UNITED STATES
FORM 8-K
CURRENT REPORT PURSUANT
Date of report (Date of earliest event reported): March 31, 2004
ENTERPRISE PRODUCTS PARTNERS L.P.
Delaware | 1-14323 | 76-0568219 | ||
(State or Other Jurisdiction of Incorporation or Organization) |
(Commission File Number) |
(I.R.S. Employer Identification No.) |
||
2727 North Loop West, Houston, Texas | 77008-1044 | |||
(Address of Principal Executive Offices) | (Zip Code) |
(713) 880-6500
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 the unaudited consolidated financial statements of GulfTerra for the three months ended March 31, 2004 and 2003 and the unaudited pro forma financial statement of Enterprise for the three months ended March 31, 2004 and 2003. Enterprise is filing these financial statements with this Current Report so that they will be incorporated by reference in its currently effective registration statements.
In addition to the GulfTerra financial statements, the information included under Item 5 of this Current Report reflects a series of excerpts from the Company's prospectus supplement that is subject to completion dated August 2, 2004 (the "Prospectus Supplement"). The excerpts retain the pagination of the Prospectus Supplement to allow for accurate cross references to other sections of the Prospectus Supplement. The Prospectus Supplement relates to an underwritten offering by the Company of 13,750,000 of the Company's common units. References in the following excerpts to "the offering" or "this offering" refer to such underwritten offering of common units.
Item 5. OTHER EVENTS
2
GULFTERRA ENERGY PARTNERS, L.P.
CONSOLIDATED FINANCIAL STATEMENTS
For the Three Months Ended March 31, 2004 and 2003
3
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Quarter Ended | ||||||||||
March 31, | ||||||||||
2004 | 2003(1) | |||||||||
Operating revenues
|
$ | 220,339 | $ | 230,095 | ||||||
Operating expenses | ||||||||||
Cost of natural gas and other products
|
64,427 | 90,753 | ||||||||
Operation and maintenance
|
48,496 | 40,644 | ||||||||
Depreciation, depletion and amortization
|
26,223 | 23,697 | ||||||||
Gain on sale of long-lived assets
|
(24 | ) | (106 | ) | ||||||
139,122 | 154,988 | |||||||||
Operating income
|
81,217 | 75,107 | ||||||||
Earnings from unconsolidated affiliates
|
2,208 | 3,316 | ||||||||
Minority interest income (expense)
|
12 | (33 | ) | |||||||
Other income
|
160 | 383 | ||||||||
Interest and debt expense
|
28,031 | 34,486 | ||||||||
Loss due to write-off of unamortized debt
issuance costs
|
| 3,762 | ||||||||
Income before cumulative effect of accounting
change
|
55,566 | 40,525 | ||||||||
Cumulative effect of accounting change
|
| 1,690 | ||||||||
Net income
|
$ | 55,566 | $ | 42,215 | ||||||
Income allocation
|
||||||||||
Series B unitholders
|
$ | | $ | 3,876 | ||||||
General partner
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 21,129 | $ | 14,860 | ||||||
Cumulative effect of accounting change
|
| 17 | ||||||||
$ | 21,129 | $ | 14,877 | |||||||
Common unitholders
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 29,065 | $ | 17,454 | ||||||
Cumulative effect of accounting change
|
| 1,340 | ||||||||
$ | 29,065 | $ | 18,794 | |||||||
Series C unitholders
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 5,372 | $ | 4,335 | ||||||
Cumulative effect of accounting change
|
| 333 | ||||||||
$ | 5,372 | $ | 4,668 | |||||||
Basic and diluted earnings per common unit
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 0.49 | $ | 0.40 | ||||||
Cumulative effect of accounting change
|
| 0.03 | ||||||||
Net income
|
$ | 0.49 | $ | 0.43 | ||||||
Basic weighted average number of common units
outstanding
|
58,946 | 44,020 | ||||||||
Diluted weighted average number of common units
outstanding
|
59,242 | 44,104 | ||||||||
Distributions declared per common unit
|
$ | 0.710 | $ | 0.675 | ||||||
(1) | See Note 1, Basis of Presentation and Summary of Significant Accounting Policies; Revenue Recognition and Cost of Natural Gas and Other Products. |
See accompanying notes.
4
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, | December 31, | ||||||||||
2004 | 2003 | ||||||||||
ASSETS | |||||||||||
Current assets
|
|||||||||||
Cash and cash equivalents
|
$ | 23,257 | $ | 30,425 | |||||||
Accounts receivable, net
|
166,432 | 154,235 | |||||||||
Affiliated note receivable
|
3,713 | 3,768 | |||||||||
Other current assets
|
23,525 | 20,595 | |||||||||
Total current assets
|
216,927 | 209,023 | |||||||||
Property, plant, and equipment, net
|
2,916,484 | 2,894,492 | |||||||||
Intangible assets
|
3,309 | 3,401 | |||||||||
Investments in unconsolidated affiliates
|
190,732 | 175,747 | |||||||||
Other noncurrent assets
|
36,564 | 38,917 | |||||||||
Total assets
|
$ | 3,364,016 | $ | 3,321,580 | |||||||
LIABILITIES AND PARTNERS CAPITAL | |||||||||||
Current liabilities
|
|||||||||||
Accounts payable
|
$ | 139,857 | $ | 168,133 | |||||||
Accrued interest
|
33,982 | 11,199 | |||||||||
Current maturities of senior secured term loan
|
3,000 | 3,000 | |||||||||
Other current liabilities
|
40,702 | 27,035 | |||||||||
Total current liabilities
|
217,541 | 209,367 | |||||||||
Revolving credit facility
|
387,000 | 382,000 | |||||||||
Senior secured term loan, less current maturities
|
297,000 | 297,000 | |||||||||
Long-term debt
|
1,137,161 | 1,129,807 | |||||||||
Other noncurrent liabilities
|
41,596 | 49,043 | |||||||||
Total liabilities
|
2,080,298 | 2,067,217 | |||||||||
Commitments and contingencies
|
|||||||||||
Minority interest
|
1,801 | 1,777 | |||||||||
Partners capital
|
|||||||||||
Limited partners
|
|||||||||||
Common units; 59,685,667 and
58,404,649 units issued and outstanding
|
930,340 | 898,072 | |||||||||
Series C units; 10,937,500 units issued
and outstanding
|
338,297 | 341,350 | |||||||||
General partner
|
13,280 | 13,164 | |||||||||
Total partners capital
|
1,281,917 | 1,252,586 | |||||||||
Total liabilities and partners capital
|
$ | 3,364,016 | $ | 3,321,580 | |||||||
See accompanying notes.
5
GULFTERRA ENERGY PARTNERS, L.P.
Quarter Ended | ||||||||||||
March 31, | ||||||||||||
2004 | 2003 | |||||||||||
Cash flows from operating activities
|
||||||||||||
Net income
|
$ | 55,566 | $ | 42,215 | ||||||||
Less cumulative effect of accounting change
|
| 1,690 | ||||||||||
Income before cumulative effect of accounting
change
|
55,566 | 40,525 | ||||||||||
Adjustments to reconcile net income to net cash
provided by operating activities
|
||||||||||||
Depreciation, depletion and amortization
|
26,223 | 23,697 | ||||||||||
Distributed earnings of unconsolidated affiliates
|
||||||||||||
Earnings from unconsolidated affiliates
|
(2,208 | ) | (3,316 | ) | ||||||||
Distributions from unconsolidated affiliates
|
750 | 4,710 | ||||||||||
Gain on sale of long-lived assets
|
(24 | ) | (106 | ) | ||||||||
Loss due to write-off of unamortized debt
issuance costs
|
| 3,762 | ||||||||||
Amortization of debt issuance costs
|
1,358 | 2,092 | ||||||||||
Other noncash items
|
3,036 | 523 | ||||||||||
Working capital changes, net of acquisitions and
noncash transactions
|
(21,241 | ) | (443 | ) | ||||||||
Net cash provided by operating activities
|
63,460 | 71,444 | ||||||||||
Cash flows from investing activities
|
||||||||||||
Additions to property, plant and equipment
|
(47,833 | ) | (81,937 | ) | ||||||||
Proceeds from sale and retirement of assets
|
93 | 3,088 | ||||||||||
Additions to investments in unconsolidated
affiliates
|
(5,800 | ) | (133 | ) | ||||||||
Net cash used in investing activities
|
(53,540 | ) | (78,982 | ) | ||||||||
Cash flows from financing activities
|
||||||||||||
Net proceeds from revolving credit facility
|
44,933 | 98,991 | ||||||||||
Repayments of revolving credit facility
|
(40,000 | ) | (119,000 | ) | ||||||||
Repayment of senior secured acquisition term loan
|
| (237,500 | ) | |||||||||
Debt issuance costs for senior secured term loan
|
(57 | ) | | |||||||||
Net proceeds from (debt issuance costs for)
issuance of long-term debt
|
(30 | ) | 293,277 | |||||||||
Net proceeds from conversion of Series F
units
|
48,274 | | ||||||||||
Distributions to partners
|
(70,529 | ) | (52,080 | ) | ||||||||
Contribution from general partner
|
321 | | ||||||||||
Net cash used in financing activities
|
(17,088 | ) | (16,312 | ) | ||||||||
Decrease in cash and cash equivalents
|
(7,168 | ) | (23,850 | ) | ||||||||
Cash and cash equivalents at beginning of period
|
30,425 | 36,099 | ||||||||||
Cash and cash equivalents at end of period
|
$ | 23,257 | $ | 12,249 | ||||||||
See accompanying notes.
6
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Comprehensive Income
Quarter Ended | ||||||||
March 31, | ||||||||
2004 | 2003 | |||||||
Net income
|
$ | 55,566 | $ | 42,215 | ||||
Other comprehensive loss
|
(4,299 | ) | (5,715 | ) | ||||
Total comprehensive income
|
$ | 51,267 | $ | 36,500 | ||||
Accumulated Other Comprehensive Loss
March 31, | December 31, | ||||||||
2004 | 2003 | ||||||||
Beginning balance
|
$ | (9,027 | ) | $ | (5,622 | ) | |||
Unrealized mark-to-market losses on cash flow
hedges arising during period
|
(8,092 | ) | (12,924 | ) | |||||
Reclassification adjustments for changes in
initial value of derivative instruments to settlement date
|
3,793 | 10,018 | |||||||
Accumulated other comprehensive loss from
investment in unconsolidated affiliate
|
| (499 | ) | ||||||
Ending balance
|
$ | (13,326 | ) | $ | (9,027 | ) | |||
Accumulated other comprehensive loss allocated to:
|
|||||||||
Common units interest
|
$ | (11,085 | ) | $ | (7,488 | ) | |||
Series C units interest
|
$ | (2,068 | ) | $ | (1,409 | ) | |||
General partners interests
|
$ | (173 | ) | $ | (130 | ) | |||
See accompanying notes.
7
GULFTERRA ENERGY PARTNERS, L.P.
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We are a publicly held Delaware master limited partnership (MLP) established in 1993 for the purpose of providing midstream energy services, including gathering, transportation, fractionation, storage and other related activities for producers of natural gas and oil, onshore and offshore in the Gulf of Mexico. Our 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 Products Partners L.P. (Enterprise), a publicly traded MLP.
We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read it along with our 2003 Annual Report on Form 10-K, as amended, which includes a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2004, and for the quarters ended March 31, 2004 and 2003, are unaudited. We derived the balance sheet as of December 31, 2003, from the audited balance sheet filed in our 2003 Annual Report on Form 10-K, as amended. In our opinion, we have made all adjustments, all of which are of a normal, recurring nature, to fairly present our interim period results. Information for interim periods may not depict the results of operations for the entire year. In addition, prior period information presented in these financial statements includes reclassifications which were made to conform to the current period presentation. These reclassifications have no effect on our previously reported net income or partners capital.
With respect to our Texas intrastate pipeline system, which we acquired in April 2002, we had previously used the pre-acquisition accounting methodology for the cash settlement of natural gas imbalance receivables, which included the cash settlement amounts as a component of operating revenues and cost of natural gas and other products. However, effective January 1, 2004, we have conformed our accounting for cash settlements on that system to the same method we use to account for imbalance receivable settlements on our other systems, which method accounts for these types of cash settlements as an adjustment to cost of natural gas and other products. We have determined that this revision is not material to our previously reported financial statements. Accordingly, we have not revised our previously filed financial statements to reflect this change in methodology.
Unbilled Trade Receivables and Accrued Gas Purchase Costs
As of March 31, 2004 and December 31, 2003, we had included in accounts receivable, net on our balance sheets, unbilled trade receivables of $73.3 million and $63.1 million. Also, as of March 31, 2004 and December 31, 2003, we had included in accounts payable on our balance sheets, accrued gas purchase costs of $16.9 million and $15.4 million.
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. As of March 31, 2004 and December 31, 2003, our allowance was $4.0 million.
As generally used in the energy industry and in this document, the following terms have the following meanings:
/d
|
= per day | MBbls | = thousand barrels | |||
Bbl
|
= barrel | MDth | = thousand dekatherms | |||
Bcf
|
= billion cubic feet | MMcf | = million cubic feet | |||
When we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch. |
8
Revenue Recognition and Cost of Natural Gas and Other Products |
Typhoon Oil Pipeline, a wholly owned subsidiary, has transportation agreements with BHP and ChevronTexaco which provide that Typhoon Oil purchase the oil produced at the inlet of its pipeline for an index price less an amount that compensates Typhoon Oil for transportation services. At the outlet of its pipeline, Typhoon Oil resells this oil back to these producers at the same index price. As disclosed in our 2003 Annual Report on Form 10-K, as amended, we now record revenue from these buy/sell transactions upon delivery of the oil based on the net amount billed to the producers. For the quarter ended March 31, 2003, we reduced by $48.8 million our revenues and cost of natural gas and other products to conform to the current period presentation. This revision had no effect on operating income, net income or partners capital.
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 partners current board of directors and for those grants made prior to El Paso Corporations acquisition of our general partner in August 1998 under our Omnibus Plan and Director Plan. For the quarters ending March 31, 2004 and 2003, 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 Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, to account for all of our other stock-based compensation programs.
9
If compensation expense had been determined by applying the fair value method in SFAS No. 123 to all of our grants, our net income allocated to common unitholders and net income per common unit would have approximated the pro forma amounts below:
Quarter Ended | |||||||||
March 31, | |||||||||
2004 | 2003 | ||||||||
(In thousands, except | |||||||||
per unit amounts) | |||||||||
Net income as reported(1)
|
$ | 55,566 | $ | 42,215 | |||||
Less: Additional stock-based employee
compensation expense determined under fair value based method
|
(7 | ) | (191 | ) | |||||
Pro forma net income
|
$ | 55,559 | $ | 42,024 | |||||
Pro forma net income allocated to common
unitholders
|
$ | 29,058 | $ | 18,603 | |||||
Earnings per common unit:
|
|||||||||
Basic, as reported
|
$ | 0.49 | $ | 0.43 | |||||
Basic, pro forma
|
$ | 0.49 | $ | 0.42 | |||||
Diluted, as reported
|
$ | 0.49 | $ | 0.43 | |||||
Diluted, pro forma
|
$ | 0.49 | $ | 0.42 | |||||
(1) | Stock-based employee compensation expense of $134 thousand and $313 thousand are included in net income for the quarters ended March 31, 2004 and March 31, 2003. |
The effects of applying SFAS No. 123 in this pro forma disclosure may not be indicative of future amounts.
Our remaining accounting policies are consistent with those discussed in our 2003 Annual Report on Form 10-K, as amended, except as discussed below.
Consolidation of Variable Interest Entities
During the first quarter of 2004, we adopted the provisions of Financial Accounting Standards Board Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51, as replaced by FIN No. 46-R. This interpretation defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity and excludes certain joint ventures of other entities that meet the characteristics of a business. Our adoption of FIN No. 46 had no effect on our reported results or financial position.
2. 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.
In April 2004, Enterprise and El Paso Corporation amended their agreement with respect to the ownership of Enterprises general partner interest upon the completion of our merger with Enterprise.
As originally envisioned in the merger agreement, El Paso Corporation was to contribute its 50-percent ownership interest in our general partner to Enterprises general partner, in exchange for a 50-percent ownership interest in Enterprises general partner. Under the amended transaction, El Paso Corporation will still contribute its 50-percent ownership interest in our general partner to Enterprises general partner, but in exchange, El Paso Corporation will receive a 9.9-percent ownership interest in Enterprises general partner and
10
The remaining transactions with respect to our merger with Enterprise are unchanged. These include:
| the payment of $500 million in cash from Enterprise to El Paso Corporation for approximately 13.8 million units, which include 2.9 million of our common units and all of our Series C units owned by El Paso Corporation; | |
| the exchange of 1.81 Enterprise common units for each GulfTerra common unit owned by GulfTerras unitholders, including the remaining approximately 7.5 million GulfTerra common units owned by El Paso Corporation. |
Merger Related Costs
As a result of the pending merger with Enterprise, we determined that it was in our and our unitholders best interest to offer selected employees of El Paso Corporation incentives to continue to focus on the business of the partnership during the merger process. We have accounted for these incentives under the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. As of March 31, 2004, we recorded a liability and a related deferred charge of $4.3 million, which are reflected in other current liabilities and other current assets on our balance sheets. Our liability was estimated based upon the number of employees accepting the offer and the discounted amount they are expected to be paid. We are amortizing the deferred asset to expense ratably over the expected period of the services required in order to qualify for receiving the payments. We expect to amortize the entire expense by merger close. During the quarter ended March 31, 2004, we had amortized $0.6 million to expense. If our expectations of future amounts to be paid or the period of service to be rendered change, we will adjust our liability.
Additionally, during the first quarter of 2004, we recognized an expense of $3.5 million associated with a fairness opinion we received on our pending merger with Enterprise. All of our merger related costs are included in operation and maintenance expenses on our statements of income and are allocated across all of our operating segments.
3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
We hold investments in various affiliates which we account for using the equity method of accounting. Summarized financial information for these investments are as follows:
Quarter Ended March 31, 2004
Deepwater | Cameron | ||||||||||||||||||||
Coyote | Gateway(1) | Highway(1) | Poseidon | Total | |||||||||||||||||
End of period ownership interest
|
50% | 50% | 50% | 36% | |||||||||||||||||
Operating results data:
|
|||||||||||||||||||||
Operating revenues
|
$ | 1,800 | $ | | $ | | $ | 9,275 | |||||||||||||
Other income
|
1 | 5 | 32 | 13 | |||||||||||||||||
Operating expenses
|
(198 | ) | (26 | ) | | (1,336 | ) | ||||||||||||||
Depreciation
|
(360 | ) | | | (2,109 | ) | |||||||||||||||
Other expenses
|
(171 | ) | (214 | ) | (127 | ) | (881 | ) | |||||||||||||
Net income
|
$ | 1,072 | $ | (235 | ) | $ | (95 | ) | $ | 4,962 | |||||||||||
Our share:
|
|||||||||||||||||||||
Allocated income (loss)
|
$ | 536 | $ | (118 | ) | $ | (48 | ) | $ | 1,786 | |||||||||||
Adjustments(2)
|
(2 | ) | 32 | (9 | ) | 61 | |||||||||||||||
Earnings (loss) from unconsolidated affiliates
|
$ | 534 | $ | (86 | ) | $ | (57 | ) | $ | 1,847 | $ | 2,208 | (3) | ||||||||
Allocated distributions
|
$ | 750 | $ | | $ | | $ | | $ | 750 | |||||||||||
11
Quarter Ended March 31, 2003
Deepwater | |||||||||||||||||
Coyote | Gateway(1) | Poseidon | Total | ||||||||||||||
End of period ownership interest
|
50% | 50% | 36% | ||||||||||||||
Operating results data:
|
|||||||||||||||||
Operating revenues
|
$ | 1,923 | $ | | $ | 12,062 | |||||||||||
Other income
|
2 | 13 | 21 | ||||||||||||||
Operating expenses
|
(121 | ) | | (771 | ) | ||||||||||||
Depreciation
|
(339 | ) | | (2,084 | ) | ||||||||||||
Other expenses
|
(197 | ) | (5 | ) | (1,475 | ) | |||||||||||
Net income
|
$ | 1,268 | $ | 8 | $ | 7,753 | |||||||||||
Our share:
|
|||||||||||||||||
Allocated income
|
$ | 634 | $ | 4 | $ | 2,791 | |||||||||||
Adjustments(2)
|
(5 | ) | (4 | ) | (104 | ) | |||||||||||
Earnings from unconsolidated affiliate
|
$ | 629 | $ | | $ | 2,687 | $ | 3,316 | |||||||||
Allocated distributions
|
$ | 750 | $ | | $ | 3,960 | $ | 4,710 | |||||||||
(1) | Cameron Highway Oil Pipeline Company and Deepwater Gateway, L.L.C. are development stage companies; therefore there are no operating revenues or operating expenses. Since their formations in June 2003 and June 2002, they have incurred organizational expenses and received interest income. |
(2) | We recorded adjustments primarily for differences from estimated earnings reported in our Quarterly Report on Form 10-Q and actual earnings reported in the unaudited financial statements of our unconsolidated affiliates. |
(3) | Total earnings from unconsolidated affiliates includes a $30 thousand reduction associated with the true-up of the gain on the sale of our interest in Copper Eagle. |
4. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consisted of the following:
March 31, | December 31, | |||||||||
2004 | 2003 | |||||||||
(In thousands) | ||||||||||
Property, plant and equipment, at
cost(1)
|
||||||||||
Pipelines
|
$ | 2,487,102 | $ | 2,487,102 | ||||||
Platforms and facilities
|
121,105 | 121,105 | ||||||||
Processing plants
|
305,904 | 305,904 | ||||||||
Oil and natural gas properties
|
131,100 | 131,100 | ||||||||
Storage facilities
|
337,927 | 337,535 | ||||||||
Construction work-in-progress
|
431,258 | 383,640 | ||||||||
3,814,396 | 3,766,386 | |||||||||
Less accumulated depreciation, depletion and
amortization
|
897,912 | 871,894 | ||||||||
Total property, plant and equipment, net
|
$ | 2,916,484 | $ | 2,894,492 | ||||||
(1) | Includes leasehold acquisition costs with an unamortized balance of $2.4 million and $3.2 million at March 31, 2004 and December 31, 2003. 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 definitive guidance is provided. |
12
5. FINANCING TRANSACTIONS
The close of the merger with Enterprise, announced in December 2003, will constitute a change of control, and thus a default, under our credit facility, therefore we will either repay or amend the facility prior to the close. In addition, the merger close will constitute a change of control under our indentures, and 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 close. 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 close after the receipt of all necessary approvals. We do not intend to close until appropriate financing is in place.
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 12, and is 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 or the federal funds rate plus 0.5%); or (ii) LIBOR. The interest rate we are charged is contingent upon our leverage ratio, as defined in our credit facility, and credit ratings we are assigned by S&P or Moodys. Depending on the credit ratings on our senior secured credit facility and our leverage ratio, the interest we are charged varies from 1.00% to 2.75% over LIBOR or 0.00% to 1.75% over the variable base rate discussed above. 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 could restrict our ability to make distributions to our unitholders. In addition, our failure to comply with the provisions of any of the covenants could also be a breach of our merger agreement with Enterprise.
Revolving Credit Facility
At March 31, 2004, we had $387 million outstanding under our revolving credit facility at an average interest rate of 3.11%. 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 amount available to us at March 31, 2004, under this facility was $313 million.
Senior Secured Term Loan
At March 31, 2004, we had $300 million outstanding under our senior secured term loan with an average interest rate of 3.36%. 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%.
Long-Term Debt
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 our 8 1/2% senior subordinated notes due June 2010. We will recognize additional costs totaling $4.1 million resulting from the
13
In April 2004, we initiated a full redemption of all our outstanding $175 million aggregate principal amount of 10 3/8% senior subordinated notes due 2009. The notes will be redeemed on June 1, 2004, at a redemption price of 105.2% of the principal amount, plus accrued and unpaid interest to June 1, 2004. Interest on the notes will cease to accrue on and after June 1, 2004, and the only remaining right of holders of the notes will be to receive payment of the redemption price upon surrender to the paying agent, plus accrued and unpaid interest up to, but not including, June 1, 2004. In connection with the redemption of the notes, we will recognize additional expense during the second quarter of 2004 totaling $12.1 million resulting from the payment of the redemption premium and the write-off of unamortized debt issuance costs.
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. In addition, our failure to comply with the provisions of any of the covenants could also be a breach of our merger agreement with Enterprise. 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 Moodys 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.
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% senior subordinated notes due 2011. With this swap agreement, we paid the counterparty a LIBOR based interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. The net amount to be paid or received under the interest rate swap contract is added to or deducted from the interest and debt expense on our senior subordinated notes for which the swap contract was executed, payable semi-annually in June and December. In December 2003, we received $2.8 million related to the interest rate swap contract. We accounted for this derivative as a fair value hedge under SFAS No. 133. In March 2004, we terminated our fixed to floating interest rate swap with our counterparty. The value of the transaction at termination was zero, and as such neither we, nor our counterparty, were required to make any additional payments. Also, neither we, nor our counterparty, have any future obligations under this transaction.
Industrial Revenue Bonds
In April 2004, we reduced the sales tax assessable by the State of Mississippi related to our Petal natural gas storage expansion and pipeline project completed in September 2002, by completing that projects qualification for tax incentives available under the Mississippi Business Finance Act (MBFA). To complete the qualification, Petal Gas Storage, L.L.C. (Petal), our indirect, wholly-owned subsidiary, borrowed $52 million from the Mississippi Business Finance Corporation (MBFC) pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52.0 million in Industrial Development Revenue Bonds to us. The loan agreement and the Industrial Development Revenue Bonds have identical interest rates of 6.25% and maturities of fifteen years. The bonds and tax exemptions are authorized under the MBFA. Petal may repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue.
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Other Credit Facilities
Poseidon
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. The interest rates Poseidon is charged on balances outstanding under its credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidons assets. As of March 31, 2004, Poseidon had $119 million outstanding with an average interest rate of 2.60%.
Poseidons credit agreement contains covenants such as restrictions on debt levels, restrictions on liens, restrictions on mergers and on the sales of assets and dividend restrictions and requirements to maintain certain financial ratios.
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 at 3.49% through January 2004. This interest rate swap expired on January 9, 2004.
Deepwater Gateway
Deepwater Gateway, our joint venture that is constructing the Marco Polo tension leg platform (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. Interest rates are variable and the loan is collateralized by substantially all of Deepwater Gateways 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 March 31, 2004, Deepwater Gateway had $155 million outstanding under the project finance loan at an average interest rate of 2.88% 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.
Cameron Highway
Cameron Highway Oil Pipeline Company, an unconsolidated affiliate in which we have a 50 percent joint venture ownership interest, 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 construction loan bears interest at a variable rate. 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 March 31, 2004, Cameron Highway has $109 million outstanding under the construction loan at an average interest rate of 4.18%.
The interest rate on Cameron Highways 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 March 31, 2004, Cameron Highway has $89 million outstanding under the notes at an average interest rate of 7.29%.
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The project loan facility as a whole is secured by (1) substantially all of Cameron Highways 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, 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 remainder of 2004 and the following 4 years and in total thereafter are as follows at March 31, 2004 (in thousands):
2004
|
$ | 3,000 | |||
2005
|
3,000 | ||||
2006
|
390,000 | ||||
2007
|
3,000 | ||||
2008
|
288,000 | ||||
Thereafter
|
1,135,600 | ||||
Total long-term debt and other financing
obligations, including current maturities
|
$ | 1,822,600 | |||
6. PARTNERS CAPITAL
Cash distributions
In February 2004, we paid cash distributions of $0.71 per common and Series C unit, representing $49.3 million in aggregate. In addition, we paid our general partner $21.3 million related to its general partner interest. In April 2004, we declared a cash distribution of $0.71 per common unit for the quarter ended March 31, 2004, which we will pay on May 14, 2004, to holders of record as of April 30, 2004. Also in May 2004, we will pay our general partner $21.2 million in incentive distributions. At the current distribution rate, our general partner receives approximately 30.2 percent of our total cash distributions for its role as our general partner.
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Series F Convertible Units |
In connection with a public offering in May 2003, we issued 80 Series F convertible units convertible into a maximum of 8,329,679 common units and comprised of two separate detachable units. 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 prior to 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 (i) of 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 business 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 March 31, 2004 and May 3, 2004, was $41.12 and $39.01 per common unit. Holders of Series F convertible units are not entitled to vote or to receive distributions. The value of the Series F convertible units was $2.6 million as of March 31, 2004, and is included in partners capital as a component of common units.
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 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 March 31, 2004 and 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. Additionally, our general partner contributed to us $0.3 million in cash in order to maintain its one percent general partner interest.
Any Series F1 convertible units for which a conversion notice has not been delivered prior to the merger closing date, or termination of the merger, will expire upon the closing, or termination, of the merger with Enterprise. Any Series F2 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.
Option Plans
Total unamortized deferred compensation as of March 31, 2004 and December 31, 2003, was approximately $1.1 million and $1.5 million. 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. We did not grant any unit options or restricted units under the Omnibus Plan or the Director Plan during the quarter ended March 31, 2004.
Net proceeds from unit options exercised during the quarter ended March 31, 2004, was approximately $4.6 million. There were no unit options exercised during the quarter ended March 31, 2003.
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7. EARNINGS PER COMMON UNIT
The following table sets forth the computation of basic and diluted earnings per common unit (in thousands, except per unit amounts):
Quarter Ended | ||||||||||
March 31, | ||||||||||
2004 | 2003 | |||||||||
Numerator:
|
||||||||||
Numerator for basic earnings per common
unit
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 29,065 | $ | 17,454 | ||||||
Cumulative effect of accounting change
|
| 1,340 | ||||||||
$ | 29,065 | $ | 18,794 | |||||||
Denominator:
|
||||||||||
Denominator for basic earnings per common
unit weighted-average common units
|
58,946 | 44,020 | ||||||||
Effect of dilutive securities:
|
||||||||||
Unit options
|
275 | 74 | ||||||||
Restricted units
|
21 | 10 | ||||||||
Denominator for diluted earnings per common
unit adjusted for weighted-average common units
|
59,242 | 44,104 | ||||||||
Basic and diluted earnings per common unit
|
||||||||||
Income before cumulative effect of accounting
change
|
$ | 0.49 | $ | 0.40 | ||||||
Cumulative effect of accounting change
|
| 0.03 | ||||||||
$ | 0.49 | $ | 0.43 | |||||||
8. RELATED PARTY TRANSACTIONS
There have been no changes to our related party relationships, except as described below, from those described in Note 10 of our audited financial statements filed in our 2003 Annual Report on Form 10-K, as amended.
Revenues received from related parties for the quarters ended March 31, 2004 and 2003, were approximately 13 percent of our total revenue.
Our transactions with related parties and affiliates are as follows:
Quarter Ended | |||||||||
March 31, | |||||||||
2004 | 2003 | ||||||||
(In thousands) | |||||||||
Revenues received from related
parties:
|
|||||||||
Natural gas pipelines and plants
|
$ | 20,686 | $ | 22,950 | |||||
Oil and NGL logistics
|
8,359 | 6,869 | |||||||
$ | 29,045 | $ | 29,819 | ||||||
Expenses paid to related parties:
|
|||||||||
Cost of natural gas and other products
|
$ | 9,515 | $ | 14,975 | |||||
Operation and maintenance
|
22,587 | 23,717 | |||||||
$ | 32,102 | $ | 38,692 | ||||||
Reimbursements received from related
parties:
|
|||||||||
Operation and maintenance
|
$ | 966 | $ | 525 | |||||
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The following table provides summary data categorized by our related parties:
Quarter Ended | ||||||||||
March 31, | ||||||||||
2004 | 2003 | |||||||||
(In thousands) | ||||||||||
Revenues received from related
parties:
|
||||||||||
El Paso Corporation
|
||||||||||
El Paso Merchant Energy North America Company
|
$ | 7,609 | $ | 10,812 | ||||||
El Paso Production Company
|
2,262 | 2,358 | ||||||||
Tennessee Gas Pipeline Company
|
| 55 | ||||||||
El Paso Field Services
|
18,991 | 16,594 | ||||||||
Enterprise
|
183 | | ||||||||
$ | 29,045 | $ | 29,819 | |||||||
Cost of natural gas and other products paid to
related parties:
|
||||||||||
El Paso Corporation
|
||||||||||
El Paso Merchant Energy North America Company
|
$ | 9,055 | $ | 10,278 | ||||||
El Paso Field Services
|
402 | 4,677 | ||||||||
El Paso Natural Gas Company
|
19 | 20 | ||||||||
Southern Natural Gas
|
39 | | ||||||||
$ | 9,515 | $ | 14,975 | |||||||
Operation and maintenance expenses paid to
related parties:
|
||||||||||
El Paso Corporation
|
||||||||||
El Paso Field Services
|
$ | 22,455 | $ | 23,624 | ||||||
Unconsolidated Subsidiaries
|
||||||||||
Poseidon Oil Pipeline Company
|
132 | 93 | ||||||||
$ | 22,587 | $ | 23,717 | |||||||
Reimbursements received from related
parties:
|
||||||||||
Unconsolidated Subsidiaries
|
||||||||||
Cameron Highway
|
$ | 217 | $ | | ||||||
Deepwater Gateway
|
183 | | ||||||||
Poseidon Oil Pipeline Company
|
566 | 525 | ||||||||
$ | 966 | $ | 525 | |||||||
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Our accounts receivable due from related parties consisted of the following as of:
March 31, | December 31, | |||||||||
2004 | 2003 | |||||||||
(In thousands) | ||||||||||
El Paso Corporation
|
||||||||||
El Paso Production Company
|
$ | 6,373 | $ | 5,991 | ||||||
El Paso Merchant Energy North America Company
|
10,657 | 4,113 | ||||||||
Tennessee Gas Pipeline Company
|
1,559 | 1,350 | ||||||||
El Paso Field Services
|
11,113 | 16,571 | ||||||||
El Paso Natural Gas Company
|
4,411 | 4,255 | ||||||||
ANR Pipeline Company
|
1,662 | 1,600 | ||||||||
Other
|
54 | 830 | ||||||||
Enterprise
|
199 | | ||||||||
36,028 | 34,710 | |||||||||
Unconsolidated Subsidiaries
|
||||||||||
Deepwater Gateway
|
4,319 | 3,939 | ||||||||
Cameron Highway
|
7,375 | 9,302 | ||||||||
Poseidon
|
1,036 | | ||||||||
Other
|
| 14 | ||||||||
12,730 | 13,255 | |||||||||
Total
|
$ | 48,758 | $ | 47,965 | ||||||
Our accounts payable due to related parties consisted of the following as of:
March 31, | December 31, | |||||||||
2004 | 2003 | |||||||||
(In thousands) | ||||||||||
El Paso Corporation
|
||||||||||
El Paso Merchant Energy North America Company
|
$ | 9,270 | $ | 7,523 | ||||||
El Paso Production Company
|
4,164 | 4,069 | ||||||||
El Paso Field Services
|
13,750 | 13,869 | ||||||||
Tennessee Gas Pipeline Company
|
973 | 1,278 | ||||||||
El Paso Natural Gas Company
|
1,164 | 942 | ||||||||
El Paso Corporation
|
1,322 | 6,249 | ||||||||
Southern Natural Gas
|
20 | 1,871 | ||||||||
Other
|
671 | 667 | ||||||||
31,334 | 36,468 | |||||||||
Unconsolidated Subsidiaries
|
||||||||||
Deepwater Gateway
|
2,268 | 2,268 | ||||||||
Poseidon
|
774 | | ||||||||
Other
|
10 | 134 | ||||||||
3,052 | 2,402 | |||||||||
Total
|
$ | 34,386 | $ | 38,870 | ||||||
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Other Matters
In connection with the sale of some 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, all of which have been received.
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 resolution of these matters results in judgments against us. For a further discussion of these matters see Note 9, Commitments and 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 as of March 31, 2004, from ANR Pipeline Company for our Phoenix project. These amounts collected 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.
9. 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.
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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, 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, attorneys 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 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.
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, requesting unspecified monetary damages. 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 are 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 us and BP, we requested that BP indemnify us 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, requesting unspecified monetary damages. 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.
Commodity Futures Trading Commission Investigation. On April 2, 2004, certain affiliates of El Paso Corporation received subpoenas from the Commodity Futures Trading Commission (CFTC) in connection with the CFTCs investigation of reporting affecting the price of natural gas in the fall of 2003. Our two storage fields, Petal and Wilson, are covered by this subpoena. Specifically, the CFTC requested the companies to provide information, on behalf of themselves and their affiliates, relating to storage reports provided to the Energy Information Administration for the period October 2003 through December 2003. It is our understanding that the CFTC is conducting an industry-wide investigation of storage reporting. We are cooperating fully with the CFTCs investigation.
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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. and City of Edinburg 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 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 lowers courts calculation of past judgment interest but otherwise affirmed the judgment. A petition for review by the Texas Supreme Court was filed, and the Supreme Court has requested full briefing of the issues.
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 Citys 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 Unions 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 sought rehearing which the Supreme Court denied.
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 March 31, 2004, 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.
23
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 March 2004, we had a reserve of approximately $21 million, which is included in other non-current liabilities on our balance sheets, 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 be indemnified for liabilities discovered during the proceeding three years from the closing 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 penalty of $365,750 for the cited violation. 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. responded to the NoE challenging several of the allegations and the penalty amount and is awaiting a response from the TCEQ.
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 Federal Energy Regulatory Commission (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 High Island Offshore System (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.
24
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, and several requests for rehearing were filed. On that date, each transmission provider filed with FERC and posted on the internet website a plan and scheduling for implementing this Final Rule. On April 8, 2004, we filed for an exemption from the rule on behalf of Petal and HIOS. On April 16, 2004, the FERC issued its order on rehearing which, among other things, affirmed that the final rule was needed and extended the implementation date to September 1, 2004. At this time, we cannot predict the impact of the final rule on HIOS and Petals organizational structure, but at a minimum, adoption of the regulations in the form outlined in the Final Rule may place additional administrative and operational burdens on us.
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 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 conducted a hearing on this matter and an initial decision from the Administrative Law Judge was provided in April 2004. We are in the process of filing briefs on our exceptions to this decision. We are also in separate discussions with our customers to reach a settlement on this rate case.
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 March 31, 2004, we had recorded fuel differences of approximately $7.3 million, which is included in other non-current assets on our balance sheets. 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. Any amount we are unable to resolve or collect from our customers will negatively impact our earnings. At this time we are not able to determine what amount, if any, may be collectible from our customers.
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 FERCs 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. On March 22, 2004, the FERC extended the 45 day time limit to July 12, 2004. 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 March 2004, GulfTerra Texas filed for rehearing of the triennial rate case requirement. The FERC plans to issue an order on rehearing of the triennial rate case requirement by June 21, 2004.
25
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 Falcons late intervention in February 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 Falcons assertions and requesting that the complaint be denied. The Railroad Commission has set their case for hearing beginning on June 29, 2004. The City Board of Public Service of San Antonio filed an intervention in opposition to Falcons 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.
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.
10. ACCOUNTING FOR HEDGING ACTIVITIES
A majority of our commodity purchases and sales, which relate to sales of oil and natural gas associated with our production operations, purchases and sales of natural gas associated with pipeline operations, sales of natural gas liquids 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.
We estimate the entire $13.3 million of unrealized losses included in accumulated other comprehensive income at March 31, 2004, will be reclassified from accumulated other comprehensive income as a reduction to earnings over the next nine months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the income statement in operating revenues, cost of natural gas and other products, or interest and debt expense, depending on the item being hedged. The effect of reclassifying these amounts to the income statement line items is recording our earnings for the period related to the hedged items at the hedged price under the derivative financial instruments.
In February and August 2003, we entered into 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 March 31, 2004, the fair value of these cash flow hedges was a liability of $9.2 million, as the market price at that date was higher than the hedge price. For the quarter ended March 31, 2004, we reclassified approximately $1.7 million of unrealized accumulated loss related to these derivatives from accumulated other comprehensive income as a decrease in revenue. No ineffectiveness exists in this hedging relationship because all purchase and sale prices are based on the same index and volumes as the hedge transaction.
26
During 2003, we entered into additional derivative financial instruments to hedge a portion of our business exposure to changes in natural gas liquids (NGL) prices during 2004. We entered into financial swaps for 6,000 barrels per day for the period from August 2003 to September 2004. The average fixed price received is $0.47 per gallon for 2004 while we pay a monthly average floating price based on the Oil Pricing Information Service (OPIS) average price for each month. As of March 31, 2004, the fair value of these cash flow hedges was a liability of $4.1 million. For the quarter ended March 31, 2004, we reclassified approximately $2.1 million of unrealized accumulated loss related to these derivatives from accumulated other comprehensive income to earnings. No ineffectiveness exists in this hedging relationship because all purchase and sales prices are based on the same index and volumes as the hedge transaction.
In connection with our GulfTerra Intrastate Alabama operations, we 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 2003 to offset the risk of increasing natural gas prices. For January and February 2004, we contracted to purchase 20,000 MMBtu and for March 2004, we contracted to purchase 15,000 MMBtu. The average fixed price paid during 2004 was $5.28 per MMBtu while we received a floating price based on the SONAT-Louisiana index (Southern Natural Pipeline index as published by the periodical Inside FERC). As of March 31, 2004, these cash flow hedges expired and we reclassified a gain of approximately $45 thousand from accumulated other comprehensive income to earnings. No ineffectiveness existed in this hedging relationship because all purchase and sale prices were based on the same index and volumes as the hedge transaction.
In July 2003, to achieve a 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% senior subordinated notes due 2011. With this swap agreement, we paid the counterparty a LIBOR based interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. We accounted for this derivative as a fair value hedge under SFAS No. 133. In March 2004, we terminated our fixed to floating interest rate swap with our counterparty. The value of the transaction at termination was zero and as such neither we, nor our counterparty, were required to make any payments. Also, neither we, nor our counterparty, have any future obligations under this transaction.
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. The counterparty for our GulfTerra Alabama Intrastate operations is UBS Warburg, and we do not require collateral or anticipate non-performance by this counterparty.
11. 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. 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. |
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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, 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 segments 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 and depreciation and amortization, neither 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.
The following are results as of and for the quarters ended March 31:
Natural Gas | Oil and | Natural | ||||||||||||||||||||||
Pipelines and | NGL | Gas | Platform | Non-Segment | ||||||||||||||||||||
Plants | Logistics | Storage | Services | Activity(1) | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Quarter Ended March 31, 2004
|
||||||||||||||||||||||||
Revenue from external customers
|
$ | 181,503 | $ | 15,188 | $ | 12,450 | $ | 6,642 | $ | 4,556 | $ | 220,339 | ||||||||||||
Intersegment revenue
|
33 | | | 585 | (618 | ) | | |||||||||||||||||
Depreciation, depletion and amortization
|
17,388 | 3,092 | 2,948 | 1,353 | 1,442 | 26,223 | ||||||||||||||||||
Earnings from unconsolidated affiliates
|
534 | 1,790 | (30 | ) | (86 | ) | | 2,208 | ||||||||||||||||
Performance cash flows
|
82,013 | 7,468 | 9,061 | 6,363 | N/A | N/A | ||||||||||||||||||
Assets
|
2,329,952 | 472,482 | 311,326 | 167,044 | 83,212 | 3,364,016 | ||||||||||||||||||
Quarter Ended March 31, 2003
|
||||||||||||||||||||||||
Revenue from external customers (2)
|
$ | 197,189 | $ | 11,968 | $ | 11,606 | $ | 4,382 | $ | 4,950 | $ | 230,095 | ||||||||||||
Intersegment revenue
|
38 | | 92 | 646 | (776 | ) | | |||||||||||||||||
Depreciation, depletion and amortization
|
16,553 | 2,197 | 2,962 | 1,200 | 785 | 23,697 | ||||||||||||||||||
Earnings from unconsolidated affiliates
|
629 | 2,687 | | | | 3,316 | ||||||||||||||||||
Performance cash flows
|
77,835 | 11,600 | 7,001 | 4,235 | N/A | N/A | ||||||||||||||||||
Assets
|
2,249,828 | 322,324 | 326,795 | 160,128 | 108,407 | 3,167,482 |
(1) | Represents predominantly our oil and natural gas production activities as well as intersegment eliminations. Our intersegment revenues, along with our intersegment operating expenses, consist of normal course of business-type transactions between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the Non-Segment Activity column, to remove intersegment transactions. |
(2) | Revenue from external customers for our Oil and NGL Logistics segment has been reduced by $48.8 million to reflect the revision of Typhoon Oil Pipelines revenues and cost of natural gas and other products to conform to the current period presentation. See Note 1, Basis of Presentation and Summary of Significant Accounting Policies; Revenue Recognition and Cost of Natural Gas and Other Products. |
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A reconciliation of our segment performance cash flows to our net income is as follows:
Quarter Ended | |||||||||
March 31, | |||||||||
2004 | 2003 | ||||||||
(In thousands) | |||||||||
Natural gas pipelines and plants
|
$ | 82,013 | $ | 77,835 | |||||
Oil and NGL logistics
|
7,468 | 11,600 | |||||||
Natural gas storage
|
9,061 | 7,001 | |||||||
Platform services
|
6,363 | 4,235 | |||||||
Segment performance cash flows
|
104,905 | 100,671 | |||||||
Plus: Other, nonsegment results
|
5,405 | 5,266 | |||||||
Earnings from
unconsolidated affiliates
|
2,208 | 3,316 | |||||||
Cumulative
effect of accounting change
|
| 1,690 | |||||||
Less: Interest and debt expense
|
28,031 | 34,486 | |||||||
Loss due to
write-off of unamortized debt issuance costs
|
| 3,762 | |||||||
Depreciation,
depletion and amortization
|
26,223 | 23,697 | |||||||
Cash
distributions from unconsolidated affiliates
|
750 | 4,710 | |||||||
Minority
interest
|
(12 | ) | 33 | ||||||
Net cash
payment received from El Paso Corporation
|
1,960 | 2,040 | |||||||
Net income
|
$ | 55,566 | $ | 42,215 | |||||
12. GUARANTOR FINANCIAL INFORMATION
As of March 31, 2004 and 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 of our subsidiaries, excluding our unrestricted subsidiaries. Non-guarantor subsidiaries for the quarter ended March 31, 2004, consisted of our unrestricted subsidiaries. Non-guarantor subsidiaries for the quarter ended March 31, 2003, consisted of Matagorda Island Area Gathering System, Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.
The following condensed consolidating financial statements are included so that separate financial statements of our guarantor subsidiaries are not required to be filed with the SEC. These condensed consolidating financial statements present our investments in both consolidated subsidiaries and unconsolidated affiliates using the equity method of accounting. 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.
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Condensed Consolidating Statements of Income
Non-guarantor | Guarantor | Consolidating | Consolidated | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Total | |||||||||||||||||
(In thousands) | |||||||||||||||||||||
Operating revenues
|
$ | | $ | 134 | $ | 220,205 | $ | | $ | 220,339 | |||||||||||
Operating expenses
|
|||||||||||||||||||||
Cost of natural gas and other products
|
| | 64,427 | | 64,427 | ||||||||||||||||
Operation and maintenance
|
| 63 | 48,433 | | 48,496 | ||||||||||||||||
Depreciation, depletion and amortization
|
36 | | 26,187 | | 26,223 | ||||||||||||||||
Gain on sale of long-lived assets
|
| | (24 | ) | | (24 | ) | ||||||||||||||
36 | 63 | 139,023 | | 139,122 | |||||||||||||||||
Operating income (loss)
|
(36 | ) | 71 | 81,182 | | 81,217 | |||||||||||||||
Earnings from consolidated affiliates
|
65,833 | | | (65,833 | ) | | |||||||||||||||
Earnings (loss) from unconsolidated affiliates
|
| (30 | ) | 2,238 | | 2,208 | |||||||||||||||
Minority interest income
|
| 12 | | | 12 | ||||||||||||||||
Other income
|
73 | | 87 | | 160 | ||||||||||||||||
Interest and debt expense
|
10,304 | (7 | ) | 17,734 | | 28,031 | |||||||||||||||
Net income
|
$ | 55,566 | $ | 60 | $ | 65,773 | $ | (65,833 | ) | $ | 55,566 | ||||||||||
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Condensed Consolidating Statements of Income
Non-guarantor | Guarantor | Consolidating | Consolidated | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries(1) | Eliminations | Total | |||||||||||||||||
(In thousands) | |||||||||||||||||||||
Operating revenues
|
$ | | $ | 277 | $ | 229,818 | $ | | $ | 230,095 | |||||||||||
Operating expenses
|
|||||||||||||||||||||
Cost of natural gas and other products
|
| | 90,753 | | 90,753 | ||||||||||||||||
Operation and maintenance
|
467 | 74 | 40,103 | | 40,644 | ||||||||||||||||
Depreciation, depletion and amortization
|
37 | 10 | 23,650 | | 23,697 | ||||||||||||||||
Gain on sale of long-lived assets
|
| | (106 | ) | | (106 | ) | ||||||||||||||
504 | 84 | 154,400 | | 154,988 | |||||||||||||||||
Operating income (loss)
|
(504 | ) | 193 | 75,418 | | 75,107 | |||||||||||||||
Earnings from consolidated affiliates
|
61,505 | | | (61,505 | ) | | |||||||||||||||
Earnings from unconsolidated affiliates
|
| | 3,316 | | 3,316 | ||||||||||||||||
Minority interest expense
|
| (33 | ) | | | (33 | ) | ||||||||||||||
Other income
|
248 | | 135 | | 383 | ||||||||||||||||
Interest and debt expense
|
15,272 | | 19,214 | | 34,486 | ||||||||||||||||
Loss due to write-off of unamortized debt
issuance costs
|
3,762 | | | | 3,762 | ||||||||||||||||
Income before cumulative effect of accounting
change
|
42,215 | 160 | 59,655 | (61,505 | ) | 40,525 | |||||||||||||||
Cumulative effect of accounting change
|
| | 1,690 | | 1,690 | ||||||||||||||||
Net income
|
$ | 42,215 | $ | 160 | $ | 61,345 | $ | (61,505 | ) | $ | 42,215 | ||||||||||
(1) | Operating revenues and cost of natural gas and other products for our guarantor subsidiaries has been reduced by $48.8 million to reflect the revision of Typhoon Oil Pipelines revenues and cost of natural gas and other products to conform to the current period presentation. See Note 1, Basis of Presentation and Summary of Significant Accounting Policies; Revenue Recognition and Cost of Natural Gas and Other Products. |
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Condensed Consolidating Balance Sheets
Non-guarantor | Guarantor | Consolidating | Consolidated | |||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Total | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||||
Current assets
|
||||||||||||||||||||||
Cash and cash equivalents
|
$ | 23,257 | $ | | $ | | $ | | $ | 23,257 | ||||||||||||
Accounts receivable, net
|
||||||||||||||||||||||
Trade
|
2,287 | 80 | 115,307 | | 117,674 | |||||||||||||||||
Affiliates
|
747,417 | 206 | 44,331 | (743,196 | ) | 48,758 | ||||||||||||||||
Affiliated note receivable
|
| 3,713 | | | 3,713 | |||||||||||||||||
Other current assets
|
6,675 | | 16,850 | | 23,525 | |||||||||||||||||
Total current assets
|
779,636 | 3,999 | 176,488 | (743,196 | ) | 216,927 | ||||||||||||||||
Property, plant and equipment, net
|
8,508 | 431 | 2,907,545 | | 2,916,484 | |||||||||||||||||
Intangible assets
|
| | 3,309 | | 3,309 | |||||||||||||||||
Investment in unconsolidated affiliates
|
| | 190,732 | | 190,732 | |||||||||||||||||
Investment in consolidated affiliates
|
2,169,692 | | 700 | (2,170,392 | ) | | ||||||||||||||||
Other noncurrent assets
|
198,495 | | 8,068 | (169,999 | ) | 36,564 | ||||||||||||||||
Total assets
|
$ | 3,156,331 | $ | 4,430 | $ | 3,286,842 | $ | (3,083,587 | ) | $ | 3,364,016 | |||||||||||
Current liabilities
|
||||||||||||||||||||||
Accounts payable
|
||||||||||||||||||||||
Trade
|
$ | | $ | 17 | $ | 105,454 | $ | | $ | 105,471 | ||||||||||||
Affiliates
|
9,101 | | 768,481 | (743,196 | ) | 34,386 | ||||||||||||||||
Accrued interest
|
33,982 | | | | 33,982 | |||||||||||||||||
Current maturities of senior secured term loan
|
3,000 | | | | 3,000 | |||||||||||||||||
Other current liabilities
|
7,171 | | 33,531 | | 40,702 | |||||||||||||||||
Total current liabilities
|
53,254 | 17 | 907,466 | (743,196 | ) | 217,541 | ||||||||||||||||
Revolving credit facility
|
387,000 | | | | 387,000 | |||||||||||||||||
Senior secured term loans, less current maturities
|
297,000 | | | | 297,000 | |||||||||||||||||
Long-term debt
|
1,137,161 | | | | 1,137,161 | |||||||||||||||||
Other noncurrent liabilities
|
(1 | ) | | 211,596 | (169,999 | ) | 41,596 | |||||||||||||||
Minority interest
|
| 1,801 | | | 1,801 | |||||||||||||||||
Partners capital
|
1,281,917 | 2,612 | 2,167,780 | (2,170,392 | ) | 1,281,917 | ||||||||||||||||
Total liabilities and partners capital
|
$ | 3,156,331 | $ | 4,430 | $ | 3,286,842 | $ | (3,083,587 | ) | $ | 3,364,016 | |||||||||||
32
Condensed Consolidating Balance Sheets
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
|
| 113 | 106,157 | | 106,270 | ||||||||||||||||||
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 | ||||||||||||||||||
Investment in unconsolidated affiliates
|
| | 175,747 | | 175,747 | ||||||||||||||||||
Investment 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 | $ | 129,241 | $ | | $ | 129,263 | |||||||||||||
Affiliates
|
10,691 | 3,499 | 767,988 | (743,308 | ) | 38,870 | |||||||||||||||||
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 loan, 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 | ||||||||||||
33
Condensed Consolidating Statements of Cash Flows
Non-guarantor | Guarantor | Consolidating | Consolidated | |||||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Total | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Cash flows from operating activities
|
||||||||||||||||||||||||
Net income
|
$ | 55,566 | $ | 60 | $ | 65,773 | $ | (65,833 | ) | $ | 55,566 | |||||||||||||
Adjustments to reconcile net income to net cash
provided by operating activities
|
||||||||||||||||||||||||
Depreciation, depletion and amortization
|
36 | | 26,187 | | 26,223 | |||||||||||||||||||
Distributed earnings of unconsolidated affiliates
|
||||||||||||||||||||||||
Earnings from unconsolidated affiliates
|
| 30 | (2,238 | ) | | (2,208 | ) | |||||||||||||||||
Distributions from unconsolidated affiliates
|
| | 750 | | 750 | |||||||||||||||||||
Gain on sale of long-lived assets
|
| | (24 | ) | | (24 | ) | |||||||||||||||||
Amortization of debt issuance costs
|
1,358 | | | | 1,358 | |||||||||||||||||||
Other noncash items
|
604 | 24 | 2,408 | | 3,036 | |||||||||||||||||||
Working capital changes, net of effects of
acquisitions and noncash transactions
|
22,518 | (61 | ) | (43,698 | ) | | (21,241 | ) | ||||||||||||||||
Net cash provided by operating activities
|
80,082 | 53 | 49,158 | (65,833 | ) | 63,460 | ||||||||||||||||||
Cash flows from investing activities
|
||||||||||||||||||||||||
Additions to property, plant and equipment
|
(505 | ) | | (47,328 | ) | | (47,833 | ) | ||||||||||||||||
Proceeds from sale and retirement of assets
|
| | 93 | | 93 | |||||||||||||||||||
Additions to investments in unconsolidated
affiliates
|
| | (5,800 | ) | | (5,800 | ) | |||||||||||||||||
Net cash used in investing activities
|
(505 | ) | | (53,035 | ) | | (53,540 | ) | ||||||||||||||||
Cash flows from financing activities
|
||||||||||||||||||||||||
Net proceeds from revolving credit facility
|
44,933 | | | | 44,933 | |||||||||||||||||||
Repayments of revolving credit facility
|
(40,000 | ) | | | | (40,000 | ) | |||||||||||||||||
Net proceeds from senior secured term loan
|
(57 | ) | | | | (57 | ) | |||||||||||||||||
Net proceeds from issuance of long-term debt
|
(30 | ) | | | | (30 | ) | |||||||||||||||||
Net proceeds from issuance of common units
|
48,274 | | | | 48,274 | |||||||||||||||||||
Advances with affiliates
|
(69,657 | ) | (53 | ) | 3,877 | 65,833 | | |||||||||||||||||
Distributions to partners
|
(70,529 | ) | | | | (70,529 | ) | |||||||||||||||||
Contribution from general partner
|
321 | | | | 321 | |||||||||||||||||||
Net cash provided by (used in) financing
activities
|
(86,745 | ) | (53 | ) | 3,877 | 65,833 | (17,088 | ) | ||||||||||||||||
Decrease in cash and cash equivalents
|
$ | (7,168 | ) | $ | | $ | | $ | | (7,168 | ) | |||||||||||||
Cash and cash equivalents at beginning of period
|
30,425 | |||||||||||||||||||||||
Cash and cash equivalents at end of period
|
$ | 23,257 | ||||||||||||||||||||||
34
Condensed Consolidating Statements of Cash Flows
Non-guarantor | Guarantor | Consolidating | Consolidated | |||||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Total | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Cash flows from operating activities
|
||||||||||||||||||||||||
Net income
|
$ | 42,215 | $ | 160 | $ | 61,345 | $ | (61,505 | ) | $ | 42,215 | |||||||||||||
Less cumulative effect of accounting change
|
| | 1,690 | | 1,690 | |||||||||||||||||||
Income before cumulative effect of accounting
change
|
42,215 | 160 | 59,655 | (61,505 | ) | 40,525 | ||||||||||||||||||
Adjustments to reconcile net income to net cash
provided by operating activities
|
||||||||||||||||||||||||
Depreciation, depletion and amortization
|
37 | 10 | 23,650 | | 23,697 | |||||||||||||||||||
Distributed earnings of unconsolidated affiliates
|
||||||||||||||||||||||||
Earnings from unconsolidated affiliates
|
| | (3,316 | ) | | (3,316 | ) | |||||||||||||||||
Distributions from unconsolidated affiliates
|
| | 4,710 | | 4,710 | |||||||||||||||||||
Gain on sale of long-lived assets
|
| | (106 | ) | | (106 | ) | |||||||||||||||||
Loss due to write-off of unamortized debt
issuance costs
|
3,762 | | | | 3,762 | |||||||||||||||||||
Amortization of debt issuance costs
|
1,938 | | 154 | | 2,092 | |||||||||||||||||||
Other noncash items
|
270 | 33 | 220 | | 523 | |||||||||||||||||||
Working capital changes, net of effects of
acquisitions and noncash transactions
|
17,888 | (170 | ) | (18,161 | ) | | (443 | ) | ||||||||||||||||
Net cash provided by operating activities
|
66,110 | 33 | 66,806 | (61,505 | ) | 71,444 | ||||||||||||||||||
Cash flows from investing activities
|
||||||||||||||||||||||||
Additions to property, plant and equipment
|
(309 | ) | | (81,628 | ) | | (81,937 | ) | ||||||||||||||||
Proceeds from sale and retirement of assets
|
| | 3,088 | | 3,088 | |||||||||||||||||||
Additions to investments in unconsolidated
affiliates
|
| (133 | ) | | | (133 | ) | |||||||||||||||||
Net cash used in investing activities
|
(309 | ) | (133 | ) | (78,540 | ) | | (78,982 | ) | |||||||||||||||
Cash flows from financing activities
|
||||||||||||||||||||||||
Net proceeds from revolving credit facility
|
98,991 | | | | 98,991 | |||||||||||||||||||
Repayments of revolving credit facility
|
(119,000 | ) | | | | (119,000 | ) | |||||||||||||||||
Repayment of senior secured acquisition term loan
|
(237,500 | ) | | | | (237,500 | ) | |||||||||||||||||
Net proceeds from issuance of long-term debt
|
293,277 | | | | 293,277 | |||||||||||||||||||
Advances with affiliates
|
(63,775 | ) | 100 | 2,170 | 61,505 | | ||||||||||||||||||
Distributions to partners
|
(52,080 | ) | | | | (52,080 | ) | |||||||||||||||||
Net cash provided by (used in) financing
activities
|
(80,087 | ) | 100 | 2,170 | 61,505 | (16,312 | ) | |||||||||||||||||
Decrease in cash and cash equivalents
|
$ | (14,286 | ) | $ | | $ | (9,564 | ) | $ | | (23,850 | ) | ||||||||||||
Cash and cash equivalents at beginning of period
|
36,099 | |||||||||||||||||||||||
Cash and cash equivalents at end of period
|
$ | 12,249 | ||||||||||||||||||||||
35
ENTERPRISE PRODUCTS PARTNERS L.P.
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
For the Three Months Ended March 31, 2004
36
INDEX TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Enterprise Products Partners L.P. Unaudited Pro Forma Consolidated Financial Statements:
Introduction
|
F-2 | |||
Unaudited Pro Forma Condensed Statement of
Consolidated Operations for the three months ended
March 31, 2004
|
F-4 | |||
Unaudited Pro Forma Condensed Statement of
Consolidated Operations for the year ended December 31, 2003
|
F-6 | |||
Unaudited Pro Forma Condensed Consolidated
Balance Sheet at March 31, 2004
|
F-8 | |||
Notes to Unaudited Pro Forma Condensed
Consolidated Financial Statements
|
F-10 | |||
Pro Forma Sensitivity Analysis
|
F-20 |
F-1
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Introduction
The following unaudited pro forma condensed consolidated financial statements have been prepared to assist in the analysis of financial effects of the proposed merger between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. announced on December 15, 2003. The unaudited pro forma condensed statements of consolidated operations for the three months ended March 31, 2004 and the year ended December 31, 2003 assume the merger-related transactions (as described beginning on page F-10) all occurred on January 1 of each period presented. The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the merger-related transactions as if they had occurred on March 31, 2004 (to the extent not already recorded). In addition, these pro forma financial statements give effect to (i) Enterprises sale of 17,250,000 common units (including the over-allotment of 2,250,000 common units) in May 2004; (ii) the issuance of 1,757,347 Enterprise common units pursuant to its DRIP in May 2004; and (iii) the conversion of Enterprises 4,413,549 Class B special units into an equal number of its common units on July 29, 2004. These adjustments are found under the column labeled Adjustments Due to Other Recent Events. These pro forma financial statements also reflect Enterprises sale of 13,750,000 common units in this offering.
The unaudited pro forma condensed consolidated financial statements are based on assumptions that Enterprise and GulfTerra believe are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results of the combined company. Please read Pro Forma Sensitivity Analysis beginning on page F-20 for assumptions related to variable interest rates, fair value estimates and long-term financing scenarios.
Unless the context requires otherwise, references to Enterprise are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. References to GulfTerra are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to El Paso Corporation are intended to mean El Paso Corporation, its subsidiaries and affiliates (other than GulfTerra). El Paso Corporation was the majority owner of GulfTerras general partner prior to December 15, 2003 and owns a limited partner interest in GulfTerra.
The unaudited pro forma condensed consolidated financial statements of Enterprise should be read in conjunction with and are qualified in their entirety by reference to the notes accompanying such unaudited pro forma condensed consolidated financial statements and with the historical consolidated financial statements and related notes of Enterprise included in its Annual Report on Form 10-K for the year ended December 31, 2003 and Quarterly Report on Form 10-Q for the three months ended March 31, 2004. The condensed consolidated financial statements of GulfTerra included herein are qualified in their entirety by reference to the historical consolidated financial statements and related notes of GulfTerra included in its Annual Report on Form 10-K and 10-K/A for the year ended December 31, 2003 and Quarterly Report on Form 10-Q for the three months ended March 31, 2004. The combined financial statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (collectively, the South Texas midstream assets) included herein are qualified in their entirety by reference to the historical combined financial statements and related notes of the South Texas midstream assets included in Enterprises Current Reports on Form 8-K filed with the Commission on April 16, 2004 and June 16, 2004 and incorporated by reference into this document.
F-2
The pending merger-related transactions will be accounted for using the purchase method of accounting. For purposes of this pro forma financial information, goodwill represents potential intangible assets, excess of fair values over GulfTerras historical carrying values of tangible assets, and remaining goodwill, if any. The estimates of fair value of the acquired assets and liabilities are based on preliminary assumptions which will be updated and will change from the amounts shown. Such changes could impact amounts allocated to goodwill, intangible assets and other balance sheet accounts.
The unaudited pro forma condensed consolidated financial statements do not give effect to any divestiture of assets that may be required for governmental approval of the proposed merger.
F-3
ENTERPRISE PRODUCTS PARTNERS
UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS
South Texas | Step Three | ||||||||||||||||||||||||||||
Step Two | Midstream | Enterprise | |||||||||||||||||||||||||||
Enterprise | GulfTerra | Step Two | Enterprise | Assets | Step Three | Pro Forma | |||||||||||||||||||||||
Historical | Historical | Adjustments | Pro Forma | Historical | Adjustments | (to Part 2) | |||||||||||||||||||||||
(Amount in millions, except per unit amounts) | |||||||||||||||||||||||||||||
REVENUES
|
$ | 1,704.9 | $ | 220.3 | $ | (0.2 | )(m) | $ | 1,925.0 | $ | 376.0 | $ | (26.5 | )(r) | $ | 2,120.6 | |||||||||||||
(153.9 | )(t) | ||||||||||||||||||||||||||||
COSTS AND EXPENSES
|
|||||||||||||||||||||||||||||
Operating costs and expenses
|
1,621.5 | 139.1 | (0.2 | )(m) | 1,745.2 | 366.2 | (1.6 | )(s) | 1,928.3 | ||||||||||||||||||||
(15.2 | )(n) | (26.5 | )(r) | ||||||||||||||||||||||||||
(152.7 | )(t) | ||||||||||||||||||||||||||||
(2.3 | )(u) | ||||||||||||||||||||||||||||
Selling, general and administrative
|
9.5 | 11.1 | (n) | 20.6 | 2.3 | (u) | 22.9 | ||||||||||||||||||||||
Total
|
1,631.0 | 139.1 | (4.3 | ) | 1,765.8 | 366.2 | (180.8 | ) | 1,951.2 | ||||||||||||||||||||
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED
AFFILIATES
|
13.4 | (10.6 | )(h) | 5.0 | 5.0 | ||||||||||||||||||||||||
2.2 | (n) | ||||||||||||||||||||||||||||
OPERATING INCOME
|
87.3 | 81.2 | (4.3 | ) | 164.2 | 9.8 | 0.4 | 174.4 | |||||||||||||||||||||
OTHER INCOME (EXPENSE)
|
|||||||||||||||||||||||||||||
Interest expense
|
(32.6 | ) | (28.0 | ) | 2.2 | (i) | (61.1 | ) | (0.9 | )(p) | (62.0 | ) | |||||||||||||||||
(2.7 | )(j) | ||||||||||||||||||||||||||||
Earnings from unconsolidated affiliates
|
2.2 | (2.2 | )(n) | ||||||||||||||||||||||||||
Other, net
|
1.4 | 0.2 | 0.2 | (l) | 1.8 | (0.1 | ) | 1.7 | |||||||||||||||||||||
Total
|
(31.2 | ) | (25.6 | ) | (2.5 | ) | (59.3 | ) | (0.1 | ) | (0.9 | ) | (60.3 | ) | |||||||||||||||
INCOME BEFORE PROVISION FOR INCOME TAXES AND
MINORITY INTEREST
|
56.1 | 55.6 | (6.8 | ) | 104.9 | 9.7 | (0.5 | ) | 114.1 | ||||||||||||||||||||
PROVISION FOR INCOME TAXES
|
(1.6 | ) | (1.6 | ) | (1.6 | ) | |||||||||||||||||||||||
INCOME BEFORE MINORITY INTEREST
|
54.5 | 55.6 | (6.8 | ) | 103.3 | 9.7 | (0.5 | ) | 112.5 | ||||||||||||||||||||
MINORITY INTEREST
|
(3.0 | ) | (3.0 | ) | (3.0 | ) | |||||||||||||||||||||||
INCOME FROM CONTINUING OPERATIONS
|
$ | 51.5 | $ | 55.6 | $ | (6.8 | ) | $ | 100.3 | $ | 9.7 | $ | (0.5 | ) | $ | 109.5 | |||||||||||||
ALLOCATION OF INCOME FROM CONTINUING
OPERATIONS:
|
|||||||||||||||||||||||||||||
Limited Partners
|
$ | 44.3 | $ | 98.2 | |||||||||||||||||||||||||
General Partner
|
$ | 7.2 | $ | 11.3 | |||||||||||||||||||||||||
BASIC EARNINGS PER UNIT:
|
|||||||||||||||||||||||||||||
Number of units used in denominator
|
218.5 | 105.1 | (f) | 323.6 | |||||||||||||||||||||||||
Income from continuing operations
|
$ | 0.21 | $ | 0.30 | |||||||||||||||||||||||||
DILUTED EARNINGS PER UNIT:
|
|||||||||||||||||||||||||||||
Number of units used in denominator
|
219.0 | 105.1 | (f) | 324.1 | |||||||||||||||||||||||||
Income from continuing operations
|
$ | 0.20 | $ | 0.30 | |||||||||||||||||||||||||
F-4
ENTERPRISE PRODUCTS PARTNERS
UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS
Adjustments | |||||||||||||||||||||
Step Three | Due to | Adjustments | Further | ||||||||||||||||||
Enterprise | Other | Adjusted | Due to | Adjusted | |||||||||||||||||
Pro Forma | Recent | Enterprise | This | Enterprise | |||||||||||||||||
(from Part 1) | Events | Pro Forma | Offering | Pro Forma | |||||||||||||||||
(Amount in millions, except per unit amounts) | |||||||||||||||||||||
REVENUES
|
$ | 2,120.6 | $ | 2,120.6 | $ | 2,120.6 | |||||||||||||||
COSTS AND EXPENSES
|
|||||||||||||||||||||
Operating costs and expenses
|
1,928.3 | 1,928.3 | 1,928.3 | ||||||||||||||||||
Selling, general and administrative
|
22.9 | 22.9 | 22.9 | ||||||||||||||||||
Total
|
1,951.2 | 1,951.2 | 1,951.2 | ||||||||||||||||||
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED
AFFILIATES
|
5.0 | 5.0 | 5.0 | ||||||||||||||||||
OPERATING INCOME
|
174.4 | 174.4 | 174.4 | ||||||||||||||||||
OTHER INCOME (EXPENSE)
|
|||||||||||||||||||||
Interest expense
|
(62.0 | ) | $ | 0.7 | (v) | (61.3 | ) | $ | 1.5 | (w) | (59.8 | ) | |||||||||
Other, net
|
1.7 | 1.7 | 1.7 | ||||||||||||||||||
Total
|
(60.3 | ) | 0.7 | (59.6 | ) | 1.5 | (58.1 | ) | |||||||||||||
INCOME BEFORE PROVISION FOR INCOME TAXES AND
MINORITY INTEREST
|
114.1 | 0.7 | 114.8 | 1.5 | 116.3 | ||||||||||||||||
PROVISION FOR INCOME TAXES
|
(1.6 | ) | (1.6 | ) | (1.6 | ) | |||||||||||||||
INCOME BEFORE MINORITY INTEREST
|
112.5 | 0.7 | 113.2 | 1.5 | 114.7 | ||||||||||||||||
MINORITY INTEREST
|
(3.0 | ) | (3.0 | ) | (3.0 | ) | |||||||||||||||
INCOME FROM CONTINUING OPERATIONS
|
$ | 109.5 | $ | 0.7 | $ | 110.2 | $ | 1.5 | $ | 111.7 | |||||||||||
ALLOCATION OF INCOME FROM CONTINUING
OPERATIONS:
|
|||||||||||||||||||||
Limited Partners
|
$ | 98.2 | $ | 99.5 | |||||||||||||||||
General Partner
|
11.3 | $ | 12.2 | ||||||||||||||||||
BASIC EARNINGS PER UNIT:
|
|||||||||||||||||||||
Number of units used in denominator
|
323.6 | 19.0 | (v) | 13.8 | (w) | 356.4 | |||||||||||||||
Income from continuing operations
|
$ | 0.30 | $ | 0.28 | |||||||||||||||||
DILUTED EARNINGS PER UNIT:
|
|||||||||||||||||||||
Number of units used in denominator
|
324.1 | 19.0 | (v) | 13.8 | (w) | 356.9 | |||||||||||||||
Income from continuing operations
|
0.30 | $ | 0.28 | ||||||||||||||||||
F-5
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS
Step Two | ||||||||||||||||||||||||||
Step One | Enterprise | |||||||||||||||||||||||||
Enterprise | Step One | Enterprise | GulfTerra | Step Two | Pro Forma | |||||||||||||||||||||
Historical | Adjustments | Pro Forma | Historical | Adjustments | (to Part 2) | |||||||||||||||||||||
(Amounts in millions, except per unit amounts) | ||||||||||||||||||||||||||
REVENUES
|
$ | 5,346.4 | $ | 5,346.4 | $ | 871.5 | $ | (26.8 | )(m) | $ | 6,191.1 | |||||||||||||||
COSTS AND EXPENSES
|
||||||||||||||||||||||||||
Operating costs and expenses
|
5,046.8 | 5,046.8 | 557.0 | (26.8 | )(m) | 5,528.2 | ||||||||||||||||||||
(48.8 | )(n) | |||||||||||||||||||||||||
Selling, general and administrative
|
37.5 | 37.5 | 48.8 | (n) | 86.3 | |||||||||||||||||||||
Total
|
5,084.3 | 5,084.3 | 557.0 | (26.8 | ) | 5,614.5 | ||||||||||||||||||||
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED
AFFILIATES
|
(14.0 | ) | $ | 34.7 | (b) | 20.7 | 11.4 | (n) | (2.6 | ) | ||||||||||||||||
(34.7 | )(h) | |||||||||||||||||||||||||
OPERATING INCOME
|
248.1 | 34.7 | 282.8 | 314.5 | (23.3 | ) | 574.0 | |||||||||||||||||||
OTHER INCOME (EXPENSE)
|
||||||||||||||||||||||||||
Interest expense
|
(140.8 | ) | (8.7 | )(c) | (149.5 | ) | (127.8 | ) | 9.0 | (i) | (279.0 | ) | ||||||||||||||
(10.7 | )(j) | |||||||||||||||||||||||||
Loss due to early redemptions of debt
|
(36.9 | ) | (36.9 | ) | ||||||||||||||||||||||
Earnings from unconsolidated affiliates
|
11.4 | (11.4 | )(n) | |||||||||||||||||||||||
Other, net
|
6.4 | 6.4 | 1.1 | 0.8 | (l) | 8.3 | ||||||||||||||||||||
Total
|
(134.4 | ) | (8.7 | ) | (143.1 | ) | (152.2 | ) | (12.3 | ) | (307.6 | ) | ||||||||||||||
INCOME BEFORE PROVISION FOR INCOME TAXES AND
MINORITY INTEREST
|
113.7 | 26.0 | 139.7 | 162.3 | (35.6 | ) | 266.4 | |||||||||||||||||||
PROVISION FOR INCOME TAXES
|
(5.3 | ) | (5.3 | ) | (5.3 | ) | ||||||||||||||||||||
INCOME BEFORE MINORITY INTEREST
|
108.4 | 26.0 | 134.4 | 162.3 | (35.6 | ) | 261.1 | |||||||||||||||||||
MINORITY INTEREST
|
(3.9 | ) | 0.9 | (a) | (3.0 | ) | (0.9 | ) | (3.9 | ) | ||||||||||||||||
INCOME FROM CONTINUING OPERATIONS
|
$ | 104.5 | $ | 26.9 | $ | 131.4 | $ | 161.4 | $ | (35.6 | ) | $ | 257.2 | |||||||||||||
ALLOCATION OF INCOME FROM CONTINUING
OPERATIONS:
|
||||||||||||||||||||||||||
Limited Partners
|
$ | 83.8 | $ | 222.3 | ||||||||||||||||||||||
General Partner
|
$ | 20.7 | $ | 34.9 | ||||||||||||||||||||||
BASIC EARNINGS PER UNIT:
|
||||||||||||||||||||||||||
Number of units used in denominator
|
199.9 | 105.1 | (f) | 305.0 | ||||||||||||||||||||||
Income from continuing operations
|
$ | 0.42 | $ | 0.73 | ||||||||||||||||||||||
DILUTED EARNINGS PER UNIT:
|
||||||||||||||||||||||||||
Number of units used in denominator
|
206.4 | 105.1 | (f) | 311.5 | ||||||||||||||||||||||
Income from continuing operations
|
$ | 0.41 | $ | 0.71 | ||||||||||||||||||||||
The accompanying notes are an integral part of these unaudited pro forma
F-6
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS
Adjustments | ||||||||||||||||||||||||||||||||||
Step Two | South Texas | Due to | Adjustments | Further | ||||||||||||||||||||||||||||||
Enterprise | Midstream | Step Three | Other | Adjusted | Due to | Adjusted | ||||||||||||||||||||||||||||
Pro Forma | Assets | Step Three | Enterprise | Recent | Enterprise | This | Enterprise | |||||||||||||||||||||||||||
(from Part 1) | Historical | Adjustments | Pro Forma | Events | Pro Forma | Offering | Pro Forma | |||||||||||||||||||||||||||
(Amounts in millions, except per unit amounts) | ||||||||||||||||||||||||||||||||||
REVENUES
|
$ | 6,191.1 | $ | 1,430.7 | $ | (36.9 | )(r) | $ | 7,153.0 | $ | 7,153.0 | $ | 7,153.0 | |||||||||||||||||||||
(431.9 | )(t) | |||||||||||||||||||||||||||||||||
COSTS AND EXPENSES
|
||||||||||||||||||||||||||||||||||
Operating costs and expenses
|
5,528.2 | 1,423.2 | (36.9 | )(r) | 6,474.1 | 6,474.1 | 6,474.1 | |||||||||||||||||||||||||||
(6.0 | )(s) | |||||||||||||||||||||||||||||||||
(427.2 | )(t) | |||||||||||||||||||||||||||||||||
(7.2 | )(u) | |||||||||||||||||||||||||||||||||
Selling, general and administrative
|
86.3 | 7.2 | (u) | 93.5 | 93.5 | 93.5 | ||||||||||||||||||||||||||||
Total
|
5,614.5 | 1,423.2 | (470.1 | ) | 6,567.6 | 6,567.6 | 6,567.6 | |||||||||||||||||||||||||||
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED
AFFILIATES
|
(2.6 | ) | (2.6 | ) | (2.6 | ) | (2.6 | ) | ||||||||||||||||||||||||||
OPERATING INCOME
|
574.0 | 7.5 | 1.3 | 582.8 | 582.8 | 582.8 | ||||||||||||||||||||||||||||
OTHER INCOME (EXPENSE)
|
||||||||||||||||||||||||||||||||||
Interest expense
|
(279.0 | ) | (3.6 | )(p) | (282.6 | ) | $ | 5.8 | (v) | (276.8 | ) | $ | 6.0 | (w) | (270.8 | ) | ||||||||||||||||||
Loss due to early redemptions of debt
|
(36.9 | ) | (36.9 | ) | (36.9 | ) | (36.9 | ) | ||||||||||||||||||||||||||
Other, net
|
8.3 | 0.1 | 8.4 | 8.4 | 8.4 | |||||||||||||||||||||||||||||
Total
|
(307.6 | ) | 0.1 | (3.6 | ) | (311.1 | ) | 5.8 | (305.3 | ) | 6.0 | (299.3 | ) | |||||||||||||||||||||
INCOME BEFORE PROVISION FOR INCOME TAXES AND
MINORITY INTEREST
|
266.4 | 7.6 | (2.3 | ) | 271.7 | 5.8 | 277.5 | 6.0 | 283.5 | |||||||||||||||||||||||||
PROVISION FOR INCOME TAXES
|
(5.3 | ) | (5.3 | ) | (5.3 | ) | (5.3 | ) | ||||||||||||||||||||||||||
INCOME BEFORE MINORITY INTEREST
|
261.1 | 7.6 | (2.3 | ) | 266.4 | 5.8 | 272.2 | 6.0 | 278.2 | |||||||||||||||||||||||||
MINORITY INTEREST
|
(3.9 | ) | (3.9 | ) | (3.9 | ) | (3.9 | ) | ||||||||||||||||||||||||||
INCOME FROM CONTINUING OPERATIONS
|
$ | 257.2 | $ | 7.6 | $ | (2.3 | ) | $ | 262.5 | $ | 5.8 | $ | 268.3 | $ | 6.0 | $ | 274.3 | |||||||||||||||||
ALLOCATION OF INCOME FROM CONTINUING
OPERATIONS:
|
||||||||||||||||||||||||||||||||||
Limited Partners
|
$ | 222.3 | $ | 236.0 | ||||||||||||||||||||||||||||||
General Partner
|
$ | 34.9 | $ | 38.3 | ||||||||||||||||||||||||||||||
BASIC EARNINGS PER UNIT:
|
||||||||||||||||||||||||||||||||||
Number of units used in denominator
|
305.0 | 19.0 | (v) | 13.8 | (w) | 337.8 | ||||||||||||||||||||||||||||
Income from continuing operations
|
$ | 0.73 | $ | 0.70 | ||||||||||||||||||||||||||||||
DILUTED EARNINGS PER UNIT:
|
||||||||||||||||||||||||||||||||||
Number of units used in denominator
|
311.5 | 19.0 | (v) | 13.8 | (w) | 344.3 | ||||||||||||||||||||||||||||
Income from continuing operations
|
$ | 0.71 | $ | 0.69 | ||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these unaudited pro forma
F-7
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
South | |||||||||||||||||||||||||||||||
Texas | Step Three | ||||||||||||||||||||||||||||||
Step Two | Midstream | Enterprise | |||||||||||||||||||||||||||||
Enterprise | GulfTerra | Step Two | Enterprise | Assets | Step Three | Pro Forma | |||||||||||||||||||||||||
Historical | Historical | Adjustments | Pro Forma | Historical | Adjustments | (to Part 2) | |||||||||||||||||||||||||
(Amounts in millions) | |||||||||||||||||||||||||||||||
ASSETS | |||||||||||||||||||||||||||||||
Current Assets
|
|||||||||||||||||||||||||||||||
Cash and cash equivalents
|
$ | 52.8 | $ | 23.3 | $ | 31.1 | (d) | $ | 85.1 | $ | 169.9 | (o) | $ | 85.1 | |||||||||||||||||
500.0 | (e) | (169.9 | )(o) | ||||||||||||||||||||||||||||
(500.0 | )(e) | ||||||||||||||||||||||||||||||
9.8 | (e) | ||||||||||||||||||||||||||||||
(31.9 | )(k) | ||||||||||||||||||||||||||||||
Accounts and notes receivable, net
|
408.6 | 170.1 | 17.2 | (l) | 595.7 | $ | 156.4 | (156.4 | )(t) | 595.7 | |||||||||||||||||||||
(0.2 | )(m) | ||||||||||||||||||||||||||||||
Inventories
|
168.3 | 168.3 | 19.9 | 188.2 | |||||||||||||||||||||||||||
Other current assets
|
56.0 | 23.5 | (3.7 | )(i) | 75.8 | 4.0 | (4.0 | )(t) | 75.8 | ||||||||||||||||||||||
Total Current Assets
|
685.7 | 216.9 | 22.3 | 924.9 | 180.3 | (160.4 | ) | 944.8 | |||||||||||||||||||||||
Property, plant and equipment, net
|
2,951.6 | 2,916.5 | 5,868.1 | 313.6 | (161.5 | )(s) | 6,020.2 | ||||||||||||||||||||||||
Investments in and Advances to Unconsolidated
Affiliates
|
766.3 | 190.7 | (425.0 | )(h) | 532.0 | 532.0 | |||||||||||||||||||||||||
Intangible Assets, net
|
265.1 | 3.3 | 268.4 | 268.4 | |||||||||||||||||||||||||||
Goodwill
|
82.4 | 2,601.1 | (i) | 2,683.5 | 2,683.5 | ||||||||||||||||||||||||||
Other Assets
|
31.2 | 36.6 | 23.1 | (l) | 90.9 | 90.9 | |||||||||||||||||||||||||
Total Assets
|
$ | 4,782.3 | $ | 3,364.0 | $ | 2,221.5 | $ | 10,367.8 | $ | 493.9 | $ | (321.9 | ) | $ | 10,539.8 | ||||||||||||||||
LIABILITIES & COMBINED EQUITY | |||||||||||||||||||||||||||||||
Current Liabilities
|
|||||||||||||||||||||||||||||||
Current maturities of debt
|
$ | 15.0 | $ | 3.0 | $ | 500.0 | (e) | $ | 518.0 | $ | 169.9 | (o) | $ | 687.9 | |||||||||||||||||
Accounts payable
|
83.7 | 139.8 | 223.5 | $ | 166.4 | (166.4 | )(t) | 223.5 | |||||||||||||||||||||||
Accrued gas payables and other expenses
|
618.7 | 34.0 | (0.2 | )(m) | 652.5 | 25.5 | (25.5 | )(t) | 652.5 | ||||||||||||||||||||||
Other current liabilities
|
50.6 | 40.7 | 91.3 | 1.2 | (1.2 | )(t) | 91.3 | ||||||||||||||||||||||||
Total Current Liabilities
|
768.0 | 217.5 | 499.8 | 1,485.3 | 193.1 | (23.2 | ) | 1,655.2 | |||||||||||||||||||||||
Long-Term Debt
|
2,195.9 | 1,821.2 | 84.9 | (i) | 4,102.0 | 4,102.0 | |||||||||||||||||||||||||
Other Long-Term Liabilities
|
9.0 | 41.6 | 50.6 | 2.1 | 52.7 | ||||||||||||||||||||||||||
Minority Interest
|
88.5 | 1.8 | 90.3 | 90.3 | |||||||||||||||||||||||||||
Commitments and Contingencies
|
|||||||||||||||||||||||||||||||
Combined Equity
|
|||||||||||||||||||||||||||||||
Limited Partners
|
|||||||||||||||||||||||||||||||
Common Units
|
1,576.6 | 930.3 | 30.8 | (d) | 4,401.4 | 4,401.4 | |||||||||||||||||||||||||
2,378.3 | (e) | ||||||||||||||||||||||||||||||
(970.8 | )(e) | ||||||||||||||||||||||||||||||
9.7 | (e) | ||||||||||||||||||||||||||||||
446.5 | (g) | ||||||||||||||||||||||||||||||
Class B special units
|
99.6 | 30.0 | (e) | 135.1 | 135.1 | ||||||||||||||||||||||||||
5.5 | (g) | ||||||||||||||||||||||||||||||
Series C Units
|
338.3 | (338.3 | )(e) | ||||||||||||||||||||||||||||
General Partner
|
34.2 | 13.3 | 0.3 | (d) | 92.6 | 92.6 | |||||||||||||||||||||||||
49.1 | (e) | ||||||||||||||||||||||||||||||
0.1 | (e) | ||||||||||||||||||||||||||||||
9.3 | (g) | ||||||||||||||||||||||||||||||
(13.7 | )(h) | ||||||||||||||||||||||||||||||
Treasury Units
|
(11.4 | ) | (11.4 | ) | (11.4 | ) | |||||||||||||||||||||||||
Owners net investment
|
298.7 | (331.4 | )(q) | ||||||||||||||||||||||||||||
32.7 | (t) | ||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income
|
21.9 | 21.9 | 21.9 | ||||||||||||||||||||||||||||
Total Combined Equity
|
1,720.9 | 1,281.9 | 1,636.8 | 4,639.6 | 298.7 | (298.7 | ) | 4,639.6 | |||||||||||||||||||||||
Total Liabilities & Combined Equity
|
$ | 4,782.3 | $ | 3,364.0 | $ | 2,221.5 | $ | 10,367.8 | $ | 493.9 | $ | (321.9 | ) | $ | 10,539.8 | ||||||||||||||||
The accompanying notes are an integral part of these unaudited pro forma
F-8
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
Adjustments | |||||||||||||||||||||||
Step Three | Due to | Adjustments | Further | ||||||||||||||||||||
Enterprise | Other | Adjusted | Due to | Adjusted | |||||||||||||||||||
Pro Forma | Recent | Enterprise | This | Enterprise | |||||||||||||||||||
(from Part 1) | Events | Pro Forma | Offering | Pro Forma | |||||||||||||||||||
(Amounts in millions) | |||||||||||||||||||||||
ASSETS | |||||||||||||||||||||||
Current Assets
|
|||||||||||||||||||||||
Cash and cash equivalents
|
$ | 85.1 | $ | 404.7 | (v) | $ | 120.4 | $ | 293.3 | (w) | $ | 120.4 | |||||||||||
(16.3 | )(v) | (11.6 | )(w) | ||||||||||||||||||||
(353.1 | )(v) | (281.7 | )(w) | ||||||||||||||||||||
Accounts and notes receivable, net
|
595.7 | 595.7 | 595.7 | ||||||||||||||||||||
Inventories
|
188.2 | 188.2 | 188.2 | ||||||||||||||||||||
Other current assets
|
75.8 | (1.0 | )(v) | 74.8 | 74.8 | ||||||||||||||||||
Total Current Assets
|
944.8 | 34.3 | 979.1 | | 979.1 | ||||||||||||||||||
Property, plant and equipment, net
|
6,020.2 | 6,020.2 | 6,020.2 | ||||||||||||||||||||
Investments in and Advances to Unconsolidated
Affiliates
|
532.0 | 532.0 | 532.0 | ||||||||||||||||||||
Intangible Assets, net
|
268.4 | 268.4 | 268.4 | ||||||||||||||||||||
Goodwill
|
2,683.5 | 2,683.5 | 2,683.5 | ||||||||||||||||||||
Other Assets
|
90.9 | 90.9 | 90.9 | ||||||||||||||||||||
Total Assets
|
$ | 10,539.8 | $ | 34.3 | $ | 10,574.1 | $ | | $ | 10,574.1 | |||||||||||||
LIABILITIES & COMBINED EQUITY | |||||||||||||||||||||||
Current Liabilities
|
|||||||||||||||||||||||
Current maturities of debt
|
$ | 687.9 | $ | (353.1 | )(v) | $ | 334.8 | (281.7 | )(w) | $ | 53.1 | ||||||||||||
Accounts payable
|
223.5 | 223.5 | 223.5 | ||||||||||||||||||||
Accrued gas payables and other expenses
|
652.5 | 652.5 | 652.5 | ||||||||||||||||||||
Other current liabilities
|
91.3 | 91.3 | 91.3 | ||||||||||||||||||||
Total Current Liabilities
|
1,655.2 | (353.1 | ) | 1,302.1 | (281.7 | ) | 1,020.4 | ||||||||||||||||
Long-Term Debt
|
4,102.0 | 4,102.0 | 4,102.0 | ||||||||||||||||||||
Other Long-Term Liabilities
|
52.7 | 52.7 | 52.7 | ||||||||||||||||||||
Minority Interest
|
90.3 | 90.3 | 90.3 | ||||||||||||||||||||
Commitments and Contingencies
|
|||||||||||||||||||||||
Combined Equity
|
|||||||||||||||||||||||
Limited Partners
|
|||||||||||||||||||||||
Common Units
|
4,401.4 | 396.6 | (v) | 4,916.1 | 287.4 | (w) | 5,192.1 | ||||||||||||||||
(16.0 | )(v) | (11.4 | )(w) | ||||||||||||||||||||
(1.0 | )(v) | ||||||||||||||||||||||
135.1 | (x) | ||||||||||||||||||||||
Class B Special Units
|
135.1 | (135.1 | )(x) | ||||||||||||||||||||
General Partner
|
92.6 | 8.1 | (v) | 100.4 | 5.9 | (w) | 106.1 | ||||||||||||||||
(0.3 | )(v) | (0.2 | )(w) | ||||||||||||||||||||
Treasury Units
|
(11.4 | ) | (11.4 | ) | (11.4 | ) | |||||||||||||||||
Owners net investment
|
|||||||||||||||||||||||
Accumulated Other Comprehensive Income
|
21.9 | 21.9 | 21.9 | ||||||||||||||||||||
Total Combined Equity
|
4,639.6 | 387.4 |