Form 10-Q
Table of Contents

 

 

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 March 31, 2010

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.

Large accelerated filer  x        Accelerated filer  ¨        Non-accelerated filer  ¨        Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 of the Exchange Act).    Yes  ¨    No  x

As of May 3, 2010, there were 106,731,349 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol “MMP.”

 

 

 


Table of Contents

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

 

ITEM 1.      FINANCIAL STATEMENTS   

CONSOLIDATED STATEMENTS OF INCOME

   2

CONSOLIDATED BALANCE SHEETS

   3

CONSOLIDATED STATEMENTS OF CASH FLOWS

   4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

   5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

  
  1.    Organization and Basis of Presentation    6
  2.    Product Sales Revenues    7
  3.    Segment Disclosures    8
  4.    Inventory    9
  5.    Employee Benefit Plans    9
  6.    Debt    10
  7.    Derivative Financial Instruments    11
  8.    Commitments and Contingencies    13
  9.    Long-Term Incentive Plan    14
  10.    Distributions    15
  11.    Fair Value Disclosures    16
  12.    Subsequent Events    17
ITEM 2.      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   

Results of Operations

   18

Liquidity and Capital Resources

   20

Other Items

   23

New Accounting Pronouncements

   25
ITEM 3.      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    26
ITEM 4.      CONTROLS AND PROCEDURES    27
Forward-Looking Statements    28
PART II
OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS    30
ITEM 1A.    RISK FACTORS    30
ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS    30
ITEM 3.    DEFAULTS UPON SENIOR SECURITIES    30
ITEM 4.    RESERVED    30
ITEM 5.    OTHER INFORMATION    30
ITEM 6.    EXHIBITS    30

 

1


Table of Contents

PART I

FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)

 

     Three Months Ended
March 31,
 
     2009     2010  

Transportation and terminals revenues

   $ 155,020      $ 173,169   

Product sales revenues

     57,716        156,336   

Affiliate management fee revenue

     190        190   
                

Total revenues

     212,926        329,695   

Costs and expenses:

    

Operating

     60,467        62,109   

Product purchases

     52,630        132,884   

Depreciation and amortization

     23,152        26,342   

General and administrative

     21,136        23,242   
                

Total costs and expenses

     157,385        244,577   

Equity earnings

     519        1,189   
                

Operating profit

     56,060        86,307   

Interest expense

     15,552        21,774   

Interest income

     (221     (4

Interest capitalized

     (936     (848

Debt placement fee amortization

     220        328   

Other income

     (82     —     
                

Income before provision for income taxes

     41,527        65,057   

Provision for income taxes

     357        523   
                

Net income

   $ 41,170      $ 64,534   
                

Allocation of net income:

    

Noncontrolling owners’ interests

   $ 29,148      $ —     

Limited partners’ interest

     12,022        64,534   
                

Net income

   $ 41,170      $ 64,534   
                

Basic and diluted net income per limited partner unit

   $ 0.30      $ 0.60   
                

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation

     39,637        106,843   
                

See notes to consolidated financial statements.

 

2


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

 

     December 31,
2009
    March 31,
2010
 
           (Unaudited)  
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 4,168      $ 6,916   

Accounts receivable (less allowance for doubtful accounts of $139 and $134 at December 31, 2009 and March 31, 2010, respectively)

     72,978        64,162   

Other accounts receivable

     8,216        7,018   

Inventory

     193,001        242,643   

Energy commodity derivatives deposit

     17,943        19,871   

Reimbursable costs

     13,280        11,691   

Other current assets

     14,382        17,451   
                

Total current assets

     323,968        369,752   

Property, plant and equipment

     3,398,606        3,437,316   

Less: accumulated depreciation

     617,989        642,526   
                

Net property, plant and equipment

     2,780,617        2,794,790   

Equity investments

     22,054        22,223   

Long-term receivables

     618        569   

Goodwill

     14,766        14,766   

Other intangibles (less accumulated amortization of $9,974 and $10,491 at December 31, 2009 and March 31, 2010, respectively)

     5,896        5,379   

Debt placement costs (less accumulated amortization of $4,038 and $4,366 at December 31, 2009 and March 31, 2010, respectively)

     10,894        10,566   

Other noncurrent assets

     4,335        4,115   
                

Total assets

   $ 3,163,148      $ 3,222,160   
                
LIABILITIES AND PARTNERS’ CAPITAL     

Current liabilities:

    

Accounts payable

   $ 37,063      $ 55,375   

Accrued payroll and benefits

     30,300        16,787   

Accrued interest payable

     32,877        29,412   

Accrued taxes other than income

     21,261        19,163   

Environmental liabilities

     11,943        11,728   

Deferred revenue

     27,776        28,739   

Accrued product purchases

     36,797        44,050   

Energy commodity derivatives contracts

     9,257        12,924   

Other current liabilities

     22,123        21,111   
                

Total current liabilities

     229,397        239,289   

Long-term debt

     1,680,004        1,734,109   

Long-term pension and benefits

     22,582        25,353   

Other noncurrent liabilities

     12,317        13,684   

Environmental liabilities

     22,494        21,127   

Commitments and contingencies

    

Partners’ capital:

    

Limited partner unitholders (106,588 units and 106,731 units outstanding at December 31, 2009 and March 31, 2010, respectively)

     1,204,355        1,194,879   

Accumulated other comprehensive loss

     (8,001     (6,281
                

Total partners’ capital

     1,196,354        1,188,598   
                

Total liabilities and partners’ capital

   $ 3,163,148      $ 3,222,160   
                

See notes to consolidated financial statements.

 

3


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

 

     Three Months Ended
March 31,
 
     2009     2010  

Operating Activities:

    

Net income

   $ 41,170      $ 64,534   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization expense

     23,152        26,342   

Debt placement fee amortization

     220        328   

Loss (gain) on sale and retirement of assets

     1,253        (1,617

Equity earnings

     (519     (1,189

Distributions from equity investment

     519        1,020   

Equity-based incentive compensation expense

     3,217        4,959   

Amortization of prior service cost (credit) and actuarial loss

     (15     15   

Changes in operating assets and liabilities:

    

Accounts receivable and other accounts receivable

     (5,925     10,014   

Inventory

     (18,091     (49,642

Energy commodity derivative contracts, net of derivative deposits

     (5,211     1,821   

Reimbursable costs

     (3,591     1,589   

Accounts payable

     3,245        19,850   

Accrued payroll and benefits

     (6,001     (13,513

Accrued interest payable

     6,786        (3,465

Accrued taxes other than income

     (1,703     (2,098

Accrued product purchases

     16,355        7,253   

Current and noncurrent environmental liabilities

     (2,524     (1,582

Other current and noncurrent assets and liabilities

     7,368        8,718   
                

Net cash provided by operating activities

     59,705        73,337   

Investing Activities:

    

Property, plant and equipment:

    

Additions to property, plant and equipment

     (47,585     (41,553

Proceeds from sale and disposition of assets

     —          3,037   

Changes in accounts payable related to capital expenditures

     (301     (1,538

Distributions in excess of equity investment earnings

     1,031        —     
                

Net cash used by investing activities

     (46,855     (40,054

Financing Activities:

    

Distributions paid

     (70,027     (75,779

Net borrowings under revolver

     42,000        50,600   

Increase (decrease) in outstanding checks

     2,490        (1,672

Settlement of tax withholdings on long-term incentive compensation

     (3,450     (3,371

Costs associated with the simplification of capital structure

     (5,345     —     

Other

     —          (313
                

Net cash used by financing activities

     (34,332     (30,535
                

Change in cash and cash equivalents

     (21,482     2,748   

Cash and cash equivalents at beginning of period

     37,912        4,168   
                

Cash and cash equivalents at end of period

   $ 16,430      $ 6,916   
                

Supplemental non-cash financing activity:

    

Issuance of limited partner units in settlement of long-term incentive plan awards

   $ 1,943      $ 2,034   

See notes to consolidated financial statements.

 

4


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

 

     Three Months Ended
March 31,
 
     2009     2010  

Net income

   $ 41,170      $ 64,534   

Other comprehensive income:

    

Net loss on commodity hedges

     —          (289

Reclassification of net gain on interest rate cash flow hedges to interest expense

     (41     (41

Reclassification of net loss on commodity hedges to product sales revenues

     —          2,035   

Amortization of prior service cost (credit) and actuarial loss

     (15     15   
                

Total other comprehensive income (loss)

     (56     1,720   
                

Comprehensive income

     41,114        66,254   

Comprehensive income attributable to non-controlling owners’ interest in consolidated subsidiaries

     (29,093     —     
                

Comprehensive income attributable to partners’ capital

   $ 12,021      $ 66,254   
                

See notes to consolidated financial statements.

 

5


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Organization and Basis of Presentation

Organization

Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P. together with its subsidiaries. We are a Delaware limited partnership, and our limited partner units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC (“MMP GP”), a Delaware limited liability company, serves as our general partner and is a wholly-owned subsidiary of ours.

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 marketing strategies and business knowledge.

Basis of Presentation

In September 2009, pursuant to a Simplification Agreement (the “Simplification Agreement”), approximately 39.6 million of our limited partner units were issued to unitholders of Magellan Midstream Holdings, L.P. (“Holdings”), Magellan Midstream Holdings GP, LLC (Holdings’ general partner) and MMP GP were contributed to us by Holdings and Holdings was dissolved (collectively, the “simplification”). A full description of the Simplification Agreement was provided in our Annual Report on Form 10-K for the year ended December 31, 2009. As a result of the simplification, both Holdings’ general partner and MMP GP became our wholly-owned subsidiaries. Therefore, we no longer pay incentive distribution rights and all of the non-controlling owners’ interests that existed prior to the simplification were acquired.

The historical financial statements included in this report were originally those of Holdings. Although Magellan Midstream Partners, L.P. was the surviving entity for legal purposes, Holdings was the surviving entity for accounting purposes; consequently, the name of these financial statements was changed from “Magellan Midstream Holdings, L.P.” to “Magellan Midstream Partners, L.P.” The reconciliation of net income as reported prior to the simplification to the net income reported in these financial statements is as follows (in thousands):

 

     Three Months Ended
March  31, 2009
 

Net income, as previously reported

   $ 45,231   

Depreciation expense (a)

     (3,837

Other (b)

     (224
        

Net income

   $ 41,170   
        

 

  (a) Holdings acquired 54.6% of general and limited partner interests in us on June 17, 2003. At that time, Holdings recorded our property, plant and equipment at 54.6% of fair values (reflecting Holdings’ ownership percentages in us at that time) and at 45.4% of historical carrying values. As a result of this “step-up” in basis, Holdings recorded higher depreciation expense.
  (b) Other adjustments included the amortization of the step-up to fair value made by Holdings on June 17, 2003 of other items and stand-alone general and administrative (“G&A”) expenses that Holdings incurred.

Basic and diluted earnings per unit as originally reported for the three months ended March 31, 2009 was $0.19. The difference between this amount and the $0.30 currently reported for basic and diluted earnings per unit for that period is due to the retrospective restatement of the weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation as a result of the simplification.

In the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2009, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2010, and the results of operations for the three months ended March 31, 2009 and 2010 and cash flows for the three months ended March 31, 2009 and 2010. The results of operations for the three months ended March 31, 2010 are not necessarily indicative of the results to be expected for the full year ending December 31, 2010.

 

6


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report 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, 2009.

 

2. Product Sales Revenues

The amounts reported as product sales revenues on our consolidated statements of income include revenues from the sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange (“NYMEX”) contracts. We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending and fractionation activities. During the first quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging. However, beginning in July 2009, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and were recorded as cash flow hedges. We also use NYMEX contracts as economic hedges against changes in the value of petroleum products associated with linefill and working inventory associated with our Houston-to-El Paso, Texas pipeline section (the pipeline we acquired from Longhorn Partners Pipeline, L.P. in July 2009), none of which have qualified for hedge accounting treatment. As a result of the various types of NYMEX contracts we execute, the amounts reported as product sales revenues can include amounts from the following sources:

 

   

The physical sale of petroleum products;

 

   

Mark-to-market adjustments of NYMEX contracts that did not qualify for hedge accounting;

 

   

The effective portion of the gains or losses of NYMEX contracts that matured during the period, which were accounted for as cash flow hedges; and

 

   

Any ineffective portion of NYMEX contracts accounted for as cash flow hedges.

For the three months ended March 31, 2009 and 2010, product sales revenues included the following (in thousands):

 

     Three Months Ended  
     March 31,
2009
    March 31,
2010
 

Physical sale of petroleum products

   $ 61,254      $ 165,305   

NYMEX contract adjustments:

    

Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our petroleum products blending and fractionation activities

     (3,538     (2,282

The effective portion of gains and losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our petroleum products blending and fractionation activities

     —          (2,035

Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill and working inventory

     —          (4,652
                

Total NYMEX contract adjustments

     (3,538     (8,969
                

Total product sales revenues

   $ 57,716      $ 156,336   
                

The increase in physical sale of petroleum products between the three months ended March 31, 2009 and the three months ended March 31, 2010 was due to the physical sale of petroleum products related to management of the linefill and working inventory associated with the Houston-to-El Paso pipeline section we acquired in July 2009.

 

7


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

3. Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenues from affiliates and external customers, operating expenses, product purchases and equity earnings. Transactions between our business segments are conducted and recorded on the same basis as transactions with third-party entities.

Management believes that investors benefit from having access to the same financial measures that they use. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“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 tables. Operating profit includes expense items, such as depreciation and amortization expense and G&A costs, that management does not consider when evaluating the core profitability of our operations.

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum products terminals segment to our petroleum products pipeline system segment. The East Houston terminal is an origin for our pipeline system and has been increasingly utilized as a pipeline terminal. For instance, we are building a connection between the East Houston terminal and our recently-acquired Houston-to-El Paso pipeline section to serve as an origin for that pipeline. Further, we are in the final stages of constructing a pipeline connection from our East Houston terminal to a third-party pipeline near Houston to allow us to transport petroleum products from the Port Arthur, Texas refinery region into our pipeline markets. We are commercially managing the East Houston terminal as a pipeline facility to provide seamless marketing to our customers so they no longer must work with different segments to do business at the East Houston facility. Since the beginning of 2010, this facility has been realigned under petroleum products pipeline management and its operating results have been reported both internally and externally as part of that segment. As a result, historical financial results for our segments have been adjusted to conform to the current period’s presentation. The historical adjustments to revenues and expenses were not material and consolidated operating profit did not change as a result of this reclassification. The net book value of the asset transferred was approximately $79.0 million.

 

     Three Months Ended March 31, 2009  
     (in thousands)  
     Petroleum
Products
Pipeline
System
    Petroleum
Products
Terminals
   Ammonia
Pipeline
System
    Intersegment
Eliminations
    Total  

Transportation and terminals revenues

   $ 114,901      $ 37,406    $ 3,229      $ (516   $ 155,020   

Product sales revenues

     54,232        3,484      —          —          57,716   

Affiliate management fee revenue

     190        —        —          —          190   
                                       

Total revenues

     169,323        40,890      3,229        (516     212,926   

Operating expenses

     43,000        15,337      3,113        (983     60,467   

Product purchases

     51,588        1,536      —          (494     52,630   

Equity earnings

     (519     —        —          —          (519
                                       

Operating margin

     75,254        24,017      116        961        100,348   

Depreciation and amortization expense

     14,778        7,061      352        961        23,152   

G&A expenses

     15,337        5,179      620        —          21,136   
                                       

Operating profit (loss)

   $ 45,139      $ 11,777    $ (856   $ —        $ 56,060   
                                       

 

8


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

     Three Months Ended March 31, 2010  
     (in thousands)  
     Petroleum
Products
Pipeline
System
    Petroleum
Products
Terminals
   Ammonia
Pipeline
System
   Intersegment
Eliminations
    Total  

Transportation and terminals revenues

   $ 122,915      $ 45,659    $ 5,093    $ (498   $ 173,169   

Product sales revenues

     152,226        4,110      —        —          156,336   

Affiliate management fee revenue

     190        —        —        —          190   
                                      

Total revenues

     275,331        49,769      5,093      (498     329,695   

Operating expenses

     42,820        16,373      3,981      (1,065     62,109   

Product purchases

     130,776        2,606      —        (498     132,884   

Equity earnings

     (1,189     —        —        —          (1,189
                                      

Operating margin

     102,924        30,790      1,112      1,065        135,891   

Depreciation and amortization expense

     16,861        8,059      357      1,065        26,342   

G&A expenses

     16,852        5,774      616      —          23,242   
                                      

Operating profit

   $ 69,211      $ 16,957    $ 139    $ —        $ 86,307   
                                      

 

4. Inventory

Inventory at December 31, 2009 and March 31, 2010 was as follows (in thousands):

 

     December 31,
2009
   March 31,
2010

Refined petroleum products

   $ 152,776    $ 186,682

Natural gas liquids

     17,263      18,197

Transmix

     17,230      31,981

Additives

     5,732      5,783
             

Total inventory

   $ 193,001    $ 242,643
             

 

5. Employee Benefit Plans

We sponsor two union pension plans for certain employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension plans and other postretirement benefit plan during the three months ended March 31, 2009 and 2010 (in thousands):

 

     Three Months Ended
March 31, 2009
    Three Months Ended
March 31, 2010
 
     Pension
Benefits
    Other Post-
Retirement
Benefits
    Pension
Benefits
    Other Post-
Retirement
Benefits
 

Components of net periodic benefit costs:

        

Service cost

   $ 1,389      $ 116      $ 1,937      $ 88   

Interest cost

     784        279        866        203   

Expected return on plan assets

     (686     —          (854     —     

Amortization of prior service cost (credit)

     77        (213     77        (213

Amortization of net actuarial loss

     57        64        151        —     
                                

Net periodic benefit cost

   $ 1,621      $ 246      $ 2,177      $ 78   
                                

 

9


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

6. Debt

Consolidated debt at December 31, 2009 and March 31, 2010 was as follows (in thousands):

 

     December 31,
2009
   March 31,
2010
   Weighted-Average
Interest Rate at
March 31, 2010 (1)

Revolving credit facility

   $ 101,600    $ 152,200    0.6%

6.45% Notes due 2014

     249,732      249,745    6.3%

5.65% Notes due 2016

     252,897      252,789    5.7%

6.40% Notes due 2018

     260,340      260,036    5.9%

6.55% Notes due 2019

     566,500      570,401    4.6%

6.40% Notes due 2037

     248,935      248,938    6.3%
                

Total debt

   $ 1,680,004    $ 1,734,109   
                

 

  (1) Weighted-average interest rate includes the impact of interest rate swaps and the amortization of discounts and gains and losses realized on various cash flow hedges (see Note 7—Derivative Financial Instruments for detailed information regarding the amortization of these gains and losses).

Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of the associated notes.

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used for general purposes, including capital expenditures. As of March 31, 2010, $152.2 million was outstanding under this facility and $4.4 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million. The outstanding principal amount of the notes was increased by $3.1 million and $3.0 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap (see Note 7—Derivative Financial Instruments).

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased by $10.4 million and $10.1 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps (see Note 7—Derivative Financial Instruments).

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt (see Note 7—Derivative Financial Instruments). The outstanding principal amount of the notes was increased (decreased) by $(1.6) million and $2.6 million at December 31, 2009 and March 31, 2010, respectively, for the fair value less accrued interest of the associated interest rate swap agreements.

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $248.9 million.

The revolving credit facility and notes described above are senior indebtedness.

 

10


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

7. Derivative Financial Instruments

Commodity Derivatives

Our petroleum products blending activities generate gasoline products and we can estimate the timing and quantities of sales of these products. We use a combination of forward sales contracts and NYMEX contracts to lock in most of the product margins realized from our blending activities. We account for the forward sales contracts we use in our blending activities as normal sales.

As discussed in Note 2—Product Sales Revenues, we use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending activities. In third quarter 2009, we began using NYMEX contracts as economic hedges against the changes in value of the linefill petroleum products purchased in connection with our Houston-to-El Paso pipeline section. Through the second quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging. However, beginning in July 2009, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and have been recorded as cash flow hedges. None of the NYMEX contracts we used as economic hedges of the linefill of our Houston-to-El Paso pipeline section qualified for hedge accounting treatment.

At March 31, 2010, the fair value of open NYMEX contracts, representing 2.4 million barrels of petroleum products, was a net liability of $14.1 million, of which $12.9 million was recorded as energy commodity derivatives contracts and $1.2 million was recorded as noncurrent liabilities on our consolidated balance sheet. These open NYMEX contracts mature between April 2010 and July 2011. At March 31, 2010, we had made margin deposits of $19.9 million for these contracts, which were recorded as an energy commodity derivatives deposit on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet.

Interest Rate Derivatives

In June and August 2009, we entered into $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% for the $150.0 million swaps and 2.34% for the other $100.0 million. The agreements terminate in June 2019, which is the maturity date of the related notes. Payments settle in January and July each year. During each period, we record the impact of these swaps based on the forward LIBOR curve. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to our interest expense. These interest rate derivatives contain credit-risk-related contingent features. These contingent features provide that in the event of our default on any obligation of $25.0 million or more or a merger in which our credit rating becomes “materially weaker,” which would generally be interpreted as falling below investment grade, the counterparties to our interest rate derivatives agreements could terminate those agreements and require immediate settlement. None of our interest rate derivatives were in a net liability position as of March 31, 2010.

The changes in derivative gains included in accumulated other comprehensive loss (“AOCL”) for the three months ended March 31, 2009 and 2010 were as follows (in thousands):

 

     Three Months Ended
March  31,
 

Derivative Gains Included in AOCL

   2009     2010  

Beginning balance

   $ 3,653      $ 1,743   

Net loss on commodity hedges

     —          (289

Reclassification of net gain on cash flow hedges to interest expense

     (41     (41

Reclassification of net loss on commodity hedges to product sales revenues

     —          2,035   
                

Ending balance

   $ 3,612      $ 3,448   
                

As of March 31, 2010, the net gain estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.2 million.

 

11


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The following is a summary of the current impact of our historical derivative activity on long-term debt resulting from the termination of or the discontinuance of hedge accounting treatment of fair value hedges as of December 31, 2009 and March 31, 2010, and for the three months ended March 31, 2009 and 2010 (in thousands):

 

          Unamortized Amount
Recorded in Long-term Debt
   Amount Reclassified to Interest
Expense from Long-term Debt
 

Hedge

   Total Gain
Realized
   As of
December 31, 2009
   As of
March 31, 2010
   Three Months
Ended

March  31, 2009
    Three Months
Ended

March  31, 2010
 

Fair value hedges (date executed):

             

Interest rate swaps 6.40% Notes (July 2008)

   $ 11,652    $ 10,358    $ 10,054    $ (304   $ (304

Interest rate swaps 5.65% Notes (October 2004)

     3,830      3,093      2,979      (114     (114
                                 

Total fair value hedges

      $ 13,451    $ 13,033    $ (418   $ (418
                                 

The following is a summary of the effect of derivatives accounted for under ASC 815-25, Derivatives and Hedging—Fair Value Hedges, that were designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2010 (in thousands):

 

Derivative Instrument

  

Location of Gain

Recognized on Derivative

   Amount of Gain
Recognized  on

Derivative
   Amount of  Interest
Expense Recognized on
Fixed-Rate Debt (Related
Hedged Item)
 

Interest rate swap agreements

  

Interest expense

   $ 3,016    $ (8,641

The following is a summary of the effect of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2009 and 2010 (in thousands):

 

     Three Months Ended March 31,  2009
Effective Portion
 

Derivative Instrument

   Amount of Gain
Recognized in
AOCL on Derivative
   

Location of Gain Reclassified from

AOCL into Income

   Amount of Gain  Reclassified
from AOCL into Income
 

Interest rate swap agreements

   $ —       

Interest expense

   $ 41   
     Three Months Ended March 31,  2010
Effective Portion
 

Derivative Instrument

   Amount of Gain
(Loss)  Recognized in
AOCL on Derivative
   

Location of Gain (Loss) Reclassified from

AOCL into Income

   Amount of Gain (Loss)  Reclassified
from AOCL into Income
 

Interest rate swap agreements

   $ —       

Interest expense

   $ 41   

NYMEX commodity contracts

     (289  

Product sales revenues

     (2,035
                   

Total cash flow hedges

   $ (289  

Total

   $ (1,994
                   

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2009 or 2010.

The following is a summary of the effect of derivatives accounted for under ASC 815-10-35; Paragraph 2, Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2009 and 2010 (in thousands):

 

          Amount of Gain (Loss) Recognized on Derivative  

Derivative Instrument

   Location of Gain  (Loss)
Recognized on Derivative
   Three Months Ended
March 31, 2009
    Three Months Ended
March 31, 2010
 

Interest rate swap agreements

   Other income    $ 82      $ —     

NYMEX commodity contracts

   Product sales revenues      (3,538     (6,934
                   
   Total    $ (3,456   $ (6,934
                   

 

12


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The following is a summary of the amounts included in our consolidated balance sheet of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were designated as hedging instruments as of December 31, 2009 and March 31, 2010 (in thousands):

 

    

December 31, 2009

    

Asset Derivatives

  

Liability Derivatives

Derivative Instrument

  

Balance Sheet Location

   Fair Value   

Balance Sheet Location

   Fair Value

Interest rate swap agreements, current portion

  

Other current assets

   $ 4,446   

Other current liabilities

   $ —  

Interest rate swap agreements, noncurrent portion

  

Other noncurrent assets

     —     

Other noncurrent liabilities

     1,649

NYMEX commodity contracts

  

Energy commodity derivatives contracts

     —     

Energy commodity derivatives contracts

     1,211
                   
  

Total

   $ 4,446   

Total

   $ 2,860
                   

 

    

March 31, 2010

    

Asset Derivatives

  

Liability Derivatives

Derivative Instrument

  

Balance Sheet Location

   Fair Value   

Balance Sheet Location

   Fair Value

Interest rate swap agreements, current portion

  

Other current assets

   $ 8,243   

Other current liabilities

   $ —  

Interest rate swap agreements, noncurrent portion

  

Other noncurrent assets

     —     

Other noncurrent liabilities

     3,882
                   
  

Total

   $ 8,243   

Total

   $ 3,882
                   

The following is a summary of the amounts included in our consolidated balance sheet of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were not designated as hedging instruments as of December 31, 2009 and March 31, 2010 (in thousands):

 

    

December 31, 2009

    

Asset Derivatives

  

Liability Derivatives

Derivative Instrument

  

Balance Sheet Location

   Fair Value   

Balance Sheet Location

   Fair Value

NYMEX commodity contracts

  

Energy commodity derivatives contracts

   $ —     

Energy commodity derivatives contracts

   $ 8,046

NYMEX commodity contracts

  

Other noncurrent assets

     —     

Other noncurrent liabilities

     1,146
                   
  

Total

   $ —     

Total

   $ 9,192
                   

 

    

March 31, 2010

    

Asset Derivatives

  

Liability Derivatives

Derivative Instrument

  

Balance Sheet Location

   Fair Value   

Balance Sheet Location

   Fair Value

NYMEX commodity contracts

  

Energy commodity derivatives contracts

   $ —     

Energy commodity derivatives contracts

   $ 12,924

NYMEX commodity contracts

  

Other noncurrent assets

     —     

Other noncurrent liabilities

     1,228
                   
  

Total

   $ —     

Total

   $ 14,152
                   

 

8. Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $34.4 million and $32.9 million at December 31, 2009 and March 31, 2010, respectively. Environmental liabilities 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 liabilities will be paid over the next 10 years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expense was $1.3 million and $2.4 million for the three months ended March 31, 2009 and 2010, respectively.

Unrecognized Contingent Liability: Clean Air Act. Section 185 of the Clean Air Act (“CAA 185”) requires each state to assess fees against major stationary emission sources in “severe” or “extreme” non-attainment areas. During 2009, the Texas Commission on Environmental Quality (“TCEQ”), in response to an Environmental Protection Agency (“EPA”) request, issued proposed rules which, if adopted as proposed, may result in fees assessed against our Galena Park, Texas terminal for the 2008 and 2009 calendar years of up to $8.1 million and $4.8 million, respectively.

 

13


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Based on the monitoring data for the Houston/Galveston/Brazoria, Texas area prepared by the TCEQ, which indicates that the area obtained the ozone standard for past three consecutive years, the TCEQ is pursuing a Termination Determination from the EPA, which, if approved by the EPA, would terminate any requirements by the TCEQ to pursue actions under CAA 185. However, an environmental group has submitted a petition in Federal Court challenging the Termination Determination process. We believe we will not be assessed penalties under CAA 185 and at March 31, 2010 we had no amounts accrued for this matter.

Environmental Receivables. Receivables from insurance carriers related to environmental matters were $3.9 million at both December 31, 2009 and March 31, 2010.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $7.0 million as of March 31, 2010. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

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 these 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 financial position, results of operations or cash flows.

 

9. Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate of 3.2 million of our limited partner units. The remaining units available under the LTIP at March 31, 2010 total 1.0 million. The compensation committee of our general partner’s board of directors administers the LTIP.

Our equity-based incentive compensation expense was as follows (in thousands):

 

     Three Months Ended
     March 31, 2009    March 31, 2010
     Equity
Method
   Liability
Method
   Total    Equity
Method
   Liability
Method
   Total

2007 awards

   $ 934    $ 195    $ 1,129    $ —      $ 6    $ 6

2008 awards

     1,256      292      1,548      2,463      1,106      3,569

2009 awards

     349      95      444      350      274      624

2010 awards

     —        —        —        456      130      586

Retention awards

     96      —        96      174      —        174
                                         

Total

   $ 2,635    $ 582    $ 3,217    $ 3,443    $ 1,516    $ 4,959
                                         

In January 2010, the cumulative amounts of the January 2007 LTIP awards were settled by issuing 140,317 limited partner units and distributing those units to the LTIP participants. The minimum tax withholdings associated with this settlement and employer taxes totaling $3.9 million were paid in January 2010.

 

14


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

In February 2010, the compensation committee of our general partners’ board of directors approved 241,327 unit award grants pursuant to our LTIP. These award grants have a three-year vesting period that will end on December 31, 2012.

 

10. Distributions

Distributions we paid during 2009 and 2010 were as follows (in thousands, except per unit amounts):

 

Payment Date

   Per Unit  Cash
Distribution
Amount
   Limited Partner
Units
   General
Partner (a)
   Total Cash
Distribution

02/13/09

   $ 0.71    $ 47,537    $ 23,478    $ 71,015

05/15/09

     0.71      47,537      23,478      71,015

08/14/09

     0.71      47,537      23,478      71,015

11/13/09

     0.71      75,677      —        75,677
                           

Total

   $ 2.84    $ 218,288    $ 70,434    $ 288,722
                           

02/12/10

   $ 0.71    $ 75,779    $ —      $ 75,779

05/14/10 (b)

     0.72      76,847      —        76,847
                           

Total

   $ 1.43    $ 152,626    $ —      $ 152,626
                           

 

(a)    Includes amounts paid to MMP GP for its incentive distribution rights.

(b)    Our general partner declared this cash distribution in April 2010 to be paid on May 14, 2010 to unitholders of record at the close of business on May 7, 2010

Distributions paid during 2009 by Holdings to its limited partners prior to its dissolution were as follows (in thousands, except per unit amounts):

 

Payment Date

   Per Unit Cash
Distribution
Amount
   Total Cash
Distribution

02/13/09

   $ 0.56759    $ 22,490

05/15/09

     0.56759      22,490

08/14/09

     0.56759      22,490
             

Total

   $ 1.70277    $ 67,470
             

Total distributions paid were as follows (in thousands):

 

     Three Months Ended
March 31,
     2009     2010

Cash distributions we paid

   $ 71,015      $ 75,779

Less distributions we paid to our general partner

     (23,478     —  
              

Distributions we paid to outside owners

     47,537        75,779

Cash distributions paid by Holdings to its outside owners

     22,490        —  
              

Total distributions

   $ 70,027      $ 75,779
              

 

15


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

11. Fair Value Disclosures

Fair Value of Financial Instruments

We used the following methods and assumptions in estimating our fair value disclosure for financial instruments:

Cash and cash equivalents. The carrying amounts reported in the balance sheet approximate fair value due to the short-term maturity or variable rates of these instruments.

Energy commodity derivatives deposit. This asset represents a short-term deposit we paid associated with our energy commodity derivatives contracts. The carrying amount reported in the balance sheet approximates fair value as the deposits paid change daily in relation to the associated contracts.

Long-term receivables. Fair value was determined by estimating the present value of future cash flows using a risk-free rate of interest.

Energy commodity derivatives contracts. The carrying amounts reported in the balance sheet represent fair value of the liability (see Note 7—Derivative Financial Instruments).

Debt. The fair value of our publicly traded notes, excluding the value of interest rate swaps qualifying as fair value hedges, was based on the prices of those notes at December 31, 2009 and March 31, 2010. The carrying amount of borrowings under our revolving credit facility approximates fair value due to the variable rates of that instrument.

Interest rate swaps. Fair value was determined based on an assumed exchange, at each period end, in an orderly transaction with the financial institution counterparties of the interest rate derivative agreements (see Note 7 – Derivative Financial Instruments). The exchange value is calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

The following table reflects the carrying amounts and fair values of our financial instruments as of December 31, 2009 and March 31, 2010 (in thousands):

 

Assets (Liabilities)

   December 31, 2009     March 31, 2010  
   Carrying
Amount
    Fair
Value
    Carrying
Amount
    Fair
Value
 

Cash and cash equivalents

   $ 4,168      $ 4,168      $ 6,916      $ 6,916   

Energy commodity derivatives contracts (current)

     (9,257     (9,257     (12,924     (12,924

Energy commodity derivatives contracts (noncurrent)

     (1,146     (1,146     (1,228     (1,228

Long-term receivables

     618        589        569        548   

Energy commodity derivatives deposit

     17,943        17,943        19,871        19,871   

Debt

     (1,680,004     (1,777,064     (1,734,109     (1,836,825

Interest rate swaps (current)

     4,446        4,446        8,243        8,243   

Interest rate swaps (noncurrent)

     (1,649     (1,649     (3,882     (3,882

 

16


Table of Contents

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Fair Value Measurements

The following tables summarize the fair value measurements of our NYMEX commodity contracts and interest rate swaps as of December 31, 2009 and March 31, 2010, based on the three levels established by ASC 820-10-50; Paragraph 2, Fair Value Measurements and Disclosures—Overall—Disclosure (in thousands):

 

Assets (Liabilities)

         Asset Fair Value Measurements as of
December 31, 2009 using:
   Total     Quoted Prices in
Active  Markets

for Identical
Assets
(Level 1)
    Significant
Other
Observable

Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)

Energy commodity derivatives contracts (current)

   $ (9,257   $ (9,257   $ —        $ —  

Energy commodity derivatives contracts (noncurrent)

     (1,146     (1,146 )     —          —  

Interest rate swaps (current)

     4,446        —          4,446        —  

Interest rate swaps (noncurrent)

     (1,649     —          (1,649     —  

 

Assets (Liabilities)

         Asset Fair Value Measurements as of
March 31, 2010 using:
   Total     Quoted Prices in
Active  Markets
for Identical
Assets
(Level 1)
    Significant
Other
Observable

Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)

Energy commodity derivatives contracts (current)

   $ (12,924   $ (12,924   $ —        $ —  

Energy commodity derivatives contracts (noncurrent)

     (1,228     (1,228 )     —          —  

Interest rate swaps (current)

     8,243        —          8,243        —  

Interest rate swaps (noncurrent)

     (3,882     —          (3,882     —  

 

12. Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

In April 2010, our general partner declared a quarterly distribution of $0.72 per unit to be paid on May 14, 2010, to unitholders of record at the close of business on May 7, 2010. The total cash distributions to be paid are $76.8 million (see Note 10—Distributions for details).

 

17


Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

We are 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 March 31, 2010, our three operating segments included:

 

   

petroleum products pipeline system, which is primarily comprised of our 9,500-mile petroleum products pipeline system, including 52 terminals;

 

   

petroleum products terminals, which principally includes our six marine terminal facilities and 27 inland terminals; and

 

   

ammonia pipeline system, representing our 1,100-mile ammonia pipeline and six associated terminals.

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum products terminals segment to our petroleum products pipeline system segment due to its increasing usage as a pipeline terminal. Since the beginning of 2010, this facility has been under petroleum products pipeline management and its operating results have been reported both internally and externally as part of that segment. As a result, historical financial results for our segments have been adjusted to conform to the current period’s presentation. This historical reclassification did not materially impact segment financial results and consolidated financial results did not change.

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 partnership. 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, 2009.

Recent Developments

Cash Distribution. During April 2010, the board of directors of our general partner declared a quarterly cash distribution of $0.72 per unit for the period of January 1, 2010 through March 31, 2010. This quarterly cash distribution will be paid on May 14, 2010 to unitholders of record on May 7, 2010. Total distributions to be paid under this declaration are approximately $76.8 million.

Health Care Reform. On March 23, 2010, the Patient Protection and Affordable Care Act was enacted and on March 30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010 was also enacted (collectively, the “Health Care Acts”). The initial impact of the Health Care Acts for most entities will be that the employers which receive the Medicare Part D subsidy will recognize the deferred tax effects of the reduced deductibility of the postretirement prescription drug coverage in the period the Health Care Acts were enacted. Because our postretirement benefit plans do not receive this Medicare Part D subsidy, we will be unaffected by this provision of the Health Care Acts.

As with any significant government action, the other provisions of the Health Care Acts are still being assessed, and we expect that government agencies, such as the Departments of the Treasury, Health and Human Services and Labor will provide additional regulations or interpretations of certain provisions of the Health Care Acts in the future. These additional regulations, interpretations or other guidance may provide clarification of certain aspects of the Health Care Acts. We will evaluate this guidance when it is received to determine whether it results in a significant event for our plans.

Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed 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 following table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of our operations. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in this table. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.

 

18


Table of Contents

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2010

 

     Three Months Ended
March  31,
    Variance
Favorable  (Unfavorable)
 
     2009     2010     $ Change     % Change  

Financial Highlights ($ in millions, except operating statistics)

        

Transportation and terminals revenues:

        

Petroleum products pipeline system

   $ 114.9      $ 122.9      $ 8.0      7   

Petroleum products terminals

     37.4        45.7        8.3      22   

Ammonia pipeline system

     3.2        5.1        1.9      59   

Intersegment eliminations

     (0.5     (0.5     —        —     
                          

Total transportation and terminals revenues

     155.0        173.2        18.2      12   

Affiliate management fee revenue

     0.2        0.2        —        —     

Operating expenses:

        

Petroleum products pipeline system

     43.0        42.9        0.1      —     

Petroleum products terminals

     15.3        16.4        (1.1   (7

Ammonia pipeline system

     3.1        4.0        (0.9   (29

Intersegment eliminations

     (1.0     (1.1     0.1      10   
                          

Total operating expenses

     60.4        62.2        (1.8   (3

Product margin:

        

Product sales

     57.7        156.4        98.7      171   

Product purchases

     52.6        132.9        (80.3   (153
                          

Product margin

     5.1        23.5        18.4      361   

Equity earnings

     0.5        1.2        0.7      140   
                          

Operating margin

     100.4        135.9        35.5      35   

Depreciation and amortization expense

     23.2        26.4        (3.2   (14

G&A expense

     21.1        23.2        (2.1   (10
                          

Operating profit

     56.1        86.3        30.2      54   

Interest expense (net of interest income and interest capitalized)

     14.4        20.9        (6.5   (45

Debt placement fee amortization

     0.2        0.3        (0.1   (50

Other income

     (0.1     —          (0.1   (100
                          

Income before provision for income taxes

     41.6        65.1        23.5      56   

Provision for income taxes

     0.4        0.6        (0.2   (50
                          

Net income

   $ 41.2      $ 64.5      $ 23.3      57   
                          

Operating Statistics

        

Petroleum products pipeline system:

        

Transportation revenue per barrel shipped

   $ 1.145      $ 1.222       

Volume shipped (million barrels)

     71.7        69.7       

Petroleum products terminals:

        

Marine terminal average storage utilized (million barrels per month)

     22.5        23.8       

Inland terminal throughput (million barrels)

     26.0        26.1       

Ammonia pipeline system:

        

Volume shipped (thousand tons)

     124        167       

Transportation and terminals revenues increased by $18.2 million, resulting from:

 

   

an increase in petroleum products pipeline system revenues of $8.0 million primarily attributable to higher transportation revenues, higher capacity and storage lease revenues and incremental fees for ethanol blending and additives. Transportation revenues increased primarily as a result of higher average tariffs due largely to mid-year 2009 tariff escalations;

 

19


Table of Contents
   

an increase in petroleum products terminals revenues of $8.3 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily at our Galena Park, Texas and Wilmington, Delaware facilities due to leasing new storage tanks placed in service and higher rates on existing storage. Inland revenues benefitted from higher fees due to ethanol blending; and

 

   

an increase in ammonia pipeline system revenues of $1.9 million due to increased shipments. First quarter 2009 shipments were negatively impacted by operational issues at two of our customers’ plants.

Operating expenses increased by $1.8 million, resulting from:

 

   

a decrease in petroleum products pipeline system expenses of $0.1 million as lower property taxes and more favorable product overages were largely offset by higher operating expenses related to our Houston-to-El Paso, Texas pipeline section (acquired from Longhorn Partners Pipeline, L.P. in third quarter 2009);

 

   

an increase in petroleum products terminals expenses of $1.1 million primarily related to timing of maintenance projects and higher personnel costs; and

 

   

an increase in ammonia pipeline system expenses of $0.9 million due primarily to an increase in environmental costs due to a 2010 pipeline release.

Product sales revenues primarily resulted from our petroleum products blending activities, product marketing and linefill management associated with our Houston-to-El Paso pipeline section, terminal product gains and transmix fractionation. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the future price of petroleum products related to these activities. Product margin increased $18.4 million between periods primarily due to the timing of realized profits for these hedged volumes. Due to mark-to-market adjustments, much of the profit related to the commodity sales activity in first quarter 2009 was realized in late 2008. Product margin also increased due to profits from our linefill management activities associated with our Houston-to-El Paso pipeline section.

Depreciation and amortization expense increased by $3.2 million primarily due to expansion capital projects placed into service during the past twelve months and the acquisition of our Houston-to-El Paso pipeline section.

G&A expense increased by $2.1 million between periods primarily due to higher equity-based incentive compensation costs.

Interest expense, net of interest income and interest capitalized, increased $6.5 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.69 billion for first quarter 2010 from $1.09 billion for first quarter 2009 principally due to borrowings for expansion capital expenditures and the Houston-to-El Paso pipeline section acquisition. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.1% in first quarter 2010 from 5.6% in 2009.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $59.7 million and $73.3 million for the three months ended March 31, 2009 and 2010, respectively. The $13.6 million increase from 2009 to 2010 was primarily attributable to:

 

   

an increase in net income of $23.3 million;

 

   

a $15.9 million increase in cash resulting from a $10.0 million decrease in accounts receivable and other accounts receivable in 2010 versus a $5.9 million increase in 2009 primarily due to the timing of payments received from customers; and

 

   

a $16.7 million increase in cash resulting from a $19.9 million increase in accounts payable in 2010 versus a $3.2 million increase in 2009 due primarily to the timing of invoices received from vendors and suppliers.

 

20


Table of Contents

These increases were partially offset by:

 

   

a $31.5 million decrease in cash resulting from a $49.6 million increase in inventory in 2010 versus an $18.1 million increase in inventory in 2009 primarily due to the linefill and working inventory of our Houston-to-El Paso pipeline section, which we acquired in July 2009; and

 

   

a $10.3 million decrease in cash resulting from a $3.5 million decrease in accrued interest payable in 2010 versus a $6.8 million increase in 2009 due primarily to the timing of semi-annual interest payments.

Net cash used by investing activities for the three months ended March 31, 2009 and 2010 was $46.9 million and $40.1 million, respectively. During 2010, we spent $41.6 million for capital expenditures, which included $6.4 million for maintenance capital and $35.2 million for expansion capital. Also, during first quarter 2010, we settled our insurance claim related to a tank fire at one of our petroleum products pipeline system terminals and we recognized proceeds of $3.0 million from that settlement. During 2009, we spent $47.6 million for capital expenditures, which included $11.3 million for maintenance capital and $36.3 million for expansion capital.

Net cash used by financing activities for the three months ended March 31, 2009 and 2010 was $34.3 million and $30.5 million, respectively. During 2010, we paid cash distributions of $75.8 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects, were $50.6 million. Net borrowings on our revolving credit facility during first quarter 2009, primarily to finance expansion capital projects, were $42.0 million.

During first quarter 2010, we paid $75.8 million in cash distributions to our unitholders. Based on the declared quarterly distribution of $0.72 per unit associated with the first quarter of 2010, we will pay $76.8 million in distributions during second quarter 2010. If we continue to pay cash distributions at this current level and the number of outstanding units remains the same, we will pay total cash distributions of $307.4 million on an annual basis.

In January 2010, the cumulative amounts of the January 2007 award grants were settled by issuing 140,317 limited partner units and distributing those units to the participants. Associated tax withholdings and employer taxes totaling $3.9 million were paid in January 2010.

Capital Requirements

Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending consists primarily of:

 

   

maintenance capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental regulations; and

 

   

expansion 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.

For the three months ended March 31, 2010, our maintenance capital spending was $6.4 million, including $0.4 million of spending reimbursable by insurance. For 2010, we expect to incur maintenance capital expenditures for our existing businesses of approximately $45.0 million.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During first quarter 2010, we spent $35.2 million for organic growth projects. Based on the progress of expansion projects already underway, we expect to spend approximately $250.0 million of expansion capital during 2010, including acquisitions, with an additional $30.0 million in future years to complete these projects.

Liquidity

As of March 31, 2010, total debt reported on our consolidated balance sheet was $1,734.1 million. The difference between this amount and the $1,702.2 million face value of our outstanding debt results from gains and losses realized on various cash flow hedges and unamortized discounts and premiums on debt issuances.

 

21


Table of Contents

Consolidated debt at December 31, 2009 and March 31, 2010 was as follows (in thousands):

 

     December 31,
2009
   March 31,
2010
   Weighted-Average
Interest Rate at
March 31, 2010 (1)
 

Revolving credit facility

   $ 101,600    $ 152,200    0.6

6.45% Notes due 2014

     249,732      249,745    6.3

5.65% Notes due 2016

     252,897      252,789    5.7

6.40% Notes due 2018

     260,340      260,036    5.9

6.55% Notes due 2019

     566,500      570,401    4.6

6.40% Notes due 2037

     248,935      248,938    6.3
                

Total debt

   $ 1,680,004    $ 1,734,109   
                

 

  (1) Weighted-average interest rate includes the impact of interest rate swaps and the amortization of discounts and gains and losses realized on various cash flow hedges.

Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of the associated notes.

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used for general purposes, including capital expenditures. As of March 31, 2010, $152.2 million was outstanding under this facility and $4.4 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million. The outstanding principal amount of the notes was increased by $3.1 million and $3.0 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased by $10.4 million and $10.1 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps.

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt. The outstanding principal amount of the notes was increased (decreased) by $(1.6) million and $2.6 million at December 31, 2009 and March 31, 2010, respectively, for the fair value less accrued interest of the associated interest rate swap agreements.

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $248.9 million.

The revolving credit facility and notes described above are senior indebtedness.

 

22


Table of Contents

Interest rate derivatives.

In June and August 2009, we entered into a total of $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% for the $150.0 million swaps and 2.34% for the other $100.0 million. The agreements terminate in June 2019, which is the maturity date of the related notes. Payments settle in January and July each year. During each period, we record the impact of these swaps based on the forward LIBOR curve. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to our interest expense. These interest rate derivatives contain credit-risk-related contingent features. These contingent features provide that in the event of our default on any obligation of $25.0 million or more or a merger in which our credit rating becomes “materially weaker,” which would generally be interpreted as falling below investment grade, the counterparties to our interest rate derivatives agreements could terminate those agreements and require immediate settlement. None of our interest rate derivatives were in a liability position as of March 31, 2010.

Credit ratings. Our current corporate credit ratings are BBB by Standard and Poor’s and Baa2 by Moody’s Investor Services.

Off-Balance Sheet Arrangements

None.

Environmental

Our operations are subject to federal, state and local environmental laws and regulations. We have accrued liabilities for estimated costs at our facilities and properties. We record liabilities when environmental costs are probable and can be reasonably estimated. The determination of amounts recorded for environmental liabilities involves significant judgments and assumptions by management. Due to the inherent uncertainties involved in determining environmental liabilities, it is reasonably possible that the actual amounts required to extinguish these liabilities could be materially different from those we have recognized.

Clean Air Act. Section 185 of the Clean Air Act (“CAA 185”) requires each state to assess fees against major stationary emission sources in “severe” or “extreme” non-attainment areas. During 2009, the Texas Commission on Environmental Quality (“TCEQ”), in response to an Environmental Protection Agency (“EPA”) request, issued proposed rules which, if adopted as proposed, may result in fees assessed against our Galena Park, Texas terminal for the 2008 and 2009 calendar years of up to $8.1 million and $4.8 million, respectively.

Based on the monitoring data for the Houston/Galveston/Brazoria, Texas area prepared by the TCEQ, which indicates that the area obtained the ozone standard for past three consecutive years, the TCEQ is pursuing a Termination Determination from the EPA, which, if approved by the EPA, would terminate any requirements by the TCEQ to pursue actions under CAA 185. However, an environmental group has submitted a petition in Federal Court challenging the Termination Determination process. We believe our Galena Park, Texas terminal will not be assessed penalties under CAA 185 and at March 31, 2010 we had no amounts accrued for this matter.

Other Items

NYMEX Contracts. We began using NYMEX contracts during the third quarter of 2008 as economic hedges against changes in the future price of petroleum products. From the third quarter of 2008 through the second quarter of 2009, none of the NYMEX contracts we entered into qualified as hedges for accounting purposes under ASC 815-30, Derivatives and Hedging. Beginning with the third quarter of 2009, because of other agreements that we entered into, some of the NYMEX contracts entered into qualified for hedge accounting treatment. Currently, we have two specific groups of commodities that are being hedged with NYMEX contracts:

 

 

Future sales of petroleum products generated from our blending and fractionation activities:

 

  Ø Since July 2009, some of the NYMEX contracts associated with future sales of petroleum products qualified for hedge accounting treatment and have been recorded as cash flow hedges. The gains and losses resulting from the mark-to-market changes in value of these contracts are not included in product sales revenues in our consolidated statement of income until the petroleum products they are hedging are physically sold. As of March 31, 2010, we had no open NYMEX contracts of petroleum products that qualified for hedge accounting treatment. During the first quarter of 2010, we recognized $2.0 million of losses associated with derivative agreements that qualified as hedges when the hedged products were sold and the contracts were settled.

 

23


Table of Contents
  Ø We had open NYMEX contracts for 0.8 million barrels of petroleum products as of March 31, 2010 that did not qualify for hedge accounting treatment. These contracts mature between April 2010 and October 2010. The cumulative amount of unrealized losses through March 31, 2010 associated with these agreements of $2.8 million have been recorded as a decrease in product sales revenues on our consolidated statements of income and energy commodity derivatives contracts on our consolidated balance sheet, of which $1.8 million was recorded during the first quarter 2010. Additionally, we realized losses of $0.5 million on NYMEX contracts that did not qualify for hedge accounting treatment that settled during first quarter 2010.

 

 

Future commodity sales of linefill and working inventory associated with our Houston-to-El Paso pipeline section acquisition:

 

  Ø At March 31, 2010, we had open NYMEX contracts covering 1.6 million barrels to hedge against changes in the future price of petroleum products associated with the linefill barrels. Contracts covering 1.4 million barrels mature between April 2010 and July 2010 and contracts covering 0.2 million barrels mature in July 2011. Because these NYMEX contracts do not qualify for hedge accounting treatment, we recognize the period change in fair value of these agreements in our consolidated income statement. The cumulative amount of unrealized losses through March 31, 2010 associated with these agreements were $11.3 million, which have been recorded as a decrease in product sales revenues on our consolidated statements of income, and $10.1 million and $1.2 million were recorded as energy commodity derivatives contracts and other noncurrent liabilities, respectively, on our consolidated balance sheet. Of the $11.3 million of cumulative losses, $5.0 million was recorded in the first quarter 2010. Additionally, we recognized $0.3 million of gains associated with the linefill NYMEX contracts that were settled during the first quarter of 2010 and recorded as product sales revenues on our consolidated income statement.

The following table provides a summary of the mark-to-market gains and losses associated with NYMEX contracts and the accounting period that the gains and losses were recognized in our consolidated statements of income for the three months ended March 31, 2009 and 2010 (in millions):

 

2009

      

NYMEX losses associated with physical product sales in first quarter 2009

   $ (0.4

NYMEX losses associated with physical product sales in 2009 subsequent to March 31, 2009

     (3.1
        

Total NYMEX losses recorded in first quarter 2009

   $ (3.5
        

2010

      

NYMEX losses associated with physical product sales in first quarter 2010

   $ (2.2

NYMEX losses associated with future physical product sales

     (6.8
        

Total NYMEX losses recorded in first quarter 2010

   $ (9.0
        

Ammonia Pipeline Testing. We will be performing extensive hydrostatic testing of our ammonia pipeline system during 2010. Expenditures during 2010 to complete this testing are estimated to be up to $10.0 million, which is $5.0 million higher than testing costs incurred in 2009. During certain periods of testing, it is anticipated that the pipeline will be unavailable for shipments, resulting in reduced shipment volumes. We are unable to estimate the impact this will have on our current year revenues because we expect our customer movements before and after the testing to be higher than at historical levels.

Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted. Approximately 40% of our tariffs are subject to this indexing methodology while the remaining 60% of the tariffs can be adjusted at our discretion based on competitive factors. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. The preliminary change in PPI-FG for 2009 is approximately negative 2.5%. As a result, we expect to decrease our rates in the 40% of our markets that are subject to the FERC’s index methodology by approximately 1.2% in July 2010.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our

 

24


Table of Contents

petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $7.0 million as of March 31, 2010. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

New Accounting Pronouncements

On February 24, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements. This ASU amended the guidance on subsequent events to remove the requirement for entities that file financial statements with the Securities and Exchange Commission (“SEC”) to disclose the date through which it has evaluated subsequent events. This ASU was effective on its issuance date. Our adoption of this ASU did not have an impact on our financial position, results of operations or cash flows.

On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This ASU requires disclosure of: (i) separate fair value measurements for each class of assets and liabilities, (ii) significant transfers between level 1 and level 2 in the fair value hierarchy and the reasons for such transfers, (iii) gains and losses for the period and purchases, sales, issuances, and settlements for Level 3 fair value measurements, (iv) transfers into and out of Level 3 of the hierarchy and the reasons for such transfers, and (v) the valuation techniques applied and inputs used in determining Level 2 and Level 3 measurements for each class of assets and liabilities. This ASU was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Early adoption is allowed. Our adoption of the applicable sections of this ASU did not have a material impact on our financial position, results of operations or cash flows.

In August 2009, the FASB issued ASU No. 2009-05, an update to Accounting Standards Codification (“ASC”) 820-10-35, Fair Value Measurements. This ASU provides guidance on measuring the fair value of liabilities. The guidance in this ASU was effective for the first reporting period, including interim periods, beginning after August 28, 2009. Our adoption of this ASU on September 1, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. The new codification supersedes all existing GAAP standards and became the single source of GAAP authoritative literature, effective for financial statements issued for interim and annual periods ending after September 15, 2009.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (as amended). This Statement requires the disclosure of subsequent events to be distinguished between recognized and non-recognized subsequent events. Further, entities are required to include a description of the period through which subsequent events were evaluated. (Note: ASU No. 2010-09 superseded the requirement to disclose the period through which subsequent events were evaluated for entities who file financial statements with the SEC). Our adoption of this Standard on June 30, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued FASB Staff Position (“FSP”) No. FAS 107-1 and Accounting Principles Board (“APB”) 28-1, Interim Disclosures About Fair Value of Financial Instruments. This FSP amended SFAS No. 107 (FASB ASC 825-10) and APB Opinion No. 28: (FASB ASC 270-10) by requiring quarterly as well as annual disclosures of the fair value of all financial instruments. The disclosures are to be in a form that makes it clear whether the fair value and carrying amounts represent assets or liabilities and how the carrying amounts relate to what is reported on the balance sheet. Our adoption of this Standard on June 30, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued FSP No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies. This FSP amended and clarified FASB Statement No. 141 (revised 2007), Business Combinations, to address application issues on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP was effective for assets or liabilities arising from contingencies in business combinations that occurred following the start of the first fiscal year that begins on or after December 15, 2008. Our adoption of this FSP did not have a material impact on our financial position, results of operations or cash flows.

 

25


Table of Contents
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 have established policies to monitor and control these market risks. We also enter into derivative agreements to help manage our exposure to commodity price and interest rate risks.

Commodity Price Risk

We use derivatives to help us manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2010, we had commitments under forward purchase contracts for product purchases of approximately 0.4 million barrels that are being accounted for as normal purchases totaling approximately $34.6 million, and we had commitments under forward sales contracts for product sales of approximately 0.2 million barrels that are being accounted for as normal sales totaling approximately $17.5 million.

We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending activities. In 2009, we began using NYMEX contracts as economic hedges against the changes in value of the petroleum products associated with linefill purchased in connection with our Houston-to-El Paso pipeline section. Through the second quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging. However, beginning in July 2009, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and have been recorded as cash flow hedges. None of the NYMEX contracts we used as economic hedges of the linefill of our Houston-to-El Paso pipeline section qualified for hedge accounting treatment.

At March 31, 2010, the fair value of open NYMEX contracts, representing 2.4 million barrels of petroleum products, was a net liability of $14.1 million, of which $12.9 million was recorded as energy commodity derivatives contracts and $1.2 million was recorded as noncurrent liabilities on our consolidated balance sheet. These open NYMEX contracts mature between April 2010 and July 2011. At March 31, 2010, we had made margin deposits of $19.9 million for these contracts, which were recorded as an energy commodity derivatives deposit on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet.

Based on our open NYMEX contracts at March 31, 2010, a $1.00 per barrel increase in the price of the NYMEX contract for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $2.4 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of the NYMEX contract for RBOB or heating oil would result in a $2.4 million increase in our product sales revenues. However, the increases or decreases in product sales revenues we recognize from our open NYMEX contracts are substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

During 2009, we entered into a total of $250.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes issued in June and August 2009 to floating-rate debt. Under the terms of the agreements, we will receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% on $150.0 million of the agreements and pay six-month LIBOR in arrears plus 2.34% on the other $100.0 million. The agreements terminate in June 2019, which is the maturity date of the related notes. Payments settle in January and July each year. During each period, we will record the impact of these swaps based on the forward LIBOR curve. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to interest expense. A 0.125% change in LIBOR would result in an annual adjustment to our interest expense of $0.3 million associated with these hedges.

As of March 31, 2010, we had $152.2 million outstanding on our variable rate revolving credit facility. Considering the amount outstanding on our revolving credit facility as of March 31, 2010, our annual interest expense would change by $0.2 million if LIBOR were to change by 0.125%.

 

26


Table of Contents
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. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

27


Table of Contents

Forward-Looking Statements

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,” “should” and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

The following are among the important factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts we have discussed in this report:

 

   

overall demand for refined petroleum products, natural gas liquids, crude oil and ammonia in the United States;

 

   

price fluctuations for refined petroleum products and natural gas liquids and expectations about future prices for these products;

 

   

changes in general economic conditions, interest rates and price levels in the United States;

 

   

changes in the financial condition of our customers;

 

   

our ability to secure financing in the credit and capital markets in amounts and on terms that will allow us to execute our growth strategy and maintain adequate liquidity;

 

   

development of alternative energy sources, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, regulatory developments or other trends that could affect demand for our services;

 

   

changes in the throughput or interruption in service on petroleum products pipelines owned and operated by third parties and connected to our assets;

 

   

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, the United States Surface Transportation Board and state regulatory agencies;

 

   

shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;

 

   

weather patterns materially different than historical trends;

 

   

an increase in the competition our operations encounter;

 

   

the occurrence of natural disasters, terrorism, operational hazards or unforeseen interruptions for which we are not adequately insured;

 

   

the treatment of us as a corporation for federal or state income tax purposes or if we become subject to significant forms of other taxation;

 

   

our ability to identify expansion projects or to complete identified expansion projects on time and at projected costs;

 

   

our ability to make and integrate acquisitions and successfully complete our business strategy;

 

   

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 have other adverse consequences;

 

   

the effect of changes in accounting policies;

 

   

the potential that our 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;

 

28


Table of Contents
   

the ability of third parties to perform on their contractual obligations to us;

 

   

supply disruption; and

 

   

global and domestic economic repercussions from terrorist activities and the government’s response thereto.

This list of important factors is not exclusive. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions or otherwise.

 

29


Table of Contents

PART II

OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

In June 2009, we received notice from the Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Water Act with respect to a release of petroleum product that occurred in Oklahoma in January 2008. The DOJ stated that the maximum statutory penalty for alleged violations of the Clean Water Act for the release was approximately $1.2 million. As a result of subsequent negotiations, we and the EPA agreed on a settlement in the amount of $0.4 million.

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 these 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.

 

ITEM 1A. RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

 

ITEM 4. RESERVED

 

ITEM 5. OTHER INFORMATION

None.

 

ITEM 6. EXHIBITS

 

Exhibit 12      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 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.

 

30


Table of Contents

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 May 4, 2010.

 

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)

 

31


Table of Contents

INDEX TO EXHIBITS

 

EXHIBIT
NUMBER

 

DESCRIPTION

12   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 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.

 

32