associated with Deepwater Holdings are included in earnings
from unconsolidated affiliates for the periods prior to October 2001. We have
included the
26
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
operating results of Deepwater Holdings and the Chaco plant in our consolidated
financial statements from the acquisition date.
Since the Chaco transaction was an asset acquisition, we have assigned the
total purchase price to property, plant and equipment and investment in
processing agreement. Since the Deepwater Holdings transaction was an
acquisition of additional interests in a business, we are providing summary
information related to the acquisition of Deepwater Holdings in the following
table (in thousands):
Fair value of assets acquired............................... $ 81,331
Cash acquired............................................... 5,386
Fair value of liabilities assumed........................... (60,917)
--------
Net cash paid..................................... $ 25,800
========
In connection with our acquisition of the San Juan assets in November 2002,
the original terms of the processing, lease and operating agreements between the
Chaco plant and El Paso Field Services were terminated. The effect on our
operation of the Chaco plant resulting from our acquisition of the San Juan
assets is discussed above.
GTM Texas (formerly EPN Texas)
In February 2001, we acquired GTM Texas from a subsidiary of El Paso
Corporation for $133 million. We funded the acquisition of these assets by
borrowing from our revolving credit facility. These assets include more than 500
miles of NGL gathering and transportation pipelines. The NGL pipeline system
gathers and transports unfractionated and fractionated products. We also
acquired three fractionation plants with a capacity of approximately 96 MBbls/d.
These plants fractionate NGL into ethane, propane, butane and natural gasoline
products that are used by refineries and petrochemical plants along the Texas
Gulf Coast. We accounted for the acquisition as a purchase and assigned the
purchase price to the assets acquired based upon the estimated fair value of the
assets as of the acquisition date. We have included the operating results of GTM
Texas in our consolidated financial statements from the acquisition date.
The following selected unaudited pro forma information represents our
consolidated results of operations on a pro forma basis for the year ended
December 31, 2001, as if we acquired GTM Texas, the Chaco plant and the
remaining 50 percent interest in Deepwater Holdings on January 1, 2001:
2001
---------------------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
Operating revenues.......................................... $269,681
Operating income............................................ $101,406
Net income allocated to limited partners.................... $ 39,157
Basic and diluted net income per unit....................... $ 1.14
Gulf of Mexico Assets
In accordance with an FTC order related to El Paso Corporation's merger
with The Coastal Corporation, we, along with Deepwater Holdings, agreed to sell
several of our offshore Gulf of Mexico assets to third parties in January 2001.
Total consideration received for these assets was approximately $163 million
consisting of approximately $109 million for the assets we sold and
approximately $54 million for the assets Deepwater Holdings sold. The offshore
assets sold include interests in Stingray, UTOS, Nautilus, Manta Ray Offshore,
Nemo, Tarpon, and the Green Canyon pipeline assets, as well as interests in two
offshore platforms and one dehydration facility. We recognized net losses from
the asset sales of approximately $12 million, and Deepwater Holdings recognized
losses of approximately $21 million. Our share of Deepwater Holdings' losses
27
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was approximately $14 million, which has been reflected in earnings from
unconsolidated affiliates in the accompanying 2001 consolidated statement of
income.
As additional consideration for the above transactions, El Paso Corporation
agreed to make payments to us totaling $29 million. These payments were made in
quarterly installments of $2.25 million for three years beginning in 2001 and we
will receive the final payment of $2 million in the first quarter of 2004. From
this additional consideration, we realized income of approximately $25 million
in the first quarter of 2001, which has been reflected in other income in the
accompanying 2001 consolidated statement of income.
3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
We hold investments in unconsolidated affiliates which are accounted for
using the equity method of accounting. As of December 31, 2003, the carrying
amount of our equity investments exceeded the underlying equity in net assets by
approximately $3.0 million, which is included in our oil and NGL logistics
segment. With our adoption of SFAS No. 142 on January 1, 2002, we no longer
amortize this excess amount, refer to Note 1, Summary of Significant Accounting
Policies, Goodwill and Other Intangible Assets. Summarized financial information
for these investments is as follows:
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2003
--------------------------------------------------------
DEEPWATER CAMERON
COYOTE GATEWAY(C) HIGHWAY(C) POSEIDON TOTAL
------- ---------- ---------- ---------- -------
(IN THOUSANDS)
END OF PERIOD OWNERSHIP
INTEREST....................... 50% 50% 50% 36%
======= ======== ======== ==========
OPERATING RESULTS DATA:
Operating revenues............. $ 7,200 $ -- $ -- $ 41,293
Other income................... 7 47 37 56
Operating expenses............. (355) -- -- (3,694)
Depreciation................... (1,381) -- -- (8,316)
Other expenses................. (736) (31) (171) (6,313)
------- -------- -------- ----------
Net income (loss).............. $ 4,735 $ 16 $ (134) $ 23,026
======= ======== ======== ==========
OUR SHARE:
Allocated income (loss)........ $ 2,368 $ 8 $ (67) $ 8,289
Adjustments(a)................. 9 (8) 67 (191)
------- -------- -------- ----------
Earnings from unconsolidated
affiliate................... $ 2,377 $ -- $ -- $ 8,098 $11,373(b)
======= ======== ======== ========== =======
Allocated distributions........ $ 3,500 $ -- $ -- $ 8,640 $12,140
======= ======== ======== ========== =======
FINANCIAL POSITION DATA:
Current assets................. $ 987 $ 8,271 $ 53,644 $ 98,937
Noncurrent assets.............. 31,897 230,825 266,554 218,893
Current liabilities............ 34,784 18,294 26,332 91,146
Noncurrent liabilities......... -- 155,000 125,000 123,000
---------------
(a) We recorded adjustments primarily for differences from estimated earnings
reported in our Annual Report on our Form 10-K and actual earnings reported
in the unaudited financial statements of our unconsolidated affiliates.
(b) Total earnings from unconsolidated affiliates includes a $898 thousand gain
associated with the sale of our interest in Copper Eagle.
(c) Cameron Highway Oil Pipeline Company and Deepwater Gateway, L.L.C. are
development stage companies; therefore there are no operating revenues or
operating expenses to provide operational results. Since their formations,
they have incurred organizational expenses and received interest income.
28
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Cameron Highway. In June 2003, we formed Cameron Highway Oil Pipeline
Company and contributed to this newly formed company the $458 million Cameron
Highway oil pipeline system construction project. Cameron Highway is responsible
for building and operating the pipeline, which is scheduled for completion
during the fourth quarter of 2004. We entered into producer agreements with
three major anchor producers, BP Exploration & Production Company, BHP Billiton
Petroleum (Deepwater), Inc., and Union Oil Company of California, which
agreements were assigned to and assumed by Cameron Highway. The producer
agreements require construction of the 390-mile Cameron Highway oil pipeline.
In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
Energy Corporation for $86 million, forming a joint venture with Valero. Valero
paid us approximately $70 million at closing, including $51 million representing
50 percent of the capital investment expended through that date for the pipeline
project. In July 2003, we recognized $19 million as a gain from the sale of
long-lived assets. In addition, Valero will pay us $5 million once the system is
completed and another $11 million by the end of 2006. We expect to reflect the
receipts of these additional amounts in the periods received as gains from the
sale of long-lived assets in our statement of income. In connection with the
formation of the Cameron Highway joint venture, Valero agreed to pay their
proportionate share of pipeline construction costs that exceed Cameron Highway's
capital resources, including the initial equity contributions and proceeds from
Cameron Highway's project loan facility.
The Cameron Highway oil pipeline system project is expected to be funded
with 37 percent equity, or $169 million through capital contributions from us
and Valero, the two Cameron Highway partners, which contributions have already
been made, and 63 percent debt through a $325 million project loan facility,
consisting of a $225 million construction loan and $100 million of senior
secured notes. See Note 6 for additional discussion of the project loan
facility. As of December 31, 2003, Cameron Highway has spent approximately $256
million (of which $85 million constituted equity contributions by us) related to
this pipeline, which is in the construction stage. We and Valero are obligated
to make additional capital contributions to Cameron Highway if and to the extent
that the construction costs for the pipeline exceed Cameron Highway's capital
resources, including initial equity contributions and proceeds from Cameron
Highway's project loan facility.
Deepwater Gateway. As of December 31, 2003, we have contributed $33
million, as our 50 percent share, to Deepwater Gateway, which amount satisfies
our initial equity funding requirement related to the Marco Polo TLP. We expect
that the remaining costs associated with the Marco Polo TLP will be funded
through the $155 million project finance loan and Deepwater Gateway's members'
contingent equity obligations (of which our share is $14 million). This project
finance loan will mature in July 2004 unless construction is completed before
that time and Deepwater Gateway meets other specified conditions, in which case
the project finance loan will convert into a term loan with a final maturity
date of July 2009. The loan agreement requires Deepwater Gateway to maintain a
debt service reserve equal to six months' interest. Other than that debt service
reserve and any other reserve amounts agreed upon by more than 66.7 percent
majority interest of Deepwater Gateway's members, Deepwater Gateway will (after
the project finance loan is either repaid or converted into a term loan)
distribute any available cash to its members quarterly. Deepwater Gateway is not
currently generating income or cash flow. Deepwater Gateway is managed by a
management committee consisting of representative from each of its members.
Front Runner Oil Pipeline. In September 2003, we announced that Poseidon,
our 36 percent owned joint venture, entered into an agreement for the purchase
and sale of crude oil from the Front Runner Field. Poseidon will construct, own
and operate the $28 million project, which will connect the Front Runner
platform with Poseidon's existing system at Ship Shoal Block 332. The new
36-mile, 14-inch pipeline is expected to be operational by the third quarter of
2004 and have a capacity of 65 MBbls/d. As Poseidon expects to fund Front
Runner's capital expenditures from its operating cash flow and from its
revolving credit
29
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
facility, we do not expect to receive distributions from Poseidon until the
Front Runner oil pipeline is completed.
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
-----------------------------------------------
DEEPWATER
COYOTE(A) POSEIDON GATEWAY(B) TOTAL
--------- ----------- ---------- --------
(IN THOUSANDS)
END OF PERIOD OWNERSHIP INTEREST...................... 50% 36% 50%
======= ========== ========
OPERATING RESULTS DATA:
Operating revenues.................................. $ 635 $ 54,261 $ --
Other income........................................ 2 26,695 20
Operating expenses.................................. (38) (4,691) --
Depreciation........................................ (110) (8,356) --
Other expenses...................................... (75) (6,923) (234)
------- ---------- --------
Net income (loss)................................... $ 414 $ 60,986 $ (214)
======= ========== ========
OUR SHARE:
Allocated income (loss)............................. $ 207 $ 21,955 $ (107)
Adjustments(c)...................................... (13) (8,510) 107
------- ---------- --------
Earnings from unconsolidated affiliate.............. $ 194 $ 13,445 $ -- $13,639
======= ========== ======== =======
Allocated distributions............................. $ 2,000 $ 15,804 $ -- $17,804
======= ========== ======== =======
FINANCIAL POSITION DATA:
Current assets...................................... $ 1,575 $ 152,784 $ 10,745
Noncurrent assets................................... 33,349 218,463 110,309
Current liabilities................................. 34,559 119,974 28,268
Noncurrent liabilities.............................. -- 148,000 27,000
---------------
(a) We acquired an interest in Coyote Gas Treating, L.L.C. in November 2002 as
part of the San Juan assets acquisition.
(b) In June 2002, we formed Deepwater Gateway, L.L.C., a 50/50 joint venture
with Cal Dive International, Inc., to construct and install the Marco Polo
TLP. Also in August 2002, Deepwater Gateway obtained a project finance loan
to fund a substantial portion of the cost to construct the Marco Polo TLP.
For further discussion of this project loan, see Note 6, Financing
Transactions. Deepwater Gateway, L.L.C. is a development stage company;
therefore there are no operating revenues or operating expenses to provide
operational results. Since Deepwater Gateway's formation in 2002, it has
incurred organizational expenses and received interest income.
(c) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on our Form 10-K and actual earnings
recorded in the audited annual reports of our unconsolidated affiliates. The
adjustment for Poseidon primarily represents the receipt of proceeds from a
favorable litigation related to the January 2000 pipeline rupture.
30
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
--------------------------------------------------------------
DEEPWATER DIVESTED
HOLDINGS(A) POSEIDON INVESTMENTS(B) OTHER(C) TOTAL
----------- ---------- -------------- -------- -------
(IN THOUSANDS)
END OF PERIOD OWNERSHIP INTEREST....... 100% 36% -- 50%
======== ========== ====== ====
OPERATING RESULTS DATA:
Operating revenues................... $ 40,933 $ 70,401 $1,982 $145
Other income (loss).................. -- 394 (85) --
Operating expenses................... (16,740) (1,586) (590) (73)
Depreciation......................... (8,899) (10,552) (953) --
Other (expenses) income.............. (5,868) (7,668) 222 (22)
Loss on sale of assets............... (21,453) -- -- --
-------- ---------- ------ ----
Net income (loss).................... $(12,027) $ 50,989 $ 576 $ 50
======== ========== ====== ====
OUR SHARE:
Allocated income (loss)(d)........... $ (9,925) $ 18,356 $ 148 $ 25
Adjustments(e)....................... -- (146) (9) --
-------- ---------- ------ ----
Earnings (loss) from unconsolidated
affiliates........................ $ (9,925) $ 18,210 $ 139 $ 25 $ 8,449
======== ========== ====== ==== =======
Allocated distributions.............. $ 12,850 $ 22,212 $ -- $ -- $35,062
======== ========== ====== ==== =======
FINANCIAL POSITION DATA:
Current assets....................... $ 91,367 $177
Noncurrent assets.................... 226,570 --
Current liabilities.................. 80,365 33
Noncurrent liabilities............... 150,000 --
---------------
(a) In January 2001, Deepwater Holdings sold its Stingray and West Cameron
subsidiaries. Deepwater Holdings sold its interest in its UTOS subsidiary in
April 2001. In October 2001, we acquired the remaining 50 percent of
Deepwater Holdings and as a result of this transaction, from the acquisition
date Deepwater Holdings is consolidated in our financial statements. The
information presented for Deepwater Holdings as an equity investment is
through October 18, 2001.
(b) Divested Investments contains Manta Ray Offshore Gathering Company, L.L.C.
and Nautilus Pipeline Company L.L.C. In January 2001, we sold our 25.67
percent interest in Manta Ray Offshore and our 25.67 percent interest in
Nautilus.
(c) Through October 2001 this company processed gas for Deepwater Holdings'
Stingray subsidiary. This agreement was terminated in October 2001, and as
of this date there are no operations related to this investment.
(d) The income (loss) from Deepwater Holdings is not allocated proportionately
with our ownership percentage because the capital contributed by us was a
larger amount of the total capital at the time of formation. Therefore, we
were allocated a larger amount of amortization of Deepwater Holdings' excess
purchase price of its investments. Also, we were allocated a larger portion
of Deepwater Holdings' $21 million loss incurred in 2001 due to the sale of
Stingray, UTOS, and the West Cameron dehydration facility. Our total share
of the losses relating to these sales was approximately $14 million.
(e) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on Form 10-K and actual earnings
reported in the audited annual reports of our unconsolidated affiliates.
31
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consisted of the following:
DECEMBER 31,
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS)
Property, plant and equipment, at cost(1)
Pipelines................................................. $2,487,102 $2,317,503
Platforms and facilities.................................. 121,105 128,582
Processing plants......................................... 305,904 300,897
Oil and natural gas properties............................ 131,100 127,975
Storage facilities........................................ 337,535 331,562
Construction work-in-progress............................. 383,640 177,964
---------- ----------
3,766,386 3,384,483
Less accumulated depreciation, depletion and amortization... 871,894 659,545
---------- ----------
Total property, plant and equipment, net.................... $2,894,492 $2,724,938
========== ==========
---------------
(1) Includes leasehold acquisition costs with an unamortized balance of $3.2
million and $4.1 million at December 31, 2003 and 2002. One interpretation
being considered relative to SFAS No. 141, Business Combinations and SFAS
No. 142, Goodwill and Intangible Assets is that oil and gas mineral rights
held under lease and other contractual arrangements representing the right
to extract such reserves for both undeveloped and developed leaseholds
should be classified separately from oil and gas properties, as intangible
assets on our consolidated balance sheets. We will continue to include these
costs in property, plant, and equipment until further guidance is provided.
Due to the sale of our interest in the Manta Ray Offshore system in January
2001, we lost a primary connecting point to our Manta Ray pipeline. As a result,
we abandoned the Manta Ray pipeline and recorded an impairment of approximately
$3.9 million in the first quarter of 2001 which is reflected in the natural gas
pipelines and plants segment.
5. INVESTMENT IN PROCESSING AGREEMENT
As part of our October 2001 Chaco transaction, we paid $121.5 million to El
Paso Field Services for a 20-year fee-based processing agreement. The processing
agreement was being amortized on a straight-line basis over the life of the
agreement and we recorded amortization expense of $5.6 million in 2002 and $1.5
million in 2001 related to this asset. As a result of the San Juan acquisition
in November 2002, we now own the gathering system and related facilities
previously owned by El Paso Field Services, including the rights of El Paso
Field Services under the arrangements relating to the Chaco plant. As part of
the San Juan acquisition, the processing agreement was terminated.
6. FINANCING TRANSACTIONS
CREDIT FACILITY
Our credit facility consists of two parts: the revolving credit facility
maturing in 2006 and a senior secured term loan maturing in 2008. Our credit
facility is guaranteed by us and all of our subsidiaries, except for our
unrestricted subsidiaries, as detailed in Note 16, and are collateralized with
substantially all of our assets (excluding the assets of our unrestricted
subsidiaries). The interest rates we are charged on our credit facility are
determined at our option using one of two indices that include (i) a variable
base rate (equal to the greater of the prime rate as determined by JPMorgan
Chase Bank, the federal funds rate plus 0.5% or the Certificate of Deposit (CD)
rate as determined by JPMorgan Chase Bank increased by 1.00%); or (ii) LIBOR.
The interest rate we are charged is contingent upon our leverage ratio, as
defined in our credit facility, and ratings we are assigned by S&P or Moody's.
The interest we are charged would increase by 0.25% if the credit ratings
32
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
on our senior secured credit facility decrease or our leverage ratio decreases,
or, alternatively, would decrease by 0.25% if these ratings are increased or our
leverage ratio improves. Additionally, we pay commitment fees on the unused
portion of our revolving credit facility at rates that vary from 0.30% to 0.50%.
Our credit facility contains covenants that include restrictions on our and our
subsidiaries' ability to incur additional indebtedness or liens, sell assets,
make loans or investments, acquire or be acquired by other companies and amend
some of our contracts, as well as requiring maintenance of certain financial
ratios. Failure to comply with the provisions of any of these covenants could
result in acceleration of our debt and other financial obligations and that of
our subsidiaries and restrict our ability to make distributions to our
unitholders. The financial covenants associated with our credit facility are as
follows:
(a) The ratio of consolidated EBITDA, as defined in our credit
agreements, to consolidated interest expense cannot be less than 2.0 to
1.0;
(b) The ratio of consolidated total senior indebtedness on the last
day of any fiscal quarter to the consolidated EBITDA for the four quarters
ending on the last day of the current quarter cannot exceed 3.25 to 1.0;
and
(c) The ratio of our consolidated total indebtedness on the last day
of any fiscal quarter to the consolidated EBITDA for the four quarters
ending on the last day of the current quarter cannot exceed 5.25 to 1.0.
Among other things, our credit agreement includes as an event of default a
change of control, defined as the failure of El Paso Corporation and its
subsidiaries to no longer own at least 50 percent of our general partner. We are
in compliance with the financial ratios and covenants contained in each of our
credit facilities at December 31, 2003.
Revolving Credit Facility
In September 2003, we renewed our revolving credit facility to, among other
things, expand the credit available from $600 million to $700 million and extend
the maturity from May 2004 to September 2006.
At December 31, 2003, we had $382 million outstanding under our revolving
credit facility at an average interest rate of 3.17%. We may elect that all or a
portion of the revolving credit facility bear interest at either the variable
rate described above increased by 1.0% or LIBOR increased by 2.0%. The total
amount available to us at December 31, 2003, under this facility was $318
million.
Senior Secured Term Loan
In December 2003, we refinanced the term loan portion of our credit
facility to provide greater financial flexibility by, among other things,
expanding the existing term component from $160 million to $300 million,
extending the maturity from October 2007 to December 2008, reducing the
semi-annual payments from $2.5 million to $1.5 million and reducing the interest
rate we are charged by 1.25%. We used the proceeds from the term loan to repay
the $155 million outstanding under the initial term loan and to temporarily
reduce amounts outstanding under our revolving credit facility. We charged $2.8
million to interest and debt expense in December 2003 to write-off unamortized
debt issuance costs associated with the initial term loan.
The senior secured term loan is payable in semi-annual installments of $1.5
million in June and December of each year for the first nine installments and
the remaining balance at maturity in December 2008. We may elect that all or a
portion of the senior secured term loan bear interest at either 1.25% over the
variable base rate discussed above; or LIBOR increased by 2.25%. As of December
31, 2003, we had $300 million outstanding with an average interest rate of
3.42%.
33
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
GulfTerra Holding Term Credit Facility (formerly EPN Holding Term Credit
Facility)
In connection with our acquisition of the EPN Holding assets from El Paso
Corporation in April 2002, EPN Holding entered into a $560 million term credit
facility with a group of commercial banks. The term credit facility provided a
term loan (the GulfTerra Holding term loan) of $535 million to finance the
acquisition of the EPN Holding assets, and a revolving credit facility (the
GulfTerra Holding revolving credit facility) of up to $25 million to finance EPN
Holding's working capital. At the time of its acquisition, EPN Holding borrowed
$535 million ($531 million, net of issuance costs) under this term loan and had
$25 million available under the GulfTerra Holding revolving credit facility. We
used net proceeds of approximately $149 million from our April 2002 common unit
offering, $0.6 million contributed by our general partner to maintain its one
percent capital account balance and $225 million of the net proceeds from our
May 2002 offering of 8 1/2% Senior Subordinated Notes to reduce indebtedness
under the term loan. In July 2003, we repaid the remaining $160 million balance
of this term credit facility with proceeds from our issuance of $250 million
6 1/4% senior notes due 2010. We recognized a loss of $1.2 million related to
the write-off of unamortized debt issuance costs in connection with our
repayment of this facility.
Senior Secured Acquisition Term Loan
As part of our November 2002 San Juan assets acquisition, we entered into a
$237.5 million senior secured acquisition term loan to fund a portion of the
purchase price. We repaid this senior secured acquisition term loan in March
2003 with proceeds from our issuance of $300 million 8 1/2% senior subordinated
notes due 2010. We recognized a loss of $3.8 million related to the write-off of
unamortized debt issuance costs in connection with our repayment of this
facility. From the issuance of the senior secured acquisition term loan in
November 2002 to its repayment date, the interest rates on our revolving credit
facility and GulfTerra Holding term credit facility were 2.25% over the variable
base rate described above or LIBOR increased by 3.50%.
Argo Term Loan
This loan with a balance of $95 million, including current maturities, at
December 31, 2001, was repaid in full in April 2002, in connection with the EPN
Holding assets acquisition.
SENIOR NOTES
In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due June 2010. We used the proceeds of approximately $245.1
million, net of issuance costs, to repay $160 million of indebtedness under the
GulfTerra Holding term credit facility and to temporarily repay $85.1 million of
the balance outstanding under our revolving credit facility. The interest on our
senior notes is payable semi-annually in June and December with the principal
maturing in June 2010. Our senior notes are unsecured obligations that rank
senior to all our existing and future subordinated debt and equally with all of
our existing and future senior debt, although they are effectively junior in
right of payment to all of our existing and future senior secured debt to the
extent of the collateral securing that debt. Our senior notes are guaranteed by
us and all of our subsidiaries, except for our unrestricted subsidiaries.
We may redeem some or all of our senior notes, at our option, at any time
with at least 30 days notice at a price equal to the greater of (1) 100 percent
of the principal amount plus accrued interest, or (2) the sum of the present
value of the remaining scheduled payments plus accrued interest.
SENIOR SUBORDINATED NOTES
Each issue of our senior subordinated notes is subordinated in right of
payment to all of our existing and future senior debt, including our existing
credit facility and the senior notes we issued in July 2003.
34
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes. The interest on these notes is payable
semi-annually in June and December, and the notes mature in June 2010. We used
the proceeds of approximately $293.5 million, net of issuance costs, to repay
$237.5 million of indebtedness under our senior secured acquisition term loan
and to temporarily repay $55.5 million of the balance outstanding under our
revolving credit facility. We may, at our option, prior to June 1, 2006, redeem
up to 33 percent of the originally issued aggregate principal amount of these
notes at a redemption price of 108.50 percent of the principal amount, and in
December 2003, we redeemed $45 million under this provision (see discussion
below). We may redeem all or part of the remainder of these notes at any time on
or after June 1, 2007. The redemption price on that date is 104.25 percent of
the principal amount, declining annually until it reaches 100 percent of the
principal amount.
In November 2002, we issued $200 million in aggregate principal amount of
10 5/8% Senior Subordinated Notes. The interest on these notes is payable
semi-annually in June and December, and mature in December 2012. These notes
were issued for $198 million, net of discount of $1.5 million to yield 10.75%
(proceeds of $194 million, net of issuance costs) which we used to fund a
portion of the acquisition of the San Juan assets. We may, at our option, prior
to December 1, 2005, redeem up to 33 percent of the originally issued aggregate
principal amount of the notes at a redemption price of 110.625%, and in December
2003, we redeemed $66 million under this provision (see discussion below). On or
after December 1, 2007, we may redeem all or part of the remainder of these
notes at 105.313% of the principal amount.
In May 2002, we issued $230 million in aggregate principal amount of 8 1/2%
Senior Subordinated Notes. The interest on these notes is payable semi-annually
in June and December, and mature June 2011. The Senior Subordinated Notes were
issued for $234.6 million (proceeds of approximately $230 million, net of
issuance costs). We used proceeds of $225 million to reduce indebtedness under
our EPN Holding term credit facility and the remainder for general partnership
purposes. We may, at our option, prior to June 1, 2004, redeem up to 33 percent
of the originally issued aggregate principal amount of the senior subordinated
notes due June 2011, at a redemption price of 108.500%, and in December 2003, we
redeemed $75.9 million under this provision (see discussion below). On or after
June 1, 2006, we may redeem all or part of the remainder of these notes at
104.250% of the principal amount.
In May 2001, we issued $250 million in aggregate principal amount of 8 1/2%
Senior Subordinated Notes. The interest on these notes is payable semi-annually
in June and December, and mature in June 2011. Proceeds of approximately $243
million, net of issuance costs, were used to reduce indebtedness under our
revolving credit facility. We may, at our option, prior to June 1, 2004, redeem
up to 33 percent of the originally issued aggregate principal amount of the
senior subordinated notes due June 2011, at a redemption price of 108.500%, and
in December 2003, we redeemed $82.5 million under this provision (see discussion
below). On or after June 1, 2006, we may redeem all or part of the remainder of
these notes at 104.250% of the principal amount.
In May 1999, we issued $175 million in aggregate principal amount of
10 3/8% Senior Subordinated Notes. The interest on these notes is payable
semi-annually in June and December, and mature in June 2009. Proceeds of
approximately $169 million, net of issuance costs, were used to reduce
indebtedness under our revolving credit facility. On or after June 1, 2004, we
may redeem all or part of these notes at 105.188% of the principal amount.
Our subsidiaries, except GulfTerra Energy Partners Finance Corporation and
our unrestricted subsidiaries, have guaranteed our obligations under the senior
notes and all of the issuances of senior subordinated notes described above. In
addition, we could be required to repurchase the senior notes and senior
subordinated notes if certain circumstances relating to change of control or
asset dispositions exist.
In July 2003, to achieve a better 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%
35
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
senior subordinated notes due 2011. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under SFAS No. 133. At
December 31, 2003, the fair value of the swap was a liability, included in
non-current liabilities, of approximately $7.4 million. The fair value of the
hedged debt decreased by the same amount.
In December 2003, we used a portion of the net proceeds from our October
2003 equity offerings to redeem approximately $269.4 million in principal amount
of our senior subordinated notes. The terms of our indentures allow us to use
proceeds from an equity offering, within a 90 day period after the offering, to
redeem up to 33 percent of the principal during the first three years the notes
are outstanding. We incurred additional costs totaling $29.1 million resulting
from the payment of the redemption premiums and the write-off of unamortized
debt issuance costs, premiums and discounts. We accounted for these costs as an
expense during the fourth quarter of 2003 in accordance with the provisions of
SFAS No. 145.
In March 2004, we gave notice to exercise our right, under the terms of our
senior subordinated notes' indentures, to repay, at a premium, approximately
$39.1 million in principal amount of those senior subordinated notes. The
indentures provide that, within 90 days of an equity offering, we can call up to
33 percent of the original face amount at a premium. The amount we can repay is
limited to the net proceeds of the offering. We will recognize additional costs
totaling $4.1 million resulting from the payment of the redemption premiums and
the writeoff of unamortized debt issuance costs. We will account for these costs
as an expense during the second quarter of 2004 in accordance with the
provisions of SFAS No. 145.
RESTRICTIVE PROVISIONS OF SENIOR AND SENIOR SUBORDINATED NOTES
Our senior and senior subordinated notes include provisions that, among
other things, restrict our ability and the ability of our subsidiaries
(excluding our unrestricted subsidiaries) to incur additional indebtedness or
liens, sell assets, make loans or investments, acquire or be acquired by other
companies, and enter into sale and lease-back transactions, as well as requiring
maintenance of certain financial ratios. Failure to comply with the provisions
of these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries in addition to restricting our ability
to make distributions to our unitholders. Many restrictive covenants associated
with our senior notes will effectively be removed following a period of 90
consecutive days during which they are rated Baa3 or higher by Moody's or BBB-
or higher by S&P, and some of the more restrictive covenants associated with
some (but not all) of our senior subordinated notes will be suspended should
they be similarly rated.
OTHER CREDIT FACILITIES
Poseidon
As of December 31, 2003, Poseidon Oil Pipeline Company, L.L.C., an
unconsolidated affiliate in which we have a 36 percent joint venture ownership
interest, was party to a $185 million credit agreement under which it had $123
million outstanding at December 31, 2003.
In January 2004, Poseidon amended its credit agreement and decreased the
availability to $170 million. The amended facility matures in January 2008. The
outstanding balance from the previous facility was transferred to the new
facility.
In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of the
$123 million outstanding under its credit facility at 3.49% through January
2004. Poseidon, under its credit facility, currently pays an additional 1.25%
over the LIBOR rate resulting in an effective interest rate of 4.74% on the
hedged notional amount. The interest rates Poseidon is charged on balances
outstanding under its credit facility are dependent on its leverage ratio as
defined in the Poseidon credit facility. Poseidon's interest rate at December
31, 2003 was LIBOR plus 1.25% for Eurodollar
36
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
loans and a variable base rate equal to the greater of the prime rate or 0.50%
plus the federal funds rate (as those terms are defined in the Poseidon credit
agreement) plus 0.25% for Base Rate loans. As of December 31, 2003, the
remaining $48 million was at an average interest rate of 2.46%.
Under its amended credit facility, based on Poseidon's leverage ratio for
the year ended December 31, 2003, Poseidon's interest rate is LIBOR plus 2.00%
for Eurodollar loans and a variable base rate equal to the greater of the prime
rate or 0.50% plus the federal funds rate (as those terms are defined in the
Poseidon credit agreement) plus 1.00% for Base Rate loans. Poseidon's interest
rates will decrease by 0.25% if their leverage ratio declines to 3.00 to 1.00 or
less, by 0.50% if their leverage ratio declines to 2.00 to 1.00 or less, or by
0.625% if their leverage ratio declines to 1.00 to 1.00 or less. Additionally,
Poseidon pays commitment fees on the unused portion of the credit facility at
rates that vary from 0.25% to 0.375%. This credit agreement requires Poseidon to
maintain a debt service reserve equal to two times the previous quarters'
interest.
Poseidon's credit agreement contains covenants such as restrictions on debt
levels, restrictions on liens collateralizing debt and guarantees, restrictions
on mergers and on the sales of assets and dividend restrictions. A breach of any
of these covenants could result in acceleration of Poseidon's debt and other
financial obligations.
Under the Poseidon $170 million revolving credit facility, the financial
debt covenants are:
(a) Poseidon must maintain consolidated tangible net worth in an amount
not less than $75 million plus 100% of the net cash proceeds from the
issuance by Poseidon of equity securities of any kind;
(b) the ratio of Poseidon's EBITDA, as defined in Poseidon's credit
agreement, to interest expense paid or accrued during the four
quarters ending on the last day of the current quarter must be at
least 2.50 to 1.00; and
(c) the ratio of total indebtedness of Poseidon to EBITDA for the four
quarters ending on the last day of the current quarter shall not
exceed 4.50 to 1.00 in 2004, 3.50 to 1.00 in 2005 and 3.00 to 1.00
thereafter.
Poseidon was in compliance with the above covenants and the covenants under
its previous facility as of December 31, 2003.
Deepwater Gateway
In August 2002, Deepwater Gateway, our joint venture that is constructing
the Marco Polo TLP, obtained a $155 million project finance loan from a group of
commercial lenders to finance a substantial portion of the cost to construct the
Marco Polo TLP and related facilities. Deepwater Gateway may elect that all or a
portion of the project finance loan bear interest at either (i) LIBOR plus 1.75%
or (ii) an alternate base rate (equal to the greater of the prime rate, the base
CD rate plus 1% or the federal funds rate plus 0.5%, as those terms are defined
in the project finance loan agreement) plus 0.75%. Deepwater Gateway must also
pay commitment fees of 0.375% per year on the unused portion of the project
finance loan. The loan is collateralized by substantially all of Deepwater
Gateway's assets. If Deepwater Gateway defaults on its payment obligations under
the project finance loan, we would be required to pay to the lenders all
distributions we or any of our subsidiaries have received from Deepwater Gateway
up to $22.5 million. As of December 31, 2003, Deepwater Gateway had $155 million
outstanding under the project finance loan at an average interest rate of 2.94%
and had not paid us or any of our subsidiaries any distributions.
This project finance loan will mature in July 2004 unless construction is
completed before that time and Deepwater Gateway meets other specified
conditions, in which case the project finance loan will convert into a term loan
with a final maturity date of July 2009. Upon conversion of the project finance
loan to a term loan, Deepwater Gateway will be required to maintain a debt
service reserve of not less than the projected principal, interest and fees due
on the term loan for the immediately succeeding six month period. In addition,
37
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Deepwater Gateway is prohibited from making distributions until the project
finance loan has been repaid or is converted.
Cameron Highway
Cameron Highway Oil Pipeline Company (Cameron Highway), an unconsolidated
affiliate in which we have a 50 percent joint venture ownership interest (See
Note 3 for additional discussion relating to the formation of Cameron Highway),
entered into a $325 million project loan facility, consisting of a $225 million
construction loan and $100 million of senior secured notes, each of which fund
proportionately as construction costs are incurred.
The $225 million construction loan bears interest at Cameron Highway's
option at each borrowing at either (i) 2.00% over the variable base rate (equal
to the greater of the prime rate as determined by JPMorgan Chase Bank, the
federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as
determined by JPMorgan Chase Bank increased by 1.00%); or (ii) 3.00% over LIBOR.
Upon completion of the construction, the construction loan will convert to a
term loan maturing July 2008, subject to the terms of the loan agreement. At the
end of the first quarter following the first anniversary of the conversion into
a term loan, Cameron Highway will be required to make quarterly principal
payments of $8.125 million, with the remaining unpaid principal amount payable
on the maturity date. If the construction loan fails to convert into a term loan
by December 31, 2006, the construction loan and senior secured notes become
fully due and payable. At December 31, 2003, Cameron Highway had $69 million
outstanding under the construction loan at an average interest rate of 4.21%.
The interest rate on Cameron Highway's senior secured notes is 3.25% over
the rate on 10-year U.S. Treasury securities. Principal payments of $4 million
are due quarterly from September 2008 through December 2011, $6 million each
from March 2012 through December 2012, and $5 million each from March 2013
through the principal maturity date of December 2013. At December 31, 2003,
Cameron Highway had $56 million outstanding under the notes at an average
interest rate of 7.38%.
Under the terms of its project loan facility, Cameron Highway must pay each
of the lenders and the senior secured noteholders commitment fees of 0.5% per
year on any unused portion of such lender's or noteholder's committed funds. The
project loan facility as a whole is collateralized by (1) substantially all of
Cameron Highway's assets, including, upon conversion, a debt service reserve
capital account, and (2) all of the equity interest in Cameron Highway. Other
than the pledge of our equity interest and our construction obligations under
the relevant producer agreements, as discussed in Note 3, the debt is
non-recourse to us. The construction loan and senior secured notes prohibit
Cameron Highway from making distributions to us until the construction loan is
converted into a term loan and Cameron Highway meets certain financial
requirements.
DEBT MATURITY TABLE
Aggregate maturities of the principal amounts of long-term debt and other
financing obligations for the next 5 years and in total thereafter are as
follows (in thousands):
2004...................................................... $ 3,000
2005...................................................... 3,000
2006...................................................... 385,000
2007...................................................... 3,000
2008...................................................... 288,000
Thereafter.................................................. 1,135,600
----------
Total long-term debt and other financing
obligations, including current maturities........ $1,817,600
==========
38
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
INTEREST AND DEBT EXPENSE
We recognized the interest cost incurred in connection with our financing
transactions as follows for each of the years ended December 31:
2003 2002 2001
-------- ------- --------
(IN THOUSANDS)
Interest expense incurred............................. $140,282 $87,522 $ 54,885
Interest capitalized.................................. (12,452) (5,571) (11,755)
-------- ------- --------
Net interest expense................................ 127,830 81,951 43,130
Less: Interest expense on discontinued operations..... -- 891 1,588
-------- ------- --------
Net interest expense on continuing operations....... $127,830 $81,060 $ 41,542
======== ======= ========
LOSS DUE TO EARLY REDEMPTIONS OF DEBT
We recognized losses associated with early redemptions of debt as follows
for each of the years ended December 31:
2003 2002
------- ------
(IN THOUSANDS)
Loss due to payment of redemption premiums.................. $24,302 $ --
Loss due to write-off of unamortized debt issuance costs,
premiums and discounts.................................... 12,544 2,434
------- ------
$36,846 $2,434
======= ======
7. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
The carrying amounts and estimated fair values of our financial instruments
at December 31 are as follows:
2003 2002
---------------------- ----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Liabilities:
Revolving credit facility........................ $382.0 $382.0 $491.0 $491.0
GulfTerra Holding term credit facility........... -- -- 160.0 160.0
Senior secured term loan......................... 300.0 300.0 160.0 160.0
Senior secured acquisition term loan............. -- -- 237.5 237.5
10 3/8% senior subordinated notes................ 175.0 189.9 175.0 186.4
8 1/2% senior subordinated notes(1).............. 167.5 188.4 250.0 233.1
8 1/2% senior subordinated notes(1).............. 156.6 173.4 234.3 214.5
10 5/8% senior subordinated notes................ 133.1 165.5 198.5 205.5
8 1/2% senior subordinated notes................. 255.0 290.7 -- --
6 1/4% senior notes.............................. 250.0 262.5 -- --
Non-trading derivative instruments
Commodity swap and forward contracts.......... $ 9.0 $ 9.0 $ 4.7 $ 4.7
Interest rate swap............................ 7.4 7.4 -- --
---------------
(1) Excludes market value of interest rate swap, see interest rate swap
discussion below.
39
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The notional amounts and terms of the financial instruments held for
purposes other than trading were as follows at December 31:
2003 2002
---------------------------- --------------------------
NOTIONAL NOTIONAL
VOLUME VOLUME
------------ MAXIMUM ---------- MAXIMUM
BUY SELL TERM IN YEARS BUY SELL TERM IN YEARS
--- ------ ------------- --- ---- -------------
Commodity
Natural Gas (MDth)..................... 85 10,980 <1 95 10,950 <1
NGL (MBbl)............................. -- 1,644 <1 -- -- --
In July 2003, 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 will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%.
As of December 31, 2003, and 2002, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. The fair value of long-term debt with variable interest rates
approximates its carrying value because the variable interest rates on these
loans reprice frequently to reflect currently available interest rates. We
estimated the fair value of debt with fixed interest rates based on quoted
market prices for the same or similar issues. We estimated the fair value of all
derivative financial instruments from prices indicated for the same or similar
commodity transactions for a specific index.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of
our customers' failure to pay. Our customers are concentrated in the energy
sector, and the creditworthiness of several industry participants have been
called into question. We maintain credit policies to minimize overall credit
risk. We monitor our exposure to and determine, as appropriate, whether we
should request prepayments, letters of credit or other collateral from our
counterparties.
8. PARTNERS' CAPITAL
General
As of December 31, 2003, we had 58,404,649 common units outstanding. Common
units totaling 48,020,404 are owned by the public, representing an 82.2 percent
common unit interest in us. As of December 31, 2003, El Paso Corporation,
through its subsidiaries, owned 10,384,245 common units, or 17.8 percent of our
outstanding common units, all of our 10,937,500 Series C units and 50 percent of
our one percent general partner interest.
Offering of Common Units
During 2003, we issued the following common units in public offerings:
COMMON UNITS PUBLIC OFFERING NET OFFERING
OFFERING DATE ISSUED PRICE PROCEEDS
------------- ------------ --------------- --------------
(PER UNIT) (IN THOUSANDS)
October 2003................................ 4,800,000 $40.60 $186.1
August 2003................................. 507,228 $39.43 $ 19.7
June 2003................................... 1,150,000 $36.50 $ 40.3
May 2003(1)................................. 1,118,881 $35.75 $ 38.3
April 2003.................................. 3,450,000 $31.35 $103.1
---------------
(1) Offering includes 80 Series F convertible units offered. Refer to
description below.
40
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In addition to our public offerings of common units, in October 2003, we
sold 3,000,000 common units privately to Goldman Sachs in connection with their
purchase of a 9.9 percent membership interest in our general partner. We used
the net proceeds of $111.5 million from that private sale and the net proceeds
from the other common unit public offerings to temporarily reduce amounts
outstanding under our revolving credit facility, senior subordinated notes, and
for general partnership purposes.
In May 2003, we issued 1,118,881 common units and 80 Series F convertible
units in a registered offering to a large institutional investor for
approximately $38.3 million net of offering costs. Our Series F convertible
units are not listed on any securities exchange or market. Each Series F
convertible unit is comprised of two separate detachable units -- a Series F1
convertible unit and a Series F2 convertible unit -- that have identical terms
except for vesting and termination dates and the number of underlying common
units into which they may be converted. The Series F1 units are convertible into
up to $80 million of common units anytime after August 12, 2003, and until the
date we merge with Enterprise (subject to other defined extension rights). The
Series F2 units are convertible into up to $40 million of common units. The
Series F2 units terminate on March 30, 2005 (subject to defined extension
rights). The price at which the Series F convertible units may be converted to
common units is equal to the lesser of (i) the prevailing price (as defined
below), if the prevailing price is equal to or greater than $35.75, or (ii) the
prevailing price minus the product of 50 percent of the positive difference, if
any, of $35.75 minus the prevailing price. The prevailing price is equal to the
lesser of (i) the average closing price of our common units for the 60 business
days ending on and including the fourth business day prior to our receiving
notice from the holder of the Series F convertible units of their intent to
convert them into common units; (ii) the average closing price of our common
units for the first seven business days of the 60 day period included in (i); or
(iii) the average closing price of our common units for the last seven days of
the 60 day period included in (i). The price at which the Series F convertible
units could have been converted to common units, assuming we had received a
conversion notice on December 31, 2003 and March 2, 2004, was $40.38 and $39.40.
The Series F convertible units may be converted into a maximum of 8,329,679
common units. Holders of Series F convertible units are not entitled to vote or
receive distributions. The $4.1 million value associated with the Series F
convertible units is included in partners' capital as a component of common
units capital.
In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at December 31, 2003.
In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million.
Any Series F convertible units outstanding at the merger date will be
converted into rights to receive Enterprise common units, subject to the
restrictions governing the Series F units. The number of Enterprise common units
and the price per unit at conversion will be adjusted based on the 1.81 exchange
ratio.
In connection with the offerings in 2003, our general partner contributed
to us approximately $2.0 million of our Series B preference units and cash of
$3.1 million in order to maintain its one percent general partner interest.
In April 2002, we completed simultaneous offerings of 4,083,938 common
units, which included a public offering of 3,000,000 common units and a private
offering, at the same unit price, of 1,083,938 common units to our general
partner (pursuant to our general partner's anti-dilution rights under our
partnership agreement)
41
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
as a transaction not involving a public offering. We used the net cash proceeds
of approximately $149 million to reduce indebtedness under EPN Holding's term
credit facility. Also in April 2002, we issued in a private offering 159,497
common units at the then-current market price of $37.74 per unit to a subsidiary
of El Paso Corporation as partial consideration for our acquisition of the EPN
Holding assets. In addition, our general partner contributed approximately $0.6
million in cash to us in April 2002 in order to maintain its one percent capital
account balance.
In October 2001, we completed simultaneous offerings of 5,627,070 common
units, which included a public offering of 4,150,000 common units and a private
offering, at the same unit price, of 1,477,070 common units to our general
partner (pursuant to our general partner's anti-dilution rights under our
partnership agreement) as a transaction not involving a public offering. We used
the net cash proceeds of approximately $212 million to redeem 44,608 of our
Series B preference units for their liquidation value of $50 million and to
reduce the balance outstanding under our revolving credit facility. In addition,
our general partner contributed $2.1 million in cash to us in order to satisfy
its one percent contribution requirement.
In March 2001, we completed a public offering of 2,250,000 common units. We
used the net cash proceeds of $66.6 million from the offering to reduce the
balance outstanding under our revolving credit facility. In addition, our
general partner contributed $0.7 million to us in order to satisfy its one
percent capital contribution requirement.
Series B Preference Units
In August 2000, we issued 170,000 Series B preference units with a value of
$170 million to acquire the Petal and Hattiesburg natural gas storage
businesses. In October 2001, we redeemed 44,608 of the Series B preference units
for $50 million liquidation value including accrued distributions of
approximately $5.4 million, bringing the total number of units outstanding to
125,392. As of December 31, 2002, the liquidation value of the outstanding
Series B preference units was approximately $158 million. In October 2003, we
redeemed all 123,865 of our remaining outstanding Series B preference units for
$156 million, a 7 percent discount from their liquidation value of $167 million.
For this redemption, we used borrowings under our revolving credit facility. We
reflected the discount as an increase to the common units capital, Series C
units capital and to our general partner's capital accounts.
Series C Units
In November 2002, we issued to a subsidiary of El Paso Corporation
10,937,500 of Series C units at a price of $32 per unit, $350 million in the
aggregate, as part of our consideration paid for the San Juan assets. The
issuance of the Series C units was an exempt transaction under Section 4(2) of
the Securities Act of 1993 as a transaction not involving a public offering. The
Series C units are similar to our existing common units, except that the Series
C units are non-voting. After April 30, 2003, the holder of the Series C units
has the right to cause us to propose a vote of our common unitholders as to
whether the Series C units should be converted into common units. If our common
unitholders approve the conversion, then each Series C unit can convert into a
common unit. If our common unitholders do not approve the conversion within 120
days after the vote is requested, then the distribution rate for the Series C
units will increase to 105 percent of the common unit distribution rate in
effect from time to time. Thereafter, the Series C unit distribution rate will
increase on April 30, 2004, to 110 percent of the common unit distribution rate
and on April 30, 2005, to 115 percent of the common unit distribution rate. In
addition, our general partner contributed $3.5 million to us in order to satisfy
its one percent capital contribution requirement. The holder of the Series C
units has thus far not requested a vote to convert the Series C units into
common units. As part of the proposed merger with Enterprise, Enterprise will
purchase from a subsidiary of El Paso Corporation all of our outstanding Series
C units. These units will not be converted to Enterprise common units in the
merger but rather will remain
42
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
limited partnership interests in GulfTerra after the closing of the merger
transaction and, as such interest, will lose their GulfTerra common unit
conversion and distribution rights.
Cash Distributions
We make quarterly distributions of 100 percent of our available cash, as
defined in the partnership agreement, to our unitholders and to our general
partner. Available cash generally consists of all cash receipts plus reductions
in reserves less all cash disbursements and net additions to reserves. Our
general partner has broad discretion to establish cash reserves for any proper
partnership purpose. These can include cash reserves for future capital and
maintenance expenditures, reserves to stabilize distributions of cash to the
unitholders and our general partner, reserves to reduce debt, or, as necessary,
reserves to comply with the terms of our agreements or obligations.
Cash distributions on common units, Series C units and to our general
partner are discretionary in nature and are not entitled to arrearages of
minimum quarterly distributions. The following table reflects our per unit cash
distributions to our common unitholders and the total distributions paid to our
common unitholders, Series C unitholder and general partner during the year
ended December 31, 2003:
COMMON COMMON SERIES C GENERAL
MONTH PAID UNIT UNITHOLDERS UNITHOLDER PARTNER
---------- ---------- ----------- ----------- -------
(PER UNIT) (IN MILLIONS)
February.................................... $0.675 $29.7 $ 7.4 $15.0
====== ===== ===== =====
May......................................... $0.675 $32.0 $ 7.4 $15.9
====== ===== ===== =====
August...................................... $0.700 $34.8 $ 7.7 $18.0
====== ===== ===== =====
November.................................... $0.710 $41.4 $ 7.8 $21.2
====== ===== ===== =====
In January 2004, we declared a cash distribution of $0.71 per common and
Series C unit, $49.3 million in aggregate, for the quarter ended December 31,
2003, which we paid on February 14, 2004. In addition, we paid our general
partner $21.3 million related to its general partner interest. At the current
distribution rates, our general partner receives approximately 30.2 percent of
our total cash distributions for its role as our general partner.
Option Plans
In August 1998, we adopted the 1998 Omnibus Compensation Plan (Omnibus
Plan) to provide our general partner with the ability to issue unit options to
attract and retain the services of knowledgeable officers and key management
personnel. Unit options to purchase a maximum of 3 million common units may be
issued pursuant to the Omnibus Plan. Unit options granted to date pursuant to
the Omnibus Plan are not immediately exercisable. For unit options granted in
2001, one-half of the unit options are considered vested and exercisable one
year after the date of grant and the remaining one-half of the unit options are
considered vested and exercisable one year after the first anniversary of the
date of grant. These unit options expire ten years from such grant date, but
shall be subject to earlier termination under certain circumstances. No grants
of unit options were made in 2002. During 2003, under our Omnibus Plan, we
granted 17,500 unit options, 25,000 time-vested restricted units and will grant
25,000 restricted units, if certain performance targets are achieved, to
employees of El Paso Field Services whose primary responsibilities are the
commercial management of our assets.
In August 1998, we also adopted the 1998 Common Unit Plan for Non-Employee
Directors (Director Plan), formerly the 1998 Unit Option Plan for Non-Employee
Directors, to provide our general partner with the ability to issue unit options
to attract and retain the services of knowledgeable directors. Unit
43
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
options and restricted units to purchase a maximum of 100,000 of our common
units may be issued pursuant to the Director Plan. Under the Director Plan, each
non-employee director receives a grant of 2,500 unit options upon initial
election to the Board of Directors and an annual unit option grant of 2,000 unit
options and, beginning in 2001, an annual restricted unit grant equal to the
director's annual retainer (including Chairman's retainers, if applicable)
divided by the fair market value of the common units on the grant date upon each
re-election to the Board of Directors. Each unit option that is granted will
vest immediately at the date of grant and will expire ten years from such date,
but will be subject to earlier termination in the event that such non-employee
director ceases to be a director of our general partner for any reason, in which
case the unit options expire 36 months after such date except in the case of
death, in which case the unit options expire 12 months after such date. Each
director receiving a grant of restricted units is recorded as a unitholder and
has all the rights of a unitholder with respect to such units, including the
right to distributions on those units. The restricted units are nontransferable
during the director's service on the Board of Directors. The restrictions on the
restricted units will end and the director will receive one common unit for each
restricted unit granted upon the director's termination. The Director Plan is
administered by a management committee consisting of the Chairman of the Board
of Directors of the general partner and such other senior officers of our
general partner or its affiliates as the Chairman may designate. During 2003,
under the Director Plan, we granted 5,226 restricted units at a fair value per
unit of $36.37 and 10,500 unit options with a grant price of $35.92. Restricted
units awards representing 5,429 and 4,090 were granted during 2002 and 2001 with
a fair value of $32.23 and $33.00 per unit. As of December 31, 2003, 12,292
restricted units were outstanding.
We have accounted for all of these unit options and restricted units,
except for the unit options issued to non-employee directors, in accordance with
SFAS No. 123. Under SFAS No. 123, we report the fair value of these issuances as
deferred compensation. Deferred compensation is amortized to compensation
expense over the respective vesting or performance period. We have accounted for
the unit options issued to the non-employee directors of our general partner's
Board of Directors in accordance with APB No. 25.
We issued time-vested restricted units and the performance-based restricted
units at fair value at their date of grant. The restrictions on the time-vested
units will lapse in four years from the date of grant. The restrictions on the
performance-based restricted units will lapse if we achieve a specified level of
target performance for identified "greenfield" projects by June 1, 2007 (for the
15,000 performance-based restricted units issued in June 2003) and by August 1,
2007 (for the 10,000 performance-based restricted units issued in August 2003).
If we do not reach those targets by the applicable dates, the performance-based
units will be forfeited. We will amortize the fair value of the time-vested
restricted units over their four-year restricted period and the fair value of
the performance-based restricted units over their performance periods. The
performance-based restricted units are not entitled to vote or to receive
distributions, until after (and if) we achieve specified level of target
performance. The restricted units issued to non-employee directors of our
general partner's Board of Directors were issued at fair value at their date of
grant. This fair value is being amortized to compensation expense over the
period of service, which we have estimated to be one year.
Total unamortized deferred compensation as of December 31, 2003 and 2002
was approximately $1.5 million and $1.2 million. Our 2001 deferred compensation
is fully amortized. Deferred compensation is reflected as a reduction of
partners' capital and is allocated 1 percent to our general partner and 99
percent to our limited partners.
44
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes activity under the Omnibus Plan and Director
Plan (excluding our restricted units) as of and for the years ended December 31,
2003, 2002 and 2001.
2003 2002 2001
--------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED
# UNITS OF AVERAGE # UNITS OF AVERAGE # UNITS OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
---------- -------- ---------- -------- ---------- --------
Outstanding at beginning of
year........................... 1,550,000 $32.17 1,614,500 $32.09 925,500 $27.15
Granted........................ 28,000 35.08 8,000 32.23 1,016,500 35.00
Exercised...................... 318,000 31.74 42,500 27.19 307,500 27.17
Forfeited...................... -- -- -- -- -- --
Canceled....................... 144,000 34.99 30,000 34.99 20,000 27.19
--------- --------- ---------
Outstanding at end of year....... 1,116,000 $32.00 1,550,000 $32.17 1,614,500 $32.09
========= ========= =========
Options exercisable at end of
year........................... 1,106,000 $31.98 1,068,500 $30.88 606,500 $27.22
========= ========= =========
The fair value of each unit option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions:
ASSUMPTION 2003 2002 2001
---------- ----- ----- -----
Expected term in years...................................... 7 8 8
Expected volatility......................................... 28.93% 31.05% 27.50%
Expected distributions...................................... 8.88% 8.09% 9.55%
Risk-free interest rate..................................... 3.31% 3.24% 5.05%
The Black-Scholes weighted average fair value of options granted during
2003, 2002, and 2001 was $3.55, $3.71, and $2.62 per unit option, respectively.
Options outstanding as of December 31, 2003, are summarized below:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------- ----------------------------
WEIGHTED AVERAGE WEIGHTED WEIGHTED
RANGE OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
$19.86 to $27.80 423,500 4.6 $27.13 423,500 $27.13
$27.80 to $39.72 692,500 6.9 $34.99 682,500 $34.99
--------- ---------
$19.86 to $39.72 1,116,000 6.0 $32.00 1,106,000 $31.98
========= =========
45
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. EARNINGS PER COMMON UNIT
The following table sets forth the computation of basic and diluted
earnings per common unit (in thousands, except for unit amounts):
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
2003 2002 2001
-------- -------- --------
Numerator:
Numerator for basic earnings per common unit --
Income from continuing operations................ $65,155 $34,275 $12,174
Income from discontinued operations.............. -- 5,085 1,086
Cumulative effect of accounting change........... 1,340 -- --
------- ------- -------
$66,495 $39,360 $13,260
======= ======= =======
Denominator:
Denominator for basic earnings per common unit --
weighted-average common units.................... 49,953 42,814 34,376
Effect of dilutive securities:
Unit options..................................... 177 -- --
Restricted units................................. 15 -- --
Series F convertible units....................... 86 -- --
------- ------- -------
Denominator for diluted earnings per common unit --
adjusted for weighted-average common units....... 50,231 42,814 34,376
======= ======= =======
Basic earnings per common unit
Income from continuing operations................... $ 1.30 $ 0.80 $ 0.35
Income from discontinued operations................. -- 0.12 0.03
Cumulative effect of accounting change.............. 0.03 -- --
------- ------- -------
$ 1.33 $ 0.92 $ 0.38
======= ======= =======
Diluted earnings per common unit
Income from continuing operations................... $ 1.30 $ 0.80 $ 0.35
Income from discontinued operations................. -- 0.12 0.03
Cumulative effect of accounting change.............. 0.02 -- --
------- ------- -------
$ 1.32 $ 0.92 $ 0.38
======= ======= =======
46
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. RELATED PARTY TRANSACTIONS
The majority of our related party transactions are with affiliates of our
general partner. Under an agreement that was in place before an indirect
subsidiary of El Paso Corporation purchased our general partner, an affiliate of
our general partner was obligated to provide individuals to perform the day to
day financial, administrative, accounting and operational functions for us. As
our activities increased, the fee for such services has also increased. Further,
we provide services to various El Paso Corporation subsidiaries and, in turn,
they provide us services. In addition, we have acquired a number of assets from
subsidiaries of El Paso Corporation. We have not had any material transactions
with Enterprise, other than the merger agreement transactions, since Enterprise
acquired 50 percent of our general partner.
The following table provides summary data of our transactions with related
parties for the years ended December 31:
2003 2002 2001
-------- -------- -------
(IN THOUSANDS)
Revenues received from related parties:
Natural gas pipelines and plants.......................... $ 84,375 $159,608 $20,710
Oil and NGL Logistics..................................... 29,413 26,288 25,249
Platform services(1)...................................... -- -- 35
Natural gas storage....................................... -- 3,016 2,325
Other(1).................................................. -- 9,809 5,676
-------- -------- -------
$113,788 $198,721 $53,995
======== ======== =======
Expenses paid to related parties:
Purchased natural gas costs............................... $ 33,148 $ 22,784 $34,768
Operation and maintenance................................. 91,208 60,458 33,721
-------- -------- -------
$124,356 $ 83,242 $68,489
======== ======== =======
Reimbursements received from related parties:
Operation and maintenance................................. $ 2,426 $ 2,100 $11,499
======== ======== =======
---------------
(1) In addition to revenues from continuing operations reflected above, we also
received revenues from related parties in 2002 and 2001 of $6.8 million and
$8.2 million for our Prince TLP and $1.0 million and $0.7 million for our 9
percent overriding royalty interest which are included in income from
discontinued operations on our income statements.
For the years ended December 31, 2003, 2002 and 2001, revenues received
from related parties consisted of approximately 13%, 43% and 28% of our revenue
from continuing operations. Also, we have undertaken efforts to reduce our
transactions with El Paso Merchant Energy North America Company (Merchant
Energy) and as of June 30, 2003, we replaced all our month-to-month arrangements
that were previously with Merchant Energy with similar arrangements with third
parties.
47
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table provides summary data categorized by our related
parties for the years ended December 31:
2003 2002 2001
-------- -------- -------
(IN THOUSANDS)
Revenues received from related parties:
El Paso Corporation
El Paso Merchant Energy North America Company.......... $ 30,146 $ 92,675 $16,433
El Paso Production Company(1).......................... 9,109 9,054 4,230
Southern Natural Gas Company........................... 13 112 277
Tennessee Gas Pipeline Company......................... 93 -- 638
El Paso Field Services................................. 74,427 96,880 32,382
Unconsolidated Subsidiaries
Manta Ray Offshore(2).................................. -- -- 35
-------- -------- -------
$113,788 $198,721 $53,995
======== ======== =======
Purchased natural gas costs paid to related parties:
El Paso Corporation
El Paso Merchant Energy North America Company.......... $ 27,777 $ 19,226 $28,169
El Paso Production Company............................. -- 2,251 6,412
Southern Natural Gas Company........................... 143 245 187
Tennessee Gas Pipeline Company......................... -- 70 --
El Paso Field Services................................. 5,181 950 --
El Paso Natural Gas Company............................ 47 42 --
-------- -------- -------
$ 33,148 $ 22,784 $34,768
======== ======== =======
Operating expenses paid to related parties:
El Paso Corporation
El Paso Field Services................................. $ 90,925 $ 60,000 $33,187
Unconsolidated Subsidiaries
Poseidon Oil Pipeline Company.......................... 283 458 534
-------- -------- -------
$ 91,208 $ 60,458 $33,721
======== ======== =======
Reimbursements received from related parties:
Unconsolidated Subsidiaries
Deepwater Holdings(3).................................. $ -- $ -- $ 9,399
Poseidon Oil Pipeline Company.......................... 2,426 2,100 2,100
-------- -------- -------
$ 2,426 $ 2,100 $11,499
======== ======== =======
---------------
(1) In addition to revenues from continuing operations from El Paso Production
Company reflected above, during 2002 and 2001 we also received revenues of
$7.8 million and $8.9 million from El Paso Production Company which are
included in income from discontinued operations in our income statements.
(2) We sold our interest in Manta Ray Offshore in January 2001 in connection
with El Paso Corporation's merger with the Coastal Corporation.
(3) In January 2001, Deepwater Holdings sold its Stingray and West Cameron
subsidiaries. In April 2001, Deepwater Holdings sold its UTOS subsidiary. In
October 2001, we acquired the remaining 50 percent of Deepwater Holdings,
and as a result of this transaction, on a going forward basis, Deepwater
Holdings is consolidated in our financial statements and our agreement with
Deepwater Holdings terminated.
Revenues received from related parties
EPN Holding Assets. Our revenues from related parties increased in 2002 as
a result of our EPN Holding transaction in which we acquired gathering,
transportation and processing contracts with affiliates of our general partner.
For the years ended December 31, 2003 and 2002, we received $26.5 million and
48
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$68.9 million from El Paso Merchant Energy North America Company, $19.9 million
and $35.8 million from El Paso Field Services and $3.4 million and $4.0 million
from El Paso Production Company.
GTM Texas. In connection with our acquisition of GTM Texas in February
2001, we entered into a 20-year fee-based transportation and fractionation
agreement with El Paso Field Services. Pursuant to this agreement, we receive a
fixed fee for each barrel of NGL transported and fractionated by our facilities.
Approximately 25 percent of our per barrel fee is escalated annually for
increases in inflation. For the years ended December 31, 2003, 2002 and 2001, we
received revenue of approximately $21.5 million, $26.0 million and $25.2 million
related to this agreement.
Chaco processing plant. In connection with our Chaco transaction in
October 2001, we entered into a 20-year fee-based processing agreement with El
Paso Field Services. Pursuant to this agreement, we receive a fixed fee for each
dekatherm of natural gas that we process at the Chaco plant. For the years ended
December 31, 2002 and 2001, we received revenue of $29.6 million and $6.5
million related to this agreement. In accordance with the original construction
financing agreements, the Chaco plant is under an operating lease to El Paso
Field Services. For the years ended December 31, 2002 and 2001, we received $1.8
million and $0.6 million related to this lease. As a result of the San Juan
asset acquisition in November 2002, the processing agreement and the operating
lease were terminated.
Storage facilities. With the April 2002 acquisition of the EPN Holding
assets, we purchased contracts held by Wilson Storage with El Paso Merchant
Energy North America Company. For the year ended December 31, 2002, we received
approximately $2.9 million from El Paso Merchant Energy North America Company
for natural gas storage fees. El Paso Merchant Energy North America Company and
Tennessee Gas Pipeline Company use our Petal and Hattiesburg storage facilities
from time to time. For the years ended December 31, 2002 and 2001 we received
approximately $0.1 million and $1.6 million from El Paso Merchant Energy North
America Company for natural gas storage fees. For the year ended December 31,
2001 we received approximately $0.7 million from Tennessee Gas Pipeline Company.
Prince TLP. In September 2001, we placed our Prince TLP in service. Prior
to April 1, 2002, we received a monthly demand charge of approximately $1.9
million as well as processing fees from El Paso Production Company related to
production on the Prince TLP. For the year ended December 31, 2002 and the four
months ended December 31, 2001, we received $6.8 million and $8.2 million in
platform revenue related to this agreement. In connection with our acquisition
of the EPN Holding assets from El Paso Corporation, in April 2002 we sold our
Prince TLP to subsidiaries of El Paso Corporation and these revenues are
reflected in our income from discontinued operations.
Production fields. Through 2000 we had agreed to sell substantially all of
our oil and natural gas production to El Paso Merchant Energy North America
Company on a month to month basis. The agreement provided fees equal to two
percent of the sales value of crude oil and condensate and $0.015 per dekatherm
of natural gas for marketing production. Beginning in the fourth quarter of
2000, we began selling our oil and natural gas directly to third parties and our
oil and natural gas sales related to El Paso Merchant Energy North America
Company were approximately $9.8 million and $5.7 million for years ended
December 31, 2002 and 2001.
In October 1999, we farmed out our working interest in the Prince Field to
El Paso Production Company. Under the terms of the farmout agreement, our net
overriding royalty interest in the Prince Field increased to a weighted average
of approximately nine percent. El Paso Production Company began production on
the Prince Field in September 2001. For the year ended December 31, 2002 and the
four months ended December 31, 2001, we recorded approximately $1.0 million and
$0.7 million in revenues related to our overriding royalty interest in the
Prince Field. In connection with our acquisition of the EPN Holding assets from
El Paso Corporation, in April 2002 we sold our 9 percent overriding royalty
interest in the Prince Field to
49
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
subsidiaries of El Paso Corporation and these revenues are reflected in our
income from discontinued operations.
GulfTerra Alabama Intrastate. Several El Paso Corporation subsidiaries buy
and transport natural gas on our GulfTerra Alabama Intrastate system. For the
years ended December 31, 2003, 2002 and 2001, we received approximately $0.7
million, $6.8 million and $8.3 million from El Paso Merchant Energy North
America Company. For the years ended December 31, 2003, 2002 and 2001, we
received approximately $4.5 million, $4.5 million and $4.2 million from El Paso
Production Company. For the years ended December 31, 2003, 2002 and 2001, we
received approximately $0.1 million, $0.1 million and $0.2 million from Southern
Natural Gas Company.
HIOS. In October 2001, HIOS became a wholly-owned asset through our
acquisition of the remaining 50 percent equity interest in Deepwater Holdings.
HIOS is a natural gas transmission system that has entered into interruptible
transportation agreements at a non-discounted rate of $0.1244. For the years
ended December 31, 2003 and 2002 and approximately three months ended December
31, 2001, we received $0.1 million, $1.4 million and $0.8 million from El Paso
Merchant Energy. For the year ended December 31, 2003 and 2002, we received $1.2
million and $0.6 million from El Paso Production Company.
Texas NGL assets. In connection with our acquisition of the San Juan
assets in November, 2002, we entered into a 10-year transportation agreement
with El Paso Field Services. Pursuant to this agreement, beginning January 1,
2003, we receive a fee of $1.5 million per year for transportation on our NGL
pipeline which extends from Corpus Christi to near Houston. In addition, we
provide transportation, fractionation, storage and terminaling services to El
Paso Field Services, as well as to various third parties, typically under
agreements of one year term or less. We received approximately $7.5 million and
$0.3 million in revenues from El Paso Field Services for the years ended
December 31, 2003 and 2002.
Other. In addition to the revenues discussed above, we received $2.8
million and $2.6 million from El Paso Merchant North America and $25.6 million
and $3.3 million from El Paso Field Services during 2003 and 2002 for additional
gathering and processing services. The 2003 increase in revenues for El Paso
Field Services was primarily as a result of higher natural gas prices and NGL
volumes sold to El Paso Field Services from our Big Thicket assets.
Unconsolidated Subsidiaries. For the years ended December 31, 2001 we
received approximately $0.03 million from Manta Ray Offshore Gathering as
platform access and processing fees related to our South Timbalier 292 platform
and our Ship Shoal 332 platform. We sold our interest in Manta Ray Offshore in
January 2001 in connection with El Paso's merger with the Coastal Corporation.
Expenses paid to related parties
Cost of natural gas. Our cost of natural gas paid to related parties
increased in 2003 and 2002 as a result of our San Juan assets acquisitions and
our EPN Holding transaction in which we acquired contracts with affiliates of
our general partner. For the year ended December 31, 2003, our San Juan assets
had cost of natural gas expenses of $1.3 million from El Paso Merchant Energy
North America and $0.3 million from El Paso Field Services. For the year ended
December 31, 2003 and 2002, our EPN Holding assets had cost of natural gas
expenses of $0.9 million and $0.3 million from El Paso Merchant Energy North
America Company and $3.5 million and $0.4 million from El Paso Field Services
relating to the GulfTerra Texas gathering system. GulfTerra Alabama Intrastate's
purchases of natural gas include transactions with affiliates of our general
partner. For the years ended December 31, 2003, 2002 and 2001, we had natural
gas purchases of approximately $25.6 million, $18.9 million and $28.2 million
from El Paso Merchant Energy North America Company, and $0.1 million, $0.2
million and $0.2 million from Southern Natural Gas Company and $2.3 million and
$6.4 million from El Paso Production Company for the years ended December 31,
2002 and 2001. We also receive lease and throughput fees from El Paso Field
Services for Hattiesburg and Anse
50
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
La Butte. For the year ended December 31, 2002 we received $0.5 million from El
Paso Field Services related to these fees.
Operating Expenses. Substantially all of the individuals who perform the
day-to-day financial, administrative, accounting and operational functions for
us, as well as those who are responsible for directing and controlling us, are
currently employed by El Paso Corporation. Under a general and administrative
services agreement between subsidiaries of El Paso Corporation and us, a fee of
approximately $0.8 million per month was charged to our general partner, and
accordingly, to us, which is intended to approximate the amount of resources
allocated by El Paso Corporation and its affiliates in providing various
operational, financial, accounting and administrative services on behalf of our
general partner and us. In April 2002, in connection with our acquisition of EPN
Holding assets, our general and administrative services agreement was extended
to December 31, 2005, and the fee increased to approximately $1.6 million per
month. In November 2002, as a result of the San Juan assets acquisition, the
monthly fee under our general and administrative services agreement increased by
$1.3 million, bringing our total monthly fee to $2.9 million. We believe this
fee approximates the actual costs incurred. Under the terms of the partnership
agreement, our general partner is entitled to reimbursement of all reasonable
general and administrative expenses and other reasonable expenses incurred by
our general partner and its affiliates for, or on our behalf, including, but not
limited to, amounts payable by our general partner to El Paso Corporation under
its management agreement. We are also charged for insurance and other costs paid
directly by El Paso Field Services on our behalf.
As we became operator of additional facilities or systems, acquired new
operations or constructed new facilities, we entered into additional management
and operating agreements with El Paso Field Services. All fees paid under these
contracts approximate actual costs incurred.
The following table shows the amount El Paso Field Services charged us for
each of our agreements for the year ended December 31:
2003 2002 2001
------- ------- -------
(IN THOUSANDS)
Basic management fee.................................... $34,800 $18,092 $ 9,300
Operating fees(1)....................................... 52,924 38,422 19,821
Insurance and other costs............................... 3,201 3,486 4,066
------- ------- -------
$90,925 $60,000 $33,187
======= ======= =======
---------------
(1) Operating fees increased from 2002 to 2003 and from 2001 to 2002 due to the
acquisition of the San Juan assets and EPN Holding assets.
Cost Reimbursements. In connection with becoming the operator of Poseidon,
we entered into an operating agreement in January 2001. All fees received under
contracts approximate actual costs incurred.
Acquisitions
We have purchased assets from related parties. See Note 2 for a discussion
of these asset acquisitions.
Other Matters
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 Corporation, we
have been indemnified for potential future liabilities, expenses and capital
requirements above a negotiated threshold. Specifically, an indirect subsidiary
of El Paso Corporation has agreed to indemnify us for specific litigation
matters to the extent the ultimate resolutions of these matters result in
judgments against us. For a further discussion of these matters see Note 11,
Commitments and
51
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Contingencies, Legal Proceedings. Some of our agreements obligate certain
indirect subsidiaries of El Paso Corporation to pay for capital costs related to
maintaining assets which were acquired by us, if such costs exceed negotiated
thresholds. We have made claims for approximately $5 million for costs incurred
during the year ended December 31, 2003 as costs exceeded the established
thresholds for the year ended December 31, 2003.
We have also entered into capital contribution arrangements with entities
owned by El Paso Corporation, including its regulated pipelines, in the past,
and will most likely do so in the future, as part of our normal commercial
activities in the Gulf of Mexico. We have an agreement to receive $6.1 million,
of which $3.0 million has been collected, from ANR Pipeline Company for our
Phoenix project. As of December 31, 2003, we have received $10.5 million from
ANR Pipeline and $7.0 million from El Paso Field Services for the Marco Polo
natural gas pipeline. In October 2003, we collected $2 million from Tennessee
Gas Pipeline for our Medusa project. These amounts are reflected as a reduction
in project costs. Regulated pipelines often contribute capital toward the
construction costs of gathering facilities owned by others which are, or will
be, connected to their pipelines. El Paso Field Services' contribution is in
anticipation of additional natural gas volumes that will flow through to its
onshore natural gas processing facilities.
In August 2003, Arizona Gas Storage L.L.C., along with its 50 percent
partner APACS Holdings L.L.C., sold their interest in Copper Eagle Gas Storage
L.L.C. to El Paso Natural Gas Company (EPNG), a subsidiary of El Paso
Corporation. Copper Eagle Gas Storage is developing a natural gas storage
project located outside of Phoenix, Arizona. Arizona Gas Storage is an indirect
60 percent owned subsidiary of us and 40 percent owned by IntraGas US, a Gaz de
France North American subsidiary. APACS Holdings L.L.C. is a wholly owned
subsidiary of Pinnacle West Energy, a subsidiary of Pinnacle West Capital
Corporation. We have the right to receive $6.2 million of the sale proceeds,
including a note receivable for $4.9 million to be paid quarterly over the next
twelve months, from EPNG and we recorded a gain of $882 thousand related to the
sale of Copper Eagle. In the event of EPNG default, the Copper Eagle Gas Storage
project will revert back to the original owners without compensation to EPNG.
In September 2003, we entered into a nonbinding letter of intent with
Southern Natural Gas Company, a subsidiary of El Paso Corporation, regarding the
proposed development and sale of a natural gas storage cavern and the proposed
sale of an undivided interest in a pipeline and other facilities related to that
natural gas storage cavern. The new storage cavern would be located at our
storage complex near Hattiesburg, Mississippi. If Southern Natural Gas
determines that there is sufficient market interest, it would purchase the land
and mineral rights related to the proposed storage cavern and would pay our
costs to construct the storage cavern and related facilities. Upon completion of
the storage cavern, Southern Natural Gas would acquire an undivided interest in
our Petal pipeline connected to the storage cavern. We would also enter into an
arrangement with Southern Natural Gas under which we would operate the storage
cavern and pipeline on its behalf.
Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our general partner's board of directors, which committee
consists solely of directors meeting the independent director requirements
established by the NYSE and the Sarbanes-Oxley Act, and then approved by our
general partner's full board of directors.
In October 2003, we exchanged with El Paso Corporation its obligation to
repurchase the Chaco plant from us in 19 years for additional assets (refer to
Note 2). Also in October 2003, we redeemed all of our outstanding Series B
preference units (refer to Note 8).
The counterparty for one of our San Juan hedging activities is J. Aron and
Company, an affiliate of Goldman Sachs. Goldman Sachs was also a co-manager of
our 4,800,000 public common unit offering in October 2003, and is one of the
lenders under our revolving credit facility and owned 9.9 percent of our general
partner during part of the fourth quarter of 2003.
52
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our accounts receivable due from related parties consisted of the following
as of:
DECEMBER 31, DECEMBER 31,
2003 2002
------------ ------------
(IN THOUSANDS)
El Paso Corporation
El Paso Merchant Energy North America Company............. $ 4,113 $30,512
El Paso Production Company................................ 5,991 4,346
Tennessee Gas Pipeline Company............................ 1,350 930
El Paso Field Services(1)................................. 16,571 36,071
El Paso Natural Gas Company............................... 4,255 1,033
ANR Pipeline Company...................................... 1,600 671
Other..................................................... 830 627
------- -------
34,710 74,190
------- -------
Unconsolidated Subsidiaries
Deepwater Gateway......................................... 3,939 9,636
Cameron Highway........................................... 9,302 --
Other..................................................... 14 --
------- -------
13,255 9,636
------- -------
Total............................................. $47,965 $83,826
======= =======
----------
(1) The December 2002 receivable balance includes approximately $15 million of
natural gas imbalances relating to our EPN Holding acquisition.
Our accounts payable due to related parties consisted of the following as
of:
DECEMBER 31, DECEMBER 31,
2003 2002
------------ ------------
(IN THOUSANDS)
El Paso Corporation
El Paso Merchant Energy North America Company............. $ 7,523 $ 8,871
El Paso Production Company................................ 4,069 14,518
Tennessee Gas Pipeline Company............................ 1,278 1,319
El Paso Field Services(1)................................. 13,869 55,648
El Paso Natural Gas Company............................... 942 1,475
El Paso Corporation....................................... 6,249 4,181
Southern Natural Gas...................................... 1,871 --
Other..................................................... 667 132
------- -------
36,468 86,144
------- -------
Unconsolidated Subsidiaries
Deepwater Gateway......................................... 2,268 --
Other..................................................... 134 --
------- -------
2,402 --
------- -------
Total............................................. $38,870 $86,144
======= =======
----------
(1) The December 2002 payable balance includes approximately $19 million of
working capital adjustments relating to our EPN Holding acquisition due to
El Paso Field Services; and approximately $22 million of natural gas
imbalances relating to our EPN Holding acquisition.
53
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In connection with the sale of our Gulf of Mexico assets in January 2001,
El Paso Corporation agreed to make quarterly payments to us of $2.25 million for
three years beginning March 2001 and ending with a $2 million payment in the
first quarter of 2004. The present value of the amounts due from El Paso
Corporation were classified as follows:
DECEMBER 31, DECEMBER 31,
2003 2002
------------ ------------
(IN THOUSANDS)
Accounts receivable, net.................................... $1,960 $ 8,403
Other noncurrent assets..................................... -- 1,960
------ -------
$1,960 $10,363
====== =======
11. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Grynberg. In 1997, we, along with numerous other energy companies, were
named defendants in actions brought by Jack Grynberg on behalf of the U.S.
Government under the False Claims Act. Generally, these complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Native American lands, which
deprived the U.S. Government of royalties. The plaintiff in this case seeks
royalties that he contends the government should have received had the volume
and heating value been differently measured, analyzed, calculated and reported,
together with interest, treble damages, civil penalties, expenses and future
injunctive relief to require the defendants to adopt allegedly appropriate gas
measurement practices. No monetary relief has been specified in this case. These
matters have been consolidated for pretrial purposes (In re: Natural Gas
Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming,
filed June 1997). Discovery is proceeding. Our costs and legal exposure related
to these lawsuits and claims are not currently determinable.
Will Price (formerly Quinque). We, along with numerous other energy
companies, are named defendants in Will Price, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes
and heating content of natural gas on non-federal and non-Native American lands,
and seek certification of a nationwide class of natural gas working interest
owners and natural gas royalty owners to recover royalties that they contend
these owners should have received had the volume and heating value of natural
gas produced from their properties been differently measured, analyzed,
calculated and reported, together with prejudgment and postjudgment interest,
punitive damages, treble damages, attorney's fees, costs and expenses, and
future injunctive relief to require the defendants to adopt allegedly
appropriate gas measurement practices. No monetary relief has been specified in
this case. Plaintiffs' motion for class certification of a nationwide class of
natural gas working interest owners and natural gas royalty owners was denied on
April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition,
which narrows the proposed class to royalty owners in wells in Kansas, Wyoming
and Colorado and removes claims as to heating content. A second class action
petition has been filed as to heating content claims. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.
In connection with our April 2002 acquisition of the EPN Holding assets,
subsidiaries of El Paso Corporation have agreed to indemnify us against all
obligations related to existing legal matters at the acquisition date, including
the legal matters involving Leapartners, L.P., City of Edinburg, Houston Pipe
Line Company LP, and City of Corpus Christi discussed below.
During 2000, Leapartners, L.P. filed a suit against El Paso Field Services
and others in the District Court of Loving County, Texas, alleging a breach of
contract to gather and process natural gas in areas of western Texas related to
an asset now owned by GulfTerra Holding. In May 2001, the court ruled in favor
of
54
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Leapartners and entered a judgment against El Paso Field Services of
approximately $10 million. El Paso Field Services filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. On August 15, 2003 the Court of
Appeals reversed the lower's courts calculation of past judgment interest but
otherwise affirmed the judgment. A motion for a rehearing was denied. A petition
for review by the Texas Supreme Court has been filed.
Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as
EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, was involved in
litigation with the City of Edinburg concerning the City's claim that GulfTerra
Texas was required to pay pipeline franchise fees under a contract the City had
with Rio Grande Valley Gas Company, which was previously owned by GulfTerra
Texas and is now owned by Southern Union Gas Company. An adverse judgment
against Southern Union and GulfTerra Texas was rendered in Hidalgo County State
District court in December 1998 and found a breach of contract, and held both
GulfTerra Texas and Southern Union jointly and severally liable to the City for
approximately $4.7 million. The judgment relied on the single business
enterprise doctrine to impose contractual obligations on GulfTerra Texas and
Southern Union entities that were not parties to the contract with the City.
GulfTerra Texas appealed this case to the Texas Supreme Court seeking reversal
of the judgment rendered against GulfTerra Texas. The City sought a remand to
the trial court of its claim of tortious interference against GulfTerra Texas.
Briefs were filed and oral arguments were held in November 2002. In October
2003, the Texas Supreme Court issued an opinion in favor of GulfTerra Texas and
Southern Union on all issues. The City has requested rehearing.
In December 2000, a 30-inch natural gas pipeline jointly owned by GulfTerra
Intrastate, L.P. (GulfTerra Intrastate) now owned by GulfTerra Holding, and
Houston Pipe Line Company LP ruptured in Mont Belvieu, Texas, near Baytown,
resulting in substantial property damage and minor physical injury. GulfTerra
Intrastate is the operator of the pipeline. Two lawsuits were filed in the state
district court in Chambers County, Texas by eight plaintiffs, including two
homeowners' insurers. The suits sought recovery for physical pain and suffering,
mental anguish, physical impairment, medical expenses, and property damage.
Houston Pipe Line Company was added as an additional defendant. In accordance
with the terms of the operating agreement, GulfTerra Intrastate agreed to assume
the defense of and to indemnify Houston Pipe Line Company. As of December 31,
2003, all claims have now been settled and these settlements had no impact on
our financial statements.
The City of Corpus Christi, Texas (the "City") alleged that GulfTerra Texas
and various Coastal entities owed it monies for past obligations under City
ordinances that propose to tax GulfTerra Texas on its gross receipts from local
natural gas sales for the use of street rights-of-way. Some but not all of the
GulfTerra Texas pipe at issue has been using the rights-of-way since the 1960's.
In addition, the City demanded that GulfTerra Texas agree to a going-forward
consent agreement in order for the GulfTerra Texas pipe and Coastal pipe to have
the right to remain in the City rights-of-way. In December 2003, GulfTerra Texas
and the City entered into a license agreement releasing GulfTerra Texas from any
past obligations and providing certain rights for the use of the City
rights-of-way and City owned property. This agreement was retroactive to October
1, 2002.
In August 2002, we acquired the Big Thicket assets, which consist of the
Vidor plant, the Silsbee compressor station and the Big Thicket gathering system
located in east Texas, for approximately $11 million from BP America Production
Company (BP). Pursuant to the purchase agreement, we have identified
environmental conditions that we are working with BP and appropriate regulatory
agencies to address. BP has agreed to indemnify us for exposure resulting from
activities related to the ownership or operation of these facilities prior to
our purchase (i) for a period of three years for non-environmental claims and
(ii) until one year following the completion of any environmental remediation
for environmental claims. Following expiration of these indemnity periods, we
are obligated to indemnify BP for environmental or non-environmental claims. We,
along with BP and various other defendants, have been named in the following two
lawsuits for claims based on activities occurring prior to our purchase of these
facilities.
55
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Christopher Beverly and Gretchen Beverly, individually and on behalf of the
estate of John Beverly v. GulfTerra GC, L.P., et. al. In June 2003, the
plaintiffs sued us in state district court in Hardin County, Texas. The
plaintiffs are the parents of John Christopher Beverly, a two year old child who
died on April 15, 2002, allegedly as the result of his exposure to arsenic,
benzene and other harmful chemicals in the water supply. Plaintiffs allege that
several defendants responsible for that contamination, including us and BP. Our
connection to the occurrences that are the basis for this suit appears to be our
August 2002 purchase of certain assets from BP, including a facility in Hardin
County, Texas known as the Silsbee compressor station. Under the terms of the
indemnity provisions in the Purchase and Sale Agreement between GulfTerra and
BP, GulfTerra requested that BP indemnify GulfTerra for any exposure. BP has
agreed to indemnify us in this matter.
Melissa Duvail, et. al., v. GulfTerra GC, L.P., et. al. In June 2003,
seventy-four residents of Hardin County, Texas, sued us and others in state
district court in Hardin County, Texas. The plaintiffs allege that they have
been exposed to hazardous chemicals, including arsenic and benzene, through
their water supply, and that the defendants are responsible for that exposure.
As with the Beverly case, our connection with the occurrences that are the basis
of this suit appears to be our August 2002 purchase of certain assets from BP,
including a facility known as the Silsbee compressor station, which is located
in Hardin County, Texas. Under the terms of the indemnity provisions in the
Purchase and Sale Agreement between us and BP, BP has agreed to indemnify us for
this matter.
In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.
For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we will establish the necessary
accruals. As of December 31, 2003, we had no reserves for our legal matters.
While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on information known to date, 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. As new information becomes
available or relevant developments occur, we will establish accruals as
appropriate.
Environmental
Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2003, we had a reserve of approximately $21 million, included in other
noncurrent liabilities, for remediation costs expected to be incurred over time
associated with mercury meters. We assumed this liability in connection with our
April 2002 acquisition of the EPN Holding assets. As part of the November 2002
San Juan assets acquisition, El Paso Corporation has agreed to indemnify us for
all the known and unknown environmental liabilities related to the assets we
purchased up to the purchase price of $766 million. We will only be indemnified
for unknown liabilities for up to three years from the purchase date of this
acquisition. In addition, we have been indemnified by third parties for
remediation costs associated with other assets we have purchased. We expect to
make capital expenditures for environmental matters of approximately $3 million
in the aggregate for the years 2004 through 2008, primarily to comply with clean
air regulations.
Shoup Air Permit Violation. On December 16, 2003, El Paso Field Services,
L.P. received a Notice of Enforcement (NoE) from the Texas Commission on
Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at its
Shoup, Texas plant. The NoE included a draft Agreed Order assessing a
56
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
penalty of $365,750 for the cited violations. The alleged violations pertained
to emission limit exceedences, testing, reporting, and recordkeeping issues in
2001. While the NoE was addressed to El Paso Field Services, L.P., the substance
of the NoE also concerns equipment owned at the Shoup plant by Gulfterra GC,
L.P. El Paso Field Services, L.P. has responded to the NoE and is preparing to
meet with the TCEQ to discuss the alleged violations and the proposed penalty.
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
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages 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.
Rates and Regulatory Matters
Marketing Affiliate Final Rule. In November 2003, the FERC issued a Final
Rule extending its standards of conduct governing the relationship between
interstate pipelines and marketing affiliates to all energy affiliates. Since
our HIOS natural gas pipeline and Petal natural gas storage facility, including
the 60-mile Petal natural gas pipeline, are interstate facilities as defined by
the Natural Gas Act, the regulations dictate how HIOS and Petal conduct business
and interact with all energy affiliates of El Paso Corporation and us.
The standards of conduct require us, absent a waiver, to functionally
separate our HIOS and Petal interstate facilities from our other entities. We
must dedicate employees to manage and operate our interstate facilities
independently from our other Energy Affiliates. This employee group must
function independently and is prohibited from communicating non-public
transportation information or customer information to its Energy Affiliates.
Separate office facilities and systems are necessary because of the requirement
to restrict affiliate access to interstate transportation information. The Final
Rule also limits the sharing of employees and offices with Energy Affiliates.
The Final Rule was effective on February 9, 2004, subject to possible rehearing.
On that date, each transmission provider filed with FERC and posted on the
internet website a plan and scheduling for implementing this Final Rule. By June
1, 2004, written procedures implementing this Final Rule will be posted on the
internet website. Requests for rehearing have been filed and are pending. At
this time, we cannot predict the outcome of these requests, but at a minimum,
adoption of the regulations in the form outlined in the Final Rule will place
additional administrative and operational burdens on us.
Pipeline Safety Final Rule. In December 2003, the U.S. Department of
Transportation issued a Final Rule requiring pipeline operators to develop
integrity management programs for gas transmission pipelines located where a
leak or rupture could do the most harm in "high consequence areas," or HCA. The
final rule requires operators to (1) perform ongoing assessments of pipeline
integrity; (2) identify and characterize applicable threats to pipeline segments
that could impact an HCA; (3) improve data collection, integration and analysis;
(4) repair and remediate the pipeline as necessary; and (5) implement preventive
and mitigative actions. The final rule incorporates the requirements of the
Pipeline Safety Improvement Act of 2002, a new bill signed into law in December
2002. The Final Rule is effective as of January 14, 2004. At this time, we
cannot predict the outcome of this final rule.
Other Regulatory Matters. HIOS is subject to the jurisdiction of the FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. HIOS operates under a FERC approved
57
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tariff that governs its operations, terms and conditions of service, and rates.
We timely filed a required rate case for HIOS on December 31, 2002. The rate
filing and tariff changes are based on HIOS' cost of service, which includes
operating costs, a management fee and changes to depreciation rates and negative
salvage amortization. We requested the rates be effective February 1, 2003, but
the FERC suspended the rate increase until July 1, 2003, subject to refund. As
of July 1, 2003, HIOS implemented the requested rates, subject to a refund, and
has established a reserve for its estimate of its refund obligation. We will
continue to review our expected refund obligation as the rate case moves through
the hearing process and may increase or decrease the amounts reserved for refund
obligation as our expectation changes. The FERC has conducted a hearing on this
matter and an initial decision is expected to be issued in April 2004.
During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast Region (and
these assets) in late September and early October of 2002. As of December 31,
2003, we had recorded fuel differences of approximately $8.2 million, which is
included in other non-current assets. We are currently in discussions with the
FERC as well as our customers regarding the potential collection of some or all
of the fuel differences. At this time we are not able to determine what amount,
if any, may be collectible from our customers. Any amount we are unable to
resolve or collect from our customers will negatively impact our earnings.
In December 1999, GulfTerra Texas filed a petition with the FERC for
approval of its rates for interstate transportation service. In June 2002, the
FERC issued an order that required revisions to GulfTerra Texas' proposed
maximum rates. The changes ordered by the FERC involve reductions to rate of
return, depreciation rates and revisions to the proposed rate design, including
a requirement to separately state rates for gathering service. FERC also ordered
refunds to customers for the difference, if any, between the originally proposed
levels and the revised rates ordered by the FERC. We believe the amount of any
rate refund would be minimal since most transportation services are discounted
from the maximum rate. GulfTerra Texas has established a reserve for refunds. In
July 2002, GulfTerra Texas requested rehearing on certain issues raised by the
FERC's order, including the depreciation rates and the requirement to separately
state a gathering rate. On February 25, 2004, the FERC issued an order denying
GulfTerra Texas' request for rehearing and ordered GulfTerra Texas to file,
within 45 days from the issuance of the order, a calculation of refunds and a
refund plan. Additionally, the FERC ordered GulfTerra Texas to file a new rate
case or justification of existing rates within three years from the date of the
order.
In July 2002, Falcon Gas Storage, a competitor, also requested late
intervention and rehearing of the order. Falcon asserts that GulfTerra Texas'
imbalance penalties and terms of service preclude third parties from offering
imbalance management services. The FERC denied Falcon's late intervention on
February 25, 2004. Meanwhile in December 2002, GulfTerra Texas amended its
Statement of Operating Conditions to provide shippers the option of resolving
daily imbalances using a third-party imbalance service provider.
Falcon filed a formal complaint in March 2003 at the Railroad Commission of
Texas claiming that GulfTerra Texas' imbalance penalties and terms of service
preclude third parties from offering hourly imbalance management services on the
GulfTerra Texas system. GulfTerra Texas filed a response specifically denying
Falcon's assertions and requesting that the complaint be denied. The Railroad
Commission has set their case for hearing beginning on April 13, 2004. The City
Board of Public Service of San Antonio filed an intervention in opposition to
Falcon's complaint.
While the outcome of all of our rates and regulatory matters cannot be
predicted with certainty, based on information known to date, 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. As new information
becomes available or relevant developments occur, we will establish accruals as
appropriate.
58
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Joint Ventures
We conduct a portion of our business through joint venture arrangements
(including our Cameron Highway, Deepwater Gateway and Poseidon joint ventures)
we form 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.
Operating Lease
We have long-term operating lease commitments associated with the Wilson
natural gas storage facility we acquired in April 2002 in connection with the
EPN Holding acquisition. The term of the natural gas storage facility and base
gas leases runs through January 2008, and subject to certain conditions, has one
or more optional renewal periods of five years each at fair market rent at the
time of renewal. We also have long-term operating lease commitments associated
with two NGL storage facilities in Texas we acquired in November 2002 in
connection with our San Juan asset acquisition. The leases covering these
facilities expire in 2006 and 2012.
The future minimum lease payments under these operating lease commitments
as of December 31, 2003 are as follows (in millions):
2004........................................................ $ 7
2005........................................................ 7
2006........................................................ 7
2007........................................................ 6
2008........................................................ 3
Thereafter.................................................. 2
---
Total minimum lease payments................................ $32
===
Rental expense under operating leases was approximately $7.2 million and
$3.9 million for the years ended December 31, 2003 and 2002. We did not have any
operating leases prior to our acquisition of the EPN Holding assets in April
2002.
Other Matters
As a result of current circumstances generally surrounding the energy
sector, the creditworthiness of several industry participants has been called
into question. As a result of these general circumstances, we have established
an internal group to monitor our exposure to and determine, as appropriate,
whether we should request prepayments, letters of credit or other collateral
from our counterparties.
12. 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 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. On January 1, 2001, we adopted the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. We did not have
any derivative contracts in place at December 31, 2000, and therefore, there was
no transition adjustment recorded in our financial statements. During 2003, 2002
and 2001, we entered into cash flow hedges.
59
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. From August 2002 through our acquisition date, November 27,
2002, we accounted for this derivative through current earnings since it did not
qualify for hedge accounting under SFAS No. 133. Through the acquisition date in
2002, we recognized a $0.4 million gain in the margin of our natural gas
pipelines and plants segment. Beginning with the acquisition date in November
2002, we are accounting for this derivative as a cash flow hedge under SFAS No.
133. In February and August 2003, we entered into additional derivative
financial instruments to continue to hedge our exposure during 2004 to changes
in natural gas prices relating to gathering activities in the San Juan Basin.
The derivatives are financial swaps on 30,000 MMBtu per day whereby we receive
an average fixed price of $4.23 per MMBtu and pay a floating price based on the
San Juan index. As of December 31, 2003 and 2002, the fair value of these cash
flow hedges was a liability of $5.8 million and $4.8 million, as the market
price at those dates was higher than the hedge price. For the year ended
December 31, 2003, we reclassified approximately $9.8 million of unrealized
accumulated loss related to these derivatives from accumulated other
comprehensive income as a decrease in revenue. No ineffectiveness exists in our
hedging relationship because all purchase and sale prices are based on the same
index and volumes as the hedge transaction. In connection with our San Juan
asset purchase, we also acquired the outstanding risk management positions at
the Chaco plant. The value of these NGL and natural gas positions was a $0.5
million liability at the acquisition date and this amount was included in the
working capital adjustments to the purchase price. These positions expired in
December 2002.
In connection with our GulfTerra Alabama Intrastate operations, we have
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 2002 and 2003 to offset the risk of increasing natural
gas prices. As of December 31, 2003, the fair value of these cash flow hedges
was an asset of approximately $77 thousand. For the twelve months ended December
31, 2003, we reclassified approximately $218 thousand of unrealized accumulated
gain related to these derivatives from accumulated other comprehensive income to
earnings. As of December 31, 2002, the fair value of these cash flow hedges was
an asset of $86 thousand. During the year ended December 31, 2002, we
reclassified a loss of $1.4 million from other comprehensive income to earnings.
No ineffectiveness exists in our hedging relationship because all purchase and
sale prices are based on the same index and volumes as the hedge transaction.
Beginning in April 2002, in connection with our EPN Holding acquisition, we
had swaps in place for our interest in the Indian Basin processing plant to
hedge the price received for the sale of natural gas liquids. All of these
hedges expired by December 31, 2002, and we recorded a loss of $163 thousand
during 2002 for these cash flow hedges. We did not have any ineffectiveness in
our hedging relationship since all sale prices were based on the same index as
the hedge transaction.
During 2003, we entered into additional derivative financial instruments to
hedge a portion of our business' exposure to changes in NGL prices during 2003
and 2004. We entered into financial swaps for 3,500 barrels per day for February
through June 2003, 3,200 barrels per day for July 2003, 4,900 barrels per day
for August 2003, and 6,000 barrels per day for August 2003 through September
2004. The average fixed price received was $0.49 per gallon for 2003 and will be
$0.47 per gallon for 2004 while we pay a monthly average floating price based on
the OPIS average price for each month. As of December 31, 2003, the fair value
of these cash flow hedges was a liability of $3.3 million. For the twelve months
ended December 31, 2003, we reclassified approximately $0.4 million of
unrealized accumulated loss related to these derivatives from accumulated other
comprehensive income to earnings.
60
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of its
$185 million variable rate revolving credit facility at 3.49% over the life of
the swap. Prior to April 2003, under its credit facility, Poseidon paid an
additional 1.50% over the LIBOR rate resulting in an effective interest rate of
4.99% on the hedged notional amount. Beginning in April 2003, the additional
interest Poseidon pays over LIBOR was reduced resulting in an effective fixed
interest rate of 4.74% on the hedged notional amount. This interest rate swap
expired on January 9, 2004. We have recognized as a reduction in income our 36
percent share of Poseidon's realized loss on the interest rate swap of $1.7
million for the twelve months ended December 31, 2003, or $0.6 million, through
our earnings from unconsolidated affiliates. As of December 31, 2002, the fair
value of its interest rate swap was a liability of $1.4 million, as the market
interest rate was lower than the hedge rate, resulting in accumulated other
comprehensive loss of $1.4 million. We included our 36 percent share of this
liability of $0.5 million as a reduction of our investment in Poseidon and as
loss in accumulated other comprehensive income. Additionally, we recognized in
income our 36 percent share of Poseidon's realized loss of $1.2 million for the
twelve months ended December 31, 2002, or $0.4 million, through our earnings
from unconsolidated affiliates.
We estimate the entire $9.0 million of unrealized losses included in
accumulated other comprehensive income at December 31, 2003, will be
reclassified from accumulated other comprehensive income as a reduction to
earnings over the next 12 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 at the "hedged price" under the
derivative financial instruments.
In July 2003, to achieve a better 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 out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was
1.55% at December 31, 2003) and receive a fixed rate of 8 1/2%. We are
accounting for this derivative as a fair value hedge under SFAS No. 133. As of
December 31, 2003, the fair value of the interest rate swap was a liability
included in non-current liabilities of approximately $7.4 million and the fair
value of the hedged debt decreased by the same amount.
The counterparties for our San Juan hedging activities are J. Aron and
Company, an affiliate of Goldman Sachs, and UBS Warburg. We do not require
collateral and do not anticipate non-performance by these counterparties.
Through June 2003, the counterparty for our GulfTerra Alabama Intrastate
operations was El Paso Merchant Energy. Beginning in August 2003, the
counterparty is UBS Warburg, and we do not require collateral or anticipate
non-performance by this counterparty. The counterparty for our NGL hedging
activities for the Indian Basin and Chaco plants is J. Aron and Company, an
affiliate of Goldman Sachs. We do not require collateral and do not anticipate
non-performance by this counterparty. The counterparty for Poseidon's hedging
activity is Credit Lyonnais. Poseidon does not require collateral and does not
anticipate non-performance by this counterparty. Wachovia Bank is our
counterparty on our interest rate swap on the 8 1/2% notes, and we do not
require collateral or anticipate non-performance by this counterparty.
61
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. SUPPLEMENTAL DISCLOSURES TO THE STATEMENTS OF CASH FLOWS
Cash paid for interest, net of amounts capitalized were as follows:
YEAR ENDED DECEMBER 31,
----------------------------
2003 2002 2001
-------- ------- -------
(IN THOUSANDS)
Interest............................................... $135,131 $73,598 $41,020
Noncash investing and financing activities excluded from the consolidated
statements of cash flows were as follows:
YEAR ENDED DECEMBER 31,
---------------------------
2003 2002 2001
------- -------- ------
(IN THOUSANDS)
Investment in Cameron Highway Oil Pipeline Company Joint
Venture............................................ $50,836 $ -- $ --
Exchange with El Paso Corporation....................... 23,275 -- --
Adoption of SFAS No. 143................................ 5,726 -- --
Note receivable due to sale of Copper Eagle............. 3,656
Increase in property, plant and equipment, offset by
accounts payable and other noncurrent liabilities due
to purchase price adjustments......................... 377
Acquisition of San Juan assets
Issuance of Series C units......................... -- 350,000 --
Investment in processing agreement classified to
property, plant and equipment......................... -- 114,412 --
Acquisition of EPN Holding assets
Issuance of common units........................... -- 6,000 --
Acquisition of additional 50 percent interest in
Deepwater Holdings
Working capital acquired........................... -- -- 7,494
14. MAJOR CUSTOMERS
The percentage of our revenue from major customers was as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
----- ----- -----
Chevron..................................................... 14% -- --
BHP Petroleum............................................... 14% -- --
Burlington Resources........................................ 13% -- --
El Paso Merchant Energy North America Company............... -- 21% --
El Paso Field Services...................................... -- 18% 16%
Alabama Gas Corporation..................................... -- -- 14%
The 2003 major customers are a result of our San Juan asset acquisition in
November 2002. Also, during 2003 we decreased our activities with affiliates of
El Paso Corporation, including replacing all our month-to-month arrangements
that were previously with El Paso Merchant Energy with similar arrangements with
third parties. The 2002 percentage increase in revenue from El Paso Merchant
Energy North America Company and El Paso Field Services is primarily due to our
EPN Holding acquisition completed in 2002.
62
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. BUSINESS SEGMENT INFORMATION:
Each of our segments are business units that offer different services and
products that are managed separately since each segment requires different
technology and marketing strategies and 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.
The accounting policies of the individual segments are the same as those
described in Note 1. We record intersegment revenues at rates that approximate
market.
We use performance cash flows (which we formerly referred to as EBITDA) to
evaluate the performance of our segments, determine how resources will be
allocated and develop strategic plans. We define performance cash flows as
earnings before interest, income taxes, depreciation and amortization and other
adjustments. Historically our lenders and equity investors have viewed our
performance cash flows measure as an indication of our ability to generate
sufficient cash to meet debt obligations or to pay distributions, we believe
that there has been a shift in investors' evaluation regarding investments in
MLPs and they now put as much focus on the performance of an MLP investment as
they do its ability to pay distributions. For that reason, we disclose
performance cash flows as a measure of our segment's performance. We believe
performance cash flows is also useful to our investors because it allows them to
evaluate the effectiveness of our business segments from an operational
perspective, exclusive of the costs to finance those activities, income taxes
and depreciation and amortization, none of which are directly relevant to the
efficiency of those operations. This measurement may not be comparable to
measurements used by other companies and should not be used as a substitute for
net income or other performance measures.
63
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our operating results and financial position reflect the acquisitions of
the San Juan assets in November 2002, the EPN Holding assets in April 2002, the
Chaco plant and the remaining 50 percent interest we did not already own in
Deepwater Holdings in October 2001 and GTM Texas in February 2001. The
acquisitions were accounted for as purchases and therefore operating results of
these acquired entities are included prospectively from the purchase date. The
following are results as of and for the periods ended December 31:
NATURAL GAS NATURAL
PIPELINES & OIL AND GAS PLATFORM NON-SEGMENT
PLANTS NGL LOGISTICS STORAGE SERVICES ACTIVITY(1) TOTAL
----------- ------------- -------- -------- ----------- ----------
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31,
2003
Revenue from external
customers..................... $ 734,670 $ 53,850 $ 44,297 $ 20,861 $ 17,811 $ 871,489
Intersegment revenue............ 127 -- 278 2,603 (3,008) --
Depreciation, depletion and
amortization.................. 68,747 8,603 11,720 5,334 4,442 98,846
Earnings from unconsolidated
investments................... 2,377 8,098 898 -- -- 11,373
Performance cash flows.......... 311,164 59,053 29,554 20,181 N/A N/A
Assets.......................... 2,289,546 464,246 315,853 162,275 89,660 3,321,580
FOR THE YEAR ENDED DECEMBER 31,
2002
Revenue from external
customers(2).................. $ 357,581 $ 37,645 $ 28,602 $ 16,672 $ 16,890 $ 457,390
Intersegment revenue............ 227 -- -- 9,283 (9,510) --
Depreciation, depletion and
amortization.................. 44,479 6,481 8,503 4,205 8,458 72,126
Earnings from unconsolidated
investments................... 194 13,445 -- -- -- 13,639
Performance cash flows.......... 167,185 43,347 16,629 29,224 N/A N/A
Assets.......................... 2,279,955 265,900 320,662 140,758 123,621 3,130,896
FOR THE YEAR ENDED DECEMBER 31,
2001
Revenue from external
customers..................... $ 100,683 $ 32,327 $ 19,373 $ 15,385 $ 25,638 $ 193,406
Intersegment revenue............ 381 -- -- 12,620 (13,001) --
Depreciation, depletion and
amortization.................. 12,378 5,113 5,605 4,154 7,528 34,778
Asset impairment charge......... 3,921 -- -- -- -- 3,921
Earnings (loss) from
unconsolidated investments.... (9,761) 18,210 -- -- -- 8,449
Performance cash flows.......... 52,200 47,560 13,209 30,783 N/A N/A
Assets.......................... 563,698 195,839 226,991 115,364 69,968 1,171,860
---------------
(1) Represents predominately 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) The revenue amount for our Oil and NGL Logistics segment has been reduced by
$10.5 million to reflect the reclassification of Typhoon Oil Pipeline's cost
of sales and other products. See Note 1, Summary of Significant Accounting
Policies, for a further discussion.
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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of our segment performance cash flows to our net income is
as follows:
YEARS ENDED DECEMBER 31,
------------------------------
2003 2002 2001
-------- -------- --------
Natural gas pipelines & plants....................... $311,164 $167,185 $ 52,200
Oil & NGL logistics.................................. 59,053 43,347 47,560
Natural gas storage.................................. 29,554 16,629 13,209
Platform services.................................... 20,181 29,224 30,783
-------- -------- --------
Segment performance cash flows..................... 419,952 256,385 143,752
Plus: Other, nonsegment results..................... 15,107 10,427 17,688
Earnings from unconsolidated affiliates....... 11,373 13,639 8,449
Income from discontinued operations........... -- 5,136 1,097
Cumulative effect of accounting change........ 1,690 -- --
Noncash hedge gain............................ -- 411 --
Noncash earnings related to future payments
from El Paso Corporation.................... -- -- 25,404
Less: Interest and debt expense..................... 127,830 81,060 41,542
Loss due to early redemptions of debt......... 36,846 2,434 --
Depreciation, depletion and amortization...... 98,846 72,126 34,778
Asset impairment charge....................... -- -- 3,921
Cash distributions from unconsolidated
affiliates.................................... 12,140 17,804 35,062
Minority interest............................. 917 (60) 100
Net cash payment received from El Paso
Corporation................................... 8,404 7,745 7,426
Discontinued operations of Prince
facilities.................................... -- 7,201 6,561
Loss on sale of Gulf of Mexico assets......... -- -- 11,851
-------- -------- --------
Net income........................................... $163,139 $ 97,688 $ 55,149
======== ======== ========
65
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. GUARANTOR FINANCIAL INFORMATION
In May 2001, we purchased our general partner's 1.01 percent non-managing
interest owned in twelve of our subsidiaries for $8 million. As a result of this
acquisition, all our subsidiaries, but not our equity investees, are wholly
owned by us. As of December 31, 2003, our credit facility is guaranteed by each
of our subsidiaries, excluding our unrestricted subsidiaries (Arizona Gas
Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.), and is collateralized by
substantially all of our assets. In addition, all of our senior notes and senior
subordinated notes are jointly, severally, fully and unconditionally guaranteed
by us and all our subsidiaries, excluding our unrestricted subsidiaries. As of
December 31, 2002, our revolving credit facility, GulfTerra Holding term credit
facility, senior secured term loan and senior secured acquisition term loan are
guaranteed by each of our subsidiaries, excluding our unrestricted subsidiaries
(Matagorda Island Area Gathering System, Arizona Gas Storage, L.L.C. and
GulfTerra Arizona Gas, L.L.C.), and are collateralized by our general and
administrative services agreement, substantially all of our assets, and our
general partner's one percent general partner interest. In addition, as of
December 31, 2002, all of our senior subordinated notes are jointly, severally,
fully and unconditionally guaranteed by us and all our subsidiaries excluding
our unrestricted subsidiaries. The consolidating eliminations column on our
condensed consolidating balance sheets below eliminates our investment in
consolidated subsidiaries, intercompany payables and receivables and other
transactions between subsidiaries. The consolidating eliminations column in our
condensed consolidating statements of income and cash flows eliminates earnings
from our consolidated affiliates.
Non-guarantor subsidiaries for the year ended December 31, 2003, consisted
of our unrestricted subsidiaries (Arizona Gas Storage, L.L.C. and GulfTerra
Arizona Gas, L.L.C.). Non-guarantor subsidiaries for the year ended December 31,
2002, consisted of Argo and Argo I for the quarter ended March 31, 2002, our
GulfTerra Holding (then known as EPN Holding) subsidiaries, which owned the EPN
Holding assets and equity interests in GulfTerra Holding (then known as EPN
Holding), for the quarters ended June 30, 2002 and September 30, 2002, and our
unrestricted subsidiaries for the quarter ended December 31, 2002. Non-guarantor
subsidiaries for all other periods consisted of Argo and Argo I which owned the
Prince TLP. As a result of our disposal of the Prince TLP and our related
overriding royalty interest in April 2002, the results of operations and net
book value of these assets are reflected as discontinued operations in our
statements of income and assets held for sale in our balance sheets and Argo and
Argo I became guarantor subsidiaries.
66
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
-------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Operating revenues
Natural gas pipelines and plants
Natural gas sales..................... $ -- $ -- $171,738 $ -- $171,738
NGL sales............................. -- -- 121,167 -- 121,167
Gathering and transportation.......... -- 815 387,962 -- 388,777
Processing............................ -- -- 52,988 -- 52,988
-------- ----- -------- --------- --------
-- 815 733,855 -- 734,670
-------- ----- -------- --------- --------
Oil and NGL logistics
Oil sales............................. -- -- 2,231 -- 2,231
Oil transportation.................... -- -- 26,769 -- 26,769
Fractionation......................... -- -- 22,034 -- 22,034
NGL Storage........................... -- -- 2,816 -- 2,816
-------- ----- -------- --------- --------
-- -- 53,850 -- 53,850
-------- ----- -------- --------- --------
Platform services....................... -- -- 20,861 -- 20,861
Natural gas storage..................... -- -- 44,297 -- 44,297
Other -- oil and natural gas
production............................ -- -- 17,811 -- 17,811
-------- ----- -------- --------- --------
-- 815 870,674 -- 871,489
-------- ----- -------- --------- --------
Operating expenses
Cost of natural gas and other
products........................... -- -- 287,157 -- 287,157
Operation and maintenance............. 5,908 279 183,515 -- 189,702
Depreciation, depletion and
amortization....................... 148 42 98,656 -- 98,846
(Gain) loss on sale of long-lived
assets............................. (19,000) -- 321 -- (18,679)
-------- ----- -------- --------- --------
(12,944) 321 569,649 -- 557,026
-------- ----- -------- --------- --------
Operating income........................ 12,944 494 301,025 -- 314,463
-------- ----- -------- --------- --------
Earnings from consolidated affiliates... 236,753 -- -- (236,753) --
Earnings from unconsolidated
affiliates............................ -- 898 10,475 -- 11,373
Minority interest expense............... -- (917) -- -- (917)
Other income............................ 784 -- 422 -- 1,206
Interest and debt expense (income)...... 51,721 (3) 76,112 -- 127,830
Loss due to early redemptions of debt... 35,621 -- 1,225 -- 36,846
-------- ----- -------- --------- --------
Income from continuing operations....... 163,139 478 234,585 (236,753) 161,449
Cumulative effect of accounting
change................................ -- -- 1,690 -- 1,690
-------- ----- -------- --------- --------
Net income.............................. $163,139 $ 478 $236,275 $(236,753) $163,139
======== ===== ======== ========= ========
67
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2002
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES(1) SUBSIDIARIES ELIMINATIONS TOTAL
-------- --------------- ------------ ------------- ------------
(IN THOUSANDS)
Operating revenues
Natural gas pipelines and plants
Natural gas sales.............. $ -- $ 30,778 $ 54,223 $ -- $ 85,001
NGL sales...................... -- 15,050 17,928 -- 32,978
Gathering and transportation... -- 71,560 122,776 -- 194,336
Processing..................... -- 5,316 39,950 -- 45,266
-------- -------- -------- -------- --------
-- 122,704 234,877 -- 357,581
-------- -------- -------- -------- --------
Oil and NGL logistics
Oil sales...................... -- -- 108 -- 108
Oil transportation............. -- -- 8,364 -- 8,364
Fractionation.................. -- -- 26,356 -- 26,356
NGL storage.................... -- -- 2,817 -- 2,817
-------- -------- -------- -------- --------
-- -- 37,645 -- 37,645
-------- -------- -------- -------- --------
Platform services................ -- -- 16,672 -- 16,672
Natural gas storage.............. -- 2,699 25,903 -- 28,602
Other -- oil and natural gas
production..................... -- -- 16,890 -- 16,890
-------- -------- -------- -------- --------
-- 125,403 331,987 -- 457,390
-------- -------- -------- -------- --------
Operating expenses
Cost of natural gas and other
products.................... -- 39,280 69,539 -- 108,819
Operation and maintenance...... 6,056 27,701 81,405 -- 115,162
Depreciation, depletion and
amortization................ 274 10,729 61,123 -- 72,126
Loss on sale of long-lived
assets...................... -- -- 473 -- 473
-------- -------- -------- -------- --------
6,330 77,710 212,540 -- 296,580
-------- -------- -------- -------- --------
Operating income................. (6,330) 47,693 119,447 -- 160,810
-------- -------- -------- -------- --------
Earnings from consolidated
affiliates..................... 64,851 -- 29,714 (94,565) --
Earnings from unconsolidated
affiliates..................... -- -- 13,639 -- 13,639
Minority interest income......... -- 60 -- -- 60
Other income..................... 1,471 5 61 -- 1,537
Interest and debt expense
(income)....................... (37,696) 22,048 96,708 -- 81,060
Loss due to early redemptions of
debt........................... -- -- 2,434 -- 2,434
-------- -------- -------- -------- --------
Income from continuing
operations..................... 97,688 25,710 63,719 (94,565) 92,552
Income from discontinued
operations..................... -- 4,004 1,132 -- 5,136
-------- -------- -------- -------- --------
Net income....................... $ 97,688 $ 29,714 $ 64,851 $(94,565) $ 97,688
======== ======== ======== ======== ========
---------------
(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.
68
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2001
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES(1) SUBSIDIARIES ELIMINATIONS TOTAL
-------- --------------- ------------ ------------- ------------
(IN THOUSANDS)
Operating revenues
Natural gas pipelines and plants
Natural gas sales.............. $ -- $ -- $ 59,701 $ -- $ 59,701
Gathering and transportation... -- -- 33,849 -- 33,849
Processing..................... -- -- 7,133 -- 7,133
-------- ------ -------- -------- --------
-- -- 100,683 -- 100,683
-------- ------ -------- -------- --------
Oil and NGL logistics
Oil transportation............. -- -- 7,082 -- 7,082
Fractionation.................. -- -- 25,245 -- 25,245
-------- ------ -------- -------- --------
-- -- 32,327 -- 32,327
-------- ------ -------- -------- --------
Platform services................ -- -- 15,385 -- 15,385
Natural gas storage.............. -- -- 19,373 -- 19,373
Other -- oil and natural gas
production..................... -- -- 25,638 -- 25,638
-------- ------ -------- -------- --------
-- -- 193,406 -- 193,406
-------- ------ -------- -------- --------
Operating expenses
Cost of natural gas and other
products.................... -- -- 51,542 -- 51,542
Operation and maintenance...... (200) -- 33,479 -- 33,279
Depreciation, depletion and
amortization................ 323 -- 34,455 -- 34,778
Asset impairment charge........ -- -- 3,921 -- 3,921
Loss on sale of long-lived
assets...................... 10,941 -- 426 -- 11,367
-------- ------ -------- -------- --------
11,064 -- 123,823 -- 134,887
-------- ------ -------- -------- --------
Operating income (loss).......... (11,064) -- 69,583 -- 58,519
-------- ------ -------- -------- --------
Earnings from consolidated
affiliates..................... 22,393 -- 1,308 (23,701) --
Earnings from unconsolidated
affiliates..................... -- -- 8,449 -- 8,449
Minority interest expense........ -- -- (100) -- (100)
Other income..................... 28,492 -- 234 -- 28,726
Interest and debt expense
(income)....................... (15,328) -- 56,870 -- 41,542
-------- ------ -------- -------- --------
Income from continuing
operations..................... 55,149 -- 22,604 (23,701) 54,052
Income (loss) from discontinued
operations..................... -- 1,308 (211) -- 1,097
-------- ------ -------- -------- --------
Net income....................... $ 55,149 $1,308 $ 22,393 $(23,701) $ 55,149
======== ====== ======== ======== ========
---------------
(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.
69
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
---------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Current assets
Cash and cash equivalents........ $ 30,425 $ -- $ -- $ -- $ 30,425
Accounts receivable, net
Trade......................... -- 61 43,142 -- 43,203
Unbilled trade................ -- 52 63,015 -- 63,067
Affiliates.................... 746,126 3,541 41,606 (743,308) 47,965
Affiliated note receivable....... -- 3,713 55 -- 3,768
Other current assets............. 3,573 -- 17,022 -- 20,595
---------- ------ ---------- ----------- ----------
Total current assets..... 780,124 7,367 164,840 (743,308) 209,023
Property, plant and equipment,
net.............................. 8,039 431 2,886,022 -- 2,894,492
Intangible assets.................. -- -- 3,401 -- 3,401
Investments in unconsolidated
affiliates....................... -- -- 175,747 -- 175,747
Investments in consolidated
affiliates....................... 2,108,104 -- 622 (2,108,726) --
Other noncurrent assets............ 199,761 -- 9,155 (169,999) 38,917
---------- ------ ---------- ----------- ----------
Total assets............. $3,096,028 $7,798 $3,239,787 $(3,022,033) $3,321,580
========== ====== ========== =========== ==========
Current liabilities
Accounts payable
Trade......................... $ -- $ 22 $ 113,798 $ -- $ 113,820
Affiliates.................... 10,691 3,499 767,988 (743,308) 38,870
Accrued gas purchase costs....... -- -- 15,443 -- 15,443
Accrued interest................. 10,930 -- 269 -- 11,199
Current maturities of senior
secured term loan............. 3,000 -- -- -- 3,000
Other current liabilities........ 2,601 1 24,433 -- 27,035
---------- ------ ---------- ----------- ----------
Total current
liabilities............ 27,222 3,522 921,931 (743,308) 209,367
Revolving credit facility.......... 382,000 -- -- -- 382,000
Senior secured term loans, less
current maturities............... 297,000 -- -- -- 297,000
Long-term debt..................... 1,129,807 -- -- -- 1,129,807
Other noncurrent liabilities....... 7,413 -- 211,629 (169,999) 49,043
Minority interest.................. -- 1,777 -- -- 1,777
Partners' capital.................. 1,252,586 2,499 2,106,227 (2,108,726) 1,252,586
---------- ------ ---------- ----------- ----------
Total liabilities and
partners' capital...... $3,096,028 $7,798 $3,239,787 $(3,022,033) $3,321,580
========== ====== ========== =========== ==========
70
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2002
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES(1) SUBSIDIARIES ELIMINATIONS TOTAL
---------- --------------- ------------ ------------- ------------
(IN THOUSANDS)
Current assets
Cash and cash equivalents....... $ 20,777 $ -- $ 15,322 $ -- $ 36,099
Accounts receivable, net
Trade........................ -- 36 90,343 -- 90,379
Unbilled trade............... -- 38 49,102 -- 49,140
Affiliates................... 709,230 3,055 67,513 (695,972) 83,826
Other current assets............ 1,118 -- 2,333 -- 3,451
---------- ------ ---------- ----------- ----------
Total current assets.... 731,125 3,129 224,613 (695,972) 262,895
Property, plant and equipment,
net............................. 6,716 454 2,717,768 -- 2,724,938
Intangible assets................. -- -- 3,970 -- 3,970
Investments in unconsolidated
affiliates...................... -- 5,197 90,754 -- 95,951
Investments in consolidated
affiliates...................... 1,787,767 -- 693 (1,788,460) --
Other noncurrent assets........... 205,262 -- 7,879 (169,999) 43,142
---------- ------ ---------- ----------- ----------
Total assets............ $2,730,870 $8,780 $3,045,677 $(2,654,431) $3,130,896
========== ====== ========== =========== ==========
Current liabilities
Accounts payable
Trade........................ $ -- $ 302 $ 119,838 $ -- $ 120,140
Affiliates................... 18,867 2,982 760,267 (695,972) 86,144
Accrued interest................ 14,221 -- 807 -- 15,028
Accrued gas purchase costs...... -- -- 6,584 -- 6,584
Current maturities of senior
secured term loan............ 5,000 -- -- -- 5,000
Other current liabilities....... 1,645 5 19,545 -- 21,195
---------- ------ ---------- ----------- ----------
Total current
liabilities........... 39,733 3,289 907,041 (695,972) 254,091
Revolving credit facility......... 491,000 -- -- -- 491,000
Senior secured term loans, less
current maturities.............. 392,500 -- 160,000 -- 552,500
Long-term debt.................... 857,786 -- -- -- 857,786
Other noncurrent liabilities...... (1) -- 193,725 (169,999) 23,725
Minority interest................. -- 1,942 -- -- 1,942
Partners' capital................. 949,852 3,549 1,784,911 (1,788,460) 949,852
---------- ------ ---------- ----------- ----------
Total liabilities and
partners' capital..... $2,730,870 $8,780 $3,045,677 $(2,654,431) $3,130,896
========== ====== ========== =========== ==========
---------------
(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.
71
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
--------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Cash flows from operating activities
Net income.................................. $ 163,139 $ 478 $ 236,275 $(236,753) $ 163,139
Less cumulative effect of accounting
change.................................... -- -- 1,690 -- 1,690
--------- ------- --------- --------- ---------
Income from continuing operations........... 163,139 478 234,585 (236,753) 161,449
Adjustments to reconcile net income to net
cash provided by (used in) operating
activities
Depreciation, depletion and
amortization............................ 148 42 98,656 -- 98,846
Distributed earning of unconsolidated
affiliates
Earnings from unconsolidated
affiliates............................ -- (898) (10,475) -- (11,373)
Distributions from unconsolidated
affiliates............................ -- -- 12,140 -- 12,140
(Gain) loss on sale of long-lived
assets.................................. (19,000) -- 321 -- (18,679)
Loss due to write-off of unamortized debt
issuance costs, premiums and
discounts............................... 11,320 -- 1,224 -- 12,544
Amortization of debt issuance cost........ 7,118 -- 380 -- 7,498
Other noncash items....................... 1,224 1,206 1,015 -- 3,445
Working capital changes, net of
acquisitions and non-cash
transactions............................ 3,193 (533) (362) -- 2,298
--------- ------- --------- --------- ---------
Net cash provided by operating
activities.......................... 167,142 295 337,484 (236,753) 268,168
--------- ------- --------- --------- ---------
Cash flows from investing activities
Development expenditures for oil and natural
gas properties............................ -- -- (145) -- (145)
Additions to property, plant and
equipment................................. (2,166) (19) (329,834) -- (332,019)
Proceeds from the sale and retirement of
assets.................................... 69,836 -- 8,075 -- 77,911
Proceeds from sale of investments in
unconsolidated affiliates................. -- 1,355 -- -- 1,355
Additions to investments in unconsolidated
affiliates................................ -- (211) (35,325) -- (35,536)
Repayments on note receivable............... -- 1,238 -- -- 1,238
Cash paid for acquisitions, net of cash
acquired.................................. -- (20) -- -- (20)
--------- ------- --------- --------- ---------
Net cash provided by (used in)
investing activities................ 67,670 2,343 (357,229) -- (287,216)
--------- ------- --------- --------- ---------
Cash flows from financing activities:
Net proceeds from revolving credit
facility.................................. 533,564 -- -- -- 533,564
Repayments of revolving credit facility..... (647,000) -- -- -- (647,000)
Net proceeds from senior secured acquisition
term loan................................. (23) -- -- -- (23)
Repayment of senior secured acquisition term
loan...................................... (237,500) -- -- -- (237,500)
Repayment of GulfTerra Holding term loan.... -- -- (160,000) -- (160,000)
Net proceeds from senior secured term
loan...................................... 299,512 -- -- -- 299,512
Repayment of senior secured term loan....... (160,000) -- -- -- (160,000)
Net proceeds from issuance of long-term
debt...................................... 537,428 -- -- -- 537,426
Repayments of long-term debt................ (269,401) -- -- -- (269,401)
Net proceeds from issuance of common
units..................................... 509,008 -- -- -- 509,010
Redemption of Series B preference units..... (155,673) -- -- -- (155,673)
Advances with affiliates.................... (399,780) (1,396) 164,423 236,753 --
Distributions to partners................... (238,397) -- -- -- (238,397)
Distributions to minority interests......... -- (1,242) -- -- (1,242)
Contribution from general partner........... 3,098 -- -- -- 3,098
--------- ------- --------- --------- ---------
Net cash provided by (used in)
financing activities................ (225,164) (2,638) 4,423 236,753 13,374
--------- ------- --------- --------- ---------
Increase (decrease) in cash and cash
equivalents................................. $ 9,648 $ -- $ (15,322) $ -- (5,674)
========= ======= ========= =========
Cash and cash equivalents at beginning of
year........................................ 36,099
---------
Cash and cash equivalents at end of year...... $ 30,425
=========
72
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2002
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES(1) SUBSIDIARIES ELIMINATIONS TOTAL
----------- --------------- ------------ ------------- ------------
(IN THOUSANDS)
Cash flows from operating activities
Net income....................................... $ 97,688 $ 29,714 $ 64,851 $(94,565) $ 97,688
Less income from discontinued operations......... -- 4,004 1,132 -- 5,136
----------- --------- --------- -------- -----------
Income from continuing operations................ 97,688 25,710 63,719 (94,565) 92,552
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization....... 274 10,730 61,122 -- 72,126
Distributed earnings of unconsolidated
affiliates
Earnings from unconsolidated affiliates...... -- -- (13,639) -- (13,639)
Distributions from unconsolidated
affiliates................................. -- -- 17,804 -- 17,804
Loss on sale of long-lived assets.............. -- -- 473 -- 473
Loss due to write-off of unamortized debt
issuance costs, premiums and discounts....... -- -- 2,434 -- 2,434
Amortization of debt issuance cost............. 3,449 621 373 -- 4,443
Other noncash items............................ 1,053 1,942 1,434 -- 4,429
Working capital changes, net of acquisitions and
non-cash transactions.......................... 16,812 (21,676) (5,002) -- (9,866)
----------- --------- --------- -------- -----------
Net cash provided by continuing operations....... 119,276 17,327 128,718 (94,565) 170,756
Net cash provided by discontinued operations..... -- 4,631 613 -- 5,244
----------- --------- --------- -------- -----------
Net cash provided by operating
activities............................... 119,276 21,958 129,331 (94,565) 176,000
----------- --------- --------- -------- -----------
Cash flows from investing activities
Development expenditures for oil and natural gas
properties..................................... -- -- (1,682) -- (1,682)
Additions to property, plant and equipment....... (4,619) (9,099) (188,823) -- (202,541)
Proceeds from the sale and retirement of
assets......................................... -- -- 5,460 -- 5,460
Additions to investments in unconsolidated
affiliates..................................... -- (1,910) (36,365) -- (38,275)
Cash paid for acquisitions, net of cash
acquired....................................... -- (729,000) (435,856) -- (1,164,856)
----------- --------- --------- -------- -----------
Net cash used in investing activities of
continuing operations.......................... (4,619) (740,009) (657,266) -- (1,401,894)
Net cash provided by (used in) investing
activities of discontinued operations.......... -- (3,523) 190,000 -- 186,477
----------- --------- --------- -------- -----------
Net cash used in investing activities...... (4,619) (743,532) (467,266) -- (1,215,417)
----------- --------- --------- -------- -----------
Cash flows from financing activities
Net proceeds from revolving credit facility...... 359,219 7,000 -- -- 366,219
Repayments of revolving credit facility.......... (170,000) (7,000) -- -- (177,000)
Net proceeds from GulfTerra Holding term credit
facility....................................... -- 530,529 (393) -- 530,136
Repayment of GulfTerra Holding term credit
facility....................................... -- (375,000) -- -- (375,000)
Net proceeds from senior secured acquisition term
loan........................................... 233,236 -- -- -- 233,236
Net proceeds from senior secured term loan....... 156,530 -- -- -- 156,530
Net proceeds from issuance of long-term debt..... 423,528 -- -- -- 423,528
Repayment of Argo term loan...................... -- -- (95,000) -- (95,000)
Net proceeds from issuance of common units....... 150,159 -- -- -- 150,159
Advances with affiliates......................... (1,103,585) 581,601 427,419 94,565 --
Contributions from general partner............... 4,095 -- -- -- 4,095
Distributions to partners........................ (154,468) -- -- -- (154,468)
----------- --------- --------- -------- -----------
Net cash provided by (used in) financing
activities of continuing operations............ (101,286) 737,130 332,026 94,565 1,062,435
Net cash used in financing activities of
discontinued operations........................ -- (3) -- -- (3)
----------- --------- --------- -------- -----------
Net cash provided by (used in) financing
activities............................... (101,286) 737,127 332,026 94,565 1,062,432
----------- --------- --------- -------- -----------
Increase (decrease) in cash and cash equivalents... $ 13,371 $ 15,553 $ (5,909) $ -- 23,015
=========== ========= ========= ========
Cash and cash equivalents at beginning of year..... 13,084
-----------
Cash and cash equivalents at end of year......... $ 36,099
===========
---------------
(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter
ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June
30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the
quarter ended December 31, 2002.
73
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
YEAR ENDED DECEMBER 31, 2001
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES(1) SUBSIDIARIES ELIMINATIONS TOTAL
--------- --------------- ------------ ------------- ------------
(IN THOUSANDS)
Cash flows from operating activities
Net income....................................... $ 55,149 $ 1,308 $ 22,393 $(23,701) $ 55,149
Less income from discontinued operations......... -- 1,308 (211) -- 1,097
--------- -------- ---------- -------- ---------
Income from continuing operations................ 55,149 -- 22,604 (23,701) 54,052
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization....... 323 -- 34,455 -- 34,778
Asset impairment charge........................ -- -- 3,921 -- 3,921
Distributed earnings of unconsolidated
affiliates
Earnings from unconsolidated affiliates...... -- -- (8,449) -- (8,449)
Distributions from unconsolidated
affiliates................................. -- -- 35,062 -- 35,062
Loss on sales of long-lived assets............. 10,941 -- 426 -- 11,367
Amortization of debt issuance cost............. 3,290 318 -- -- 3,608
Other noncash items............................ 270 -- 274 -- 544
Working capital changes, net of effects of
acquisitions and non-cash transactions......... (10,145) 385 (42,707) -- (52,467)
--------- -------- ---------- -------- ---------
Net cash provided by continuing operations..... 59,828 703 45,586 (23,701) 82,416
Net cash provided by discontinued operations... -- 4,296 672 -- 4,968
--------- -------- ---------- -------- ---------
Net cash provided by operating activities.... 59,828 4,999 46,258 (23,701) 87,384
--------- -------- ---------- -------- ---------
Cash flows from investing activities
Development expenditures for oil and natural gas
properties..................................... -- -- (2,018) -- (2,018)
Additions to property, plant and equipment....... (896) -- (507,451) -- (508,347)
Proceeds from the sale and retirement of
assets......................................... 89,162 -- 19,964 -- 109,126
Additions to investments in unconsolidated
affiliates..................................... -- -- (1,487) -- (1,487)
Cash paid for acquisitions, net of cash
acquired....................................... -- -- (28,414) -- (28,414)
--------- -------- ---------- -------- ---------
Net cash provided by (used in) investing
activities of continuing operations............ 88,266 -- (519,406) -- (431,140)
Net cash used in investing activities of
discontinued operations........................ -- (67,367) (1,193) -- (68,560)
--------- -------- ---------- -------- ---------
Net cash provided by (used in) investing
activities................................... 88,266 (67,367) (520,599) -- (499,700)
--------- -------- ---------- -------- ---------
Cash flows from financing activities
Net proceeds from revolving credit facility...... 559,994 -- -- -- 559,994
Repayments of revolving credit facility.......... (581,000) -- -- -- (581,000)
Net proceeds from issuance of long-term debt..... 243,032 -- -- -- 243,032
Advances with affiliates......................... (515,198) 13,563 477,934 23,701 --
Net proceeds from issuance of common units....... 286,699 -- -- -- 286,699
Redemption of Series B preference units.......... (50,000) -- -- -- (50,000)
Contributions from general partner............... 2,843 -- -- -- 2,843
Distributions to partners........................ (105,923) -- (486) -- (106,409)
--------- -------- ---------- -------- ---------
Net cash provided by (used in) financing
activities of continuing operations............ (159,553) 13,563 477,448 23,701 355,159
Net cash provided by financing activities of
discontinued operations........................ -- 49,960 -- -- 49,960
--------- -------- ---------- -------- ---------
Net cash provided by (used in) financing
activities................................... (159,553) 63,523 477,448 23,701 405,119
--------- -------- ---------- -------- ---------
Increase (decrease) in cash and cash equivalents... $ (11,459) $ 1,155 $ 3,107 $ -- (7,197)
========= ======== ========== ========
Cash and cash equivalents at beginning of year..... 20,281
---------
Cash and cash equivalents at end of year........... $ 13,084
=========
---------------
(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in
August 2000.
74
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
17. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED):
General
This footnote discusses our oil and natural gas production activities for
the year 2001. The years 2003 and 2002 are not presented since these operations
are not a significant part of our business as defined by SFAS No. 69,
Disclosures About Oil and Gas Producing Activities, and we do not expect it to
become significant in the future.
Oil and Natural Gas Reserves
The following table represents our net interest in estimated quantities of
proved developed and proved undeveloped reserves of crude oil, condensate and
natural gas and changes in such quantities at year end 2001. Estimates of our
reserves at December 31, 2001 have been made by the independent engineering
consulting firm, Netherland, Sewell & Associates, Inc. except for the Prince
Field for 2001, which was prepared by El Paso Production Company, our affiliate
and operator of the Prince Field. Net proved reserves are the estimated
quantities of crude oil and natural gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Our policy is
to recognize proved reserves only when economic producibility is supported by
actual production. As a result, no proved reserves were booked with respect to
any of our producing fields in the absence of actual production. Proved
developed reserves are proved reserve volumes that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserve volumes that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
significant expenditure is required for recompletion. Reference Rules
4-10(a)(2)(i), (ii), (iii), (3) and (4) of Regulation S-X, for detailed
definitions of proved reserves, which can be found at the SEC's website,
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Estimates of reserve quantities are based on sound geological and
engineering principles, but, by their very nature, are still estimates that are
subject to substantial upward or downward revision as additional information
regarding producing fields and technology becomes available.
OIL/CONDENSATE NATURAL GAS
MBBLS(1) MMCF(1)
-------------- -----------
Proved reserves -- December 31, 2000....................... 1,201 11,500
Revision of previous estimates........................... 1,852 5,913
Production(2)............................................ (345) (4,172)
----- ------
Proved reserves -- December 31, 2001....................... 2,708 13,241
===== ======
Proved developed reserves
December 31, 2001(2)..................................... 2,350 10,384
---------------
(1) Includes our overriding royalty interest in proved reserves on Garden Banks
Block 73 and the Prince Field.
(2) Includes our overriding royalty interest in proved reserves of 1,341 MBbls
of oil and 1,659 MMcf of natural gas on our Prince Field, which began
production in 2001. These reserves were not included in proved reserves
prior to 2001 because, consistent with our policy, economic producibility
had not been supported by actual production. Also, we had increases in
estimated proved reserves relating to our producing properties, primarily at
our West Delta 35 field. Actual production in the Prince Field for 2001 was
37 MBbls of oil and 32 MMcf of natural gas.
74
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following are estimates of our total proved developed and proved
undeveloped reserves of oil and natural gas by producing property as of December
31, 2001.
OIL (BARRELS) NATURAL GAS (MCF)
----------------------- -----------------------
PROVED PROVED PROVED PROVED
DEVELOPED UNDEVELOPED DEVELOPED UNDEVELOPED
--------- ----------- --------- -----------
(IN THOUSANDS)
Garden Banks Block 72.................... 277 -- 1,900 --
Garden Banks Block 117................... 1,065 -- 1,556 --
Viosca Knoll Block 817................... 12 -- 2,216 2,437
West Delta Block 35...................... 13 -- 3,473 --
Prince Field............................. 983 358 1,239 420
----- --- ------ -----
Total.......................... 2,350 358 10,384 2,857
===== === ====== =====
In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenue therefrom are based upon a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices, future operating costs
and future plugging and abandonment costs, all of which may vary considerably
from actual results. All such estimates are to some degree speculative, and
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net revenue expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
The meaningfulness of such estimates is highly dependent upon the assumptions
upon which they are based.
Estimates with respect to proved undeveloped reserves that may be developed
and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than upon actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves. A significant portion of our reserves is based upon
volumetric calculations.
Future Net Cash Flows
The standardized measure of discounted future net cash flows relating to
our proved oil and natural gas reserves is calculated and presented in
accordance with SFAS No. 69. Accordingly, future cash inflows were determined by
applying year-end oil and natural gas prices, as adjusted for fixed price
contracts in effect, to our estimated share of future production from proved oil
and natural gas reserves. The average prices utilized in the calculation of the
standardized measure of discounted future net cash flows at December 31, 2001,
were $16.75 per barrel of oil and $2.62 per Mcf of natural gas. Actual future
prices and costs may be materially higher or lower. Future production and
development costs were computed by applying year-end costs to future years. As
we are not a taxable entity, no future income taxes were provided. A prescribed
10 percent discount factor was applied to the future net cash flows.
In our opinion, this standardized measure is not a representative measure
of fair market value, and the standardized measure presented for our proved oil
and natural gas reserves is not representative of the reserve value. The
standardized measure is intended only to assist financial statement users in
making comparisons between companies. In the table following, the amounts of
future production costs have been restated to
75
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
include platform access fees paid to our platform segment. See note 2 to the
table for further discussion of the impact of such fees on our consolidated
standardized measure of discounted future net cash flows.
DECEMBER 31,
2001
--------------
(IN THOUSANDS)
Future cash inflows(1)...................................... $ 80,603
Future production costs(2).................................. (19,252)
Future development costs.................................... (10,530)
--------
Future net cash flows....................................... 50,821
Annual discount at 10% rate................................. (11,761)
--------
Standardized measure of discounted future net cash flows.... $ 39,060
========
---------------
(1) Our future cash inflows include estimated future receipts from our
overriding royalty interest in our Prince Field and Garden Banks Block 73.
Since these are overriding royalty interests, we do not participate in the
production or development costs for these fields, but do include their
proved reserves, production volumes and future cash inflows in our data.
(2) Our future production costs include platform access fees paid by our oil and
natural gas production business to affiliated entities included in our
platform services segment. Such platform access fees are eliminated in our
consolidated financial statements. The future platform access fees paid to
our platform segment were $4,960 for 2001. On a consolidated basis, our
standardized measure of discounted future net cash flows was $43,789 for
2001.
Estimated future net cash flows for proved developed and proved undeveloped
reserves as of December 31, 2001, are as follows:
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(IN THOUSANDS)
Undiscounted estimated future net cash flows from
proved reserves before income taxes................. $40,518 $10,303 $50,821
======= ======= =======
Present value of estimated future net cash flows from
proved reserves before income taxes, discounted at
10%................................................. $31,003 $ 8,057 $39,060
======= ======= =======
The following are the principal sources of change in the standardized
measure:
2001
--------------
(IN THOUSANDS)
Beginning of year........................................... $ 77,706
Sales and transfers of oil and natural gas produced, net
of production costs.................................... (34,834)
Net changes in prices and production costs................ (55,657)
Extensions, discoveries and improved recovery, less
related costs.......................................... --
Oil and natural gas development costs incurred during the
year................................................... 2,018
Changes in estimated future development costs............. 535
Revisions of previous quantity estimates.................. 38,090
Accretion of discount..................................... 7,771
Changes in production rates, timing and other............. 3,431
--------
End of year................................................. $ 39,060
========
76
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Development, Exploration, and Acquisition Expenditures
The following table details certain information regarding costs incurred in
our development, exploration, and acquisition activities during the year ended
December 31:
2001
--------------
(IN THOUSANDS)
Development costs........................................... $2,018
Capitalized interest........................................ --
------
Total capital expenditures........................ $2,018
======
In the year presented, we elected not to incur any costs to develop our
proved undeveloped reserves.
Capitalized Costs
Capitalized costs relating to our natural gas and oil producing activities
and related accumulated depreciation, depletion and amortization were as follows
as of December 31:
2001
--------------
(IN THOUSANDS)
Oil and natural gas properties
Proved properties......................................... $ 54,609
Wells, equipment, and related facilities.................. 104,766
--------
159,375
Less accumulated depreciation, depletion and amortization... 108,307
--------
$ 51,068
========
Results of operations
Results of operations from producing activities were as follows at December
31:
2001
--------------
(IN THOUSANDS)
Natural gas sales........................................... $18,248
Oil, condensate, and liquid sales........................... 8,062
-------
Total operating revenues............................... 26,310
Production costs(1)......................................... 16,367
Depreciation, depletion and amortization.................... 7,567
-------
Results of operations from producing activities............. $ 2,376
=======
---------------
(1) These production costs include platform access fees paid to affiliated
entities included in our platform services segment. Such platform access
fees, which were approximately $10 million in the year presented, are
eliminated in our consolidated financial statements.
77
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION:
QUARTER ENDED (UNAUDITED)
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
-------- -------- ------------ ----------- --------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
2003
Operating revenues(1).................... $230,095 $237,031 $213,831 $190,532 $871,489
Operating income......................... 75,107 77,886 92,079 69,391 314,463
Income from continuing operations........ 40,525 49,297 60,213 11,414 161,449
Cumulative effect of accounting change... 1,690 -- -- -- 1,690
-------- -------- -------- -------- --------
Net income............................... 42,215 49,297 60,213 11,414 163,139
Income allocation
Series B unitholders................... $ 3,876 $ 3,898 $ 4,018 $ -- $ 11,792
======== ======== ======== ======== ========
General partner
Income from continuing operations... $ 14,860 $ 15,856 $ 18,031 $ 20,667 $ 69,414
Cumulative effect of accounting
change............................ 17 -- -- -- 17
-------- -------- -------- -------- --------
$ 14,877 $ 15,856 $ 18,031 $ 20,667 $ 69,431
======== ======== ======== ======== ========
Common unitholders
Income from continuing operations... $ 17,454 $ 24,160 $ 31,337 $ (7,796) $ 65,155
Cumulative effect of accounting
change............................ 1,340 -- -- -- 1,340
-------- -------- -------- -------- --------
$ 18,794 $ 24,160 $ 31,337 $ (7,796) $ 66,495
======== ======== ======== ======== ========
Series C unitholders
Income from continuing operations... $ 4,335 $ 5,383 $ 6,827 $ (1,457) $ 15,088
Cumulative effect of accounting
change............................ 333 -- -- -- 333
-------- -------- -------- -------- --------
$ 4,668 $ 5,383 $ 6,827 $ (1,457) $ 15,421
======== ======== ======== ======== ========
Basic earnings per common unit
Income from continuing operations... $ 0.40 $ 0.50 $ 0.63 $ (0.14) $ 1.30
Cumulative effect of accounting
change............................ 0.03 -- -- -- 0.03
-------- -------- -------- -------- --------
Net income.......................... $ 0.43 $ 0.50 $ 0.63 $ (0.14) $ 1.33
======== ======== ======== ======== ========
Diluted earnings per common unit(2)
Income from continuing operations... $ 0.40 $ 0.50 $ 0.62 $ (0.14) $ 1.30
Cumulative effect of accounting
change............................ 0.03 -- -- -- 0.02
-------- -------- -------- -------- --------
Net income.......................... $ 0.43 $ 0.50 $ 0.62 $ (0.14) $ 1.32
======== ======== ======== ======== ========
Distributions declared and paid per
common unit............................ $ 0.675 $ 0.675 $ 0.700 $ 0.710 $ 2.760
======== ======== ======== ======== ========
Basic weighted average number of common
units outstanding...................... 44,104 48,005 50,072 57,562 49,953
======== ======== ======== ======== ========
Diluted weighted average number of common
units outstanding...................... 44,104 48,476 50,385 57,855 50,231
======== ======== ======== ======== ========
---------------
(1) Since November 2002, when we acquired the Typhoon Oil Pipeline, we have
recognized revenue attributable to it using the "gross" method, which means
we record as "revenues" all oil that we purchase from our customers at an
index price less an amount that compensates us for our service and we record
as "cost of oil" that same oil which we resell to those customers at the
index price. We believe that a "net" presentation is more appropriate than a
"gross" presentation and is consistent with how we evaluate the performance
of the Typhoon Oil Pipeline. Based on our review of the accounting
literature, we believe that generally accepted accounting principles permit
us to use the "net" method, and accordingly we have presented the results of
Typhoon Oil "net" for all periods. To reflect this reclassification,
operating revenues have been reduced by $48.8 million, $73.1 million and
$69.8 million for the quarters ended March 31, June 30 and September 30 of
2003. This change does not affect operating income or net income.
(2) As a result of the loss allocated to our common unitholders during the
quarter ended December 31, 2003, the basic and diluted earnings per common
units are the same.
78
GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
QUARTER ENDED (UNAUDITED)
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
-------- -------- ------------ ----------- --------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
2002
Operating revenues(1).................... $ 61,544 $120,489 $122,249 $153,108 $457,390
Operating income......................... 22,712 45,777 41,936 50,385 160,810
Income from continuing operations........ 14,741 28,685 23,346 25,780 92,552
Income from discontinued operations...... 4,385 60 456 235 5,136
-------- -------- -------- -------- --------
Net income............................... 19,126 28,745 23,802 26,015 97,688
Income allocation
Series B unitholders................... $ 3,552 $ 3,630 $ 3,693 $ 3,813 $ 14,688
======== ======== ======== ======== ========
General partner
Income from continuing operations... $ 8,691 $ 10,799 $ 10,755 $ 11,837 $ 42,082
Income from discontinued
operations........................ 44 -- 5 2 51
-------- -------- -------- -------- --------
$ 8,735 $ 10,799 $ 10,760 $ 11,839 $ 42,133
======== ======== ======== ======== ========
Common unitholders
Income from continuing operations... $ 2,498 $ 14,256 $ 8,898 $ 8,623 $ 34,275
Income from discontinued
operations........................ 4,341 60 451 233 5,085
-------- -------- -------- -------- --------
$ 6,839 $ 14,316 $ 9,349 $ 8,856 $ 39,360
======== ======== ======== ======== ========
Series C unitholders................... $ -- $ -- $ -- $ 1,507 $ 1,507
======== ======== ======== ======== ========
Basic and diluted earnings per common
unit
Income from continuing operations... $ 0.06 $ 0.33 $ 0.20 $ 0.21 $ 0.80
Income from discontinued
operations........................ 0.11 -- 0.01 -- 0.12
-------- -------- -------- -------- --------
Net income.......................... $ 0.17 $ 0.33 $ 0.21 $ 0.21 $ 0.92
======== ======== ======== ======== ========
Distributions declared and paid per
common unit............................ $ 0.625 $ 0.650 $ 0.650 $ 0.675 $ 2.600
======== ======== ======== ======== ========
Weighted average number of common units
outstanding............................ 39,941 42,842 44,130 44,069 42,814
======== ======== ======== ======== ========
------------------
(1) Operating revenues for the quarter ended December 31, 2002, have been
reduced by $10.5 million to reflect the reclassification of Typhoon Oil
Pipeline's cost of oil.
79
REPORT OF INDEPENDENT AUDITORS
To the Members of Poseidon Oil Pipeline Company, L.L.C.:
In our opinion, the accompanying balance sheets and the related statements
of income, members' capital, comprehensive income and changes in accumulated
other comprehensive income and cash flows present fairly, in all material
respects, the financial position of Poseidon Oil Pipeline Company, L.L.C. (the
"Company") at December 31, 2003 and 2002, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, the Company has
restated its statements of income and cash flows for the years ended December
31, 2002 and 2001, and its balance sheet as of December 31, 2002.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 17, 2004
80
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF INCOME
(IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
------- ---------- ----------
(RESTATED) (RESTATED)
Operating revenues
Crude oil handling revenues............................... $42,573 $55,490 $70,676
Other, net................................................ 450 939 1,331
------- ------- -------
Total revenues......................................... 43,023 56,429 72,007
------- ------- -------
Operating expenses
Crude oil handling costs.................................. 2,579 2,168 1,115
Operation and maintenance................................. 3,694 4,691 2,077
Depreciation and amortization............................. 8,316 8,356 10,552
------- ------- -------
14,589 15,215 13,744
------- ------- -------
Operating income............................................ 28,434 41,214 58,263
Other income (expense)
Interest income........................................... 56 95 394
Interest and debt expense................................. (5,464) (6,923) (7,668)
Other income.............................................. -- 26,600 --
------- ------- -------
Net income.................................................. $23,026 $60,986 $50,989
======= ======= =======
See accompanying notes.
81
POSEIDON OIL PIPELINE COMPANY, L.L.C.
BALANCE SHEETS
AS OF DECEMBER 31, 2003 AND 2002
(IN THOUSANDS)
2003 2002
-------- ----------
(RESTATED)
ASSETS
Current assets
Cash and cash equivalents................................. $ 7,950 $ 27,606
Accounts receivable
Trade................................................... 3,396 14,040
Affiliate............................................... 1,914 2,144
Unbilled................................................ 4,354 3,614
Other current assets...................................... 3,282 2,390
-------- --------
Total current assets.............................. 20,896 49,794
Property, plant and equipment, net.......................... 215,195 214,497
Debt reserve fund........................................... 3,576 3,551
Other noncurrent assets..................................... 122 415
-------- --------
Total assets...................................... $239,789 $268,257
======== ========
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities
Accounts payable, trade................................... $ 11,239 $ 10,423
Accounts payable, affiliate............................... 1,866 5,176
Interest rate hedge liabilities........................... -- 1,385
-------- --------
Total current liabilities......................... 13,105 16,984
Revolving credit facility................................... 123,000 148,000
Commitments and contingencies
Members' capital
Members' capital before accumulated other comprehensive
income................................................. 103,684 104,658
Accumulated other comprehensive income.................... -- (1,385)
-------- --------
Total members' capital............................ 103,684 103,273
-------- --------
Total liabilities and members' capital............ $239,789 $268,257
======== ========
See accompanying notes.
82
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
2003 2002 2001
-------- ---------- ----------
(RESTATED) (RESTATED)
Cash flows from operating activities
Net income................................................ $ 23,026 $ 60,986 $ 50,989
Adjustments to reconcile net income to cash provided by
operating activities
Depreciation and amortization.......................... 8,316 8,356 10,552
Amortization of debt issue costs....................... 293 293 186
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable............. 10,134 (2,615) (5,006)
(Increase) decrease in other current assets............ (892) 96 99
Increase (decrease) in accounts payable................ (2,494) 5,837 3,017
Decrease in reserve for revenue refund................. -- -- (1,297)
-------- -------- --------
Net cash provided by operating activities......... 38,383 72,953 58,540
-------- -------- --------
Cash flows from investing activities
Capital expenditures...................................... (9,014) (3,890) (124)
Proceeds from sale of assets.............................. -- 3,400 --
(Increase) decrease in debt reserve fund.................. (25) (52) 2,740
-------- -------- --------
Net cash provided by (used in) investing
activities...................................... (9,039) (542) 2,616
-------- -------- --------
Cash flows from financing activities
Repayments of long-term debt.............................. (25,000) (2,000) --
Debt issue costs.......................................... -- -- (894)
Distributions to partners................................. (24,000) (43,900) (61,699)
-------- -------- --------
Net cash used in financing activities............. (49,000) (45,900) (62,593)
-------- -------- --------
Increase (decrease) in cash and cash equivalents............ (19,656) 26,511 (1,437)
Cash and cash equivalents:
Beginning of period....................................... 27,606 1,095 2,532
-------- -------- --------
End of period............................................. $ 7,950 $ 27,606 $ 1,095
======== ======== ========
Supplemental disclosure of cash flow information
Cash paid for interest, net of amounts capitalized........ $ 5,034 $ 5,959 $ 6,423
======== ======== ========
See accompanying notes.
83
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF MEMBERS' CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS)
POSEIDON PIPELINE SHELL OIL MARATHON OIL
COMPANY, L.L.C. PRODUCTS U.S. COMPANY
(36%) (36%) (28%) TOTAL
----------------- ------------- ------------ --------
Balance at January 1, 2001................ $ 35,381 $ 35,381 $ 27,520 $ 98,282
Cash distributions...................... (22,212) (22,212) (17,275) (61,699)
Net income.............................. 18,356 18,356 14,277 50,989
-------- -------- -------- --------
Balance at December 31, 2001.............. 31,525 31,525 24,522 87,572
Cash distributions...................... (15,804) (15,804) (12,292) (43,900)
Net income.............................. 21,955 21,955 17,076 60,986
Other comprehensive loss................ (498) (498) (389) (1,385)
-------- -------- -------- --------
Balance at December 31, 2002.............. 37,178 37,178 28,917 103,273
Cash distributions...................... (8,640) (8,640) (6,720) (24,000)
Net income.............................. 8,289 8,289 6,448 23,026
Other comprehensive income.............. 498 498 389 1,385
-------- -------- -------- --------
Balance at December 31, 2003.............. $ 37,325 $ 37,325 $ 29,034 $103,684
======== ======== ======== ========
See accompanying notes.
84
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
--------- --------- ---------
COMPREHENSIVE INCOME
Net income.................................................. $23,026 $60,986 $50,989
Other comprehensive income (loss)........................... 1,385 (1,385) --
------- ------- -------
Total comprehensive income.................................. $24,411 $59,601 $50,989
======= ======= =======
ACCUMULATED OTHER COMPREHENSIVE INCOME
Beginning balance........................................... $(1,385) $ -- $ --
Unrealized net gain (loss) from interest rate swap.......... 1,385 (1,385) --
------- ------- -------
Ending balance.............................................. $ -- $(1,385) $ --
======= ======= =======
ACCUMULATED OTHER COMPREHENSIVE LOSS ALLOCATED TO:
Poseidon Pipeline Company, L.L.C............................ $ -- $ (498) $ --
Shell Oil Products U.S...................................... -- (498) --
Marathon Oil Company........................................ -- (389) --
------- ------- -------
$ -- $(1,385) $ --
======= ======= =======
See accompanying notes.
85
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Poseidon Oil Pipeline Company, L.L.C. is a Delaware limited liability
company, formed in February 1996, to design, construct, own and operate the
unregulated Poseidon Pipeline extending from the Gulf of Mexico to onshore
Louisiana.
Our members are Shell Oil Products U.S. (Shell), Poseidon Pipeline Company,
L.L.C. (Poseidon), a subsidiary of GulfTerra Energy Partners, L.P. (formerly El
Paso Energy Partners, L.P.), and Marathon Pipeline Company (Marathon), which own
36 percent, 36 percent, and 28 percent in us.
Manta Ray Gathering Company, L.L.C., a subsidiary of GulfTerra Energy
Partners, L.P., and an affiliate of ours, is our operator.
The terms "we," "our" or "us", as used in these notes to financial
statements, refer to Poseidon Oil Pipeline Company, L.L.C.
We are in the business of providing crude oil handling services in the Gulf
of Mexico. We provide these services in accordance with various purchase and
sale contracts with producers served by our pipeline. We buy crude oil at
various points along the pipeline and resell the crude oil at a destination
point in accordance with each individual contract. Our margin from these
purchase and sale agreements is earned based upon the differential between the
sales price and the purchase price and represents our earnings from providing
handling services. Differences between measured purchased and sold volumes in
any period are recorded as changes in exchange imbalances with producers.
Basis of Presentation
Our financial statements are prepared on the accrual basis of accounting in
conformity with accounting principles generally accepted in the United States.
Our financial statements for previous periods include reclassifications that
were made to conform to the current year presentation. Those reclassifications
have no impact on reported net income or members' capital.
Restatement of Financial Statements
We have restated our previously reported financial statements as of
December 31, 2002 and for the years ended December 31, 2002 and 2001. These
restatements had no effect on previously reported operating income, net income
or total members' capital.
For the years ended December 31, 2002 and 2001, we have restated our crude
oil handing revenues and our crude oil handling costs in our statements of
income to reflect the net amounts we earn for handling services, rather than the
gross amounts of oil purchased and sold under our buy/sell contracts with
producers. We have also restated our accounts receivable and accounts payable
balances at December 31, 2002, to give effect to this change and restated the
amounts for changes in operating assets and liabilities in our statements of
cash flows for the years ended December 31, 2002 and 2001. These restatements
had no effect on net cash provided by operating activities. Additionally, we
have reclassified the change in our debt reserve fund from a financing activity
to an investing activity in our statements of cash flows for the years ended
December 31, 2002 and 2001.
86
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The effects of these changes on our previously reported financial
statements for the years ended December 31, 2002 and 2001, and as of December
31, 2002 are presented below.
2002 2001
--------------------- ---------------------
AS AS
PREVIOUSLY AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
---------- -------- ---------- --------
(IN THOUSANDS)
Statements of Income
Crude oil handling revenue...................... $1,086,757 $55,490 $1,196,840 $70,676
Other revenue net(1)............................ -- 939 -- 1,331
Crude oil handing costs......................... 1,032,496 2,168 1,126,439 1,115
Operation and maintenance....................... 4,691 4,691 1,586 2,077
Statements of Cash Flows
(Increase) decrease in accounts receivable...... (30,141) (2,615) 27,561 (5,006)
Increase (decrease) in accounts payable......... 33,363 5,837 (29,550) 3,017
Net cash provided by (used in) investing
activities................................... (490) (542) (124) 2,616
Net cash used in financing activities........... (45,952) (45,900) (59,853) (62,593)
Balance Sheet
Accounts receivable
Trade........................................ 92,646 14,040
Affiliate.................................... 30,142 2,144
Unbilled(2).................................. -- 3,614
Accounts payable
Trade........................................ 84,191 10,423
Affiliate.................................... 34,398 5,176
---------------
(1) In prior years, we had not separately reported net results of the sales and
purchases related to pipeline allowance for losses. We have reclassified
these amounts to conform to our 2003 presentation.
(2) In prior years, we had not separately reported unbilled accounts receivable
from trade accounts receivable. We have reclassified this amount in our 2002
balance sheet to conform to our 2003 presentation.
Cash and Cash Equivalents
We consider short-term investments with little risk of change in value
because of changes in interest rates and purchased with an original maturity of
less than three months to be considered cash equivalents.
Debt Reserve Fund
In connection with our revolving credit facility, we are required to
maintain a debt reserve account as collateral on the outstanding balances. At
December 31, 2003 and 2002, the balance in the account was approximately $3.6
million and $3.6 million, and consisted of funds earning interest at 0.7% and
1.5%.
Allowance for Doubtful Accounts
Collectibility of accounts receivable is reviewed regularly and an
allowance is recorded as necessary, primarily under the specific identification
method. At December 31, 2003 and 2002, no allowance for doubtful accounts was
recorded.
87
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Property, Plant and Equipment
Contributed property, plant and equipment is recorded at fair value as
agreed to by the members at the date of contribution. Acquired property, plant
and equipment is recorded at cost. Pipeline equipment is depreciated using a
composite, straight-line method over the estimated useful lives of 3 to 30
years. Line-fill is not depreciated, as our management believes the cost of all
barrels is fully recoverable. Repair and maintenance costs are expensed as
incurred, while additions, improvements and replacements are capitalized. In
addition, interest and other financing costs are capitalized in connection with
construction as part of the cost of the asset and amortized over the related
asset's estimated useful life. No gain or loss is recognized on normal asset
retirements under the composite method.
Impairment and Disposal of Long-Lived Assets
We apply the provisions of Statement of Financial Accounting Standards
(SFAS) No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets to
account for impairment and disposal of long-lived assets. Accordingly, we
evaluate the recoverability of selected long-lived assets when adverse events or
changes in circumstances indicate that the carrying value of an asset or group
of assets may not be recoverable. We determine the recoverability of an asset or
group of assets by estimating the undiscounted cash flows expected to result
from the use and eventual disposition of the asset or group of assets at the
lowest level for which separate cash flows can be measured. If the total of the
undiscounted cash flows is less that the carrying amount for the assets, we
estimate the fair value of the asset or group of assets and recognize the amount
by which the carrying value exceeds the fair value, less cost to sell, as an
impairment loss in income from operations in the period the impairment is
determined. As provided by the provisions of SFAS No. 144, we adopted this
standard on January 1, 2002, and our adoption did not have a material impact on
our financial position or result of operations.
Additionally, as required by SFAS No. 144, we classify long-lived assets to
be disposed of other than by sale (e.g., abandonment, exchange or distribution)
as held and used until the item is abandoned, exchanged or distributed. We
evaluate assets to be disposed of other than by sale for impairment and
recognize a loss for the excess of the carrying value over the fair value.
Long-lived assets to be disposed of through sale recognition meeting specific
criteria are classified as "Held for Sale" and measured at the lower of their
cost or fair value less cost to sell. We report the results of operations of a
component classified as held for sale, including any gain or loss in the
period(s) in which they occur.
Debt Issue Costs
Debt issue costs are capitalized and amortized over the life of the related
indebtedness. Any unamortized debt issue costs are expensed at the time the
related indebtedness is repaid or terminated. As of December 31, 2003 and 2002,
debt issue costs of $122 thousand and $415 thousand are classified as an other
noncurrent asset on our balance sheet. Amortization of debt issue costs is
included in interest and debt expense on our consolidated statements of income.
Fair Value of Financial Instruments
The estimated fair values of our cash and cash equivalents, accounts
receivable and accounts payable approximate their carrying amounts in the
accompanying balance sheet due to the short-term maturity of these instruments.
The fair value of our long-term debt with variable interest rates approximates
its carrying value because of the market-based nature of the debt's interest
rates.
88
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Revenue and Related Cost Recognition
We record crude oil handling revenue when we complete the delivery of crude
oil to the agreed upon delivery point. In addition, we receive an allowance for
losses of crude oil during the handling process. To the extent our actual losses
are less than the allowance, we sell this excess oil and recognize revenue at
the point of sale. To the extent our actual losses are greater than the
allowance, we purchase oil to make-up the difference and record an expense at
the point of purchase. We have presented the net results of the sales and
purchases related to this pipeline allowance for losses as other, net in
operating revenues.
Comprehensive Income
Our comprehensive income is determined based on net income (loss), adjusted
for changes in accumulated other comprehensive income (loss) from our cash flow
hedging activities associated with our interest rate hedge for our revolving
credit facility.
Unbilled Accounts Receivable
Each month we record an estimate for our crude oil handling revenues and
reflect the related receivables as unbilled accounts receivable. Accordingly,
there is one month of estimated data recorded in our crude oil handling revenue
and our accounts receivable for the years ended December 31, 2003, 2002 and
2001. Our estimate is based on actual volume and rate data through the first
part of the month then extrapolated to the end of the month, adjusted according
for any known or expected changes.
Crude Oil Imbalances
In the course of providing crude oil handling services for customers, we
may receive quantities of crude oil that differ from the quantities committed to
be delivered. These transactions result in imbalances that are settled in kind
the following month. We value our imbalances based on the weighted average
acquisition price of produced barrels for the current month. Our imbalance
receivables and imbalance payables are classified on our balance sheet as
accounts receivable and accounts payable as follows on December 31 (in
thousands):
2003 2002
------ ------
Imbalance Receivables
Trade..................................................... $ 742 $2,123
Affiliates................................................ $ 263 $ 564
Imbalance Payables
Trade..................................................... $2,066 $3,841
Affiliates................................................ $ 340 $3,927
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.
Accounting for Hedging Activities
We apply the provisions issued in SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities to account for price risk management
activities. This statement requires us to measure all derivative instruments at
their fair value, and classify them as either assets or liabilities on our
balance sheet, with the corresponding offset to income or other comprehensive
income depending on their designation, their intended
89
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
use, or their ability to qualify as hedges under the standard. In addition, we
account for contracts entered into or modified after June 30, 2003, by applying
the provisions of SFAS No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. This statement amends SFAS No. 133 to
incorporate several interpretations of the Derivatives Implementation Group
(DIG), and also makes several minor modifications to the definition of a
derivative as it was defined in SFAS No. 133. There was no initial financial
statement impact of adopting this standard, although the FASB and DIG continue
to deliberate on the application of the standard to certain derivative
contracts, which may impact our financial statements in the future.
In January 2002, we entered into a two-year interest rate swap agreement
with Credit Lyonnais to fix the variable LIBOR based interest rate on $75
million of our variable rate revolving credit facility at 3.49% through January
2004. Prior to April 2003, under our credit facility, we paid an additional
1.50% over the LIBOR rate resulting in an effective interest rate of 4.99% on
the hedged notional amount. Beginning in April 2003, the additional interest we
pay over LIBOR was reduced to 1.25% as a result of a decrease in our leverage
ratio, resulting in an effective fixed interest rate of 4.74% on the hedged
notional amount. Our interest rate swap expired on January 9, 2004. Collateral
was not required and we do not anticipate non-performance by the counterparty.
Income Taxes
We are organized as a Delaware limited liability company and treated as a
partnership for income tax purposes, and as a result, the income or loss
resulting from our operations for income tax purposes is included in the federal
and state tax returns of our members. Accordingly, no provision for income taxes
has been recorded in the accompanying financial statements.
Management's Use of Estimates
The preparation of our financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that effect the reported amounts of assets, liabilities,
revenues and expenses, and disclosure of contingent assets and liabilities that
exist at the date of our financial statements. While we believe our estimates
are appropriate, actual results can, and often do, differ from those estimates.
Income Allocation and Cash Distributions
Our income is allocated to our members based on their ownership
percentages. At times, we may make cash distributions to our members in amounts
determined by our Management Committee, which is responsible for conducting our
affairs in accordance with our limited liability agreement.
Limitations of Member's Liability
As a limited liability company, our members or their affiliates are not
personally liable for any of our debts, obligations or liabilities simply
because they are our members.
Business Combinations
We apply the provisions of SFAS No. 141, Business Combinations to account
for business combinations. This statement requires that all transactions that
fit the definition of a business combination be accounted for using the purchase
method. This statement also established specific criteria for the recognition of
intangible assets separately from goodwill and requires unallocated negative
goodwill to be written off immediately as an extraordinary item.
90
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Accounting for Asset Retirement Obligations
We apply the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligations to account for asset retirement obligations. This statement requires
companies to record a liability for the estimated retirement and removal of
assets used in their business. The liability is discounted to its present value,
and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
Capitalized retirement and removal costs will be depreciated over the useful
life of the related asset. As provided for by the provisions of SFAS No. 143, we
adopted this standard on January 1, 2003 and our adoption of this statement did
not have a material effect on our financial position or results of operations.
Reporting Gains and Losses from the Early Extinguishment of Debt
We apply the provisions of SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections to
account for gains and losses from the early extinguishment of debt. Accordingly,
we now evaluate the nature of any debt extinguishments to determine whether to
report any gain or loss resulting from the early extinguishment of debt as an
extraordinary item or as income from continuing operations.
Accounting for Costs Associated with Exit or Disposal Activities
We apply the provisions of SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities to account for costs associated with exit or
disposal activities. This statement impacts any exit or disposal activities that
we initiate after January 1, 2003 and we now recognize costs associated with
exit or disposal activities when they are incurred rather than when we commit to
an exit or disposal plan. As provided for by the provisions of SFAS No. 143, we
adopted this standard on January 1, 2003 and our adoption of this pronouncement
did not have an effect on our financial position or results of operations.
Accounting for Guarantees
In accordance with the provisions of Financial Accounting Standards Board
(FASB) Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we record a liability at fair value, or otherwise disclose, certain
guarantees issued after December 31, 2002, that contractually require us to make
payments to a guaranteed party based on the occurrence of certain events. We do
not currently guarantee the indebtedness of others; however the recognition,
measurement and disclosure provisions of this interpretation will apply to any
guarantees we may make in the future.
Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity
We apply the provisions of SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity to account for
financial instruments with characteristics of both liabilities and equity. This
statement provides guidance on the classification of financial instruments, as
equity, as liabilities, or as both liabilities and equity. In accordance with
the provisions of SFAS No. 150, we adopted this standard on July 1, 2003, and
our adoption had no material impact on our financial statements.
91
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consisted of the following:
DECEMBER 31,
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
Pipeline and equipment, at cost............................. $265,496 $264,903
Construction work in progress............................... 9,363 942
-------- --------
274,859 265,845
Less accumulated depreciation............................... (59,664) (51,348)
-------- --------
Total property, plant and equipment, net.................... $215,195 $214,497
======== ========
During 2003, we capitalized interest costs of $6,500 into property, plant
and equipment. During 2002, we did not capitalize interest costs into property,
plant and equipment.
NOTE 3 -- LONG-TERM DEBT
As of December 31, 2003 and 2002, we had $123 million and $148 million
outstanding under our $185 million revolving credit facility that matures in
April 2004 with the full unused amount available. The average variable floating
interest rate was 2.5% and 3.4% at December 31, 2003 and 2002. We pay a variable
commitment fee on the unused portion of the credit facility. The fair value of
our revolving credit facility with variable interest rates approximates its
carrying value because of the market based nature of our debt's interest rates.
In January 2004, we amended our credit agreement and decreased the
availability to $170 million. The amended facility matures in January 2008. The
outstanding balance from the previous facility was transferred to the new
facility.
Under our amended credit facility, our interest rate is LIBOR plus 2.00%
for Eurodollar loans and a variable base rate equal to the greater of the prime
rate or 0.50% plus the federal funds rate (as those terms are defined in our
credit agreement) plus 1.00% for Base Rate loans as defined in our credit
agreement. Our interest rates will decrease by 0.25% if our leverage ratio
declines to 3.00 to 1.00 or less, by 50% if our leverage ratio declines to 2.00
to 1.00 or less, or by 0.625% if our leverage ratio declines to 1.00 to 1.00 or
less. Additionally, we pay commitment fees on the unused portion of the credit
facility at rates that vary from 0.25% to 0.375%. This credit agreement requires
us to maintain a debt service reserve equal to two times the previous quarters'
interest.
Our revolving credit facility contains covenants such as restrictions on
debt levels, restrictions on liens collateralizing debt and guarantees,
restrictions on mergers and on the sales of assets and dividend restrictions. A
breach of any of these covenants could result in acceleration of our debt and
other financial obligations.
Under our $170 million revolving credit facility, the financial debt
covenants are:
(a) we must maintain consolidated tangible net worth in an amount not less
than $75 million plus 100% of the net cash proceeds from our issuance
of equity securities of any kind;
(b) the ratio of earnings before interest, income taxes, depreciation and
amortization (EBITDA), as defined in our credit facility, to interest
expense paid or accrued during the four quarters ending on the last
day of the current quarter must be at least 2.50 to 1.00; and
(c) the ratio of our total indebtedness to earnings before interest,
income taxes, depreciation and amortization (EBITDA), as defined in
our credit facility, for the four quarters ending on the last
92
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
day of the current quarter shall not exceed 4.50 to 1.00 in 2004, 3.50
to 1.00 in 2005 and 3.00 to 1.00 thereafter.
We are in compliance with the above covenants as of the date of this
report.
We use interest rate swaps to limit our exposure to fluctuations in
interest rates. These interest rate swaps are accounted for in accordance with
SFAS No. 133. In January 2004, the two-year interest rate swap to fix the
variable LIBOR based interest rate on $75 million of our revolving facility at
3.49% expired. As of December 31, 2002, the fair value of our interest rate swap
was a liability of $1.4 million resulting in accumulated other comprehensive
loss of $1.4 million. At December 31, 2003, the fair value of the swap was
approximately zero as the swap expired January 9, 2004. The balance in
accumulated other comprehensive income was also approximately zero.
Additionally, we have recognized in income a realized loss of $1.7 million and
$1.2 million for the years ended December 31, 2003 and 2002, as interest
expense.
NOTE 4 -- MAJOR CUSTOMERS
The percentage of our crude oil handling revenues from major customers were
as follows:
FOR THE YEARS ENDED
DECEMBER 31,
------------------------
2003 2002
---------- ----------
% OF TOTAL % OF TOTAL
REVENUES REVENUES
---------- ----------
Chevron Texaco Corporation.................................. 22% 9%
Marathon Oil Company(1)..................................... 18% 24%
Shell Trading formerly Equiva Trading Company(1)............ 13% 9%
British-Borneo USA, Inc. ................................... 9% 10%
El Paso Production(1)....................................... 3% 10%
---------------
(1) Represents affiliated companies.
NOTE 5 -- RELATED PARTY TRANSACTIONS
We derive a portion of our revenues from our members and their affiliated
companies. We generated approximately $15.0 million, $25.6 million and $28.4
million in affiliated revenue. In addition, we paid Manta Ray Gathering Company,
L.L.C., a subsidiary of GulfTerra Energy Partners, approximately $2.4 million in
2003 and $2.1 million in 2002 and 2001 for management, administrative and
general overhead. During 2000, we were charged and paid Shell, the then
operator, an additional management fee of approximately $1.7 million associated
with the repair of our ruptured pipeline. Our other members disputed this
additional charge and we were subsequently reimbursed $1.6 million in 2001.
NOTE 6 -- COMMITMENTS AND CONTINGENCIES
Legal
In the normal course of business, we are involved in various legal actions
arising from our operations. In the opinion of management, the outcome of these
legal actions will not have a significant adverse effect on our financial
position or results of operations.
93
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Environmental
We are subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. We have no reserves for environmental matters, and during the next five
years, we do not expect to make any significant capital expenditures relating to
environmental matters.
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
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws, regulations and claims for
damages to property, employees, other persons and the environment resulting from
current or past operations, could result in substantial costs and liabilities in
the future. As this information becomes available, or other relevant
developments occur, we will make accruals accordingly.
Other
We are subject to regulation under the Outer Continental Shelf Lands Act,
which calls for nondiscriminatory transportation on pipelines operating in the
outer continental shelf region of the Gulf of Mexico, and regulation under the
Hazardous Liquid Pipeline Safety Act. Operations in offshore federal waters are
regulated by the United States Department of the Interior.
In February 1998, we entered into an oil purchase and sale agreement with
Pennzoil Exploration and Production (Pennzoil). The agreement provides that if
Pennzoil delivers at least 7.5 million barrels by September 2003, we will refund
$0.51 per barrel for all barrels delivered plus interest at 8 percent. At
September 30, 2003, the barrels delivered were less than the 7.5 million barrels
requirement and we believe that we have no obligation under this agreement.
Also, in December 2001, we reversed our previous accrual for revenue refund of
$1.7 million and recorded it as a component of crude oil handling revenue in our
2001 statement of income.
In January 2000, an anchor from a submersible drilling unit of Transocean
96 (Transocean) in tow ruptured our 24-inch crude oil pipeline north of the Ship
Shoal 332 platform. The accident resulted in the release of approximately 2,200
barrels of crude oil in the waters surrounding our system, caused damage to the
Ship Shoal 332 platform, and resulted in the shutdown of our system. Our cost to
repair the damaged pipeline and clean up the crude oil released into the Gulf of
Mexico was approximately $18 million and was charged to repair expenses in the
year ended December 31, 2000. By the end of the first quarter 2000, our pipeline
was repaired and placed back into service. In November 2002, we reached a
settlement with multiple parties relating to this rupture and have recorded the
proceeds of $26.6 million as other income in our 2002 statement of income.
94
(b) Pro forma financial information.
Not applicable.
(c) Exhibits.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
95
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, as
general partner
Date: April 19, 2004 By: /s/ Michael J. Knesek
-------------------------------
Michael J. Knesek
Vice President, Controller, and
Principal Accounting Officer of
Enterprise Products GP, LLC
96
EXHIBIT INDEX
Exhibit Number Description
-------------- -----------
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.