UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2005
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File No.: 1-16335
Magellan Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 73-1599053 | |
(State or other jurisdiction of incorporation or organization) |
(IRS Employer Identification No.) |
One Williams Center, P.O. Box 22186, Tulsa, Oklahoma 74121-2186
(Address of principal executive offices and zip code)
(918) 574-7000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨
As of August 4, 2005, there were outstanding 60,680,928 common units and 5,679,696 subordinated units.
Page | ||||
PART I | ||||
FINANCIAL INFORMATION | ||||
ITEM 1. |
||||
Consolidated Statements of Income for the three and six months ended June 30, 2004 and 2005 |
2 | |||
Consolidated Balance Sheets as of December 31, 2004 and June 30, 2005 |
3 | |||
Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2005 |
4 | |||
5 | ||||
ITEM 2. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 17 | ||
ITEM 3. |
27 | |||
ITEM 4. |
28 | |||
29 | ||||
PART II | ||||
OTHER INFORMATION | ||||
ITEM 1. |
30 | |||
ITEM 2. |
31 | |||
ITEM 3. |
31 | |||
ITEM 4. |
31 | |||
ITEM 5. |
31 | |||
ITEM 6. |
31 |
Page 1
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
2004 |
2005 |
2004 |
2005 |
|||||||||||||
Transportation and terminals revenues |
$ | 103,536 | $ | 122,889 | $ | 192,466 | $ | 232,965 | ||||||||
Product sales revenues |
38,521 | 132,530 | 82,735 | 280,620 | ||||||||||||
Affiliate management fee revenue |
163 | 167 | 163 | 334 | ||||||||||||
Total revenues |
142,220 | 255,586 | 275,364 | 513,919 | ||||||||||||
Costs and expenses: |
||||||||||||||||
Operating |
42,911 | 51,800 | 79,911 | 96,055 | ||||||||||||
Environmental |
18,123 | 1,772 | 42,328 | 2,972 | ||||||||||||
Environmental reimbursements |
(17,909 | ) | — | (41,324 | ) | — | ||||||||||
Product purchases |
32,382 | 122,348 | 70,881 | 253,659 | ||||||||||||
Depreciation and amortization |
9,822 | 13,931 | 19,344 | 26,901 | ||||||||||||
Affiliate general and administrative |
13,507 | 15,134 | 26,394 | 30,260 | ||||||||||||
Total costs and expenses |
98,836 | 204,985 | 197,534 | 409,847 | ||||||||||||
Equity earnings |
148 | 804 | 268 | 1,322 | ||||||||||||
Operating profit |
43,532 | 51,405 | 78,098 | 105,394 | ||||||||||||
Interest expense |
8,704 | 12,864 | 17,219 | 25,282 | ||||||||||||
Interest income |
(1,000 | ) | (1,157 | ) | (1,446 | ) | (2,142 | ) | ||||||||
Debt prepayment premium |
12,666 | — | 12,666 | — | ||||||||||||
Write-off of unamortized debt placement fees |
5,002 | — | 5,002 | — | ||||||||||||
Debt placement fee amortization |
656 | 731 | 1,338 | 1,463 | ||||||||||||
Other income |
(953 | ) | (1 | ) | (953 | ) | (300 | ) | ||||||||
Net income |
$ | 18,457 | $ | 38,968 | $ | 44,272 | $ | 81,091 | ||||||||
Allocation of net income: |
||||||||||||||||
Limited partners’ interest |
$ | 17,465 | $ | 32,037 | $ | 41,339 | $ | 68,014 | ||||||||
General partner’s interest |
992 | 6,931 | 2,933 | 13,077 | ||||||||||||
Net income |
$ | 18,457 | $ | 38,968 | $ | 44,272 | $ | 81,091 | ||||||||
Basic net income per limited partner unit |
$ | 0.31 | $ | 0.48 | $ | 0.75 | $ | 1.02 | ||||||||
Weighted average number of limited partner units outstanding used for basic net income per unit calculation |
55,594 | 66,361 | 55,190 | 66,361 | ||||||||||||
Diluted net income per limited partner unit |
$ | 0.31 | $ | 0.48 | $ | 0.75 | $ | 1.02 | ||||||||
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation |
55,720 | 66,604 | 55,298 | 66,536 | ||||||||||||
See notes to consolidated financial statements.
Page 2
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, 2004 |
June 30, 2005 |
|||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 29,833 | $ | 98,940 | ||||
Restricted cash |
5,847 | 5,825 | ||||||
Marketable securities |
87,802 | — | ||||||
Accounts receivable (less allowance for doubtful accounts of $133 and $122 at December 31, 2004 and June 30, 2005, respectively) |
36,054 | 48,115 | ||||||
Other receivables |
19,786 | 17,119 | ||||||
Affiliate accounts receivable |
8,637 | 8,291 | ||||||
Inventory |
43,397 | 56,619 | ||||||
Other current assets |
6,385 | 10,615 | ||||||
Total current assets |
237,741 | 245,524 | ||||||
Property, plant and equipment, at cost |
1,956,884 | 2,011,064 | ||||||
Less: accumulated depreciation |
463,266 | 484,956 | ||||||
Net property, plant and equipment |
1,493,618 | 1,526,108 | ||||||
Equity investment |
25,084 | 25,106 | ||||||
Long-term affiliate receivables |
4,599 | 2,546 | ||||||
Long-term receivables |
8,070 | 7,596 | ||||||
Goodwill |
22,007 | 21,621 | ||||||
Other intangibles (less accumulated amortization of $2,211 and $2,859 at December 31, 2004 and June 30, 2005, respectively) |
10,118 | 9,470 | ||||||
Debt placement costs (less accumulated amortization of $4,040 and $5,502 at December 31, 2004 and June 30, 2005, respectively) |
10,954 | 9,491 | ||||||
Other noncurrent assets |
5,641 | 7,440 | ||||||
Total assets |
$ | 1,817,832 | $ | 1,854,902 | ||||
LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 20,394 | $ | 32,738 | ||||
Affiliate accounts payable |
497 | 5,184 | ||||||
Accrued interest payable |
9,860 | 9,658 | ||||||
Accrued taxes other than income |
16,632 | 15,703 | ||||||
Affiliate payroll and benefits |
19,275 | 11,616 | ||||||
Environmental liabilities |
33,160 | 33,276 | ||||||
Deferred revenue |
12,958 | 14,324 | ||||||
Accrued product purchases |
17,313 | 19,604 | ||||||
Accrued product shortage |
7,507 | — | ||||||
Current portion of long-term debt |
15,100 | 15,100 | ||||||
Other current liabilities |
13,308 | 12,077 | ||||||
Total current liabilities |
166,004 | 169,280 | ||||||
Long-term debt |
789,568 | 791,873 | ||||||
Long-term affiliate payable |
6,578 | 5,967 | ||||||
Long-term affiliate pension and benefits |
4,120 | 7,544 | ||||||
Other deferred liabilities |
34,807 | 58,532 | ||||||
Environmental liabilities |
27,646 | 24,414 | ||||||
Commitments and contingencies |
||||||||
Partners’ capital: |
||||||||
Partners’ capital |
791,031 | 799,108 | ||||||
Accumulated other comprehensive loss |
(1,922 | ) | (1,816 | ) | ||||
Total partners’ capital |
789,109 | 797,292 | ||||||
Total liabilities and partners’ capital |
$ | 1,817,832 | $ | 1,854,902 | ||||
See notes to consolidated financial statements.
Page 3
MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended June 30, |
||||||||
2004 |
2005 |
|||||||
Operating Activities: |
||||||||
Net income |
$ | 44,272 | $ | 81,091 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
19,344 | 26,901 | ||||||
Debt placement fee amortization |
1,338 | 1,463 | ||||||
Write-off of unamortized debt placement fees |
5,002 | — | ||||||
Loss on sale and retirement of assets |
1,746 | 2,101 | ||||||
Earnings in equity investment |
(268 | ) | (1,322 | ) | ||||
Distributions from equity investments |
— | 1,300 | ||||||
Debt prepayment premium |
12,666 | — | ||||||
Gain on derivative |
(953 | ) | — | |||||
Changes in components of operating assets and liabilities: |
||||||||
Restricted cash |
2,369 | 22 | ||||||
Accounts receivable and other receivables |
(34,081 | ) | (9,394 | ) | ||||
Affiliate accounts receivable |
859 | 346 | ||||||
Inventory |
2,581 | (13,222 | ) | |||||
Accounts payable |
(4,594 | ) | 12,344 | |||||
Affiliate accounts payable |
1,980 | 4,687 | ||||||
Accrued interest payable |
(1,255 | ) | (202 | ) | ||||
Accrued taxes other than income |
668 | (526 | ) | |||||
Affiliate payroll and benefits |
(4,603 | ) | (7,659 | ) | ||||
Accrued product purchases |
(5,010 | ) | 2,291 | |||||
Accrued product shortages |
— | (7,507 | ) | |||||
Current and noncurrent environmental liabilities |
33,927 | (3,270 | ) | |||||
Other current and noncurrent assets and liabilities |
(10,157 | ) | (678 | ) | ||||
Net cash provided by operating activities |
65,831 | 88,766 | ||||||
Investing Activities: |
||||||||
Purchases of marketable securities |
— | (50,500 | ) | |||||
Sales of marketable securities |
— | 138,302 | ||||||
Additions to property, plant and equipment |
(19,721 | ) | (34,507 | ) | ||||
Proceeds from sale of assets |
1,171 | 64 | ||||||
Acquisition of businesses |
(25,441 | ) | — | |||||
Equity investment |
(25,032 | ) | — | |||||
Acquisition prepayment |
(24,622 | ) | — | |||||
Net cash provided (used) by investing activities |
(93,645 | ) | 53,359 | |||||
Financing Activities: |
||||||||
Distributions paid |
(52,695 | ) | (74,109 | ) | ||||
Capital contributions by affiliate |
6,837 | 1,043 | ||||||
Payments on credit facility |
(90,000 | ) | — | |||||
Borrowings under long-term notes, net of discount |
249,485 | — | ||||||
Payments on long-term notes |
(178,000 | ) | — | |||||
Debt placement costs |
(6,055 | ) | — | |||||
Issuance of common units, net |
45,430 | — | ||||||
Payment of debt prepayment premium |
(12,666 | ) | — | |||||
Receipts on interest rate derivatives |
6,072 | — | ||||||
Other |
— | 48 | ||||||
Net cash used by financing activities |
(31,592 | ) | (73,018 | ) | ||||
Change in cash and cash equivalents |
(59,406 | ) | 69,107 | |||||
Cash and cash equivalents at beginning of period |
111,357 | 29,833 | ||||||
Cash and cash equivalents at end of period |
$ | 51,951 | $ | 98,940 | ||||
See notes to consolidated financial statements.
Page 4
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Basis of Presentation
Unless indicated otherwise, the terms “our”, “we”, “us” and similar language refer to Magellan Midstream Partners, L.P. together with our subsidiaries. We are a Delaware master limited partnership. Magellan GP, LLC, a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest. Magellan GP, LLC is a wholly-owned subsidiary of Magellan Midstream Holdings, L.P. (“MMH”), a Delaware limited partnership principally owned by Madison Dearborn Capital Partners IV, L.P. and Carlyle/Riverstone Global Energy and Power Fund II, L.P. Magellan GP, LLC has contracted with MMH to perform all management and operating functions required for our operations.
We operate and report in three business segments: the petroleum products pipeline system, the petroleum products terminals and the ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different business strategies.
In the opinion of management, the accompanying consolidated financial statements of Magellan Midstream Partners, L.P., which are unaudited except for the consolidated balance sheet as of December 31, 2004, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of June 30, 2005, and the results of operations and cash flows for the three and six-month periods ended June 30, 2005 and 2004. The results of operations for the three and six months ended June 30, 2005 are not necessarily indicative of the results to be expected for the full year ending December 31, 2005. Certain amounts in the financial statements for 2004 have been reclassified to conform to the current period’s presentation.
In March 2005, the board of directors of our general partner approved a two-for-one split of our units, effective April 12, 2005. According to the provisions of Financial Accounting Standards Board (“FASB”) Statement No. 128, “Earnings Per Share”, we have retroactively changed the number of our units and the net income and distribution per unit amounts to give effect for this two-for-one split for all periods presented in this report.
Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2004.
Page 5
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
2. Allocation of Net Income
The allocation of net income between our general partner and limited partners is as follows (in thousands):
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
2004 |
2005 |
2004 |
2005 |
|||||||||||||
Allocation of net income to General Partner: |
||||||||||||||||
Net income |
$ | 18,457 | $ | 38,968 | $ | 44,272 | $ | 81,091 | ||||||||
Charges/(income) direct to General Partner: |
||||||||||||||||
Transition charges |
195 | — | 823 | — | ||||||||||||
Reimbursable general and administrative costs |
2,425 | 601 | 3,562 | 1,644 | ||||||||||||
Previously indemnified environmental charges |
— | 163 | — | 624 | ||||||||||||
Depreciation charges associated with previously indemnified capital costs |
— | 8 | — | 13 | ||||||||||||
Other |
(562 | ) | — | (562 | ) | — | ||||||||||
Total direct charges to General Partner |
2,058 | 772 | 3,823 | 2,281 | ||||||||||||
Income before direct charges to General Partner |
20,515 | 39,740 | 48,095 | 83,372 | ||||||||||||
General Partner’s share of distributions |
14.87 | % | 19.39 | % | 14.05 | % | 18.42 | % | ||||||||
General Partner’s allocated share of net income before direct charges |
3,050 | 7,703 | 6,756 | 15,358 | ||||||||||||
Direct charges to General Partner |
2,058 | 772 | 3,823 | 2,281 | ||||||||||||
Net income allocated to General Partner |
$ | 992 | $ | 6,931 | $ | 2,933 | $ | 13,077 | ||||||||
Net income |
$ | 18,457 | $ | 38,968 | $ | 44,272 | $ | 81,091 | ||||||||
Less: net income allocated to General Partner |
992 | 6,931 | 2,933 | 13,077 | ||||||||||||
Net income allocated to limited partners |
$ | 17,465 | $ | 32,037 | $ | 41,339 | $ | 68,014 | ||||||||
On June 17, 2003, The Williams Companies, Inc. (“Williams”) sold all of the limited partner units it owned in us and its membership interests in our general partner to MMH. The transition charges shown above represent our costs for transitioning from Williams in excess of the amount we were contractually required to pay. We recorded these excess transition costs as a capital contribution by our general partner. Charges in excess of the general and administrative (“G&A”) expense cap (see Note 5—Related Party Transactions) were $2.4 million and $3.6 million for the three and six months ended June 30, 2004, respectively, and $0.6 million and $1.6 million for the three and six months ended June 30, 2005, respectively. These amounts represent G&A expenses charged against our income during each respective period for which we either have been or will be reimbursed by our general partner under the terms of the new omnibus agreement. Consequently, these amounts have been charged directly against our general partner’s allocation of net income. We record reimbursements when received from our general partner as a capital contribution. During 2004, we and our general partner entered into an agreement with Williams to settle Williams’ indemnification obligations to us (see Note 11—Commitments and Contingencies). Following this settlement, the expenses associated with these previously indemnified costs have been charged directly to our general partner. We believe we will collect the full amount of the indemnification settlement from Williams and accordingly will continue to allocate amounts associated with previously indemnified costs to our general partner.
3. Comprehensive Income
The difference between net income and comprehensive income is the result of net losses on interest rate swaps, gains on treasury locks and the amortization of gains/losses on derivative transactions. For information on gains/losses on interest rate swaps and treasury locks, see Note 10 – Derivative Financial Instruments. Comprehensive income is as follows (in thousands):
Three Months Ended June 30, |
Six Months Ended June 30, | |||||||||||
2004 |
2005 |
2004 |
2005 | |||||||||
Net income |
$ | 18,457 | $ | 38,968 | $ | 44,272 | $ | 81,091 | ||||
Gain on interest rate swaps |
6,606 | — | 3,212 | — | ||||||||
Gain on effective portion of treasury locks |
1,907 | — | 1,907 | — | ||||||||
Amortization of cash flow hedges |
7 | 50 | 57 | 103 | ||||||||
Other comprehensive income |
8,520 | 50 | 5,176 | 103 | ||||||||
Comprehensive income |
$ | 26,977 | $ | 39,018 | $ | 49,448 | $ | 81,194 | ||||
Page 6
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
4. Segment Disclosures
Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based upon segment operating margin, which includes revenues from affiliates and external customers, operating expenses, environmental expenses, environmental reimbursements, product purchases and equity earnings.
The non-generally accepted accounting principle measure of operating margin (in the aggregate and by segment) is presented in the following tables. The components of operating margin are computed by using amounts that are determined in accordance with generally accepted accounting principles (“GAAP”). A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables below. Management believes that investors benefit from having access to the same financial measures they use to evaluate performance. Operating margin is an important measure of the economic performance of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items, such as depreciation and amortization and G&A costs that management does not consider when evaluating the core profitability of an operation.
Three Months Ended June 30, 2004 |
||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Petroleum Products Pipeline System |
Petroleum Products Terminals |
Ammonia Pipeline System |
Inter- Eliminations |
Total |
||||||||||||||||
Transportation and terminals revenues |
$ | 77,726 | $ | 22,978 | $ | 2,985 | $ | (153 | ) | $ | 103,536 | |||||||||
Product sales revenues |
36,068 | 2,453 | — | — | 38,521 | |||||||||||||||
Affiliate management fee revenue |
163 | — | — | — | 163 | |||||||||||||||
Total revenues |
113,957 | 25,431 | 2,985 | (153 | ) | 142,220 | ||||||||||||||
Operating expenses |
33,557 | 8,996 | 1,304 | (946 | ) | 42,911 | ||||||||||||||
Environmental |
14,549 | 2,689 | 885 | — | 18,123 | |||||||||||||||
Environmental reimbursements |
(14,469 | ) | (2,689 | ) | (751 | ) | — | (17,909 | ) | |||||||||||
Product purchases |
31,083 | 1,299 | — | — | 32,382 | |||||||||||||||
Equity earnings |
(148 | ) | — | — | — | (148 | ) | |||||||||||||
Operating margin |
49,385 | 15,136 | 1,547 | 793 | 66,861 | |||||||||||||||
Depreciation and amortization |
5,536 | 3,291 | 202 | 793 | 9,822 | |||||||||||||||
Affiliate G&A expenses |
9,358 | 3,551 | 598 | — | 13,507 | |||||||||||||||
Segment profit |
$ | 34,491 | $ | 8,294 | $ | 747 | $ | — | $ | 43,532 | ||||||||||
Three Months Ended June 30, 2005 |
||||||||||||||||||
(in thousands) | ||||||||||||||||||
Petroleum Products Pipeline System |
Petroleum Products Terminals |
Ammonia Pipeline System |
Inter- Eliminations |
Total |
||||||||||||||
Transportation and terminals revenues |
$ | 94,784 | $ | 25,506 | $ | 3,506 | $ | (907 | ) | $ | 122,889 | |||||||
Product sales revenues |
129,199 | 3,741 | — | (410 | ) | 132,530 | ||||||||||||
Affiliate management fee revenue |
167 | — | — | — | 167 | |||||||||||||
Total revenues |
224,150 | 29,247 | 3,506 | (1,317 | ) | 255,586 | ||||||||||||
Operating expenses |
41,745 | 9,639 | 2,012 | (1,596 | ) | 51,800 | ||||||||||||
Environmental |
1,688 | 52 | 32 | — | 1,772 | |||||||||||||
Product purchases |
121,522 | 1,364 | — | (538 | ) | 122,348 | ||||||||||||
Equity earnings |
(804 | ) | — | — | — | (804 | ) | |||||||||||
Operating margin |
59,999 | 18,192 | 1,462 | 817 | 80,470 | |||||||||||||
Depreciation and amortization |
9,074 | 3,858 | 182 | 817 | 13,931 | |||||||||||||
Affiliate G&A expenses |
10,850 | 3,755 | 529 | — | 15,134 | |||||||||||||
Segment profit |
$ | 40,075 | $ | 10,579 | $ | 751 | $ | — | $ | 51,405 | ||||||||
Page 7
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Six Months Ended June 30, 2004 |
||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Petroleum Products Pipeline System |
Petroleum Products Terminals |
Ammonia Pipeline System |
Inter- Eliminations |
Total |
||||||||||||||||
Transportation and terminals revenues |
$ | 142,362 | $ | 43,813 | $ | 6,585 | $ | (294 | ) | $ | 192,466 | |||||||||
Product sales revenues |
78,253 | 4,482 | — | — | 82,735 | |||||||||||||||
Affiliate management fee revenue |
163 | — | — | — | 163 | |||||||||||||||
Total revenues |
220,778 | 48,295 | 6,585 | (294 | ) | 275,364 | ||||||||||||||
Operating expenses |
62,013 | 17,355 | 2,285 | (1,742 | ) | 79,911 | ||||||||||||||
Environmental |
38,437 | 2,839 | 1,052 | — | 42,328 | |||||||||||||||
Environmental reimbursements |
(37,573 | ) | (2,839 | ) | (912 | ) | — | (41,324 | ) | |||||||||||
Product purchases |
68,458 | 2,423 | — | — | 70,881 | |||||||||||||||
Equity earnings |
(268 | ) | — | — | — | (268 | ) | |||||||||||||
Operating margin |
89,711 | 28,517 | 4,160 | 1,448 | 123,836 | |||||||||||||||
Depreciation and amortization |
11,042 | 6,449 | 405 | 1,448 | 19,344 | |||||||||||||||
Affiliate G&A expenses |
18,371 | 6,843 | 1,180 | — | 26,394 | |||||||||||||||
Segment profit |
$ | 60,298 | $ | 15,225 | $ | 2,575 | $ | — | $ | 78,098 | ||||||||||
Six Months Ended June 30, 2005 |
||||||||||||||||||
(in thousands) | ||||||||||||||||||
Petroleum Products Pipeline System |
Petroleum Products Terminals |
Ammonia Pipeline System |
Inter- Eliminations |
Total |
||||||||||||||
Transportation and terminals revenues |
$ | 177,439 | $ | 51,016 | $ | 6,207 | $ | (1,697 | ) | $ | 232,965 | |||||||
Product sales revenues |
274,619 | 6,411 | — | (410 | ) | 280,620 | ||||||||||||
Affiliate management fee revenue |
334 | — | — | — | 334 | |||||||||||||
Total revenues |
452,392 | 57,427 | 6,207 | (2,107 | ) | 513,919 | ||||||||||||
Operating expenses |
76,874 | 18,821 | 3,414 | (3,054 | ) | 96,055 | ||||||||||||
Environmental |
2,530 | 90 | 352 | — | 2,972 | |||||||||||||
Product purchases |
251,647 | 2,675 | — | (663 | ) | 253,659 | ||||||||||||
Equity earnings |
(1,322 | ) | — | — | — | (1,322 | ) | |||||||||||
Operating margin |
122,663 | 35,841 | 2,441 | 1,610 | 162,555 | |||||||||||||
Depreciation and amortization |
17,468 | 7,459 | 364 | 1,610 | 26,901 | |||||||||||||
Affiliate G&A expenses |
21,909 | 7,277 | 1,074 | — | 30,260 | |||||||||||||
Segment profit |
$ | 83,286 | $ | 21,105 | $ | 1,003 | $ | — | $ | 105,394 | ||||||||
5. Related Party Transactions
Affiliate Entity Transactions
In 2003, we entered into a services agreement with MMH pursuant to which MMH agreed to provide our operations and G&A services. We pay MMH for those costs and MMH reimburses us for G&A expenses in excess of a G&A cap as defined in the new omnibus agreement. The amount of G&A costs that either has been or will be reimbursed by MMH to us was $2.4 million and $3.6 million for the three and six months ended June 30, 2004, respectively, and $0.6 million and $1.6 million for the three and six months ended June 30, 2005, respectively. The following table summarizes allocated operating and G&A costs from MMH to us. These amounts are reflected in the cost and expenses in the accompanying consolidated statements of income (in thousands):
Three Months Ended June 30, |
Six Months Ended June 30, | |||||||||||
2004 |
2005 |
2004 |
2005 | |||||||||
MMH—allocated operating expenses |
$ | 14,819 | $ | 16,432 | $ | 28,193 | $ | 32,251 | ||||
MMH—allocated G&A expenses |
13,507 | 15,134 | 26,394 | 30,260 |
Additionally, MMH has indemnified us against certain environmental costs (See Note 11 – Commitments and Contingencies for a discussion of this issue). Recorded environmental liabilities associated with this indemnification were $10.4 million and $8.5 million at December 31, 2004 and June 30, 2005, respectively. Accounts receivable from MMH associated with this indemnification were $11.5 million and $9.4 million at December 31, 2004 and June 30, 2005, respectively, and are included with the affiliate and long-term affiliate accounts receivables in the consolidated balance sheets.
Page 8
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In March 2004, we acquired a 50% ownership interest in Osage Pipe Line Company, LLC (“Osage Pipeline”) and in April 2004, we began operating the Osage pipeline for which we are paid a fee. During the three and six months ended June 30, 2004, we received operating fees from Osage Pipeline of $0.2 million, and for the three and six months ended June 30, 2005, we received $0.2 million and $0.3 million, respectively, which we reported as affiliate management fee revenues.
Other Related Party Transactions
MMH is partially owned by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“Carlyle/Riverstone Fund”). Our general partner’s eight-member board of directors includes Messieurs N. John Lancaster, Jr. and Jim H. Derryberry who are nominees of the Carlyle/Riverstone Fund. On January 25, 2005, the Carlyle/Riverstone Fund, through affiliates, acquired an interest in the general partner of SemGroup, L.P. (“SemGroup”) and limited partner interests in SemGroup. The Carlyle/Riverstone Fund’s total combined general and limited partner interest in SemGroup is approximately 30%. The Carlyle/Riverstone Fund has the right to designate three members of SemGroup’s general partner’s nine-member management committee. Currently, Carlyle/Riverstone Fund has only designated one member and until the appointment of the two additional Carlyle/Riverstone designees, the existing designee is entitled to have three votes with respect to any decision by the management committee.
We are a party to a number of transactions with SemGroup and its affiliates, details of which are provided in the following table (in millions):
Three Months June 30, 2005 |
Period From June 30, 2005 | |||||
Sales of petroleum products |
$ | 25.1 | $ | 50.9 | ||
Purchases of petroleum products |
13.7 | 33.5 | ||||
Terminalling and other services revenues |
1.5 | 2.7 | ||||
Storage tank lease revenues |
0.8 | 1.2 | ||||
Storage tank lease expense |
0.3 | 0.5 |
In addition to the above, we provide common carrier transportation services to SemGroup.
The Carlyle/Riverstone Fund also has an ownership interest in the general partner of Buckeye Partners, L.P. (“Buckeye”). During the three and six months ended June 30, 2005, our operating expenses included $0.0 million and $0.3 million, respectively, of costs we incurred with Norco Pipe Line Company, LLC, which is a subsidiary of Buckeye.
The board of directors of our general partner has adopted a policy to address board of director conflicts of interests. In compliance with this policy, the Carlyle/Riverstone Fund has adopted procedures internally to assure that our proprietary and confidential information is protected from disclosure. As part of these procedures, the Carlyle/Riverstone Fund has agreed that no individual representing them will serve at the same time on our general partner’s board of directors and on the general partner’s board of directors for SemGroup or Buckeye.
6. Inventories
Inventories at December 31, 2004 and June 30, 2005 were as follows (in thousands):
December 31, 2004 |
June 30, 2005 | |||||
Refined petroleum products |
$ | 28,694 | $ | 26,250 | ||
Natural gas liquids |
12,682 | 28,144 | ||||
Additives |
1,632 | 1,836 | ||||
Other |
389 | 389 | ||||
Total inventories |
$ | 43,397 | $ | 56,619 | ||
Page 9
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
7. Equity Investment
Effective March 2, 2004, we acquired a 50% ownership in Osage Pipeline for $25.0 million. National Cooperative Refining Association (“NCRA”) owns the remaining 50% ownership interest. Our agreement with NCRA calls for equal sharing of Osage Pipeline’s net income.
We use the equity method to account for this investment. Summarized financial information for Osage Pipeline is presented below (in thousands):
Three Months Ended June 30, |
March 2, 2004 June 30, 2004 |
Six Months June 30, 2005 | ||||||||||
2004 |
2005 |
|||||||||||
Revenues |
$ | 2,572 | $ | 2,993 | $ | 3,320 | $ | 5,335 | ||||
Net income |
$ | 738 | $ | 1,940 | $ | 978 | $ | 3,308 |
The condensed balance sheet for Osage Pipeline as of December 31, 2004 and June 30, 2005 is presented below (in thousands):
December 31, 2004 |
June 30, 2005 | |||||
Current assets |
$ | 3,278 | $ | 4,339 | ||
Noncurrent assets |
$ | 5,006 | $ | 4,763 | ||
Current liabilities |
$ | 351 | $ | 460 | ||
Members’ equity |
$ | 7,933 | $ | 8,642 |
A summary of our equity investment in Osage Pipeline is as follows (in thousands):
March 2, 2004 June 30, 2004 |
Six Months Ended June 30, 2005 |
|||||||
Investment at beginning of period |
$ | 25,032 | $ | 25,084 | ||||
Earnings in equity investment: |
||||||||
Proportionate share of Osage earnings |
489 | 1,654 | ||||||
Amortization of excess investment |
(221 | ) | (332 | ) | ||||
Net earnings in equity investment |
268 | 1,322 | ||||||
Cash distributions |
— | (1,300 | ) | |||||
Equity investment at end of period |
$ | 25,300 | $ | 25,106 | ||||
Our initial investment in Osage Pipeline included an excess net investment amount of $21.7 million, which is being amortized over the average asset lives of Osage Pipeline. Excess investment is the amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment.
Page 10
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
8. Employee Benefit Plans
MMH sponsors a pension plan for union employees, a pension plan for non-union employees and a post-retirement benefit plan for selected employees. The following tables present our recognition of net periodic benefit costs related to these plans (in thousands):
Three Months Ended June 30, 2004 |
Six Months Ended June 30, 2004 | |||||||||||||
Pension Benefits |
Other Post- Retirement Benefits |
Pension Benefits |
Other Post- Retirement Benefits | |||||||||||
Components of Net Periodic Benefit Costs: |
||||||||||||||
Service cost |
$ | 925 | $ | 103 | $ | 1,850 | $ | 206 | ||||||
Interest cost |
427 | 221 | 854 | 442 | ||||||||||
Expected return on plan assets |
(409 | ) | — | (818 | ) | — | ||||||||
Amortization of prior service cost |
112 | 582 | 224 | 1,164 | ||||||||||
Net periodic benefit cost |
$ | 1,055 | $ | 906 | $ | 2,110 | $ | 1,812 | ||||||
Three Months Ended June 30, 2005 |
Six Months Ended June 30, 2005 | |||||||||||||
Pension Benefits |
Other Post- Retirement Benefits |
Pension Benefits |
Other Post- Retirement Benefits | |||||||||||
Components of Net Periodic Benefit Costs: |
||||||||||||||
Service cost |
$ | 1,272 | $ | 86 | $ | 2,543 | $ | 172 | ||||||
Interest cost |
497 | 186 | 995 | 372 | ||||||||||
Expected return on plan assets |
(451 | ) | — | (902 | ) | — | ||||||||
Amortization of prior service cost |
169 | 449 | 338 | 899 | ||||||||||
Net periodic benefit cost |
$ | 1,487 | $ | 721 | $ | 2,974 | $ | 1,443 | ||||||
We anticipate contributing a total of $4.6 million and $0.1 million for the pension and other post-retirement benefit plans, respectively, for the 2005 plan year. Through June 30, 2005, a total of $1.1 million had been contributed for the pension plans.
9. Debt
Debt at December 31, 2004 and June 30, 2005 was as follows (in thousands):
December 31, 2004 |
June 30, 2005 | |||||
Magellan Pipeline Notes: |
||||||
Long-term portion |
$ | 289,574 | $ | 287,827 | ||
Current portion |
15,100 | 15,100 | ||||
Total Magellan Pipeline Notes |
304,674 | 302,927 | ||||
6.45% Notes due 2014 |
249,507 | 249,526 | ||||
5.65% Notes due 2016 |
250,487 | 254,520 | ||||
Total debt |
$ | 804,668 | $ | 806,973 | ||
5.65% Notes due 2016
On October 15, 2004, we issued $250.0 million of senior notes due 2016. The notes were issued for the discounted price of 99.9%, or $249.7 million. Including the impact of hedges associated with these notes (see Note 10–Derivative Financial Instruments), the effective interest rate of these notes during both the three and six months ended June 30, 2005 was 5.4%. Interest is payable semi-annually in arrears on April 15 and October 15 of each year, commencing on April 15, 2005. The outstanding principal amount of the fixed-rate notes at December 31, 2004 and June 30, 2005 was increased by $0.8 million and $4.8 million, respectively, for the change in the fair value of the associated hedge (see Note 10–Derivative Financial Instruments). The discount on the notes is being accreted over the life of the notes.
Page 11
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
6.45% Notes due 2014
On May 25, 2004, we sold $250.0 million aggregate principal of 6.45% notes due June 1, 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million. Including the impact of the amortization of the realized gains on the interest hedges associated with these notes (see Note 10–Derivative Financial Instruments), the effective interest rate of these notes was 6.5% for the period from May 25, 2004 through June 30, 2004 and 6.3% for both the three and six months ended June 30, 2005. Interest is payable semi-annually in arrears on June 1 and December 1 of each year. The discount on the notes is being accreted over the life of the notes.
May 2004 Revolving Credit Facility
In May 2004, we entered into a five-year $125.0 million revolving credit facility with a syndicate of banks. In September 2004, we increased the facility to $175.0 million. As of June 30, 2005, $1.1 million of the facility was being used for letters of credit, which is not reflected as debt on our balance sheet, with no other amounts outstanding. Borrowings under this revolving credit facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.6% to 1.5% based on our credit ratings.
Magellan Pipeline Notes
During October 2002, Magellan Pipeline entered into a private placement debt agreement with a group of financial institutions for $302.0 million of fixed-rate notes. We make deposits in an escrow account in anticipation of semi-annual interest payments on these notes and the cash deposits are secured; however, the notes themselves are unsecured. The maturity date of the notes is October 7, 2007; however, we will be required on each of October 7, 2005 and October 7, 2006, to repay 5.0% of the principal amount outstanding on those dates. The outstanding principal amount of the notes at December 31, 2004 and June 30, 2005 was increased by $2.7 million and $0.9 million, respectively, for the change in the fair value of the associated hedge (see Note 10–Derivative Financial Instruments). The interest rate of the notes is fixed at 7.7%. Including the impact of the associated fair value hedge, which effectively swaps $250.0 million of the fixed-rate notes to floating-rate debt, the weighted-average interest rate for the notes was 7.6% and 7.4% for the three and six months ended June 30, 2005, respectively. The weighted-average interest rate of the notes, including the impact of the associated hedge, for both the three and six months ended June 30, 2004 was 6.6%.
Deposits for interest due the lenders are made to a cash escrow account and were reflected as restricted cash on our consolidated balance sheets of $5.8 million at both December 31, 2004 and June 30, 2005.
10. Derivative Financial Instruments
We use interest rate derivatives to help us manage interest rate risk. The following table summarizes hedges we have settled associated with various debt offerings (dollars in millions):
Hedge |
Date |
Gain/(Loss) |
Amortization Period | |||||
Interest rate hedge |
October 2002 | $ | (1.0 | ) | 5-year life of Magellan Pipeline notes | |||
Interest rate swaps and treasury lock |
May 2004 | 5.1 | 10-year life of 6.45% notes | |||||
Interest rate swaps |
October 2004 | (6.3 | ) | 12-year life of 5.65% notes |
In addition to the above, we have entered into the following interest rate swap agreements:
• | During May 2004, we entered into certain interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline senior notes. We have accounted for these interest rate hedges as fair value hedges. The notional amounts of the interest rate swap agreements total $250.0 million. Under the terms of the interest rate swap agreements, we receive 7.7% (the weighted-average interest rate of the outstanding Magellan Pipeline senior notes) and pay LIBOR plus 3.4%. |
Page 12
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
These hedges effectively convert $250.0 million of our fixed-rate debt to floating-rate debt. The interest rate swap agreements began on May 25, 2004 and expire on October 7, 2007, the maturity date of the Magellan Pipeline senior notes. Payments settle in April and October each year with LIBOR set in arrears. During each settlement period we record the impact of this swap based on our best estimate of LIBOR. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR result in an adjustment to our interest expense. A 1.0% change in LIBOR would result in an annual adjustment to our interest expense associated with this hedge of $2.5 million. The fair value of the instruments associated with this hedge at December 31, 2004 and June 30, 2005 was $2.7 million and $0.9 million, respectively, which was recorded to other noncurrent assets and long-term debt.
• | In October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016 which were issued in October 2004. The notional amount of this agreement is $100.0 million and effectively converts $100.0 million of our 5.65% fixed-rate senior notes issued in October 2004 to floating-rate debt. Under the terms of the agreement, we receive the 5.65% fixed rate of the notes and pay LIBOR plus 0.6%. The agreement began on October 15, 2004 and terminates on October 15, 2016, which is the maturity date of these senior notes. Payments settle in April and October each year with LIBOR set in arrears. During each settlement period we will record the impact of this swap based on our best estimate of LIBOR. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to our interest expense. A 1.0% change in LIBOR would result in an annual adjustment to our interest expense of $1.0 million associated with this hedge. The fair value of this hedge at December 31, 2004 and June 30, 2005, was $0.8 million and $4.8 million, respectively, which was recorded to other noncurrent assets and long-term debt. |
11. Commitments and Contingencies
Estimated liabilities for environmental costs were $60.8 million and $57.7 million at December 31, 2004 and June 30, 2005, respectively. These estimates are provided on an undiscounted basis and have been classified as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental remediation liabilities will be paid over the next ten years. Included in our environmental liabilities are the Environmental Protection Agency (“EPA”), Shawnee, Kansas Spill and Kansas City, Kansas Spill issues discussed below:
EPA Issue - In July 2001, the EPA, pursuant to Section 308 of the Clean Water Act (the “Act”) served an information request to Williams based on a preliminary determination that Williams may have systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline, which we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumes that all releases are violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those spills may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We have responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million.
Shawnee, Kansas Spill - During the fourth quarter of 2003, we experienced a line break and product spill on our petroleum products pipeline near Shawnee, Kansas. As of June 30, 2005, we estimated the total costs associated with this spill to be $9.3 million. We have spent $9.0 million on remediation at this site, leaving a remaining liability on our balance sheet at June 30, 2005 of $0.3 million. At December 31, 2004 and June 30, 2005, we had recorded a receivable from our insurance carrier of $7.4 million and $6.6 million, respectively, related to this spill.
Page 13
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Kansas City, Kansas Spill – During the second quarter of 2005, we experienced a line break and product spill on our petroleum products pipeline near our Kansas City, Kansas terminal. During the current quarter, we recorded expenses associated with this spill of approximately $1.5 million, of which $1.2 million are included in our environmental liabilities at June 30, 2005
Environmental Indemnification Settlement - Prior to May 27, 2004, Williams had agreed to indemnify us against certain environmental losses, among other things, associated with assets that Williams contributed to us at the time of our initial public offering or which we subsequently acquired from Williams. In May 2004, our general partner entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release Williams from these indemnifications. We received $35.0 million and $27.5 million from Williams on July 1, 2004 and 2005, respectively, and expect to receive installment payments from Williams of $20.0 million and $35.0 million on July 1, 2006 and 2007, respectively. While the settlement agreement releases Williams from its environmental and certain other indemnifications, certain indemnifications remain in effect. These remaining indemnifications cover:
• | Issues involving employee benefits matters; |
• | Issues involving rights of way, easements and real property, including asset titles; and |
• | Unlimited losses and damages related to tax liabilities. |
As of December 31, 2004 and June 30, 2005, known liabilities that would have been covered by Williams’ previous indemnity agreements were $40.8 million and $39.6 million, respectively. Through June 30, 2005, we have spent $10.4 million of the $117.5 million indemnification settlement amount for indemnified matters, including $3.9 million of capital costs.
MMH Indemnifications – In June 2003, at the time MMH acquired our general partner interest, MMH assumed obligations to indemnify us for $21.9 million of known environmental liabilities. To the extent the claims against MMH are less than $21.9 million, MMH will pay to Williams the remaining difference between $21.9 million and the indemnity claims paid by MMH. Recorded liabilities associated with this indemnification were $10.4 million and $8.5 million at December 31, 2004 and June 30, 2005, respectively.
Other Indemnifications - In conjunction with the 1999 acquisition of our Gulf Coast marine terminals from Amerada Hess Corporation (“Hess”), Hess agreed to indemnify us against certain environmental losses. We filed claims against Hess associated with their indemnifications to us totaling $1.9 million. During May 2005, we settled most of our claims against Hess in exchange for: (1) indemnification from the judgment in Elementis Chromium L.P., et al., v. Coastal States Petroleum Company, et al., v. Amerada Hess Corporation, et al (“Elementis Action”), under which the court found us to be liable for 10% of the cost of the clean up of certain contamination in Corpus Christi, Texas; (2) the payment of $50,000 for part of the legal fees incurred by us in defending ourselves from the Elementis Action; and (3) the transfer by Hess of certain parcels of property to us in Marrero, Louisiana. We did not settle our claim against Hess for non-payment of storage fees at our Corpus Christi, Texas terminal. We have agreed to arbitrate this dispute if a settlement agreement cannot be reached by August 31, 2005.
Environmental Receivables - Environmental receivables from MMH at December 31, 2004 and June 30, 2005 were $11.5 million and $9.4 million, respectively. Environmental receivables from insurance carriers were $7.4 million and $6.6 million at December 31, 2004 and June 30, 2005, respectively. We invoice MMH and third-party insurance companies for reimbursement as environmental remediation work is performed.
Other – We are a party to various other claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our future financial position, results of operations or cash flows.
12. Long-Term Incentive Plan
In February 2001, our general partner adopted the Williams Energy Partners’ Long-Term Incentive Plan, which was amended and restated on February 3, 2003, on July 22, 2003 and on February 3, 2004, for employees who perform services for us and directors of our general partner. The Long-Term Incentive Plan primarily consists of two components: phantom units and unit options. The Long-Term Incentive Plan permits the grant of awards covering an aggregate of 1.4 million common units. The Compensation Committee of our general partner’s Board of Directors administers the Long-Term Incentive Plan.
Page 14
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In February 2003, our general partner granted 105,650 phantom units pursuant to the Long-Term Incentive Plan. The actual number of units that will be awarded under this grant are based on certain performance metrics, which we determined at the end of 2003, and a personal performance component that will be determined at the end of 2005, with vesting to occur at that time. These units are subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature except when there is a change in control of our general partner. We have increased the accrual associated with this award to an expected payout of 180,602 units. The value of these unit awards at June 30, 2005 was $5.9 million.
Following the change in control of our general partner in June 2003, the board of directors of our general partner made the following grants to certain employees who became dedicated to providing services to us:
• | In October 2003, our general partner granted 21,280 phantom units pursuant to the Long-Term Incentive Plan. Of these awards, 20,340 units vested during 2003 and 2004. The remaining 940 units vested on July 31, 2005. The value of the 940 awards at June 30, 2005 was less than $0.1 million. |
• | In January 2004, our general partner granted 21,712 phantom units pursuant to the Long-Term Incentive Plan. Of these awards, 10,866 units vested on July 31, 2004 and 10,846 units vested on July 31, 2005. The value of the 10,846 awards at June 30, 2005 was $0.4 million. |
In February 2004, our general partner granted 159,024 phantom units pursuant to the Long-Term Incentive Plan. The actual number of units that will be awarded under this grant are based on the attainment of short-term and long-term performance metrics. The number of phantom units that could ultimately be issued under this award ranges from zero units up to a total of 318,048 units; however, the awards are also subject to personal and other performance components which could increase or decrease the number of units to be paid out by as much as 40%. The units will vest at the end of 2006. These units are subject to forfeiture if employment is terminated for any reason other than for retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s grant will be prorated based upon the completed months of employment during the vesting period and the award will be paid at the end of the vesting period. These awards do not have an early vesting feature except when there is a change in control of our general partner. We have increased our estimate of the number of units that will be awarded under this grant to 290,692 based on the attainment of higher-than-standard short-term performance metrics and the probability of attaining higher than standard on the long-term performance metrics. The value of the 290,692 unit awards on June 30, 2005 was $9.5 million.
In February 2005, our general partner granted 160,640 phantom units pursuant to the Long-Term Incentive Plan. The actual number of units that will be awarded under this grant are based on the attainment of long-term performance metrics. The number of phantom units that could ultimately be issued under this award ranges from zero units up to a total of 321,280 units; however, the awards are also subject to personal and other performance components which could increase or decrease the number of units to be paid out by as much as 20%. The units will vest at the end of 2007. These units are subject to forfeiture if employment is terminated for any reason other than for retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s grant will be prorated based upon the completed months of employment during the vesting period and the award will be paid at the end of the vesting period. These awards do not have an early vesting feature except when there is a change in control of our general partner. The value of the 160,640 unit awards on June 30, 2005 was $5.3 million.
Our equity-based incentive compensation costs for the three and six months ended June 30, 2004 and 2005 are summarized as follows (in thousands):
Three Months Ended June 30, |
Six Months Ended June 30, | |||||||||||
2004 |
2005 |
2004 |
2005 | |||||||||
2003 awards |
$ | 300 | $ | 822 | $ | 887 | $ | 1,505 | ||||
October 2003 awards |
34 | 3 | 113 | 6 | ||||||||
January 2004 awards |
213 | 43 | 373 | 87 | ||||||||
2004 awards |
310 | 1,083 | 674 | 1,960 | ||||||||
2005 awards |
— | 476 | — | 890 | ||||||||
Total |
$ | 857 | $ | 2,427 | $ | 2,047 | $ | 4,448 | ||||
Page 15
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
13. Distributions
We paid the following distributions during 2004 and 2005 (in thousands, except per unit amounts):
Cash Distribution Payment Date |
Per Unit Cash Distribution Amount |
Common Units |
Subordinated Units |
General Partner |
Total Cash | ||||||||||
02/13/04 |
$ | 0.41500 | $ | 18,020 | $ | 4,714 | $ | 3,066 | $ | 25,800 | |||||
05/14/04 |
0.42500 | 19,661 | 3,621 | 3,613 | 26,895 | ||||||||||
08/13/04 |
0.43500 | 20,994 | 3,706 | 4,313 | 29,013 | ||||||||||
11/12/04 |
0.44500 | 25,739 | 3,791 | 5,705 | 35,235 | ||||||||||
Total |
$ | 1.72000 | $ | 84,414 | $ | 15,832 | $ | 16,697 | $ | 116,943 | |||||
02/14/05 |
$ | 0.45625 | $ | 26,390 | $ | 3,887 | $ | 5,201 | $ | 35,478 | |||||
05/13/05 |
0.48000 | 29,127 | 2,726 | 6,778 | 38,631 | ||||||||||
08/12/05 (a) |
0.49750 | 30,189 | 2,825 | 7,939 | 40,953 | ||||||||||
Total |
$ | 1.43375 | $ | 85,706 | $ | 9,438 | $ | 19,918 | $ | 115,062 | |||||
(a) | Our general partner declared this cash distribution on July 20, 2005 to be paid on August 12, 2005 to unitholders of record at the close of business on August 3, 2005. |
In conjunction with our acquisition of petroleum products pipeline assets during October 2004, our general partner agreed to reduce the amount of its incentive distributions by $1.25 million for distributions paid associated with the fourth quarter of 2004 (paid in February 2005), by $1.25 million for all quarters of 2005 and by $0.75 million for all quarters of 2006.
14. Net Income Per Unit
The following table provides details of the basic and diluted net income per unit computations (in thousands, except per unit amounts):
Three Months Ended June 30, 2004 |
Six Months Ended June 30, 2004 | |||||||||||||||
Income (Numerator) |
Units (Denominator) |
Per Unit Amount |
Income (Numerator) |
Units (Denominator) |
Per Unit Amount | |||||||||||
Basic net income per limited partner unit |
$ | 17,465 | 55,594 | $ | 0.31 | $ | 41,339 | 55,190 | $ | 0.75 | ||||||
Effect of dilutive restricted unit grants |
— | 126 | — | — | 108 | — | ||||||||||
Diluted net income per limited partner unit |
$ | 17,465 | 55,720 | $ | 0.31 | $ | 41,339 | 55,298 | $ | 0.75 | ||||||
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MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Three Months Ended June 30, 2005 |
Six Months Ended June 30, 2005 | |||||||||||||||
Income (Numerator) |
Units (Denominator) |
Per Unit Amount |
Income (Numerator) |
Units (Denominator) |
Per Unit Amount | |||||||||||
Basic net income per limited partner unit |
$ | 32,037 | 66,361 | $ | 0.48 | $ | 68,014 | 66,361 | $ | 1.02 | ||||||
Effect of dilutive restricted unit grants |
— | 243 | — | — | 175 | — | ||||||||||
Diluted net income per limited partner unit |
$ | 32,037 | 66,604 | $ | 0.48 | $ | 68,014 | 66,536 | $ | 1.02 | ||||||
Units reported as dilutive securities are related to phantom unit grants (see Note 12 – Long-Term Incentive Plan).
15. Partners’ Capital
On April 12, 2005, we completed a two-for-one split of our limited partner units, and holders of record at the close of business on April 5, 2005 received one additional limited partner unit for each limited partner unit owned on that date. All references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give effect for this split for all periods presented.
On March 31, 2005, MMH owned 2,389,558 common units, 5,679,696 subordinated units and all of our general partner interest, representing a combined ownership interest in us of 14%. In April 2005, MMH sold 5,679,696 subordinated units representing limited partner interests in us in a privately negotiated transaction. Following this sale, MMH’s ownership interest in us, including their general partner interest, decreased from 14% to 6%. Upon consummation of this sale, we believe that more than 50% of the total interests in our capital and profits had been sold or exchanged over the past 12-month period due to the trading activity of our limited partner units. Because of this, we will be considered to have been terminated for federal income tax purposes and immediately reconstituted as a new partnership. Among other things, the termination will cause a significant reduction in the amount of depreciation deductions allocable to unitholders in 2005. As a result, we estimate that for only the 2005 tax year our unitholders as of April 2005 will be allocated an increased amount of federal taxable income as a percentage of cash distributed to the unitholders.
During May and June 2005, MMH sold its remaining 2,389,558 common units representing limited partner interests in us in privately negotiated transactions. Following these transactions, MMH continues to own our general partner interest, representing a 2% ownership interest in us.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
Magellan Midstream Partners, L.P. is a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. As of June 30, 2005, our three operating segments include:
• | petroleum products pipeline system, which is primarily comprised of our 8,500-mile petroleum products pipeline with 43 associated terminals; |
• | petroleum products terminals, which principally includes our six marine terminal facilities and 29 inland terminals; and |
• | ammonia pipeline system, representing our 1,100-mile ammonia pipeline and six associated terminals. |
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The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our company. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2004.
Recent Developments
Distribution - On July 20, 2005, the board of directors of our general partner declared a quarterly cash distribution of $0.4975 per unit for the period of April 1 through June 30, 2005, representing our seventeenth consecutive distribution increase since our initial public offering in February 2001. We intend to pay the quarterly distribution on August 12, 2005 to unitholders of record on August 3, 2005.
Results of Operations
We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important measure used by management to evaluate the economic performance of our operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items, such as depreciation and amortization and general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of an operation.
Operating margin is not a generally accepted accounting principle (“GAAP”) measure, but the components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the table below.
Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2005
Three Months Ended June 30, |
||||||||
2004 |
2005 |
|||||||
Financial Highlights (in millions) |
||||||||
Revenues: |
||||||||
Transportation and terminals revenues: |
||||||||
Petroleum products pipeline system |
$ | 77.7 | $ | 94.8 | ||||
Petroleum products terminals |
23.0 | 25.5 | ||||||
Ammonia pipeline system |
3.0 | 3.5 | ||||||
Intersegment eliminations |
(0.2 | ) | (0.9 | ) | ||||
Total transportation and terminals revenues |
103.5 | 122.9 | ||||||
Product sales |
38.5 | 132.5 | ||||||
Affiliate management fees |
0.2 | 0.2 | ||||||
Total revenues |
142.2 | 255.6 | ||||||
Operating expenses, environmental expenses and environmental reimbursements: |
||||||||
Petroleum products pipeline system |
33.6 | 43.4 | ||||||
Petroleum products terminals |
9.0 | 9.7 | ||||||
Ammonia pipeline system |
1.4 | 2.0 | ||||||
Intersegment eliminations |
(0.9 | ) | (1.5 | ) | ||||
Total operating expenses, environmental expenses and environmental reimbursements |
43.1 | 53.6 | ||||||
Product purchases |
32.4 | 122.3 | ||||||
Equity earnings |
(0.1 | ) | (0.8 | ) | ||||
Operating margin |
66.8 | 80.5 | ||||||
Depreciation and amortization |
9.8 | 14.0 | ||||||
Affiliate G&A expenses |
13.5 | 15.1 | ||||||
Operating profit |
$ | 43.5 | $ | 51.4 | ||||
Page 18
Three Months Ended June 30, | ||||||
2004 |
2005 | |||||
Operating Statistics |
||||||
Petroleum products pipeline system: |
||||||
Transportation revenue per barrel |
$ | 1.002 | $ | 1.015 | ||
Transportation barrels shipped (million barrels) |
63.2 | 75.0 | ||||
Petroleum products terminals: |
||||||
Marine terminal facilities: |
||||||
Average storage capacity utilized per month (barrels in millions) |
15.6 | 16.7 | ||||
Throughput (barrels in millions) |
5.7 | 13.5 | ||||
Inland terminals: |
||||||
Throughput (barrels in millions) |
26.1 | 28.9 | ||||
Ammonia pipeline system: |
||||||
Volume shipped (tons in thousands) |
162 | 186 |
Transportation and terminals revenues for the three months ended June 30, 2005 were $122.9 million compared to $103.5 million for the three months ended June 30, 2004, an increase of $19.4 million, or 19%. This increase was a result of:
• | an increase in petroleum products pipeline system revenues of $17.1 million, or 22%, primarily attributable to revenues from our October 2004 pipeline system acquisition. In addition, our existing pipeline system experienced higher revenues from ethanol blending, tank leases and terminal services, further benefiting the current period; |
• | an increase in petroleum products terminals revenues of $2.5 million, or 11%, primarily due to higher utilization and rates at our existing marine terminals and financial results from our new marine facility in East Houston, Texas, which was acquired as part of the October 2004 pipeline system acquisition. Increased throughput at our inland terminals further increased revenues during the current period; and |
• | an increase in ammonia pipeline system revenues of $0.5 million, or 17%, resulting from increased transportation volumes during the current year, in part due to maintenance work at one of our shipper’s ammonia facilities during the 2004 period. |
Operating expenses, environmental expenses and environmental reimbursements combined were $53.6 million for the three months ended June 30, 2005 compared to $43.1 million for the three months ended June 30, 2004, an increase of $10.5 million, or 24%. By business segment, this increase was principally the result of:
• | an increase in petroleum products pipeline system expenses of $9.8 million, or 29%, primarily attributable to operating costs associated with the pipeline assets acquired in October 2004. Higher environmental expenses related to a May 2005 pipeline leak, increased power costs due to higher natural gas prices and asset retirements on our existing pipeline system were offset by more favorable product gains during the current period; |
• | an increase in petroleum products terminals expenses of $0.7 million, or 8%. A portion of these increased costs resulted from the addition of our East Houston marine terminal. In addition, expenses at our other terminal facilities increased slightly due to higher operating taxes, power costs and asset retirements; and |
• | an increase in ammonia pipeline system expenses of $0.6 million, or 43%, primarily attributable to higher system integrity costs. |
Revenues from product sales were $132.5 million for the three months ended June 30, 2005, while product purchases were $122.3 million, resulting in gross margin from these transactions of $10.2 million. The gross margin resulting from product sales and purchases in second-quarter 2005 increased $4.1 million compared to the gross margin resulting from product sales and purchases in second-quarter 2004 of $6.1 million, reflecting product sales for the three months ended June 30, 2004 of $38.5 million and product purchases of $32.4 million. The amount of product sales and product purchases increased substantially during 2005 primarily as a
Page 19
result of a third-party supply agreement assumed as part of the pipeline assets we acquired during October 2004. The gross margin increase during second-quarter 2005 primarily resulted from the impact of very high gasoline prices on our petroleum products management operations and the third-party supply agreement we assumed in October 2004. We expect the annual amount of product sales and purchases to remain at a higher level than historically reported as a result of this agreement; however, we expect the gross margin to remain substantially similar to historical results on an annual basis once refined product prices stabilize.
Equity earnings were $0.8 million during the three months ended June 30, 2005 and $0.1 million for the three-month period ended June 30, 2004 as a result of increased throughput on the Osage pipeline during the current quarter.
Depreciation and amortization expense was $14.0 million for the three months ended June 30, 2005 compared to $9.8 million for the three months ended June 30, 2004, an increase of $4.2 million, or 43%, primarily related to the additional depreciation expense associated with assets acquired in October 2004.
Affiliate G&A expenses for the three months ended June 30, 2005 were $15.1 million compared to $13.5 million for the three months ended June 30, 2004, an increase of $1.6 million, or 12%. This variance was primarily due to higher G&A expense associated with our equity-based incentive compensation program, which was $2.0 million during the 2005 period and $0.7 million during the 2004 period. The higher compensation expense resulted from the increase in our unit price during the current period and additional unit awards, both of which equate to more expense related to our equity-based program. In addition, we have more G&A personnel and costs resulting from our October 2004 pipeline acquisition. These higher expenses were partially offset by the absence of transition costs during the current period as our separation from our former general partner was completed during 2004. Excluding incentive compensation expense, the amount of cash we spend for G&A costs is determined by an agreement with Magellan Midstream Holdings, L.P. (“MMH”), the current owner of our general partner. For the second quarter of 2005 and 2004, we were responsible for paying G&A costs of $12.5 million and $10.1 million, respectively. To the extent our actual G&A costs, exclusive of incentive compensation expense, exceed these amounts, MMH reimburses us for the excess. The amount of G&A reimbursed by MMH was $0.6 million for the 2005 quarter and $2.4 million for the 2004 quarter.
Interest expense, net of interest income, for the three months ended June 30, 2005 was $11.7 million compared to $7.7 million for the three months ended June 30, 2004, an increase of $4.0 million, or 52%. The weighted-average interest rate on our borrowings increased to 6.5% for the 2005 period from 6.2% for the 2004 period. Our average debt outstanding increased to $802.0 million during second-quarter 2005 from $561.6 million during second-quarter 2004 primarily due to the financing associated with our October 2004 pipeline system acquisition.
Net refinancing costs associated with our May 2004 debt placement were $16.7 million during the second quarter of 2004. These costs included a $12.7 million debt prepayment premium associated with the early extinguishment of a portion of our previously outstanding Magellan Pipeline notes and a $5.0 million non-cash write-off of the unamortized debt placement costs associated with the retired debt. Partially offsetting these charges was a $1.0 million gain on an interest rate hedge related to the refinancing.
Net income for the three months ended June 30, 2005 was $39.0 million compared to $18.5 million for the three months ended June 30, 2004, an increase of $20.5 million, or 111%. Operating margin increased by $13.7 million, or 21%, primarily due to incremental operating results associated with our recent pipeline system acquisition and improved utilization of our other assets. Depreciation and amortization expense increased by $4.2 million between periods, and G&A costs increased by $1.6 million. Net interest expense increased by $4.0 million, but net refinancing costs of $16.7 million during second-quarter 2004 were not experienced during the 2005 period.
Page 20
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2005
Six Months Ended June 30, |
||||||||
2004 |
2005 |
|||||||
Financial Highlights (in millions) |
||||||||
Revenues: |
||||||||
Transportation and terminals revenues: |
||||||||
Petroleum products pipeline system |
$ | 142.3 | $ | 177.4 | ||||
Petroleum products terminals |
43.8 | 51.0 | ||||||
Ammonia pipeline system |
6.6 | 6.2 | ||||||
Intersegment eliminations |
(0.3 | ) | (1.6 | ) | ||||
Total transportation and terminals revenues |
192.4 | 233.0 | ||||||
Product sales |
82.8 | 280.6 | ||||||
Affiliate management fees |
0.2 | 0.3 | ||||||
Total revenues |
275.4 | 513.9 | ||||||
Operating expenses, environmental expenses and environmental reimbursements: |
||||||||
Petroleum products pipeline system |
62.9 | 79.4 | ||||||
Petroleum products terminals |
17.4 | 18.9 | ||||||
Ammonia pipeline system |
2.4 | 3.8 | ||||||
Intersegment eliminations |
(1.7 | ) | (3.1 | ) | ||||
Total operating expenses, environmental expenses and environmental reimbursements |
81.0 | 99.0 | ||||||
Product purchases |
70.9 | 253.6 | ||||||
Equity earnings |
(0.3 | ) | (1.3 | ) | ||||
Operating margin |
123.8 | 162.6 | ||||||
Depreciation and amortization |
19.3 | 26.9 | ||||||
Affiliate G&A expenses |
26.4 | 30.3 | ||||||
Operating profit |
$ | 78.1 | $ | 105.4 | ||||
Operating Statistics |
||||||||
Petroleum products pipeline system: |
||||||||
Transportation revenue per barrel |
$ | 0.991 | $ | 1.010 | ||||
Transportation barrels shipped (million barrels) |
115.4 | 139.1 | ||||||
Petroleum products terminals: |
||||||||
Marine terminal facilities: |
||||||||
Average storage capacity utilized per month (barrels in millions) |
15.6 | 16.6 | ||||||
Throughput (barrels in millions) |
11.2 | 25.9 | ||||||
Inland terminals: |
||||||||
Throughput (barrels in millions) |
46.6 | 55.0 | ||||||
Ammonia pipeline system: |
||||||||
Volume shipped (tons in thousands) |
381 | 338 |
Transportation and terminals revenues for the six months ended June 30, 2005 were $233.0 million compared to $192.4 million for the six months ended June 30, 2004, an increase of $40.6 million, or 21%. This increase was a result of:
• | an increase in petroleum products pipeline system revenues of $35.1 million, or 25%, primarily attributable to revenues from our October 2004 pipeline system acquisition. In addition, our existing pipeline system experienced higher revenues related to management fee income for our operation of third-party pipelines, such as Longhorn pipeline. Higher ancillary revenues for ethanol blending, tank leases and terminal services further benefited the current period; |
• | an increase in petroleum products terminals revenues of $7.2 million, or 16%, primarily due to higher utilization and rates at our marine terminals. Further, the 2005 period also benefited from additional revenues from the ownership interests in 14 inland terminals we acquired in late January 2004, and our new marine terminal in East Houston, Texas, which was acquired as part of the October 2004 pipeline system acquisition, as well as increased throughput at our other inland terminals; and |
Page 21
• | a decrease in ammonia pipeline system revenues of $0.4 million, or 6%, resulting from reduced transportation volumes during the current year. Planned maintenance work at one of our shipper’s ammonia facilities and tight customer inventory levels due to higher production costs resulted in fewer shipments on our pipeline during the first-quarter of 2005. |
Operating expenses, environmental expenses and environmental reimbursements combined were $99.0 million for the six months ended June 30, 2005 compared to $81.0 million for the six months ended June 30, 2004, an increase of $18.0 million, or 22%. By business segment, this increase was principally the result of:
• | an increase in petroleum products pipeline system expenses of $16.5 million, or 26%, primarily attributable to operating costs associated with the pipeline assets acquired in October 2004. Higher system integrity spending, increased power costs due to higher natural gas prices and environmental expenses related to a May 2005 pipeline leak on our existing pipeline system were primarily offset by more favorable product gains during the current period; |
• | an increase in petroleum products terminals expenses of $1.5 million, or 9%, primarily due to operating costs associated with the acquired ownership interests in 14 inland terminals and the East Houston marine terminal. Expenses at our other terminals increased slightly due to higher operating taxes and power costs; and |
• | an increase in ammonia pipeline system expenses of $1.4 million, or 58%, primarily attributable to higher system integrity costs. |
Revenues from product sales were $280.6 million for the six months ended June 30, 2005, while product purchases were $253.6 million, resulting in gross margin from these transactions of $27.0 million. The gross margin resulting from product sales and purchases for the 2005 period increased $15.1 million compared to the gross margin resulting from product sales and purchases for the six-month period ended June 30, 2004 of $11.9 million reflecting product sales for the 2004 period of $82.8 million and product purchases of $70.9 million. The amount of product sales and product purchases increased substantially during 2005 primarily as a result of a third-party supply agreement assumed as part of the pipeline assets we acquired during October 2004. The gross margin increase during 2005 primarily resulted from the impact of very high gasoline prices on our petroleum products management operations and the third-party supply agreement we assumed in October 2004. We expect the annual amount of product sales and purchases to remain at a higher level than historically reported as a result of this agreement; however, we expect the gross margin to remain substantially similar to historical results on an annual basis once refined product prices stabilize.
Equity earnings were $1.3 million during the six months ended June 30, 2005 and $0.3 million for the 2004 period as a result of our acquisition of a 50% interest in Osage Pipeline during March 2004 and increased volumes on the pipeline during second-quarter 2005.
Depreciation and amortization expense was $26.9 million for the six months ended June 30, 2005 compared to $19.3 million for the six months ended June 30, 2004, an increase of $7.6 million, or 39%, primarily related to the additional depreciation expense associated with assets acquired during 2004.
Affiliate G&A expenses for the six months ended June 30, 2005 were $30.3 million compared to $26.4 million for the six months ended June 30, 2004, an increase of $3.9 million, or 15%. This increase was primarily attributable to additional G&A personnel and costs resulting from the October 2004 pipeline acquisition. Higher equity-based incentive compensation expense during the current period was partially offset by transition costs associated with our separation from our former general partner during the 2004 period. Excluding incentive compensation expense and reimbursement from MMH of $1.6 million and $3.6 million for the six months ended June 30, 2005 and 2004, respectively, our actual cash outlay for G&A costs, as determined by our agreement with MMH, was $25.0 million and $20.2 million for the six months ended June 30, 2005 and 2004, respectively, with $3.2 million of the increase related to our acquisition of pipeline system assets in October 2004.
Interest expense, net of interest income, for the six months ended June 30, 2005 was $23.1 million compared to $15.8 million for the six months ended June 30, 2004, an increase of $7.3 million, or 46%. The weighted-average interest rate on our borrowings increased to 6.4% for the 2005 period from 6.1% for the 2004 period. Our average debt outstanding increased to $802.0 million during 2005 from $565.6 million during 2004 primarily due to the financing associated with our October 2004 pipeline system acquisition.
Page 22
Net refinancing costs associated with our May 2004 debt placement were $16.7 million during the second quarter of 2004. These costs included a $12.7 million debt prepayment premium associated with the early extinguishment of a portion of our previously outstanding Magellan Pipeline notes and a $5.0 million non-cash write-off of the unamortized debt placement costs associated with the retired debt. Partially offsetting these charges was a $1.0 million gain on an interest rate hedge related to the refinancing.
Net income for the six months ended June 30, 2005 was $81.1 million compared to $44.3 million for the six months ended June 30, 2004, an increase of $36.8 million, or 83%. Operating margin increased by $38.8 million, or 31%, primarily due to incremental operating results associated with our recent acquisitions and improved utilization of our other assets. Depreciation and amortization expense increased by $7.6 million between periods, and G&A costs increased by $3.9 million. Net interest expense increased by $7.3 million, but net refinancing costs of $16.7 million during 2004 were not experienced during the 2005 period.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
During the six months ended June 30, 2005, net cash provided by operating activities exceeded distributions paid and net maintenance capital requirements by $7.2 million, and the cash distributions paid during 2005 exceeded the minimum quarterly distribution of $0.2625 per unit by $38.5 million.
Net cash provided by operating activities was $88.8 million and $65.8 million for the six months ended June 30, 2005 and 2004, respectively. The $23.0 million increase was primarily attributable to:
• | increased net income of $24.1 million largely resulting from our operations associated with the pipeline system we acquired in the fourth quarter of 2004 and excluding a $12.7 million prepayment premium during 2004 on a portion of our Magellan Pipeline senior notes, which reduced net income but was classified as cash from financing activities; and |
• | a decrease in cash in the 2004 period due to $10.1 million of cash payments associated with our separation from our former general partner. |
These increases were partially offset by an increase in inventories in 2005 of $13.2 million, compared to a decrease in inventory of $2.6 million in 2004. This increase principally reflects higher product prices in 2005 and increased volumes from a third-party supply agreement assumed as part of our pipeline system acquisition in October 2004. This increase was partially offset by an increase in accrued product purchases in 2005 of $2.3 million, compared to a decrease of $5.0 million in 2004.
Net cash provided (used) by investing activities for the six months ended June 30, 2005 and 2004 was $53.4 million and ($93.6) million, respectively. During 2005, our sales of marketable securities, net of purchases, generated $87.8 million of cash, partially offset by capital expenditures of $34.5 million. In 2004, we acquired: (i) ownership in 14 petroleum products terminals located in the southeastern United States for $25.4 million and (ii) a 50% ownership in Osage Pipeline for $25.0 million. Total maintenance capital spending before reimbursements was $9.3 million and $6.2 million during 2005 and 2004, respectively, and spending for payout projects was $25.2 million and $13.5 million during 2005 and 2004, respectively. Please see Capital Requirements below for further discussion of capital expenditures as well as maintenance capital amounts net of reimbursements.
Net cash used by financing activities for the six months ended June 30, 2005 and 2004 was $73.0 million and $31.6 million, respectively. Net cash used in 2005 primarily consisted of cash distributions paid to our unitholders. Net cash used in 2004 includes the payments of cash distributions to unitholders and net cash used to reduce overall debt, partially offset by proceeds from the issuance of additional equity in second-quarter 2004, capital contributions from our general partner and cash receipts that resulted from unwinding derivative contracts.
During the first half of 2005, we paid $74.1 million in cash distributions to our unitholders and general partner. The quarterly distribution amount associated with the second quarter of 2005 that will be paid during the third quarter of 2005 is $0.4975 per unit, which equates to a total payment of $41.0 million. If we continue to pay cash distributions at this current level and the number of outstanding units remains the same, total cash distributions of $164.3 million would be paid over the next four quarters. Of this amount, $32.3 million, or 20%, is related to our general partner’s 2% ownership interest and incentive distribution rights. In connection with our October 2004 acquisition of pipeline assets, our partnership agreement was amended to reduce the incentive cash distributions paid to our general partner by $5.0 million for distributions related to 2005 and $3.0 million related to 2006. Assuming the current quarterly distribution level and number of outstanding units, our total cash distributions over the next four quarters without this amendment would be $168.8 million, with $36.8 million of this amount, or 22%, paid to our general partner.
Page 23
Capital Requirements
Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending for our businesses consists primarily of:
• | maintenance capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental regulations; and |
• | payout capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, which we refer to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources. |
During second-quarter 2005, we spent maintenance capital of $5.4 million net of reimbursable projects. In addition, we were reimbursed $0.8 million for the following projects, resulting in no cash impact to us:
• | $0.6 million of reimbursable environmental projects covered by our May 2004 indemnity settlement. Please see Environmental below for additional discussion about this settlement; and |
• | $0.2 million of reimbursements from the U.S. government associated with grants for security enhancements at our marine terminal facilities. |
Through June 30, 2005, we have spent $7.5 million on maintenance capital during the year related to our operations, net of $1.8 million of reimbursable projects.
For 2005, we expect to incur maintenance capital expenditures net of reimbursable projects for our existing businesses of approximately $25.0 million. In addition, we intend to spend approximately $10.0 million on maintenance capital projects covered by our May 2004 indemnification settlement (see Environmental below for a discussion of our indemnification settlement).
In addition to maintenance capital expenditures, we also incur payout capital expenditures at our existing facilities. During second-quarter 2005, we spent $15.0 million for organic growth opportunities, and for the six months ended June 30, 2005, we have spent $25.2 million. Based on projects in process, we currently expect to spend approximately $75.0 million on organic growth payout capital during 2005, exclusive of amounts associated with future acquisitions.
Liquidity
As of June 30, 2005, we had $807.0 million of total debt outstanding, as described below. The difference between this amount and the $802.0 million face value of our outstanding debt is due primarily to long-term debt adjustments associated with the fair value hedges we have in place for a portion of our outstanding senior notes.
5.65% Notes due 2016. On October 15, 2004, we sold $250.0 million of 5.65% senior notes due 2016 in an underwritten public offering as part of the long-term financing of the pipeline system assets acquired during October 2004. The notes were issued at 99.9% of par, and we received proceeds after underwriters’ fees and expenses of approximately $247.6 million. Including the impact of pre-issuance hedges associated with these notes and the swap of $100.0 million of the notes from fixed-rate to floating-rate, the weighted average interest rate on the notes for both the three-month and six-month periods ending June 30, 2005 was 5.4%.
Page 24
6.45% Notes due 2014. On May 25, 2004, we sold $250.0 million of 6.45% senior notes due 2014 in an underwritten public offering at 99.8% of par. We received proceeds after underwriters’ fees and expenses of approximately $246.9 million. Including the impact of pre-issuance hedges associated with these notes, the weighted-average interest rate on the notes for both the three-month and six-month periods ending June 30, 2005 was 6.3%.
Magellan Pipeline Notes. In connection with the financing of our acquisition of Magellan Pipeline, we and Magellan Pipeline entered into a note purchase agreement on October 1, 2002. As of June 30, 2005, $302.0 million of senior notes were outstanding pursuant to this agreement. The maturity date of these notes is October 7, 2007, with scheduled prepayments equal to 5% of the outstanding balance due on both October 7, 2005 and October 7, 2006. We guarantee payment of interest and principal by Magellan Pipeline. The notes are unsecured except for cash deposited monthly by Magellan Pipeline into a cash escrow account in anticipation of semi-annual interest payments. The weighted-average interest rates for the senior notes, including the impact of the swap of $250.0 million of the senior notes from fixed-rate to floating-rate in May 2004, were approximately 7.6% and 7.4% for the three-month and six-month periods ending June 30, 2005, respectively.
Revolving Credit Facility. In May 2004, we entered into a five-year $125.0 million revolving credit facility, which we subsequently increased to $175.0 million in September 2004. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.6% to 1.5% based upon our credit ratings. As of June 30, 2005, $1.1 million of the facility was being used for letters of credit, which is not reflected as debt on our balance sheet. No other amounts were outstanding under this facility.
The debt instruments described above include various covenants. In addition to certain financial ratio covenants, these covenants limit our ability to, among other things, incur indebtedness secured by certain liens, encumber our assets, make certain investments, engage in certain sale-leaseback transactions and consolidate, merge or dispose of all or substantially all of our assets. We are in compliance with these covenants.
Management uses interest rate derivatives to manage interest rate risk. In conjunction with our existing debt instruments, we were engaged in the following derivative transactions as of June 30, 2005:
• | In October 2004, we entered into a $100.0 million interest rate swap agreement to hedge against changes in the fair value of a portion of our 5.65% senior notes due 2016. This agreement effectively changes the interest rate on $100.0 million of those notes to a floating rate of six-month LIBOR plus 0.6%, with LIBOR set in arrears. This swap agreement expires on October 15, 2016, the maturity date of the 5.65% senior notes; and |
• | In May 2004, we entered into $250.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline senior notes. These agreements effectively change the interest rate on $250.0 million of the senior notes from a fixed rate of 7.7% to a floating rate of six-month LIBOR plus 3.4%, with LIBOR set in arrears. These swap agreements expire on October 7, 2007, the maturity date of the Magellan Pipeline senior notes. |
Credit Ratings. Our current corporate credit ratings are BBB by Standard and Poor’s and Ba1 on review for potential upgrade by Moody’s Investor Services.
Debt-to-Total Capitalization. The ratio of debt-to-total capitalization is a measure frequently used by the financial community to assess the reasonableness of a company’s debt levels compared to its total capitalization, which is calculated by adding total debt and total partners’ capital. Based on the figures shown in our balance sheet, debt-to-total capitalization was 50% at June 30, 2005. Because accounting rules required the 2002 acquisition of a portion of our petroleum products pipeline system to be recorded at historical book values due to the then affiliate nature of the transaction, the $474.5 million difference between the purchase price and book value at the time of the acquisition was recorded as a decrease to our general partner’s capital account, thus lowering our overall partners’ capital by that amount.
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Environmental
Various governmental authorities in the jurisdictions in which we conduct our operations subject us to environmental laws and regulations. We have accrued liabilities for estimated site restoration costs to be incurred in the future at our facilities and properties, including liabilities for environmental remediation obligations at various sites where we have been identified as a possible responsible party. Under our accounting policies, we record liabilities when site restoration and environmental remediation obligations are either known or considered probable and can be reasonably estimated.
Prior to May 2004, The Williams Companies, Inc. (“Williams”) provided indemnifications to us for assets we previously acquired from it. The indemnifications primarily related to environmental items for periods during which Williams was the owner of those assets. In May 2004, we entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release it from those indemnification obligations. We have received $62.5 million from Williams so far, including $27.5 million on July 1, 2005, and expect to receive the remaining balance in installments of $20.0 million and $35.0 million on July 1 of 2006 and 2007, respectively. As of June 30, 2005, known liabilities that would have been covered by these indemnifications were $39.6 million. In addition, we have spent $10.4 million through June 30, 2005 that would have been covered by these indemnifications.
Further, MMH has indemnified us against certain environmental liabilities. At the time of MMH’s purchase of our general partner interest in June 2003, MMH assumed obligations to indemnify us for $21.9 million of known environmental liabilities. Through June 30, 2005, we have incurred $13.4 million of costs associated with this indemnification obligation, leaving a remaining liability of $8.5 million. Our receivable balance with MMH on June 30, 2005 was $9.4 million.
Other Items
Ownership changes – During second-quarter 2005, MMH sold its remaining limited partner interests in us, including 5.7 million subordinated units and 2.4 million common units. MMH continues to own our general partner interest, representing a 2% ownership in us.
Due to the trading activity of our limited partner units over the past year, we believe that more than 50% of the total interests in our capital and profits had been sold or exchanged over the 12-month period ending April 2005. Because of this, we were terminated for federal income tax purposes and immediately reconstituted as a new partnership, causing a significant reduction in the amount of depreciation deductions allocable to unitholders in 2005. As a result, we estimate that for only the 2005 tax year our unitholders as of April 2005 will be allocated an increased amount of federal taxable income as a percentage of cash distributed to them.
Two-for-one split - During March 2005, the board of directors of our general partner approved a two-for-one split of our limited partner units. On April 12, 2005, holders of record at the close of business on April 5, 2005 received one additional limited partner unit for each limited partner unit owned on that date. We have retroactively changed the number of units and per unit distribution amounts to give effect for this unit split.
New board member – During May 2005, our general partner’s board of directors appointed John P. DesBarres as an independent board member. All eight of our general partner’s board seats are now filled, and we comply with the New York Stock Exchange requirement of three independent directors serving on our audit committee.
Ammonia contracts - We ship ammonia for three customers on our ammonia pipeline system. Our existing transportation agreements with these customers expired at the end of June 2005. We finalized new transportation agreements with our customers that were effective July 1, 2005 and extend through June 30, 2008.
Affiliate transactions - MMH has agreed to provide services to conduct our operations and G&A functions. We pay MMH for these costs, and MMH reimburses us for G&A expenses in excess of a G&A cap defined in our new omnibus agreement. We were allocated $14.8 million and $28.2 million of operating expenses from MMH for the three and six months ended June 30, 2004, respectively, and $16.4 million and $32.3 million for the three and six months ended June 30, 2005, respectively. Further, we were allocated $13.5 million and $26.4 million of G&A expenses from MMH for the three and six months ended June 30, 2004, respectively, and $15.1 million and $30.3 million for the three and six months ended June 30, 2005, respectively. MMH has either reimbursed us or will reimburse us $2.4 million and $3.6 million of G&A costs for the three and six months ended June 30, 2004, respectively, and $0.6 million and $1.6 million for the three and six months ended June 30, 2005, respectively.
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Additionally, MMH has indemnified us against certain environmental costs (see Environmental above).
In March 2004, we acquired a 50% ownership interest in Osage Pipeline and in April 2004 we began operating the Osage pipeline for a fee. During the three and six months ended June 30, 2004, we received $0.2 million for providing this service, and for the three and six months ended June 30, 2005, we received $0.2 million and $0.3 million, respectively. These fees are reported as affiliate management fee revenues.
Related party agreements - MMH is partially owned by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“Carlyle/Riverstone Fund”). Our general partner’s eight-member board of directors includes two representatives of the Carlyle/Riverstone Fund. On January 25, 2005, the Carlyle/Riverstone Fund, through affiliates, acquired an interest in the general partner of SemGroup, L.P. (“SemGroup”) and limited partner interests in SemGroup. The Carlyle/Riverstone Fund’s total combined general and limited partner interest in SemGroup is approximately 30%. The Carlyle/Riverstone Fund has the right to designate three members of SemGroup’s general partner’s nine-member management committee. Currently, Carlyle/Riverstone Fund has only designated one member and until the appointment of the two additional Carlyle/Riverstone designees, the existing designee is entitled to have three votes with respect to any decision by the management committee.
We are a party to a number of transactions with SemGroup and its affiliates, and for the three and six months ended June 30, 2005, we recognized revenues related to: the sale of petroleum products of $25.1 million and $50.9 million, respectively; terminalling and other services of $1.5 million and $2.7 million, respectively; and revenues from leased storage tanks of $0.8 million and $1.2 million, respectively. We also provide common carrier transportation services to SemGroup. Additionally, during the three and six months ended June 30, 2005, we recognized expenses from SemGroup related to our purchase of petroleum products of $13.7 million and $33.5 million, respectively, and expenses for leased storage tanks of $0.3 million and $0.5 million, respectively.
The Carlyle/Riverstone Fund also has an ownership interest in the general partner of Buckeye Partners, L.P. (“Buckeye”). During the three and six months ended June 30, 2005, our operating expenses included $0.0 million and $0.3 million, respectively, of costs we incurred with Norco Pipe Line Company, LLC, which is a subsidiary of Buckeye.
The board of directors of our general partner has adopted a policy to address board of director conflicts of interests. In compliance with this policy, the Carlyle/Riverstone Fund has adopted procedures internally to assure that our proprietary and confidential information is protected from disclosure. As part of these procedures, the Carlyle/Riverstone Fund has agreed that no individual representing them will serve at the same time on our general partner’s board of directors and on the general partner’s board of directors for SemGroup or Buckeye.
NEW ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board (“FASB”) published Statement of Financial Accounting Standard (“SFAS”) No. 154, Accounting Changes and Error Corrections. SFAS No. 154 requires retrospective application to prior periods’ financial statements of every voluntary change in accounting principle unless it is impracticable. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, although earlier application is permitted for changes and corrections made in fiscal years beginning after June 1, 2005. We expect to adopt SFAS No. 154 in January 2006 and its initial adoption is not expected to have a material impact on our financial results, cash flows or financial position.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We may be exposed to market risk through changes in commodity prices and interest rates. We do not have foreign exchange risks. We have established policies to monitor and control these market risks.
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Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is interest rate risk. As of June 30, 2005, we had no variable interest debt outstanding; however, because of certain interest rate swap agreements discussed below, we are exposed to interest rate market risk on $350.0 million of our debt. If LIBOR were to change by 0.25%, our annual interest expense would change by $0.9 million.
During May 2004, we entered into four separate interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline senior notes. We have accounted for these interest rate hedges as fair value hedges. The notional amounts of the interest rate swap agreements total $250.0 million. Under the terms of the agreements, we receive 7.7% (the interest rate of the Magellan Pipeline senior notes) and pay LIBOR plus 3.4%. These hedges effectively convert $250.0 million of our fixed-rate debt to floating-rate debt. The interest rate swap agreements began on May 25, 2004 and expire on October 7, 2007. Payments settle in April and October of each year with LIBOR set in arrears. The fair value of this hedge at June 30, 2005 was $0.9 million.
During October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016. We have accounted for this interest rate hedge as a fair value hedge. The notional amount of the interest rate swap agreement is $100.0 million. Under the terms of the agreement, we receive 5.65% (the interest rate of the senior notes) and pay LIBOR plus 0.6%. This hedge effectively converts $100.0 million of our 5.65% fixed-rate debt to floating-rate debt. The interest rate swap agreement began on October 15, 2004 and expires on October 15, 2016. Payments settle in April and October of each year with LIBOR set in arrears. The fair value of this hedge at June 30, 2005 was $4.8 million.
As of June 30, 2005, we had entered into futures contracts for the acquisition of approximately 0.5 million barrels of petroleum products. The notional value of these agreements, with maturities from August 2005 through December 2005, was approximately $17.0 million.
As of June 30, 2005, we had entered into futures contracts for the sale of approximately 0.8 million barrels of petroleum products. The notional value of these agreements, with maturities from September 2005 through December 2005, was approximately $30.7 million.
ITEM 4. CONTROLS AND PROCEDURES
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) was performed as of the end of the period covered by the date of this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report.
Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting (internal controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant. There have been no substantial changes in our internal controls since December 31, 2004.
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Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements that discuss our expected future results based on current and pending business operations.
Forward-looking statements can be identified by words such as anticipates, believes, expects, estimates, forecasts, projects and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document.
The following are among the important factors that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted:
• | price trends and overall demand for natural gas liquids, refined petroleum products, natural gas, oil and ammonia in the United States; |
• | weather patterns materially different than historical trends; |
• | development of alternative energy sources; |
• | changes in demand for storage in our petroleum products terminals; |
• | changes in supply patterns for our marine terminals due to geopolitical events; |
• | our ability to manage interest rate and commodity price exposures; |
• | changes in our tariff rates implemented by the Federal Energy Regulatory Commission and the United States Surface Transportation Board; |
• | shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services; |
• | changes in the throughput or interruption in service on petroleum products pipelines owned and operated by third parties and connected to our petroleum products terminals or petroleum products pipeline system; |
• | loss of one or more of our three customers on our ammonia pipeline system; |
• | an increase in the competition our operations encounter; |
• | the occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured; |
• | our ability to integrate any acquired assets or businesses into our existing operations; |
• | our ability to successfully identify and close strategic acquisitions and payout projects and make cost saving changes in operations; |
• | changes in general economic conditions in the United States; |
• | changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations; |
• | the cost and effects of legal and administrative claims and proceedings against us or our subsidiaries; |
• | the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or could have other adverse consequences; |
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• | a change of control of our general partner could, under certain circumstances, result in our debt or the debt of our subsidiaries becoming due and payable; |
• | the condition of the capital markets in the United States; |
• | the effect of changes in accounting policies; |
• | the potential that internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price; |
• | MMH’s ability to perform on its environmental and G&A reimbursement obligations to us; |
• | Williams’ ability to pay the amounts owed to us under the indemnification settlement; |
• | the ability of third party entities to perform on their indemnifications to us; |
• | the ability of our general partner or its affiliates to enter into certain agreements which could negatively impact our financial position, results of operations and cash flows; |
• | supply disruption; and |
• | global and domestic economic repercussions from terrorist activities and the government’s response thereto. |
In July 2001, the EPA, pursuant to Section 308 of the Clean Water Act (the “Act”) served an information request to Williams based on a preliminary determination that Williams may have systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline, which we subsequently acquired in April 2002. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumes that all releases are violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those spills may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We have responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million.
On March 22, 2004, we received a Corrective Action Order (CPF 4-2004-5006) from the Department of Transportation Southwest Region Office of Pipeline Safety (“OPS”) as a result of the OPS’ May 2003 inspection of a former affiliate’s Integrity Management Program. The Corrective Action Order focused on timing of repairs and temporary pressure reductions upon discovery of anomalies. The OPS preliminarily assessed us with a civil penalty of $105,000. In September 2004, we presented our position to the OPS that its conclusions regarding the timing of repairs were in error and we are waiting on the OPS’ response to our presentation.
On April 22, 2005, we received a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“NOPV”) from the OPS, as a result of an inspection of our operator qualification records and procedures. The NOPV alleges that probable violations of 49 CFR Part 195.505 occurred in regards to our operator qualification program. The OPS has preliminarily assessed a civil penalty of $183,500. We have submitted a response to the NOPV and have requested a hearing with the OPS.
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We are a party to various legal actions that have arisen in the ordinary course of our business. We do not believe that the resolution of these matters will have a material adverse effect on our financial condition or results of operations.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The annual meeting of our limited partners was held on April 21, 2005. At this meeting, two individuals were elected as Class III directors of our general partner’s board of directors. A tabulation of the voting on this issue follows:
Name |
For |
Withheld |
Abstain |
Broker Non-Votes | ||||
James R. Montague |
28,994,021 | 104,588 | 0 | 0 | ||||
Don R. Wellendorf |
27,070,598 | 2,028,011 | 0 | 0 |
None.
Exhibit 12.1 | – | Ratio of earnings to fixed charges. | ||
Exhibit 31.1 | – | Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer. | ||
Exhibit 31.2 | – | Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial and accounting officer. | ||
Exhibit 32.1 | – | Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer. | ||
Exhibit 32.2 | – | Section 1350 Certification of John D. Chandler, Chief Financial Officer. | ||
Exhibit 99.1 | – | Magellan GP, LLC balance sheets as of June 30, 2005 and December 31, 2004 and notes thereto. |
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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma, on August 5, 2005.
MAGELLAN MIDSTREAM PARTNERS, L.P. | ||
By: | Magellan GP, LLC, | |
its General Partner | ||
/s/ John D. Chandler | ||
John D. Chandler | ||
Chief Financial Officer | ||
and Treasurer (Principal Accounting and | ||
Financial Officer) |
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INDEX TO EXHIBITS
EXHIBIT NUMBER |
DESCRIPTION | |
12.1 | Ratio of earnings to fixed charges. | |
31.1 | Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer. | |
31.2 | Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial and accounting officer. | |
32.1 | Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer. | |
32.2 | Section 1350 Certification of John D. Chandler, Chief Financial Officer. | |
99.1 | Magellan GP, LLC balance sheets as of June 30, 2005 and December 31, 2004 and notes thereto. |
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