MMP - 2011.6.30-10Q
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 June 30, 2011
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  x    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 August 3, 2011 there were 112,736,571 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.
CONSOLIDATED FINANCIAL STATEMENTS
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
 
 
1.
 
 
2.
 
 
3.
 
 
4.
 
 
5.
 
 
6.
 
 
7.
 
 
8.
 
 
9.
 
 
10.
 
 
11.
 
 
12.
 
 
13.
 
 
14.
 
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4.
CONTROLS AND PROCEDURES
 
 
 
PART II
OTHER INFORMATION
 
ITEM 1.
ITEM 1A.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.

 


1
Table of Contents


PART I
FINANCIAL INFORMATION

ITEM 1.
CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit amounts)
(Unaudited)
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2011
 
2010
 
2011
Transportation and terminals revenues
$
193,173

 
$
223,192

 
$
366,342

 
$
428,600

Product sales revenues
229,698

 
159,943

 
386,034

 
397,239

Affiliate management fee revenue
189

 
192

 
379

 
385

Total revenues
423,060

 
383,327

 
752,755

 
826,224

Costs and expenses:
 
 
 
 
 
 
 
Operating
70,287

 
81,323

 
132,396

 
143,684

Product purchases
183,639

 
118,836

 
316,523

 
330,066

Depreciation and amortization
25,715

 
30,664

 
52,057

 
60,027

General and administrative
20,178

 
25,281

 
43,420

 
49,871

Total costs and expenses
299,819

 
256,104

 
544,396

 
583,648

Equity earnings
1,480

 
1,443

 
2,669

 
2,810

Operating profit
124,721

 
128,666

 
211,028

 
245,386

Interest expense
22,521

 
25,988

 
44,295

 
52,474

Interest income
(7
)
 
(1
)
 
(11
)
 
(11
)
Interest capitalized
(803
)
 
(1,190
)
 
(1,651
)
 
(1,861
)
Debt placement fee amortization expense
329

 
385

 
657

 
770

Income before provision for income taxes
102,681

 
103,484

 
167,738

 
194,014

Provision for income taxes
229

 
485

 
752

 
950

Net income
$
102,452

 
$
102,999

 
$
166,986

 
$
193,064

Allocation of net income (loss):
 
 
 
 
 
 
 
Non-controlling owners’ interest
$
(68
)
 
$
—

 
$
(68
)
 
$
(63
)
Limited partners’ interest
102,520

 
102,999

 
167,054

 
193,127

Net income
$
102,452

 
$
102,999

 
$
166,986

 
$
193,064

Basic and diluted net income per limited partner unit
$
0.96

 
$
0.91

 
$
1.56

 
$
1.71

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation
106,896

 
112,847

 
106,869

 
112,804


See notes to consolidated financial statements.


2
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited, in thousands)
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2011
 
2010
 
2011
Net income
$
102,452

 
$
102,999

 
166,986

 
193,064

Other comprehensive income:
 
 
 
 
 
 
 
Net gain (loss) on commodity hedges
—

 
4,613

 
(289
)
 
4,613

Reclassification of net gain on interest rate cash flow hedges to interest expense
(41
)
 
(41
)
 
(82
)
 
(82
)
Reclassification of net loss on commodity hedges to product sales revenues
—

 
—

 
2,035

 
—

Amortization of prior service credit and actuarial loss
(36
)
 
77

 
(21
)
 
155

Total other comprehensive income (loss)
(77
)
 
4,649

 
1,643

 
4,686

Comprehensive income
102,375

 
107,648

 
168,629

 
197,750

Comprehensive loss attributable to non-controlling owners’ interest in consolidated subsidiaries
(68
)
 
—

 
(68
)
 
(63
)
Comprehensive income attributable to partners’ capital
$
102,443

 
$
107,648

 
$
168,697

 
$
197,813

See notes to consolidated financial statements.

 

3
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
 
December 31, 2010
 
June 30,
2011
 
 
 
(Unaudited)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
7,483

 
$
12,992

Restricted cash
14,379

 
—

Trade accounts receivable (less allowance for doubtful accounts of $106 and $66 at December 31, 2010 and June 30, 2011, respectively)
92,192

 
70,074

Other accounts receivable
6,175

 
18,463

Inventory
216,408

 
285,996

Energy commodity derivatives deposits
22,302

 
43,505

Reimbursable costs
13,870

 
7,945

Other current assets
11,774

 
19,592

Total current assets
384,583

 
458,567

Property, plant and equipment
3,894,610

 
3,996,609

Less: accumulated depreciation
716,054

 
771,347

Net property, plant and equipment
3,178,556

 
3,225,262

Equity investments
23,728

 
27,395

Long-term receivables
1,167

 
1,710

Goodwill
39,925

 
39,961

Other intangibles (less accumulated amortization of $11,964 and $13,481 at December 31, 2010 and June 30, 2011, respectively)
16,924

 
16,506

Debt placement costs (less accumulated amortization of $5,439 and $6,209 at December 31, 2010 and June 30, 2011, respectively)
11,871

 
11,101

Tank bottom inventory
57,937

 
63,978

Other noncurrent assets
3,209

 
4,680

Total assets
$
3,717,900

 
$
3,849,160

LIABILITIES AND OWNERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
41,425

 
$
48,958

Accrued payroll and benefits
32,393

 
25,173

Accrued interest payable
35,799

 
36,171

Accrued taxes other than income
26,953

 
23,541

Environmental liabilities
12,202

 
17,410

Deferred revenue
34,733

 
30,442

Accrued product purchases
47,324

 
46,261

Energy commodity derivatives contracts
11,790

 
8,180

Contingent liabilities
1,730

 
15,755

Other current liabilities
30,698

 
21,123

Total current liabilities
275,047

 
273,014

Long-term debt
1,906,148

 
2,042,246

Long-term pension and benefits
28,965

 
31,704

Other noncurrent liabilities
17,597

 
22,516

Environmental liabilities
20,572

 
22,230

Commitments and contingencies
 
 
 
Owners’ equity:
 
 
 
Partners’ capital:
 
 
 
Limited partner unitholders (112,481 units and 112,737 units outstanding at December 31, 2010 and June 30, 2011, respectively)
1,466,404

 
1,463,860

Accumulated other comprehensive loss
(11,096
)
 
(6,410
)
Total partners’ capital
1,455,308

 
1,457,450

Non-controlling owners’ interest in consolidated subsidiaries
14,263

 
—

Total owners’ equity
1,469,571

 
1,457,450

Total liabilities and owners’ equity
$
3,717,900

 
$
3,849,160

See notes to consolidated financial statements.

4
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
 
Six Months Ended
June 30,
 
2010
 
2011
Operating Activities:
 
 
 
Net income
$
166,986

 
$
193,064

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
52,057

 
60,027

Debt placement fee amortization
657

 
770

                   Loss (gain) on sale, retirement and impairment of assets
(1,281
)
 
7,106

Equity earnings
(2,669
)
 
(2,810
)
Distributions from equity investments
1,870

 
2,710

Equity-based incentive compensation expense
6,909

 
9,017

Amortization of prior service credit and actuarial loss
(21
)
 
155

Changes in operating assets and liabilities:
 
 
 
Restricted cash
—

 
14,379

Trade accounts receivable and other accounts receivable
9,320

 
9,830

Inventory
(15,799
)
 
(69,588
)
Energy commodity derivatives contracts, net of derivatives deposits
(2,525
)
 
(14,159
)
Reimbursable costs
2,585

 
5,925

Accounts payable
5,381

 
7,001

Accrued payroll and benefits
(7,898
)
 
(7,220
)
Accrued interest payable
(2,016
)
 
372

Accrued taxes other than income
(1,348
)
 
(3,412
)
Accrued product purchases
2,799

 
(1,063
)
Contingent liabilities
184

 
14,025

Tank bottom inventory
—

 
(6,041
)
Current and noncurrent environmental liabilities
(3,898
)
 
6,866

Other current and noncurrent assets and liabilities
2,009

 
(8,899
)
Net cash provided by operating activities
213,302

 
218,055

Investing Activities:
 
 
 
Property, plant and equipment:
 
 
 
Additions to property, plant and equipment
(97,883
)
 
(95,273
)
Proceeds from sale and disposition of assets
5,128

 
753

Increase in accounts payable related to capital expenditures
3,888

 
532

Acquisition of assets
(29,300
)
 
(17,798
)
Acquisition of non-controlling owners' interests
—

 
(40,500
)
Other
—

 
(4,600
)
Net cash used by investing activities
(118,167
)
 
(156,886
)
Financing Activities:
 
 
 
Distributions paid
(152,626
)
 
(172,205
)
Net borrowings under revolver
83,400

 
135,000

Net receipt from financial derivatives
9,565

 
—

Decrease in outstanding checks
(1,672
)
 
(11,045
)
Settlement of tax withholdings on long-term incentive compensation
(3,371
)
 
(7,410
)
Capital contributed by non-controlling owners
851

 
—

Other
(356
)
 
—

Net cash used by financing activities
(64,209
)
 
(55,660
)
Change in cash and cash equivalents
30,926

 
5,509

Cash and cash equivalents at beginning of period
4,168

 
7,483

Cash and cash equivalents at end of period
$
35,094

 
$
12,992

Supplemental non-cash financing activity:
 
 
 
Issuance of limited partner units in settlement of equity-based incentive plan awards
$
2,034

 
$
4,315

Non-cash capital contributed by non-controlling owners
$
10,299

 
$
—

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 wholly-owned Delaware limited liability company, serves as our general partner.
We operate and report in three business segments: the petroleum pipeline system, the petroleum 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 the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2010, which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of June 30, 2011, and the results of operations for the three and six months ended June 30, 2010 and 2011 and cash flows for the six months ended June 30, 2010 and 2011. The results of operations for the six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year ending December 31, 2011.
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, 2010.
 

2.
Owners’ Equity

The changes in owners’ equity for the six months ended June 30, 2011 are provided in the table below (dollars in thousands):

6
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
Limited
Partners’
Capital
 
Limited
Partners’
Accumulated 
Other
Comprehensive Loss
 
Non-controlling
Owners’  Interest
 
Total 
Owners’
Equity
Balance, January 1, 2011
$
1,466,404

 
$
(11,096
)
 
$
14,263

 
$
1,469,571

Comprehensive income:
 
 
 
 
 
 
 
Net income (loss)
193,127

 
—

 
(63
)
 
193,064

Net gain on commodity hedges
—

 
4,613

 
—

 
4,613

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

 
(82
)
 
—

 
(82
)
Amortization of prior service credit and actuarial loss
—

 
155

 
—

 
155

Total other comprehensive income (loss)
193,127

 
4,686

 
(63
)
 
197,750

Distributions
(172,205
)
 
—

 
—

 
(172,205
)
Equity method portion of equity-based incentive compensation expense
6,004

 
—

 
—

 
6,004

Issuance of 255,222 common units in settlement of long-term incentive plan awards and board of director retainer fees
4,315

 
—

 
—

 
4,315

Settlement of tax withholdings on long-term incentive compensation
(7,410
)
 
—

 
—

 
(7,410
)
Acquisition of non-controlling owners' interest
(26,300
)
 
—

 
(14,200
)
 
(40,500
)
Other
(75
)
 
—

 
—

 
(75
)
Balance, June 30, 2011
$
1,463,860

 
$
(6,410
)
 
$
—

 
$
1,457,450

 
3.
Acquisitions
Acquisitions of Assets
In January 2011, we acquired the remaining undivided interest in our Southlake, Texas terminal. We accounted for this purchase as an acquisition of assets. The operating results of the Southlake terminal are reported in our petroleum pipeline system segment.
In April 2011, we acquired an approximate 38-mile petroleum products pipeline segment connected to our petroleum pipeline system at Reagan, Texas. We accounted for this purchase as an acquisition of assets. The operating results of these assets have been included in our petroleum pipeline system segment from the acquisition date.
In May 2011, we acquired petroleum products storage tanks in Riverside, Missouri. We accounted for this purchase as an acquisition of assets. The operating results of these assets have been included in our petroleum pipeline system segment from the acquisition date.
Collectively, the costs for the above-noted asset acquisitions were $17.8 million.
Acquisition of Non-Controlling Owners' Interest
In February 2011, we acquired a private investment group's common equity in Magellan Crude Oil, LLC ("MCO") for $40.5 million, which represented all of the non-controlling owners' interest in subsidiaries on our consolidated balance sheet (see Note 2 - Owners' Equity). The operating results of MCO continue to be reported in our petroleum terminals segment.
Business Combination
In September 2010, we acquired certain assets from BP Pipelines (North America), Inc. ("BP") and accounted for this purchase as a business combination. We have not adjusted the preliminary purchase price and fair value of the assets acquired and liabilities assumed as reported in our Annual Report on Form 10-K for the year ended December 31, 2010 as we are still in the process of determining the fair value of the assets acquired and liabilities assumed. The final allocation of the purchase price will be made when that process is complete.
The following summarized pro forma consolidated income statement information assumes that the business acquired

7
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


from BP referred to above occurred as of January 1, 2010. These pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2010 or the results that will be attained in the future. The amounts presented below are in thousands:

 
 
Three Months Ended June 30,
 
 
2010
 
2011
 
 
As Reported
 
Pro Forma
Adjustments
 
Pro Forma
 
As Reported
Revenues
 
$
423,060

 
$
13,820

 
$
436,880

 
$
383,327

Net income
 
$
102,452

 
$
4,645

 
$
107,097

 
$
102,999


 
 
Six Months Ended June 30,
 
 
2010
 
2011
 
 
As Reported
 
Pro Forma
Adjustments
 
Pro Forma
 
As Reported
Revenues
 
$
752,755

 
$
27,456

 
$
780,211

 
$
826,224

Net income
 
$
166,986

 
$
10,950

 
$
177,936

 
$
193,064


Significant pro forma adjustments include historical results of the acquired assets and our calculation of general and administrative ("G&A") costs, depreciation expense and interest expense on borrowings necessary to finance the acquisition.


4.
Product Sales Revenues
The amounts reported as product sales revenues on our consolidated statements of income include revenues from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange (“NYMEX”) contracts. We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell from our business activities where we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment and we designate and account for these as either cash flow or fair value hedges. The effective portion of the fair value changes in these contracts are recognized as adjustments to product sales when the hedged product is physically sold. Any ineffectiveness in these contracts is recognized as an adjustment to product sales in the period the ineffectiveness occurs. We account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges, with the period changes in fair value recognized as product sales. See Note 9 - Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.
For the three and six months ended June 30, 2010 and 2011, product sales revenues included the following (in thousands):

8
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2011
 
2010
 
2011
Physical sale of petroleum products
$
205,932

 
$
157,793

 
$
371,237

 
$
433,422

NYMEX contract adjustments:
 
 
 
 
 
 
 
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment and 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(1)
10,195

 
(1,078
)
 
5,878

 
(21,058
)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill working inventory(1)
13,571

 
3,228

 
8,919

 
(15,199
)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our crude oil activities
—

 
—

 
—

 
74

Total NYMEX contract adjustments
23,766

 
2,150

 
14,797

 
(36,183
)
Total product sales revenues
$
229,698

 
$
159,943

 
$
386,034

 
$
397,239

 
 
 
 
 
 
 
 
(1) The associated petroleum products for these activities are, to the extent still owned as of the statement date, or were, to the extent no longer owned as of the statement date, classified as inventories in current assets on our consolidated balance sheets.


5.
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.
We believe that investors benefit from having access to the same financial measures used by management. 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 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 expenses, that management does not consider when evaluating the core profitability of our operations.


9
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
Three Months Ended June 30, 2010
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
141,461

 
$
48,446

 
$
3,783

 
$
(517
)
 
$
193,173

Product sales revenues
222,963

 
6,763

 
—

 
(28
)
 
229,698

Affiliate management fee revenue
189

 
—

 
—

 
—

 
189

Total revenues
364,613

 
55,209

 
3,783

 
(545
)
 
423,060

Operating expenses
49,450

 
18,262

 
3,235

 
(660
)
 
70,287

Product purchases
182,267

 
1,917

 
—

 
(545
)
 
183,639

Equity earnings
(1,480
)
 
—

 
—

 
—

 
(1,480
)
Operating margin
134,376

 
35,030

 
548

 
660

 
170,614

Depreciation and amortization expense
16,499

 
8,188

 
368

 
660

 
25,715

G&A expenses
14,490

 
5,104

 
584

 
—

 
20,178

Operating profit (loss)
$
103,387

 
$
21,738

 
$
(404
)
 
$
—

 
$
124,721

 
 
Three Months Ended June 30, 2011
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
161,168

 
$
56,969

 
$
5,755

 
$
(700
)
 
$
223,192

Product sales revenues
152,891

 
7,140

 
—

 
(88
)
 
159,943

Affiliate management fee revenue
192

 
—

 
—

 
—

 
192

Total revenues
314,251

 
64,109

 
5,755

 
(788
)
 
383,327

Operating expenses
51,737

 
26,627

 
3,726

 
(767
)
 
81,323

Product purchases
117,540

 
2,084

 
—

 
(788
)
 
118,836

Equity earnings
(1,443
)
 
—

 
—

 
—

 
(1,443
)
Operating margin
146,417

 
35,398

 
2,029

 
767

 
184,611

Depreciation and amortization expense
19,291

 
10,243

 
363

 
767

 
30,664

G&A expenses
18,783

 
5,838

 
660

 
—

 
25,281

Operating profit
$
108,343

 
$
19,317

 
$
1,006

 
$
—

 
$
128,666


 

10
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
Six Months Ended June 30, 2010
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
264,376

 
$
94,105

 
$
8,876

 
$
(1,015
)
 
$
366,342

Product sales revenues
375,189

 
10,873

 
—

 
(28
)
 
386,034

Affiliate management fee revenue
379

 
—

 
—

 
—

 
379

Total revenues
639,944

 
104,978

 
8,876

 
(1,043
)
 
752,755

Operating expenses
92,270

 
34,635

 
7,216

 
(1,725
)
 
132,396

Product purchases
313,043

 
4,523

 
—

 
(1,043
)
 
316,523

Equity earnings
(2,669
)
 
—

 
—

 
—

 
(2,669
)
Operating margin
237,300

 
65,820

 
1,660

 
1,725

 
306,505

Depreciation and amortization expense
33,360

 
16,247

 
725

 
1,725

 
52,057

G&A expenses
31,342

 
10,878

 
1,200

 
—

 
43,420

Operating profit (loss)
$
172,598

 
$
38,695

 
$
(265
)
 
$
—

 
$
211,028

 
 
Six Months Ended June 30, 2011
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
305,230

 
$
112,190

 
$
12,787

 
$
(1,607
)
 
$
428,600

Product sales revenues
379,879

 
17,558

 
—

 
(198
)
 
397,239

Affiliate management fee revenue
385

 
—

 
—

 
—

 
385

Total revenues
685,494

 
129,748

 
12,787

 
(1,805
)
 
826,224

Operating expenses
89,447

 
48,623

 
7,057

 
(1,443
)
 
143,684

Product purchases
326,013

 
5,858

 
—

 
(1,805
)
 
330,066

Equity earnings
(2,810
)
 
—

 
—

 
—

 
(2,810
)
Operating margin
272,844

 
75,267

 
5,730

 
1,443

 
355,284

Depreciation and amortization expense
37,843

 
20,014

 
727

 
1,443

 
60,027

G&A expenses
37,238

 
11,309

 
1,324

 
—

 
49,871

Operating profit
$
197,763

 
$
43,944

 
$
3,679

 
$
—

 
$
245,386



6.
Inventory
Inventory at December 31, 2010 and June 30, 2011 was as follows (in thousands):
 
 
December 31,
2010
 
June 30,
2011
Refined petroleum products
$
146,211

 
$
142,398

Natural gas liquids
27,982

 
72,195

Transmix
32,277

 
49,023

Crude oil
5,008

 
15,822

Additives
4,930

 
6,558

Total inventory
$
216,408

 
$
285,996


The increase in natural gas liquids was due to the purchase of butane during 2011 in anticipation of the petroleum products blending season, which begins each September.

11
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



7.
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 these plans during the three and six months ended June 30, 2010 and 2011 (in thousands):
 
 
Three Months  Ended
June 30, 2010
 
Three Months  Ended
June 30, 2011
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
1,416

 
$
88

 
$
1,985

 
$
91

Interest cost
800

 
203

 
950

 
260

Expected return on plan assets
(920
)
 
—

 
(1,022
)
 
—

Amortization of prior service cost (credit)
77

 
(212
)
 
77

 
(213
)
Amortization of actuarial loss
99

 
—

 
151

 
62

Net periodic benefit cost
$
1,472

 
$
79

 
$
2,141

 
$
200

 
 
 
 
 
 
 
 

 
 
Six Months  Ended
June 30, 2010
 
Six Months  Ended
June 30, 2011
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
3,353

 
$
176

 
$
3,970

 
$
182

Interest cost
1,666

 
406

 
1,899

 
519

Expected return on plan assets
(1,774
)
 
—

 
(2,043
)
 
—

Amortization of prior service cost (credit)
154

 
(425
)
 
154

 
(426
)
Amortization of actuarial loss
250

 
—

 
302

 
125

Net periodic benefit cost
$
3,649

 
$
157

 
$
4,282

 
$
400

 
 
 
 
 
 
 
 
Contributions estimated to be paid into the plans in 2011 are $9.4 million and $0.5 million for the pension and other postretirement benefit plans, respectively.


8.
Debt
Consolidated debt at December 31, 2010 and June 30, 2011 was as follows (in thousands):

12
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
December 31,
2010
 
June 30,
2011
 
Weighted-Average
Interest Rate  at
June 30, 2011 (1)
Revolving credit facility
$
15,000

 
$
150,000

 
0.7%
$250.0 million of 6.45% Notes due 2014
249,786

 
249,814

 
6.3%
$250.0 million of 5.65% Notes due 2016
252,466

 
252,252

 
5.7%
$250.0 million of 6.40% Notes due 2018
259,125

 
262,034

 
5.1%
$550.0 million of 6.55% Notes due 2019
581,890

 
580,216

 
5.9%
$300.0 million of 4.25% Notes due 2021
298,932

 
298,974

 
4.3%
$250.0 million of 6.40% Notes due 2037
248,949

 
248,956

 
6.3%
Total debt
$
1,906,148

 
$
2,042,246

 
 
 
(1)
Weighted-average interest rate includes the impact of outstanding interest rate swaps, the amortization/accretion of discounts and premiums and the amortization/accretion of gains and losses realized on historical cash flow and fair value hedges (see Note 9—Derivative Financial Instruments for detailed information regarding our current interest rate swaps).

The face value of our debt at June 30, 2011 was $2.0 billion. The difference between the face value and carrying value of the debt outstanding is the unamortized portion of various fair value hedges and the unamortized discounts and premiums on debt issuances. Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of the associated note.
The amounts outstanding under the notes and revolving credit facility described in the table above are senior indebtedness.
Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, was $550.0 million at June 30, 2011. 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 June 30, 2011, there was $150.0 million outstanding under this facility and $4.6 million obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets but do decrease our borrowing capacity under the facility.


9.
Derivative Financial Instruments

Commodity Derivatives

Our petroleum products blending activities produce gasoline products, and we can estimate the timing and quantities of sales of these products. We use a combination of forward purchase and sales contracts, NYMEX contracts and butane price swap purchase agreements to lock in most of the product margins realized from our blending activities that we choose to hedge.

We account for the forward purchase and sales contracts we use in our blending activities as normal purchases and sales. As of June 30, 2011, we had commitments under forward purchase contracts for product purchases of approximately 0.8 million barrels that are being accounted for as normal purchases totaling approximately $77.1 million, and we had commitments under forward sales contracts for product sales of approximately 1.1 million barrels that are being accounted for as normal sales totaling approximately $138.3 million.

We use NYMEX contracts and butane price swap purchase agreements to help manage commodity price risk. We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in future periods. Some of these NYMEX contracts qualify for hedge accounting treatment, and we designate and account for these as either cash flow or fair value hedges. We account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We use the butane price swap purchase agreements to hedge against changes in the price of butane we expect to purchase in the future. We elected to not designate the butane price swap purchase agreements we have entered into as hedges for accounting purposes because the related NYMEX contracts associated with the gasoline that will be produced and sold from these future butane purchases did not qualify for hedge accounting treatment. At June 30, 2011, we had open NYMEX contracts representing 3.9 million barrels of petroleum products we expect to sell in the future in connection with the below-

13
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


listed business activities. Additionally, we had open butane price swap agreements on the purchase of 0.3 million barrels of butane.

•
Petroleum products blending and fractionation - NYMEX contracts representing 1.9 million barrels of petroleum products, of which 0.7 million barrels were designated as cash flow hedges and 1.2 million barrels that did not qualify as hedges for accounting purposes that mature between July 2011 and April 2012. The open butane swap positions noted above, which mature between September and December 2011, are also associated with our blending and fractionation activities;

•
Linefill on our Houston-to-El Paso pipeline section - NYMEX contracts representing 1.0 million barrels of petroleum products that did not qualify as hedges for accounting purposes that mature between July 2011 and May 2012;

•
Petroleum products pipeline over/short activity - NYMEX contracts representing 0.2 million barrels of petroleum products that did not qualify as hedges for accounting purposes that mature in July 2011; and

•
Crude oil storage and pipeline:

◦
NYMEX contracts associated with our crude oil tank bottom inventory for our Cushing storage facility representing 0.7 million barrels of crude oil, designated as fair value hedges for accounting purposes, that mature in November 2013;

◦
NYMEX contracts associated with our crude oil pipeline linefill representing less than 0.1 million barrels of crude oil, designated as fair value hedges for accounting purposes, that mature in August 2011; and

◦
NYMEX contracts associated with our crude oil pipeline over/short activity representing 0.1 million barrels of crude oil that did not qualify as fair value hedges for accounting purposes that mature in July 2011.

At June 30, 2011, the fair value of our open NYMEX contracts was a net liability of $18.4 million and the value of our butane butane price swap purchase agreements was a liability of $0.8 million. Combined, the net liability was $19.2 million, of which $8.2 million was recorded as energy commodity derivatives contracts and $11.0 million was recorded as other noncurrent liabilities on our consolidated balance sheet. At June 30, 2011, we had made margin deposits of $43.5 million for these contracts, which were recorded as energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the combined fair values of our open NYMEX contracts and our open butane price swap purchase agreements against our margin deposits under a master netting arrangement with our counterparty; however, we have elected to disclose the combined fair values of our open NYMEX and butane price swap purchase agreements separately from these related margin deposits on our consolidated balance sheet. We have netted the fair values of our NYMEX agreements and butane price swap agreements together on our consolidated balance sheets.

Interest Rate Derivatives

In 2011, we entered into $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our 6.40% notes due 2018. We account for these agreements as fair value hedges. These agreements effectively convert $100.0 million of our 6.40% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.40% fixed rate of the notes and pay a weighted average rate of six-month LIBOR in arrears plus 2.75%. The agreements terminate in July 2018, 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, which provide that, in the event we default on any material obligation or in case of 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 derivative agreements could terminate their respective agreements and require immediate settlement. Our interest rate swap agreements were in a net asset position as of June 30, 2011.
Derivative activity included in accumulated other comprehensive loss ("AOCL") for the three and six months ended June 30, 2010 and 2011 was as follows (in thousands):

14
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Derivative Activity Included in AOCL
2010
 
2011
 
2010
 
2011
Beginning balance
$
3,448

 
$
3,284

 
$
1,743

 
$
3,325

Net gain (loss) on commodity hedges
—

 
4,613

 
(289
)
 
4,613

Reclassification of net gain on cash flow hedges to interest expense
(41
)
 
(41
)
 
(82
)
 
(82
)
Reclassification of net loss on commodity hedges to product sales revenues
—

 
—

 
2,035

 
—

Ending balance
$
3,407

 
$
7,856

 
$
3,407

 
$
7,856

As of June 30, 2011, the net gain estimated to be classified to interest expense and product sales revenues over the next twelve months from AOCL is approximately $0.2 million and $4.6 million, respectively.

The following table provides a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2010 and 2011 of derivatives accounted for under ASC 815-25, Derivatives and Hedging—Fair Value Hedges, that were designated as hedging instruments (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)
 
 
 
 
Three Months Ended
 
Six Months Ended
 
Three Months Ended
 
Six Months Ended
 
 
 
 
June 30, 2010
 
June 30, 2011
 
June 30, 2010
 
June 30, 2011
 
June 30, 2010
 
June 30, 2011
 
June 30, 2010
 
June 30, 2011
Interest rate swap agreements
 
Interest expense
 
$
1,588

 
$
808

 
$
4,604

 
$
1,011

 
$
(8,636
)
 
$
(4,001
)
 
$
(17,277
)
 
$
(6,223
)
During 2011, we had open NYMEX contracts on 0.7 million barrels of crude oil which were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the unrealized losses of $11.1 million from the agreements as of June 30, 2011 were fully offset by adjustments of $11.0 million and $0.1 million to tank bottom inventory and other current assets, respectively; therefore, there was no net impact on product sales revenues.
The following is a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2010 and 2011 of the effective portion of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands). See Note 4 - Product Sales Revenues for further details regarding the impact of our NYMEX agreements on product sales.
 
 
 
Three Months Ended June 30, 2010
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 June 30, 2011
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

 
NYMEX commodity contracts
 
 
4,613

 
 
Product sales revenues
 
 
—

 
Total cash flow hedges
 
 
$
4,613

 
 
Total
 
 
$
41

 

15
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
 
Six Months Ended June 30, 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
 
 
$
82

 
NYMEX commodity contracts
 
 
(289
)
 
 
Product sales revenues
 
 
(2,035
)
 
Total cash flow hedges
 
 
$
(289
)
 
 
Total
 
 
$
(1,953
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2011
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
 
 
$
82

 
NYMEX commodity contracts
 
 
4,613

 
 
Product sales revenues
 
 
—

 
Total cash flow hedges
 
 
$
4,613

 
 
Total
 
 
$
82

 
There was no ineffectiveness recognized for any of our cash flow or fair value hedges during the three and six months ended June 30, 2010 or 2011.
The following table provides a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2010 and 2011 of derivatives accounted for under ASC 815-10-35; Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments (in thousands):
 
 
 
 
Amount of Gain (Loss)
Recognized on Derivative
 
 
 
Three Months  Ended
June 30,
 
Six Months Ended June 30,
Derivative Instrument
Location of Gain (Loss)
Recognized on Derivative
 
2010
 
2011
 
2010
 
2011
NYMEX commodity contracts
Product sales revenues
 
$
23,766

 
$
2,150

 
$
16,832

 
$
(36,183
)
Butane price swap purchase contracts
Product purchases
 
—

 
(839
)
 
—

 
(839
)
 
Total
 
$
23,766

 
$
1,311

 
$
16,832

 
$
(37,022
)
The following tables provide a summary of the amounts included on our consolidated balance sheets of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were designated as hedging instruments as of December 31, 2010 and June 30, 2011 (in thousands):
 
December 31, 2010
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Other noncurrent assets
 
$
—

 
Other noncurrent liabilities
 
$
4,920

 
 
 
 
 
 
 
 
 
June 30, 2011
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Interest rate swap agreement, current portion
Other current assets
 
$
2,678

 
Other current liabilities
 
$
—

Interest rate swap agreement, noncurrent portion
Other noncurrent assets
 
1,849

 
Other noncurrent liabilities
 
—

NYMEX commodity contracts
Energy commodity derivatives contracts
 
2,209

 
Energy commodity derivatives contracts
 
107

NYMEX commodity contracts
Other noncurrent assets
 
—

 
Other noncurrent liabilities
 
10,962

 
Total
 
$
6,736

 
Total
 
$
11,069

 

16
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


The following tables provide a summary of the amounts included on our consolidated balance sheets 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, 2010 and June 30, 2011 (in thousands):
 
December 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
 
$
11,790

 
 
 
 
 
 
 
 
 
June 30, 2011
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Energy commodity derivatives contracts
 
$
5,191

 
Energy commodity derivatives contracts
 
$
14,634

Butane price swap purchase contracts
Energy commodity derivatives contracts
 
—

 
Energy commodity derivatives contracts
 
839

 
Total
 
$
5,191

 
Total
 
$
15,473

 

10.
Commitments and Contingencies

Clean Air Act - Section 185 Liability.

Section 185 of the Clean Air Act ("CAA 185") requires states to collect annual fees from major source facilities located in severe or extreme nonattainment ozone areas if the designated area within the state did not meet its attainment deadline. Imposition of the fee is mandated for each calendar year after the attainment date until the area is redesignated as an attainment area for ozone. The Environmental Protection Agency ("EPA") is required to collect the fees if a state does not meet the requirements of or if a state is not administering and enforcing CAA 185. The Houston-Galveston region was initially determined to be a severe nonattainment area that did not meet its 2007 attainment deadline and, as such, would be subject to CAA 185. The Texas Commission on Environmental Quality (“TCEQ”) drafted a “Failure to Attain Rule” (the “Rule”) to implement the requirements of CAA 185. The Rule was scheduled to be final in the spring of 2010 and would have provided for the collection of an annual failure to attain fee for emissions from calendar year 2008 forward.  We have certain facilities in the Houston area that would have been subject to the TCEQ's Rule.

Under the Rule, the annual fees to be paid by entities within the Houston-Galveston non-attainment area would have been determined by the emissions from a facility that exceed the established baseline. In January 2010, the EPA issued guidance for states developing fee programs under CAA 185. In response to and based on the standards in the EPA's guidance, the TCEQ suspended the draft Rule and submitted a request for a determination by the EPA (a "Termination Determination") that the Houston-Galveston Region no longer qualified as a severe non-attainment area. If TCEQ's request for a Termination Determination were approved by the EPA, the requirement to assess a CAA 185 fee would be terminated.  Subsequent to the TCEQ's request for a Termination Determination, the Natural Resource Defense Counsel submitted a petition in federal court challenging the legality of the EPA's guidance. Based upon the EPA's belief and assertion that the guidance would be sustained in federal court, management determined the probability of the assessment of an annual fee for the Houston-Galveston area was remote.

On July 1, 2011, the court issued an opinion in the National Resource Defense Counsel case vacating the EPA's January 2010 guidance memorandum on state's CAA 185 equivalent programs. As a result of the court's ruling, the EPA has instructed the TCEQ that it is unable to approve the Termination Determination request. In addition, the Sierra Club filed a Clean Air Act citizen suit in 2010, Sierra Club v. Jackson, seeking to compel the EPA to collect CAA 185 fees in the Houston-Galveston area.

Based on the recent court decisions and statements by the EPA, management now believes that it is probable that the TCEQ will move forward with its CAA 185 rule making process.  A number of potential alternative outcomes exist, including the possibility that we will not be assessed any CAA 185 fees.  However, management now believes it is probable we will be assessed fees for excess emissions at our Houston area facilities for the years following 2007 and estimates that the range of fees that could be assessed to us to be between $6.4 million and $13.7 million. We have recorded an accrual of $6.4 million related to this matter, of which $4.8 million was recorded as a current environmental liability and $1.6 million was recorded as

17
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


a long-term environmental liability.

Environmental Liabilities.

Liabilities recognized for estimated environmental costs were $32.8 million and $39.6 million at December 31, 2010 and June 30, 2011, respectively. We have classified environmental liabilities 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 $2.7 million and $5.1 million for the three and six months ended June 30, 2010, respectively, and $8.6 million and $12.5 million for the three and six months ended June 30, 2011, respectively, including environmental expense recognized in second-quarter 2011 for the Section 185 contingent liability accrual discussed above.

Environmental Receivables.

Receivables from insurance carriers related to environmental matters at December 31, 2010 were $2.2 million, of which $1.0 million and $1.2 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets. Receivables from insurance carriers related to environmental matters at June 30, 2011 were $2.0 million, of which $0.3 million and $1.7 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.
Unrecognized Product Gains.
Our petroleum terminals operations generate product overages and shortages that result from metering inaccuracies and product evaporation, expansion, releases and 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 terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum 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 terminals operations had a market value of approximately $1.8 million as of June 30, 2011. 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 net future product shortages.
Other.
We are a party to various other claims, legal actions and complaints arising in the ordinary course of business. While the results cannot be predicted with certainty, management believes 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.

11.
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, as of June 30, 2011, permits the grant of awards covering an aggregate of 4.7 million of our limited partner units. The remaining units available under the LTIP at June 30, 2011 total 1.6 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):
 

18
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
Three Months Ended
June 30, 2010
 
Six Months Ended
June 30, 2010
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
2007 awards
$
—

 
$
—

 
$
—

 
$
—

 
$
6

 
$
6

2008 awards
462

 
163

 
625

 
2,925

 
1,269

 
4,194

2009 awards
350

 
186

 
536

 
700

 
460

 
1,160

2010 awards
453

 
128

 
581

 
909

 
258

 
1,167

Retention awards
208

 
—

 
208

 
382

 
—

 
382

Total
$
1,473

 
$
477

 
$
1,950

 
$
4,916

 
$
1,993

 
$
6,909

 
 
Three Months Ended
June 30, 2011
 
Six Months Ended
June 30, 2011
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
2009 awards
$
2,308

 
$
1,583

 
$
3,891

 
$
3,235

 
$
2,205

 
$
5,440

2010 awards
387

 
165

 
552

 
1,337

 
519

 
1,856

2011 awards
562

 
144

 
706

 
1,124

 
289

 
1,413

Retention awards
118

 
—

 
118

 
308

 
—

 
308

Total
$
3,375

 
$
1,892

 
$
5,267

 
$
6,004

 
$
3,013

 
$
9,017

 
In January 2011, the cumulative amounts of the 2008 LTIP awards were settled by issuing 252,746 limited partner units and distributing those units to the LTIP participants. The minimum tax withholdings associated with this settlement and employer taxes of $7.4 million and $0.9 million, respectively, were paid in January 2011.

In January 2011, the compensation committee of our general partner's board of directors approved 148,670 phantom unit awards pursuant to our LTIP. These awards have a three-year vesting period that will end on December 31, 2013.


12.
Distributions
Distributions we paid during 2010 and 2011 were as follows (in thousands, except per unit amounts):
 
Payment Date
 
Per Unit Cash
Distribution
Amount
 
Total Cash Distribution to Limited Partners
2/12/2010
 
 
$
0.7100

 
 
 
$
75,779

 
5/14/2010
 
 
0.7200

 
 
 
76,847

 
Through 6/30/2010
 
 
1.4300

 
 
 
152,626

 
8/13/2010
 
 
0.7325

 
 
 
82,393

 
11/12/2010
 
 
0.7450

 
 
 
83,798

 
Total
 
 
$
2.9075

 
 
 
$
318,817

 
 
 
 
 
 
 
 
 
 
2/14/2011
 
 
$
0.7575

 
 
 
$
85,398

 
5/13/2011
 
 
0.7700

 
 
 
86,807

 
Through 6/30/2011
 
 
1.5275

 
 
 
172,205

 
8/12/2011(a)
 
 
0.7850

 
 
 
88,498

 
Total
 
 
$
2.3125

 
 
 
$
260,703

 
 
 
 
 
 
 
 
 
 
(a)
Our general partner's board of directors declared this cash distribution on July 21, 2011 to be paid on August 12, 2011 to unitholders of record at the close of business on August 4, 2011.
 


19
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


13.
Fair Value
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 and restricted cash. The carrying amounts reported on our consolidated balance sheets approximate fair value due to the short-term maturity or variable rates of these instruments.
•
Energy commodity derivatives deposits. This asset represents short-term deposits we paid associated with our energy commodity derivatives contracts. The carrying amount reported on our consolidated balance sheets 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. These include NYMEX and butane price swap purchase agreements related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets. See Note 9 - Derivative Financial Instruments for further disclosures regarding these contracts.
•
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, 2010 and June 30, 2011. 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 the end of each period, in an orderly transaction with market participants using market observable interest rate swap curves (see Note 9 – Derivative Financial Instruments). The exchange value was 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, 2010 and June 30, 2011 (in thousands):
Assets (Liabilities)
December 31, 2010
 
June 30, 2011
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Cash and cash equivalents
$
7,483

 
$
7,483

 
$
12,992

 
$
12,992

Restricted cash
$
14,379

 
$
14,379

 
$
—

 
$
—

Energy commodity derivatives deposits
$
22,302

 
$
22,302

 
$
43,505

 
$
43,505

Long-term receivables
$
1,167

 
$
1,161

 
$
1,710

 
$
1,705

Energy commodity derivatives contracts (current)
$
(11,790
)
 
$
(11,790
)
 
$
(8,180
)
 
$
(8,180
)
Energy commodity derivatives contracts (noncurrent)
$
(4,920
)
 
$
(4,920
)
 
$
(10,962
)
 
$
(10,962
)
Debt
$
(1,906,148
)
 
$
(2,048,895
)
 
$
(2,042,246
)
 
$
(2,247,520
)
Interest rate swaps (current)
$
—

 
$
—

 
$
2,678

 
$
2,678

Interest rate swaps (noncurrent)
$
—

 
$
—

 
$
1,849

 
$
1,849

Fair Value Measurements
The following tables summarize the recurring fair value measurements of our NYMEX commodity contracts and interest rate swaps as of December 31, 2010 and June 30, 2011, based on the three levels established by ASC 820-10-50; Fair Value Measurements and Disclosures—Overall—Disclosure (in thousands):
Assets (Liabilities)
 
 
Fair Value Measurements as of
December 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)
$
(11,790
)
 
$
(11,790
)
 
$
—

 
$
—

Energy commodity derivatives contracts (noncurrent)
$
(4,920
)
 
$
(4,920
)
 
$
—

 
$
—


20
Table of Contents
MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Assets (Liabilities)
 
 
Fair Value Measurements as of
June 30, 2011 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)
$
(8,180
)
 
$
(8,180
)
 
$
—

 
$
—

Energy commodity derivatives contracts (noncurrent)
$
(10,962
)
 
$
(10,962
)
 
$
—

 
$
—

Interest rate swaps (current)
$
2,678

 
$
—

 
$
2,678

 
$
—

Interest rate swaps (noncurrent)
$
1,849

 
$
—

 
$
1,849

 
$
—



14.
Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

In July 2011, our general partner's board of directors declared a quarterly distribution of $0.785 per unit to be paid on August 12, 2011 to unitholders of record at the close of business on August 4, 2011. The total cash distributions to be paid are $88.5 million (see Note 12—Distributions for details).

In July 2011, Lonny E. Townsend, Senior Vice President, General Counsel, Compliance and Ethics Officer and Assistant Secretary of Magellan GP, LLC, our general partner, informed the Board of Directors of our general partner (the "Board of Directors") that he will retire from his positions effective January 2, 2012. The Board of Directors then elected Douglas J. May to succeed Mr. Townsend in these same positions. Upon Mr. Townsend's retirement, Mr. May will become Senior Vice President, General Counsel, Compliance and Ethics Officer and Assistant Secretary of our general partner.

As part of the annual review of various executive compensation and benefit plans by the Compensation Committee of the Board of Directors, and in a continuing effort to remain competitive with peer companies and retain our executive officers, in July 2011, the Board of Directors adopted the Magellan Midstream Holdings GP, LLC Executive Severance Pay Plan (the "Plan"). Under the Plan, severance benefits will be paid to our executive officers based on years of service for the following termination events:

•
Position Elimination — Benefits payable to executive officers will be two weeks base salary for each completed year of service. Base salary excludes any incentive compensation. This benefit is consistent with the benefit all employees receive under our existing severance pay plan.

•
Change-in-Control — As defined in the Plan, to receive severance pay benefits due to a change-in-control, the executive officer must resign voluntarily for good reason or be terminated involuntarily for other than performance reasons within two years following a change-in-control. Benefits payable to the chief executive officer are three times annual base salary plus current year's target annual incentive plan payout. Benefits payable to other executive officers are two times annual base salary plus current year's target annual incentive plan payout.

In July 2011, we terminated and settled the $100.0 million of swaps and received $6.1 million, which was recorded as an adjustment to long-term debt and will be amortized over the remaining life of the 6.40% notes.


21
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, such as gasoline and diesel fuel, and crude oil. As of June 30, 2011, our three operating segments included:
•
petroleum pipeline system, comprised of approximately 9,600 miles of pipeline and 51 terminals;
•
petroleum terminals, which includes storage terminal facilities (consisting of six marine terminals located along coastal waterways and crude oil storage in Cushing, Oklahoma) and 27 inland terminals; and
•
ammonia pipeline system, representing our 1,100-mile ammonia pipeline and six associated terminals.
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, 2010.

Recent Developments

Changes in our Executive Officers. In July 2011, Lonny E. Townsend, Senior Vice President, General Counsel, Compliance and Ethics Officer and Assistant Secretary of Magellan GP, LLC, our general partner, informed the Board of Directors of our general partner (the "Board of Directors") that he will retire from his positions effective January 2, 2012. The Board of Directors then elected Douglas J. May to succeed Mr. Townsend in these same positions upon Mr. Townsend's retirement.

Acquisitions. In April 2011, we acquired an approximate 38-mile petroleum products pipeline segment connected to our petroleum pipeline system at Reagan, Texas and in May 2011, we acquired petroleum products storage tanks in Riverside, Missouri. Collectively, we paid $10.4 million for these acquisitions. The operating results of these assets have been included in our petroleum pipeline system segment from the acquisition date.

Cash Distribution. On July 21, 2011, the Board of Directors declared a quarterly cash distribution of $0.785 per unit for the period of April 1, 2011 through June 30, 2011. This quarterly cash distribution will be paid on August 12, 2011 to unitholders of record on August 4, 2011. Total distributions to be paid under this declaration are approximately $88.5 million.

Executive Officer Severance Pay Plan. As part of the annual review of various executive compensation and benefit plans by the Compensation Committee of the Board of Directors, and in a continuing effort to remain competitive with peer companies and retain our executive officers, in July 2011, the Board of Directors adopted the Magellan Midstream Holdings GP, LLC Executive Severance Pay Plan (the "Plan"). Under the Plan, severance benefits will be paid to our executive officers based on years of service for the following termination events:

•
Position Elimination — Benefits payable to executive officers will be two weeks base salary for each completed year of service. Base salary excludes any incentive compensation. This benefit is consistent with the benefit all employees receive under our existing severance pay plan.

•
Change-in-Control — As defined in the Plan, to receive severance pay benefits due to a change-in-control, the executive officer must resign voluntarily for good reason or be terminated involuntarily for other than performance reasons within two years following a change-in-control. Benefits payable to the chief executive officer are three times annual base salary plus current year's target annual incentive plan payout. Benefits payable to other executive officers are two times annual base salary plus current year's target annual incentive plan payout.

Interest Rate Swap Settlement. In July 2011, we terminated and settled the $100.0 million of swaps and received $6.1 million, which was recorded as an adjustment to long-term debt and will be amortized over the remaining life of the 6.40% notes.

Results of Operations
We believe that investors benefit from having access to the same financial measures utilized by management. Operating

22
Table of Contents


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 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 tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, 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 these tables. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.

23
Table of Contents




Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2011
 
 
Three Months  Ended
June 30,
 
Variance
Favorable  (Unfavorable)
 
2010
 
2011
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenues:
 
 
 
 
 
 
 
Petroleum pipeline system
$
141.5

 
$
161.1

 
$
19.6

 
14
Petroleum terminals
48.4

 
57.0

 
8.6

 
18
Ammonia pipeline system
3.8

 
5.8

 
2.0

 
53
Intersegment eliminations
(0.6
)
 
(0.7
)
 
(0.1
)
 
(17)
Total transportation and terminals revenues
193.1

 
223.2

 
30.1

 
16
Affiliate management fee revenue
0.2

 
0.2

 
—

 
—
Operating expenses:
 
 
 
 
 
 
 
Petroleum pipeline system
49.4

 
51.7

 
(2.3
)
 
(5)
Petroleum terminals
18.2

 
26.6

 
(8.4
)
 
(46)
Ammonia pipeline system
3.2

 
3.8

 
(0.6
)
 
(19)
Intersegment eliminations
(0.6
)
 
(0.8
)
 
0.2

 
33
Total operating expenses
70.2

 
81.3

 
(11.1
)
 
(16)
Product margin:
 
 
 
 
 
 
 
Product sales revenues
229.6

 
159.9

 
(69.7
)
 
(30)
Product purchases
183.6

 
118.8

 
64.8

 
35
Product margin
46.0

 
41.1

 
(4.9
)
 
(11)
Equity earnings
1.5

 
1.4

 
(0.1
)
 
(7)
Operating margin
170.6

 
184.6

 
14.0

 
8
Depreciation and amortization expense
25.7

 
30.6

 
(4.9
)
 
(19)
G&A expense
20.2

 
25.3

 
(5.1
)
 
(25)
Operating profit
124.7

 
128.7

 
4.0

 
3
Interest expense (net of interest income and interest capitalized)
21.7

 
24.8

 
(3.1
)
 
(14)
Debt placement fee amortization expense
0.4

 
0.4

 
—

 
—
Income before provision for income taxes
102.6

 
103.5

 
0.9

 
1
Provision for income taxes
0.1

 
0.5

 
(0.4
)
 
(400)
Net income
$
102.5

 
$
103.0

 
$
0.5

 
—
Operating Statistics:
 
 
 
 
 
 
 
Petroleum pipeline system:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.304

 
$
1.097

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Gasoline
42.8

 
52.3

 
 
 
 
Distillates
28.8

 
32.9

 
 
 
 
Aviation fuel
5.2

 
7.7

 
 
 
 
Liquefied petroleum gases
1.9

 
2.2

 
 
 
 
Crude oil
—

 
10.2

 
 
 
 
Total volume shipped
78.7

 
105.3

 
 
 
 
Petroleum terminals:
 
 
 
 
 
 
 
Storage terminal average utilization (million barrels per month)
23.8

 
31.1

 
 
 
 
Inland terminal throughput (million barrels)
30.3

 
29.3

 
 
 
 
Ammonia pipeline system:
 
 
 
 
 
 
 
Volume shipped (thousand tons)
111

 
191

 
 
 
 


24
Table of Contents


Transportation and terminals revenues increased $30.1 million, resulting from:
•
an increase in petroleum pipeline system revenues of $19.6 million. The Houston, Texas-area pipelines we purchased in September 2010 contributed $7.1 million to revenues in the current quarter and transportation volumes of 23.1 million barrels. Excluding the impact of this acquisition, revenues increased $12.5 million primarily attributable to higher transportation revenues resulting from:
◦
a 5% increase in volumes driven primarily by new customer commitments; and
◦
a 3% increase in the average per barrel tariff rate, going from $1.304 per barrel to $1.341.
Additionally, increased demand for pipeline capacity leases and higher storage lease revenues and incremental fees for terminal throughput, ethanol and other blending services contributed to the increase in revenues;
•
an increase in petroleum terminals revenues of $8.6 million, of which over 60% was contributed by the Cushing, Oklahoma storage assets acquired in September 2010. Excluding this acquisition, revenues increased at our other storage and inland terminals. Storage terminal revenues increased principally due to higher rates on existing storage contracts and from additional leases of new tanks placed in service. Inland revenues benefited from higher fees for ethanol blending; and
•
an increase in ammonia pipeline system revenues of $2.0 million. Our pipeline was unavailable for shipments during much of second quarter 2010 due to hydrostatic testing on the system.
Operating expenses increased $11.1 million, resulting from:
•
an increase in petroleum pipeline system expenses of $2.3 million primarily resulting from a $2.8 million impairment charge for a system terminal we plan to close in 2011. Otherwise, increases in asset integrity and power costs and an accrual recognized in the current quarter related to contingent air emission fees were more than offset by more favorable product overages (which reduce operating expenses);
•
an increase in petroleum terminals expenses of $8.4 million, of which $1.3 million was attributable to the Cushing storage assets acquired in September 2010. Excluding these costs, operating expenses increased $7.1 million primarily related to an accrual recognized in the current quarter for contingent air emission fees and higher losses on asset retirements resulting from the demolition of older tanks to make room for new tank construction; and
•
an increase in ammonia pipeline system expenses of $0.6 million due primarily to higher power costs resulting from additional volumes.
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 price of petroleum products we expect to sell in the future. The period change in the mark-to-market value of these contracts that are not designated as hedges for accounting purposes, the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment and any ineffectiveness of NYMEX contracts that qualify for hedge accounting treatment are also included in product sales revenues. We use butane price swap agreements to hedge against changes in the price of petroleum products we expect to purchase in future periods. The period change in the mark-to-market value of these swap agreements, which were not designated as hedges, are included as adjustments to product purchases. Product margin decreased $4.9 million between periods due primarily to lower profits from our petroleum products blending activities and higher unrealized losses from NYMEX contracts, partially offset by higher profits from our fractionation activities.
Depreciation and amortization expense increased $4.9 million primarily due to expansion capital projects placed into service and recent acquisitions.
G&A expense increased $5.1 million primarily due to higher equity-based incentive compensation expense. Equity-based incentive compensation expense increased principally because, during the current quarter, we increased the 2009 incentive award accruals to the stretch payout amount based on our strong performance against the financial metric associated with those awards. Increases to the 2010 equity-based incentive compensation expense accruals for above-target payouts related to the 2008 incentive awards were not recognized until the third and fourth quarters of 2010.
Interest expense, net of interest income and interest capitalized, increased $3.1 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $2.0 billion for second quarter 2011 from $1.7 billion for second quarter 2010 principally due to borrowings for expansion capital expenditures and acquisitions. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, increased to 5.3% in second

25
Table of Contents


quarter 2011 from 5.1% in second quarter 2010.


Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2011
 
 
Six Months  Ended
June 30,
 
Variance
Favorable  (Unfavorable)
 
2010
 
2011
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenues:
 
 
 
 
 
 
 
Petroleum pipeline system
$
264.4

 
$
305.2

 
$
40.8

 
15
Petroleum terminals
94.1

 
112.2

 
18.1

 
19
Ammonia pipeline system
8.9

 
12.8

 
3.9

 
44
Intersegment eliminations
(1.1
)
 
(1.6
)
 
(0.5
)
 
(45)
Total transportation and terminals revenues
366.3

 
428.6

 
62.3

 
17
Affiliate management fee revenue
0.4

 
0.4

 
—

 
—
Operating expenses:

 

 
 
 
 
Petroleum pipeline system
92.3

 
89.4

 
2.9

 
3
Petroleum terminals
34.6

 
48.6

 
(14.0
)
 
(40)
Ammonia pipeline system
7.2

 
7.1

 
0.1

 
1
Intersegment eliminations
(1.7
)
 
(1.4
)
 
(0.3
)
 
(18)
Total operating expenses
132.4

 
143.7

 
(11.3
)
 
(9)
Product margin:
 
 
 
 
 
 
 
Product sales revenues
386.0

 
397.2

 
11.2

 
3
Product purchases
316.5

 
330.0

 
(13.5
)
 
(4)
Product margin
69.5

 
67.2

 
(2.3
)
 
(3)
Equity earnings
2.7

 
2.8

 
0.1

 
4
Operating margin
306.5

 
355.3

 
48.8

 
16
Depreciation and amortization expense
52.1

 
60.0

 
(7.9
)
 
(15)
G&A expense
43.4

 
49.9

 
(6.5
)
 
(15)
Operating profit
211.0

 
245.4

 
34.4

 
16
Interest expense (net of interest income and interest capitalized)
42.6

 
50.6

 
(8.0
)
 
(19)
Debt placement fee amortization expense
0.7

 
0.8

 
(0.1
)
 
(14)
Income before provision for income taxes
167.7

 
194.0

 
26.3

 
16
Provision for income taxes
0.7

 
0.9

 
(0.2
)
 
(29)
Net income
$
167.0

 
$
193.1

 
$
26.1

 
16
Operating Statistics:
 
 
 
 
 
 
 
Petroleum pipeline system:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.265

 
$
1.071

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Gasoline
82.1

 
104.7

 
 
 
 
Distillates
53.2

 
62.5

 
 
 
 
Aviation fuel
10.0

 
12.8

 
 
 
 
Liquefied petroleum gases
3.1

 
3.1

 
 
 
 
Crude oil
—

 
17.2

 
 
 
 
Total volume shipped
148.4

 
200.3

 
 
 
 
Petroleum terminals:
 
 
 
 
 
 
 
Storage terminal average utilization (million barrels per month)
23.8

 
30.5

 
 
 
 
Inland terminal throughput (million barrels)
56.4

 
56.9

 
 
 
 
Ammonia pipeline system:
 
 
 
 
 
 
 
Volume shipped (thousand tons)
278

 
412

 
 
 
 


26
Table of Contents


Transportation and terminals revenues increased $62.3 million, resulting from:
•
an increase in petroleum pipeline system revenues of $40.8 million. The Houston, Texas-area pipelines we purchased in September 2010 contributed $13.8 million to revenues in the current year and transportation volumes of 42.4 million barrels. Excluding the impact of this acquisition, revenues increased $27.0 million primarily attributable to higher transportation revenues resulting from:
◦
a 6% increase in transportation volumes driven by new customer commitments; and
◦
a 2% increase in the average per barrel tariff rate, going from $1.265 per barrel to $1.293.
Additionally, higher storage lease revenues and incremental fees for terminal throughput, ethanol and other blending contributed to the increase in revenues;

•
an increase in petroleum terminals revenues of $18.1 million, of which more than half was contributed by the Cushing, Oklahoma storage assets acquired in September 2010. Excluding this acquisition, revenues increased at our other storage and inland terminals. Storage terminal revenues increased principally due to higher rates on existing storage contracts and from additional leases of new tanks placed in service. Inland revenues benefited from higher fees due to ethanol and additive blending; and

•
an increase in ammonia pipeline system revenues of $3.9 million due to increased shipments during 2011. Our pipeline was unavailable for shipments during much of 2010 due to hydrostatic testing being performed on the pipeline.
Operating expenses increased $11.3 million, resulting from:
•
a decrease in petroleum pipeline system expenses of $2.9 million. Pipeline system expenses decreased $4.5 million related to our September 2010 pipeline purchase because favorable product overages (which reduce operating expenses) more than offset other operating expenses. Excluding this reduction, petroleum pipeline expenses increased $1.6 million due largely to a $2.8 million asset impairment recognized in the current quarter. Otherwise, higher losses from asset replacements, increases in power costs due to increased pipeline volumes, higher compensation costs, an accrual recognized in the current period related to contingent air emission fees and higher property taxes were more than offset by more favorable product overages;
•
an increase in petroleum terminals expenses of $14.0 million, of which $2.8 million was attributable to the Cushing storage assets acquired in September 2010. Excluding these costs, operating expenses increased $11.2 million primarily related to an accrual recognized in the current period for contingent air emission fees, higher environmental expenses, product downgrade charges in the 2011 period and higher losses on asset retirements resulting from the demolition of older tanks to make room for new tank construction; and
•
a decrease in ammonia pipeline system expenses of $0.1 million resulting primarily from lower asset integrity and environmental costs, partially offset by lower gains on asset sales. The 2010 period included a gain on the sale of a portion of pipeline linefill (pipeline linefill for our ammonia system is recorded as property, plant and equipment).
Product sales revenues primarily result 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 NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in the future related to these activities. The period change in the mark-to-market value of these contracts that do not qualify for hedge accounting treatment, the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment and any ineffectiveness of NYMEX contracts that qualify for hedge accounting treatment are also included in product sales revenues. We use butane price swap agreements to hedge against changes in the price of petroleum products we expect to purchase in future periods. The period change in the mark-to-market value of these swap agreements, which were not designated as hedges, are included as adjustments to product purchases. Product margin decreased $2.3 million between periods due primarily to higher unrealized losses on NYMEX contracts and lower profits from our petroleum products blending activities, partially offset by higher profits from our fractionation activities and the sale of more terminal product overages at higher prices.
Depreciation and amortization expense increased $7.9 million primarily due to expansion capital projects placed into service and recent acquisitions.
G&A expense increased $6.5 million primarily due to higher equity-based incentive compensation expense. Equity-based incentive compensation expense increased principally because, during the current quarter, we increased the 2009

27
Table of Contents


incentive award accruals to the stretch payout amount based on our strong performance against the financial metric associated with those awards. Increases to the 2010 equity-based incentive compensation expense accruals for above-target payouts related to the 2008 incentive awards were not recognized until the third and fourth quarters of 2010.

Interest expense, net of interest income and interest capitalized, increased $8.0 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.9 billion for 2011 from $1.7 billion for 2010 principally due to borrowings for expansion capital expenditures and acquisitions. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, increased to 5.4% in 2011 from 5.1% in 2010.


Liquidity and Capital Resources
Distributable Cash Flow
Distributable cash flow is a non-GAAP measure that management uses to evaluate our ability to generate cash for distribution to our limited partners. Management also uses this measure as a basis for recommending to the Board of Directors the amount of cash distributions to be paid each period. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of distributable cash flow for the six months ended June 30, 2010 and 2011 to net income, which is its nearest comparable GAAP financial measure, was as follows (in thousands):
 
 
Six Months Ended June 30,
 
Increase
 
 
2010
 
2011
 
(Decrease)
Net income
 
$
166,986

 
$
193,064

 
$
26,078

Add:
 

 

 
 
Depreciation and amortization(1)
 
52,714

 
60,797

 
8,083

Equity-based incentive compensation expense(2)
 
3,509

 
1,600

 
(1,909
)
Asset retirements and impairments
 
(1,281
)
 
7,106

 
8,387

Commodity-related adjustments:
 

 

 
 
Derivative losses (gains) recognized in the period associated with future product transactions(3)
 
(13,209
)
 
8,765

 
21,974

Derivative losses recognized in previous periods associated with products sold in the period(4)
 
(7,158
)
 
(12,007
)
 
(4,849
)
Lower-of-cost-or-market adjustments

 
5,182

 
—

 
(5,182
)
Houston-to-El Paso cost of sales adjustments(5)

 
(4,233
)
 
(3,915
)
 
318

Total commodity-related adjustments
 
(19,418
)
 
(7,157
)
 
12,261

Less:
 
 
 
 
 
 
Maintenance capital
 
15,023

 
19,370

 
(4,347
)
Other
 
1,579

 
739

 
840

Distributable cash flow
 
$
185,908

 
$
235,301

 
$
49,393

 
 
 
 
 
 
 
(1)    Depreciation and amortization includes debt placement fee amortization.
(2)    Because we intend to satisfy vesting of units under our equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back for distributable cash flow purposes. Total equity-based incentive compensation expense for the six months ended June 30, 2010 and 2011 was $6.9 million and $9.0 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2010 and 2011 of $3.4 million and $7.4 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduce distributable cash flow.
(3)    Derivatives we use as economic hedges have not been designated as hedges for accounting purposes. These amounts represent the gains or losses of these economic hedges recognized in our earnings for products that had not physically sold as of the period end date.
(4)    When we physically sell products that are economically hedged (but were not designated as hedges for accounting purposes), we include in our distributable cash flow calculations the full amount of the change in fair value of the associated derivative agreement.
(5)    Cost of goods sold adjustment related to transitional commodity activities for our Houston-to-El Paso pipeline to more closely resemble current market prices for distributable cash flow purposes rather than average inventory costing as used to determine our results of operations.

Distributable cash flow increased $49.4 million. The change in net income and depreciation and amortization is discussed in detail in Results of Operations above. Cash from equity-based incentive compensation decreased primarily because the

28
Table of Contents


settlement of the equity-based unit awards in 2011 was higher than in 2010 and the corresponding tax withholdings we paid on those awards was higher in the current period. Asset retirements in the 2010 period included a $3.0 million insurance settlement and the gain from that settlement was excluded from our distributable cash flow. The 2011 amounts included an impairment expense of $2.8 million. The increase in cash flows from commodity-related adjustments is primarily due to the impact of price decreases during the 2010 period and price increases during the 2011 period. A discussion of our maintenance capital expenditures is provided in Capital Requirements below.

Cash Flows and Capital Expenditures
Net cash provided by operating activities was $213.3 million and $218.1 million for the six months ended June 30, 2010 and 2011, respectively. The $4.8 million increase from 2010 to 2011 was primarily attributable to:
•
a $42.5 million increase in net income, excluding the increases in non-cash depreciation and amortization expense and loss (gain) on sale, retirement and impairment of assets;
•
a $14.4 million increase due to the elimination of restricted cash resulting from our purchase of the private investment group's common equity in Magellan Crude Oil, LLC ("MCO") during first quarter 2011. Prior to this, MCO's cash on hand was unavailable to us for our partnership matters and was recorded as restricted cash on our consolidated balance sheet at December 31, 2010; and
•
a $10.8 million increase resulting from a $6.9 million increase in current and noncurrent environmental liabilities in 2011 versus a $3.9 million decrease in current and noncurrent environmental liabilities in 2010 primarily due to our CAA 185 contingent liability accrual (see Environmental below for further details regarding this matter) during 2011; and
These increases were partially offset by:
•
a $53.8 million decrease primarily resulting from the impact of higher product prices and higher levels of inventory purchases in 2011 as compared to 2010; specifically, a $69.6 million increase in inventory in 2011 versus a $15.8 million increase in inventory in 2010; and
•
an $11.7 million decrease resulting from a $14.2 million decrease in energy commodity derivatives contracts, net of increased derivatives deposits in 2011, versus a $2.5 million increase in 2010 primarily due to an increase in the number of NYMEX commodity contracts during 2011.
Net cash used by investing activities for the six months ended June 30, 2010 and 2011 was $118.2 million and $156.9 million, respectively. During 2011, we spent $95.3 million for capital expenditures, which included $19.4 million for maintenance capital and $75.9 million for expansion capital. Also during 2011, we acquired a private investment group's common equity in MCO for $40.5 million and spent $17.8 million on various asset acquisitions. During 2010, we spent $97.9 million for capital expenditures, which included $15.0 million for maintenance capital, excluding $0.5 million of maintenance capital spending to be reimbursed by insurance, and $82.4 million for expansion capital. In addition, during 2010 we acquired petroleum products storage tanks at various locations on our petroleum pipeline system for $29.3 million. Also, during 2010, proceeds from the sale of assets were $5.1 million, including $3.0 million of proceeds from the settlement of our insurance claim related to a tank fire at one of our petroleum pipeline system terminals.
Net cash used by financing activities for the six months ended June 30, 2010 and 2011 was $64.2 million and $55.7 million, respectively. During 2011, we paid cash distributions of $172.2 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects and the MCO buyout noted above, were $135.0 million. During 2010, we paid cash distributions of $152.6 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects, were $83.4 million. Additionally, we received $9.6 million from the settlement of our interest rate swap agreements during 2010. The settlement of tax withholdings on long-term incentive plan awards was $3.4 million and $7.4 million during the first quarter of 2010 and 2011, respectively.
The quarterly distribution amount related to our second quarter 2011 financial results (to be paid in third quarter 2011) is $0.785 per unit. If we are able to meet management's targeted distribution growth of 7% for 2011 and the number of outstanding limited partner units remains at 112.7 million, total cash distributions of approximately $351.0 million will be paid to our unitholders in 2011.

Capital Requirements
Our businesses require continual investment to maintain, 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

29
Table of Contents


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 capacity or develop pipeline connections to new supply sources.
For the six months ended June 30, 2011, our maintenance capital spending was $19.4 million. For 2011, we expect to incur maintenance capital expenditures for our existing businesses of approximately $65.0 million.
In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During the first six months of 2011, we spent $75.9 million for organic growth capital, $40.5 million to acquire the remaining interest in MCO, and $17.8 million, collectively, to acquire the remaining undivided interest in our Southlake, Texas terminal, an approximate 38-mile petroleum products pipeline segment connected to our petroleum pipeline system at Reagan, Texas and petroleum products storage tanks in Riverside, Missouri. Based on the progress of expansion projects already underway, we expect to spend approximately $240.0 million for expansion capital during 2011, including acquisitions, with an additional $60.0 million in future years to complete these projects.
Liquidity
Consolidated debt at December 31, 2010 and June 30, 2011 was as follows (in thousands):
 
 
December 31,
2010
 
June 30,
2011
 
Weighted-Average
Interest Rate  at
June 30, 2011 (1)
Revolving credit facility
$
15,000

 
$
150,000

 
0.7%
$250.0 million of 6.45% Notes due 2014
249,786

 
249,814

 
6.3%
$250.0 million of 5.65% Notes due 2016
252,466

 
252,252

 
5.7%
$250.0 million of 6.40% Notes due 2018
259,125

 
262,034

 
5.1%
$550.0 million of 6.55% Notes due 2019
581,890

 
580,216

 
5.9%
$300.0 million of 4.25% Notes due 2021
298,932

 
298,974

 
4.3%
$250.0 million of 6.40% Notes due 2037
248,949

 
248,956

 
6.3%
Total debt
$
1,906,148

 
$
2,042,246

 
 
 
(1)
Weighted-average interest rate includes the impact of current interest rate swaps, the amortization/accretion of discounts and premiums and the amortization/accretion of gains and losses realized on historical cash flow and fair value hedges.

The face value of our debt at June 30, 2011 was $2.0 billion. The difference between the face value and carrying value of the debt outstanding is the unamortized portion of various fair value hedges and the unamortized discounts and premiums on debt issuances. Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives o the associated note.
The amounts outstanding under the notes and revolving credit facility described in the table above are senior indebtedness.
Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, was $550.0 million at June 30, 2011. 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 June 30, 2011, there was $150.0 million outstanding under this facility and $4.6 million obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets but do decrease our borrowing capacity under the facility.

Interest Rate Derivatives

In 2011, we entered into $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our 6.40% notes due 2018. We account for these agreements as fair value hedges. These agreements effectively convert $100.0 million of our 6.40% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.40% fixed rate of the notes and pay a weighted average rate of six-month LIBOR in arrears plus 2.75%. The agreements

30
Table of Contents


terminate in July 2018, 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, which provide that, in the event we default on any material obligation or in case of 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 derivative agreements could terminate their respective agreements and require immediate settlement. These interest rate swap agreements were in a net asset position as of June 30, 2011.


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 Contingent Liability.

Section 185 of the Clean Air Act ("CAA 185") requires states to collect annual fees from major source facilities located in severe or extreme nonattainment ozone areas if the designated area within the state did not meet its attainment deadline. Imposition of the fee is mandated for each calendar year after the attainment date until the area is redesignated as an attainment area for ozone. The Environmental Protection Agency ("EPA") is required to collect the fees if a state does not meet the requirements of or if a state is not administering and enforcing CAA 185. The Houston-Galveston region was initially determined to be a severe nonattainment area that did not meet its 2007 attainment deadline and, as such, would be subject to CAA 185. The Texas Commission on Environmental Quality (“TCEQ”) drafted a “Failure to Attain Rule” (the “Rule”) to implement the requirements of CAA 185. The Rule was scheduled to be final in the spring of 2010 and would have provided for the collection of an annual failure to attain fee for emissions from calendar year 2008 forward.  We have certain facilities in the Houston area that would have been subject to the TCEQ's Rule.

Under the Rule, the annual fees to be paid by entities within the Houston-Galveston non-attainment area would have been determined by the emissions from a facility that exceed the established baseline. In January 2010, the EPA issued guidance for states developing fee programs under CAA 185. In response to and based on the standards in the EPA's guidance, the TCEQ suspended the draft Rule and submitted a request for a determination by the EPA (a "Termination Determination") that the Houston-Galveston Region no longer qualified as a severe non-attainment area. If TCEQ's request for a Termination Determination were approved by the EPA, the requirement to assess a CAA 185 fee would be terminated.  Subsequent to the TCEQ's request for a Termination Determination, the Natural Resource Defense Counsel submitted a petition in federal court challenging the legality of the EPA's guidance. Based upon the EPA's belief and assertion that the guidance would be sustained in federal court, management determined the probability of the assessment of an annual fee for the Houston-Galveston area was remote.

On July 1, 2011, the court issued an opinion in the National Resource Defense Counsel case vacating the EPA's January 2010 guidance memorandum on state's CAA 185 equivalent programs. As a result of the court's ruling, the EPA has instructed the TCEQ that it is unable to approve the Termination Determination request. In addition, the Sierra Club filed a Clean Air Act citizen suit in 2010, Sierra Club v. Jackson, seeking to compel the EPA to collect CAA 185 fees in the Houston-Galveston area.

Based on the recent court decisions and statements by the EPA, management now believes that it is probable that the TCEQ will move forward with its CAA 185 rule making process.  A number of potential alternative outcomes exist, including the possibility that we will not be assessed any CAA 185 fees at all.  However, management now believes it is probable we will be assessed fees for excess emissions at our Houston area facilities for the years following 2007 and estimates that the range of fees that could be assessed to us to be between $6.4 million and $13.7 million. We have recorded an accrual of $6.4 million related to this matter, of which $4.8 million was recorded as a current environmental liability and $1.6 million was recorded as a long-term environmental liability.

31
Table of Contents




Other Items

Derivative Agreements. We use NYMEX contracts and butane price swap purchase agreements to help manage commodity price risk. We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in future periods. Some of these NYMEX contracts qualify for hedge accounting treatment and we designate and account for these contracts as either cash flow or fair value hedges. We use and account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We use the butane price swap purchase agreements to hedge against changes in the price of butane we expect to purchase in the future. We elected to not designate the butane price swap purchase agreements as hedges for accounting purposes because the related NYMEX contracts associated with the gasoline sales that will be produced and sold from these future butane purchases did not qualify for hedge accounting treatment. Currently, we have three specific groups of commodities that are being hedged:

•
Future sales and purchases of petroleum products associated with our blending and fractionation activities and product overages associated with our petroleum products pipeline over/short activity:

◦
As of June 30, 2011, we had open NYMEX contracts for 1.2 million barrels of petroleum products associated with our blending and fractionation activities that did not qualify for hedge accounting treatment. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature between July 2011 and April 2012. The cumulative amount of unrealized gains through June 30, 2011 associated with these agreements, which are related to products we expect to sell in the future, was $0.3 million. We recorded this amount as an increase in product sales revenues on our consolidated statements of income and as energy commodity derivatives contracts on our consolidated balance sheet, all of which was recognized in 2011. Additionally, we recognized losses of $17.9 million on NYMEX contracts that settled during 2011 related to physical product sales during the first and second quarters of 2011. Furthermore, we realized losses of $1.2 million on NYMEX contracts that settled during 2011 but were rolled to other hedges that are associated with products we expect to sell in the future, of which $1.1 million was recognized during 2011 and $0.1 million was recognized during 2010.

◦
As of June 30, 2011, we had open NYMEX contracts for 0.7 million barrels of petroleum products associated with our blending and fractionation activities that qualified for hedge accounting treatment and were recorded as cash flow hedges. The period change in fair value of these agreements are not included in product sales revenues in our consolidated statement of income until the petroleum products hedged are physically sold. These contracts mature between September and December 2011. The cumulative amount of unrealized gains through June 30, 2011 associated with these agreements, which are related to products we expect to sell in the future, was $2.2 million. Prior to becoming qualified cash flow hedges, we recognized unrealized losses of $2.4 million on these agreements during 2011, which was recorded as a decrease in product sales revenue on our consolidated statements of income.

◦
As of June 30, 2011, we had open NYMEX contracts covering 0.2 million barrels to hedge against future price changes of product overages related to our petroleum products pipeline over/short activity that did not qualify for hedge accounting treatment. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature in July 2011. The cumulative amount of unrealized losses through June 30, 2011 associated with these agreements, which are related to products we expected to sell in the future, was $1.8 million. We recorded this amount as an increase in operating expenses on our consolidated statement of income and as energy commodity derivatives contracts on our consolidated balance sheet, all of which was recognized in 2011. Additionally, we recognized gains of $3.0 million on NYMEX contracts that settled during 2011 related to physical product sales during the first and second quarters of 2011.

◦
As of June 30, 2011, we had open butane price swap positions to purchase 0.3 million barrels of butane that we did not designate as hedges for accounting purposes. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature between August and November 2011. The cumulative amount of unrealized losses through June 30, 2011 associated with these agreements, which are related to products we expect to purchase in the future, was $0.8 million. We recorded this amount as an increase in product purchases on our consolidated statement of income and as energy commodity derivatives contracts on our consolidated balance sheet, all of which was recognized in 2011.

32
Table of Contents



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

◦
At June 30, 2011, we had open NYMEX contracts covering 1.0 million barrels to hedge against changes in the price of petroleum products associated with the linefill barrels we expect to sell in future periods. These contracts mature between July and December 2011. Because these NYMEX contracts did 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 June 30, 2011 associated with these agreements was $7.9 million, of which $4.3 million of losses were recognized during 2011 and $3.6 million of losses were recognized during 2010. Additionally, we recognized $10.9 million of losses associated with the linefill NYMEX contracts that were settled during 2011, related to physical product sales during first and second quarter 2011, that were recorded as a decrease in product sales revenues on our consolidated income statement. The linefill and working inventory associated with our Houston-to-El Paso pipeline section are classified as inventory in current assets on our consolidated balance sheets.

•
Future commodity sales of linefill, tank bottom inventory and product overages associated with our crude pipeline and storage activities:

◦
At June 30, 2011, we had open NYMEX contracts covering less than 0.1 million barrels to hedge against future price changes of linefill in a crude pipeline connected to our Cushing, Oklahoma terminal. These contracts qualified for and were designated as fair value hedges and mature in August 2011.  The unrealized losses of $0.1 million from these agreements during the current year were fully offset by an adjustment to other current assets and, therefore, there was no impact on product sales revenues. The linefill for our crude pipeline connected to our Cushing terminal is classified as an other current asset on our consolidated balance sheets. Prior to entering into the fair value hedges above, we had open NYMEX contracts hedging less than 0.1 million barrels of linefill in a crude pipeline connected to our Cushing, Oklahoma terminal that did not qualify for hedge accounting treatment. As a result, we recognized $0.1 million of gains during 2011 associated with these agreements, which were recorded as an increase in product sales revenues on our consolidated income statement.

◦
At June 30, 2011, we had open NYMEX contracts covering 0.7 million barrels to hedge future price changes on tank bottom inventory.  These contracts qualified for and were designated as fair value hedges and mature in November 2013.  The cumulative unrealized losses of $11.0 million from these agreements as of June 30, 2011 were fully offset by an adjustment to the tank bottom inventory and, therefore, there was no impact on product sales revenues. The tank bottom inventory at our Cushing terminal is separately classified as a long-term asset on our consolidated balance sheets.

◦
At June 30, 2011, we had open NYMEX contracts covering 0.1 million barrels to hedge against future price changes of product overages related to our crude pipeline activity that did not qualify for hedge accounting treatment. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature in July 2011. The cumulative amount of unrealized losses through June 30, 2011 associated with these agreements, which are related to products we expect to sell in the future, was less than $0.1 million. We recorded this amount as an increase in operating expenses on our consolidated statement of income and as energy commodity derivatives contracts on our consolidated balance sheet, all of which was recognized in 2011. Additionally, we recognized gains of $0.3 million on NYMEX contracts that settled during 2011 related to physical product sales during second quarter 2011.

The following table provides a summary of the mark-to-market gains and losses associated with NYMEX contracts and the accounting periods in which the gains and losses were recognized in our consolidated statements of income for the periods ended June 30, 2010 and 2011 (in millions):
 

33
Table of Contents


2010
 
NYMEX losses recorded during the six months ended June 30, 2010 that were associated with physical product sales during the six months ended June 30, 2010
$
(3.6
)
NYMEX gains recorded in the six months ended June 30, 2010 that were associated with future physical product sales
18.4

Total NYMEX gains which impacted product sales revenues during the six months ended June 30, 2010
$
14.8

 
 
2011
 
NYMEX losses recorded during the six months ended June 30, 2011 that were associated with physical product sales during the six months ended June 30, 2011
$
(28.8
)
NYMEX losses recorded during 2011 that were associated with future physical product sales
(7.4
)
Total NYMEX losses which impacted product sales revenues during the six months ended June 30, 2011
$
(36.2
)
 
 

Pipeline Tariff Increase. 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 each year. 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 FERC-approved methodology used for the last five-year period was the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. In December 2010, FERC approved the indexing methodology to be used for the five-year period beginning in July 2011 equal to the change in PPI-FG plus 2.65%. Certain shippers requested a rehearing of this matter by the FERC, and the FERC issued an order denying the requests for rehearing on May 23, 2011, rejecting all arguments alleged by shippers. In July 2011, a shipper filed a petition for review of this matter with the D.C. Circuit. At this time, management is unable to determine what outcome might result from this petition. Based on PPI-FG for 2010, we increased virtually all of our tariff rates by 7% on July 1, 2011, consistent with the new FERC-approved methodology.
Unrecognized Product Gains. Our petroleum terminals operations generate product overages and shortages that result from metering inaccuracies and product evaporation, expansion, releases and 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 terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum 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 terminals operations had a market value of approximately $1.8 million as of June 30, 2011. 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

In June 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-05, Comprehensive Income, which requires either that the income statement include other comprehensive income or a separate comprehensive income statement be reported immediately after the income statement.  The option to report other comprehensive income in the statement of owner's equity has been eliminated.  This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. Our adoption of this ASU in first quarter of 2011 had no impact on our results of operations, financial position or cash flows.  


34
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 manage commodity price risk. Derivatives that qualify as normal purchases and sales are accounted for using traditional accrual accounting. As of June 30, 2011, we had commitments under forward purchase contracts for product purchases of approximately 0.8 million barrels that are being accounted for as normal purchases totaling approximately $77.1 million, and we had commitments under forward sales contracts for product sales of approximately 1.1 million barrels that are being accounted for as normal sales totaling approximately $138.3 million.

We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell from our business activities where we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment and we designate and account for these as either cash flow or fair value hedges. We account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We also use butane price swap purchase agreements to hedge against changes in the price of butane that we expect to purchase in future periods. At June 30, 2011, we had open NYMEX contracts representing 3.9 million barrels of petroleum products we expect to sell in the future. Additionally, we had open butane price swap positions on the purchase of 0.3 million barrels of butane.

At June 30, 2011, the fair value of our open NYMEX contracts was a liability of $18.4 million and the value of our butane price swap purchase agreements was a liability of $0.8 million. Combined, the net liability was $19.2 million, of which $8.2 million was recorded as energy commodity derivatives contracts and $11.0 million was recorded as other noncurrent liabilities on our consolidated balance sheet.

At June 30, 2011, open NYMEX contracts representing 2.2 million barrels of petroleum products did not qualify for hedge accounting treatment. A $1.00 per barrel increase in the price of these NYMEX contracts for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $2.2 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $2.2 million increase in our product sales revenues. A $1.00 per barrel increase in the price of butane would result in a $0.3 million decrease in our product purchases and a $1.00 per barrel decrease in the price of butane would result in a $0.3 million increase in our product purchases. However, the cumulative increases or decreases in product sales revenues and purchases we recognize from our open NYMEX and butane price swap contracts will be substantially offset by higher or lower product sales revenues and purchases when the physical sale or purchase 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

In 2011, we entered into $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our 6.40% notes due 2018. We account for these agreements as fair value hedges. These agreements effectively convert $100.0 million of our 6.40% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.40% fixed rate of the notes and pay a weighted average rate of six-month LIBOR in arrears plus 2.75%. The agreements terminate in July 2018, 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. A 0.125% change in LIBOR would result in an annual adjustment to our interest expense of $0.1 million associated with these hedges.

As of June 30, 2011, we had $150.0 million outstanding on our variable rate revolving credit facility. Considering the amount outstanding on our revolving credit facility as of June 30, 2011, our annual interest expense would change by $0.2 million if LIBOR were to change by 0.125%.

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.

35
Table of Contents


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 June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. On September 1, 2010, we completed an acquisition of a business from BP Pipelines (North America), Inc. Previously, as permitted by the Securities and Exchange Commission, management had elected to exclude this acquisition from its assessment of the effectiveness of our internal control over financial reporting. However, effective with this report, management has included this acquisition in its assessment of the effectiveness of our internal control over financial reporting.

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 petroleum products, crude oil and natural gas liquids and expectations about future prices for these products;
•
changes in general economic conditions, interest rates and price levels;
•
changes in the financial condition of our customers, vendors, derivatives counterparties or lenders;
•
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 pipelines owned and operated by third parties and connected to our assets;
•
changes in demand for storage in our petroleum terminals and along our petroleum pipeline system;
•
changes in supply patterns for our storage terminals;
•
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 or more aggressive enforcement or increased assessments under existing forms of 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 that govern the product quality specifications that could impact our ability to produce gasoline volumes through our blending activities or that could require significant capital outlays for compliance;
•
changes in laws and regulations to which we are or could become subject, including tax withholding issues, safety, employment and environmental laws and regulations, including laws and regulations designed to address climate change;
•
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,

36
Table of Contents


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;
•
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.


 

37
Table of Contents



PART II
OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

In July 2011, Magellan received an information request from the U.S. Environmental Protection Agency, pursuant to Section 308 of the Clean Water Act, regarding a pipeline release in February 2011 near Texas City, Texas.  We have accrued an amount for potential monetary sanctions related to this matter of $0.1 million.  We do not believe that the ultimate resolution of this matter will have a material impact on our results of operations, financial position or cash flows.

We are a party to various claims, legal actions and complaints arising in the ordinary course of business. While the results cannot be predicted with certainty, management believes 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, 2010, 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.
 

38
Table of Contents



ITEM 6.
EXHIBITS

Exhibit Number
 
Description
 
 
 
Exhibit 10.1
—
Magellan Midstream Partners' Long-Term Incentive Plan, as amended and restated on July 21, 2011.
 
 
 
Exhibit 10.2
—
Executive Severance Pay Plan dated July 21, 2011.
 
 
 
Exhibit 12
—
Ratio of earnings to fixed charges.
 
 
 
Exhibit 31.1
—
Certification of Michael N. Mears, principal executive officer.
 
 
 
Exhibit 31.2
—
Certification of John D. Chandler, principal financial officer.
 
 
Exhibit 32.1
—
Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
 
 
 
Exhibit 32.2
—
Section 1350 Certification of John D. Chandler, Chief Financial Officer.
 
 
 
Exhibit 101.INS
—
XBRL Instance Document.
 
 
 
Exhibit 101.SCH
—
XBRL Taxonomy Extension Schema.
 
 
 
Exhibit 101.CAL
—
XBRL Taxonomy Extension Calculation Linkbase.
 
 
 
Exhibit 101.DEF
—
XBRL Taxonomy Extension Definition Linkbase.
 
 
 
Exhibit 101.LAB
—
XBRL Taxonomy Extension Label Linkbase.
 
 
 
Exhibit 101.PRE
—
XBRL Taxonomy Extension Presentation Linkbase.
 
 



39
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 August 4, 2011.
 
MAGELLAN MIDSTREAM PARTNERS, L.P.
 
 
 
By:
 
Magellan GP, LLC,
 
 
its General Partner
 
 
 
/s/ John D. Chandler
John D. Chandler
Chief Financial Officer
(Principal Accounting and Financial Officer)



40
Table of Contents



INDEX TO EXHIBITS
 
 
 
Exhibit Number
 
Description
 
 
 
Exhibit 10.1
—
Magellan Midstream Partners' Long-Term Incentive Plan, as amended and restated on July 21, 2011.
 
 
 
Exhibit 10.2
—
Executive Severance Pay Plan dated July 21, 2011.
 
 
 
Exhibit 12
—
Ratio of earnings to fixed charges.
 
 
 
Exhibit 31.1
—
Certification of Michael N. Mears, principal executive officer.
 
 
 
Exhibit 31.2
—
Certification of John D. Chandler, principal financial officer.
 
 
Exhibit 32.1
—
Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
 
 
 
Exhibit 32.2
—
Section 1350 Certification of John D. Chandler, Chief Financial Officer.
 
 
 
Exhibit 101.INS
—
XBRL Instance Document.
 
 
 
Exhibit 101.SCH
—
XBRL Taxonomy Extension Schema.
 
 
 
Exhibit 101.CAL
—
XBRL Taxonomy Extension Calculation Linkbase.
 
 
 
Exhibit 101.DEF
—
XBRL Taxonomy Extension Definition Linkbase.
 
 
 
Exhibit 101.LAB
—
XBRL Taxonomy Extension Label Linkbase.
 
 
 
Exhibit 101.PRE
—
XBRL Taxonomy Extension Presentation Linkbase.
 
 
 
 
 
 
 

 



41