10-Q 1 mmp-2012331x10q.htm MMP - 2012.3.31-10Q


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ________________________________________
FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2012
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 12b-2 of the Exchange
Act).    Yes  £    No  x
As of May 2, 2012, there were 113,100,436 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
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.
 
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


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
March 31,
 
2011
 
2012
Transportation and terminals revenues
$
205,408

 
$
217,554

Product sales revenues
237,296

 
275,730

Affiliate management fee revenue
193

 
199

Total revenues
442,897

 
493,483

Costs and expenses:
 
 
 
Operating
62,361

 
68,452

Product purchases
211,230

 
248,612

Depreciation and amortization
29,363

 
31,510

General and administrative
24,590

 
23,744

Total costs and expenses
327,544

 
372,318

Equity earnings
1,367

 
1,648

Operating profit
116,720

 
122,813

Interest expense
26,486

 
29,123

Interest income
(10
)
 
(35
)
Interest capitalized
(671
)
 
(864
)
Debt placement fee amortization expense
385

 
519

Income before provision for income taxes
90,530

 
94,070

Provision for income taxes
465

 
546

Net income
$
90,065

 
$
93,524

Allocation of net income (loss):
 
 
 
Non-controlling owners’ interest
$
(63
)
 
$

Limited partners’ interest
90,128

 
93,524

Net income
$
90,065

 
$
93,524

Basic and diluted net income per limited partner unit
$
0.80

 
$
0.83

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation
112,762

 
113,091


See notes to consolidated financial statements.


2


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited, in thousands)
 
 
Three Months Ended
March 31,
 
2011
 
2012
Net income
$
90,065

 
$
93,524

Other comprehensive income:
 
 

Reclassification of net gain on interest rate cash flow hedges to interest expense
(41
)
 
(41
)
Amortization of prior service credit and actuarial loss
78

 
852

Total other comprehensive income
37

 
811

Comprehensive income
90,102

 
94,335

Comprehensive loss attributable to non-controlling owners’ interest in consolidated subsidiaries
(63
)
 

Comprehensive income attributable to partners’ capital
$
90,165

 
$
94,335

See notes to consolidated financial statements.

 

3


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
 
December 31,
2011
 
March 31,
2012
ASSETS
 
 
(Unaudited)
Current assets:
 
 
 
Cash and cash equivalents
$
209,620

 
$
151,642

Trade accounts receivable (less allowance for doubtful accounts of $68 and $2 at December 31, 2011 and March 31, 2012, respectively)
82,497

 
103,052

Other accounts receivable
10,079

 
12,338

Inventory
258,860

 
240,167

Energy commodity derivatives contracts, net
4,914

 

Energy commodity derivatives deposits, net
26,917

 
41,667

Reimbursable costs
5,891

 
4,806

Other current assets
13,412

 
12,776

Total current assets
612,190

 
566,448

Property, plant and equipment
4,080,484

 
4,105,951

Less: accumulated depreciation
830,762

 
853,660

Net property, plant and equipment
3,249,722

 
3,252,291

Equity investments
35,594

 
39,379

Long-term receivables
2,534

 
2,852

Goodwill
53,260

 
53,260

Other intangibles (less accumulated amortization of $14,813 and $15,479 at December 31, 2011 and March 31, 2012, respectively)
15,176

 
14,510

Debt placement costs (less accumulated amortization of $5,799 and $6,318 at December 31, 2011 and March 31, 2012, respectively)
14,615

 
14,096

Tank bottom inventory
59,473

 
64,761

Other noncurrent assets
2,437

 
2,197

Total assets
$
4,045,001

 
$
4,009,794

LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
66,384

 
$
48,542

Accrued payroll and benefits
30,184

 
16,200

Accrued interest payable
40,547

 
33,259

Accrued taxes other than income
27,570

 
21,863

Environmental liabilities
17,852

 
16,881

Deferred revenue
39,983

 
41,993

Accrued product purchases
59,800

 
67,505

Energy commodity derivatives contracts, net

 
4,654

Other current liabilities
28,735

 
21,362

Total current liabilities
311,055

 
272,259

Long-term debt
2,151,775

 
2,150,107

Long-term pension and benefits
67,080

 
71,319

Other noncurrent liabilities
19,905

 
23,659

Environmental liabilities
31,783

 
30,645

Commitments and contingencies
 
 
 
Partners’ capital:
 
 
 
Limited partner unitholders (112,737 units and 113,100 units outstanding at December 31, 2011 and March 31, 2012, respectively)
1,510,604

 
1,508,195

Accumulated other comprehensive loss
(47,201
)
 
(46,390
)
Total partners’ capital
1,463,403

 
1,461,805

Total liabilities and partners' capital
$
4,045,001

 
$
4,009,794

See notes to consolidated financial statements.

4


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
 
Three Months Ended
March 31,
 
2011
 
2012
Operating Activities:
 
 
 
Net income
$
90,065

 
$
93,524

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
29,363

 
31,510

Debt placement fee amortization
385

 
519

Loss on sale, retirement and impairment of assets
1,830

 
5,407

Equity earnings
(1,367
)
 
(1,648
)
Distributions from equity investments
1,367

 
1,648

Equity-based incentive compensation expense
3,750

 
2,843

Amortization of prior service credit and actuarial loss
78

 
852

Changes in operating assets and liabilities:
 
 
 
Restricted cash
14,379

 

Trade accounts receivable and other accounts receivable
(8,658
)
 
(22,814
)
Inventory
(8,151
)
 
18,693

Energy commodity derivatives contracts, net of derivatives deposits
(1,404
)
 
(8,358
)
Reimbursable costs
6,263

 
1,085

Accounts payable
2,596

 
(16,863
)
Accrued payroll and benefits
(13,388
)
 
(13,984
)
Accrued interest payable
(4,285
)
 
(7,288
)
Accrued taxes other than income
(6,163
)
 
(5,707
)
Accrued product purchases
37,311

 
7,705

Current and noncurrent environmental liabilities
2,032

 
(2,109
)
Other current and noncurrent assets and liabilities
1,382

 
4,726

Net cash provided by operating activities
147,385

 
89,741

Investing Activities:
 
 
 
Property, plant and equipment:
 
 
 
Additions to property, plant and equipment
(50,219
)
 
(37,139
)
Proceeds from sale and disposition of assets
27

 
40

Increase (decrease) in accounts payable related to capital expenditures
2,583

 
(1,979
)
Acquisition of assets
(7,363
)
 

Acquisition of non-controlling owners' interests
(40,500
)
 

Equity investments
(1,500
)
 
(3,655
)
Distributions in excess of equity investment earnings
151

 
870

Other
(1,100
)
 

Net cash used by investing activities
(97,921
)
 
(41,863
)
Financing Activities:
 
 
 
Distributions paid
(85,398
)
 
(92,177
)
Net borrowings under revolver
62,000

 

Increase (decrease) in outstanding checks
2,393

 
(678
)
Settlement of tax withholdings on long-term incentive compensation
(7,410
)
 
(13,001
)
Net cash used by financing activities
(28,415
)
 
(105,856
)
Change in cash and cash equivalents
21,049

 
(57,978
)
Cash and cash equivalents at beginning of period
7,483

 
209,620

Cash and cash equivalents at end of period
$
28,532

 
$
151,642

Supplemental non-cash financing activity:
 
 
 
Issuance of limited partner units in settlement of equity-based incentive plan awards
$
4,315

 
$
7,295

See notes to consolidated financial statements.

5

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, 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, 2011, which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2012, and the results of operations and cash flows for the three months ended March 31, 2011 and 2012. The results of operations for the three months ended March 31, 2012 are not necessarily indicative of the results to be expected for the full year ending December 31, 2012.
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, 2011.
 

2.
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 mark-to-market adjustments from New York Mercantile Exchange ("NYMEX") contracts. We use NYMEX contracts to hedge against changes in the prices of petroleum products we expect to sell from our business activities in which 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 contracts designated as cash flow hedges 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. Changes in the fair value and any ineffectiveness of contracts designated as fair value hedges do not impact product sales. We account for certain 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 7 - Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.
For the three months ended March 31, 2011 and 2012, product sales revenues included the following (in thousands):

6

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
Three Months Ended
March 31,
 
2011
 
2012
Physical sale of petroleum products
$
275,629

 
$
307,706

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)
(19,980
)
 
(24,889
)
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)
(18,427
)
 
(7,099
)
Other
74

 
12

Total NYMEX contract adjustments
(38,333
)
 
(31,976
)
Total product sales revenues
$
237,296

 
$
275,730

 
 
 
 
(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 inventory in current assets on our consolidated balance sheets.


3.
Segment Disclosures
Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenues from affiliates and external customers, operating expenses, product purchases and equity earnings. Transactions between our business segments are conducted and recorded on the same basis as transactions with third-party entities.
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 below. Operating profit includes depreciation and amortization expense and general and administrative ("G&A") expenses that management does not focus on when evaluating the core profitability of our operations.



7

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
Three Months Ended March 31, 2011
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
144,062

 
$
55,221

 
$
7,032

 
$
(907
)
 
$
205,408

Product sales revenues
226,988

 
10,418

 

 
(110
)
 
237,296

Affiliate management fee revenue
193

 

 

 

 
193

Total revenues
371,243

 
65,639

 
7,032

 
(1,017
)
 
442,897

Operating expenses
37,710

 
21,996

 
3,331

 
(676
)
 
62,361

Product purchases
208,473

 
3,774

 

 
(1,017
)
 
211,230

Equity earnings
(1,367
)
 

 

 

 
(1,367
)
Operating margin
126,427

 
39,869

 
3,701

 
676

 
170,673

Depreciation and amortization expense
18,552

 
9,771

 
364

 
676

 
29,363

G&A expenses
18,455

 
5,471

 
664

 

 
24,590

Operating profit
$
89,420

 
$
24,627

 
$
2,673

 
$

 
$
116,720


 
 
 
Three Months Ended March 31, 2012
 
(in thousands)
 
Petroleum
Pipeline
System
 
Petroleum
Terminals
 
Ammonia
Pipeline
System
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenues
$
148,730

 
$
63,180

 
$
6,349

 
$
(705
)
 
$
217,554

Product sales revenues
266,257

 
9,765

 

 
(292
)
 
275,730

Affiliate management fee revenue
199

 

 

 

 
199

Total revenues
415,186

 
72,945

 
6,349

 
(997
)
 
493,483

Operating expenses
46,554

 
20,182

 
2,450

 
(734
)
 
68,452

Product purchases
244,881

 
4,728

 

 
(997
)
 
248,612

Equity earnings
(1,669
)
 
21

 

 

 
(1,648
)
Operating margin
125,420

 
48,014

 
3,899

 
734

 
178,067

Depreciation and amortization expense
19,663

 
10,729

 
384

 
734

 
31,510

G&A expenses
17,455

 
5,666

 
623

 

 
23,744

Operating profit
$
88,302

 
$
31,619

 
$
2,892

 
$

 
$
122,813



8

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



4.
Inventory
Inventory at December 31, 2011 and March 31, 2012 was as follows (in thousands):
 
 
December 31, 2011
 
March 31, 2012
Refined petroleum products
$
127,999

 
$
117,865

Natural gas liquids
55,490

 
46,691

Transmix
60,251

 
55,968

Crude oil
8,065

 
12,064

Additives
7,055

 
7,579

Total inventory
$
258,860

 
$
240,167



5.
Employee Benefit Plans
We sponsor two union pension plans for certain employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following table presents our consolidated net periodic benefit costs related to these plans during the three months ended March 31, 2011 and 2012 (in thousands):
 
 
Three Months  Ended
March 31, 2011
 
Three Months  Ended
March 31, 2012
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
1,985

 
$
91

 
$
3,190

 
$
138

Interest cost
949

 
259

 
1,203

 
257

Expected return on plan assets
(1,021
)
 

 
(1,176
)
 

Amortization of prior service cost (credit)
77

 
(213
)
 
77

 
(213
)
Amortization of actuarial loss
151

 
63

 
827

 
161

Net periodic benefit cost
$
2,141

 
$
200

 
$
4,121

 
$
343


Net periodic benefit costs for the pension plans increased approximately $2.0 million in first quarter 2012 primarily due to decreases in the discount rate at December 31, 2011.
Contributions estimated to be paid into the plans in 2012 are $12.7 million and $0.6 million for the pension and other postretirement benefit plans, respectively.


6.
Debt
Consolidated debt at December 31, 2011 and March 31, 2012 was as follows (in thousands):

9

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
 
 
Weighted-Average Interest Rate at March 31, 2012 (a)
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
March 31, 2012
 
Revolving credit facility
 
$

 
$

 
—%
$250.0 million of 6.45% Notes due 2014
 
249,844

 
249,859

 
6.3%
$250.0 million of 5.65% Notes due 2016
 
252,037

 
251,930

 
5.6%
$250.0 million of 6.40% Notes due 2018
 
263,477

 
262,962

 
5.3%
$550.0 million of 6.55% Notes due 2019
 
578,521

 
577,665

 
5.6%
$550.0 million of 4.25% Notes due 2021
 
558,932

 
558,723

 
4.0%
$250.0 million of 6.40% Notes due 2037
 
248,964

 
248,968

 
6.4%
Total debt
 
$
2,151,775

 
$
2,150,107

 
5.3%
 
 
 
 
 
 
 
(a)
Weighted-average interest rate includes the impact of 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 7—Derivative Financial Instruments for detailed information regarding fair value hedges and interest rate swaps).

The revolving credit facility and notes detailed in the table above are senior indebtedness.

The face value of our debt at December 31, 2011 and March 31, 2012 was $2.1 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.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in October 2016, is $800.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.875% to 1.75% based on our credit ratings and amounts outstanding under the facility. Additionally, an unused commitment fee is assessed at a rate from 0.125% to 0.3%, depending on our credit ratings, which was 0.2% at March 31, 2012. Borrowings under this facility may be used for general purposes, including capital expenditures. As of March 31, 2012, there were no borrowings outstanding under this facility and $5.0 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.


7.
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 swap agreements to help manage price changes, which has the effect of locking 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 and fractionation activities as normal purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2012, we had commitments under these forward purchase and sales contracts as follows (in millions):
 
Amount
 
Barrels
Forward purchase contracts
$
55.3


0.6
Forward sales contracts
$
44.4


0.3

We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in future periods. Our NYMEX contracts fall into one of three categories:


10

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Hedge Type
 
Hedge Purpose
 
Accounting Treatment
Qualifies for Hedge Accounting Treatment
    Cash Flow Hedge
 
To hedge the variability in cash flows related to a forecasted transaction.
 
The effective portion of changes in the value of the hedge are recorded to accumulated other comprehensive income/loss and reclassified to earnings when the forecasted transaction occurs. Any ineffectiveness is recognized currently in earnings.
    Fair Value Hedge
 
To hedge against changes in the fair value of a recognized asset or liability.
 
The effective portion of changes in the value of the hedge are recorded as adjustments to the asset or liability being hedged. Any ineffectiveness is recognized currently in earnings.
Does not Qualify For Hedge Accounting Treatment
    Economic Hedge
 
To effectively serve as either a fair value or a cash flow hedge; however, the derivative agreement does not qualify for hedge accounting treatment or is not designated as a hedge in accordance with Accounting Standards Codification ("ASC") 815, Derivatives and Hedging.
 
Changes in the value of these agreements are recognized currently in earnings.

We also use butane swap agreements, which are not designated as hedges for accounting purposes, to hedge against changes in the price of selected butane purchases we expect to complete in the future. Changes in the fair value of these agreements are recognized currently in earnings. As outlined in the table below, at March 31, 2012, we had open NYMEX contracts representing 3.1 million barrels of petroleum products and open butane swap agreements on the purchase of 25 thousand barrels of butane.

Type of Contract/Accounting Methodology
 
Product Represented by the Contract and Associated Barrels
 
Maturity Dates
NYMEX - Fair Value Hedges
 
0.7 million barrels of crude oil
 
Between June 2012 and November 2013
NYMEX - Economic Hedges
 
2.4 million barrels of refined petroleum products
 
Between April and December 2012
Butane Swap Agreements - Economic Hedges
 
25 thousand barrels of butane
 
August 2012

At March 31, 2012, the fair value of our open NYMEX contracts was a net liability of $16.4 million and the fair value of our butane swap agreements was a liability of less than $0.1 million. Combined, the net liability was $16.4 million, of which $4.7 million was recorded as a current liability to energy commodity derivatives contracts and $11.7 million was recorded as other noncurrent liabilities on our consolidated balance sheet. At March 31, 2012, we had made margin deposits of $41.7 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 swap agreements against our margin deposits under a master netting arrangement with each of our counterparties; however, we have elected to disclose the combined fair values of our open NYMEX and butane swap agreements separately from the related margin deposits on our consolidated balance sheet. We have the right of offset under the agreements and, therefore, have offset the fair values of our NYMEX agreements and butane swap agreements together for each counterparty separately on our consolidated balance sheets.
Impact of Derivatives on Income Statement, Balance Sheet and AOCL
The changes in derivative gains included in accumulated other comprehensive loss ("AOCL") for the three months ended March 31, 2011 and 2012 were as follows (in thousands):

11

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
Three Months Ended
March 31,
Derivative Gains Included in AOCL
2011
 
2012
Beginning balance
$
3,325

 
$
3,161

Reclassification of net gain on cash flow hedges to interest expense
(41
)
 
(41
)
Ending balance
$
3,284

 
$
3,120


As of March 31, 2012, the net gain estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.2 million.

The following table provides a summary of the effect on our consolidated statements of income for the three months ended March 31, 2011 and 2012 of derivatives accounted for under ASC 815-25, Derivatives and Hedging—Fair Value Hedges, that were designated as hedging instruments (in thousands):
 
 
 
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 March 31,
 
Three Months Ended March 31,
Derivative Instrument
 
 
2011
 
2012
 
2011
 
2012
Interest rate swap agreements
 
Interest expense
 
$
203

 
$

 
$
2,222

 
$

 
 
 
 
 
 
 
 
 
 
 
 
During first quarter 2012, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the unrealized losses of $11.6 million from the agreements as of March 31, 2012 were fully offset by an increase of $11.7 million to tank bottom inventory and a decrease of $0.1 million to other current assets; therefore, there was no net impact from these agreements on other income/expense.
The following tables provide a summary of the effect on our consolidated statements of income for the three months ended March 31, 2011 and 2012 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).

 
 
Three Months Ended March 31, 2011
Derivative Instrument
 
Amount of Gain (Loss) Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate swap agreements
 
 
$

 
 
Interest expense
 
 
$
41

 
 
 
Three Months Ended March 31, 2012
Derivative Instrument
 
Amount of Gain (Loss) Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate swap agreements
 
 
$

 
 
Interest expense
 
 
$
41

 

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2011 or 2012.
The following table provides a summary of the effect on our consolidated statements of income for the three months ended March 31, 2011 and 2012 of derivatives accounted for under ASC 815-10-35; Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments (in thousands):

12

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
 
 
Amount of Gain (Loss)
Recognized on Derivative
 
 
 
Three Months Ended
Derivative Instrument
Location of Gain (Loss)
Recognized on Derivative
 
March 31, 2011
 
March 31, 2012
NYMEX commodity contracts
Product sales revenues
 
$
(38,333
)
 
$
(31,976
)
NYMEX commodity contracts
Operating expenses
 
(47
)
 
(5,184
)
Butane swap agreements
Product purchases
 

 
43

 
Total
 
$
(38,380
)
 
$
(37,117
)
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, 2011 and March 31, 2012 (in thousands):
 
December 31, 2011
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Energy commodity derivatives contracts
 
$
31

 
Energy commodity derivatives contracts
 
$

NYMEX commodity contracts
Other noncurrent assets
 

 
Other noncurrent liabilities
 
6,457

 
Total
 
$
31

 
Total
 
$
6,457

 
 
March 31, 2012
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Energy commodity derivatives contracts
 
$
169

 
Energy commodity derivatives contracts
 
$

NYMEX commodity contracts
Other noncurrent assets
 

 
Other noncurrent liabilities
 
11,744

 
Total
 
$
169

 
Total
 
$
11,744

 

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, 2011 and March 31, 2012 (in thousands):
 
December 31, 2011
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Energy commodity derivatives contracts
 
$
6,403

 
Energy commodity derivatives contracts
 
$
1,514

Butane swap agreements
Energy commodity derivatives contracts
 
28

 
Energy commodity derivatives contracts
 
34

 
Total
 
$
6,431

 
Total
 
$
1,548

 
 
 
 
 
 
 
 
 
March 31, 2012
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
Energy commodity derivatives contracts
 
$
3,414

 
Energy commodity derivatives contracts
 
$
8,230

Butane swap agreements
Energy commodity derivatives contracts
 

 
Energy commodity derivatives contracts
 
7

 
Total
 
$
3,414

 
Total
 
$
8,237

 

13

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



8.
Commitments and Contingencies

Clean Air Act - Section 185 Liability

Section 185 of the Clean Air Act ("CAA 185") requires states under certain conditions to collect annual fees from major source facilities located in severe or extreme nonattainment ozone areas. 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 administer and enforce 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” to implement the requirements of CAA 185. The initial Failure to Attain 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. The initial Failure to Attain Rule was rejected by a federal court decision in July 2011. The TCEQ is now considering a new rule.

Management believes it is probable that the TCEQ will move forward with a new CAA 185 rule making process.  A number of potential alternative outcomes exist, including the possibility no CAA 185 fees will be assessed to us.  However, management 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 $10.8 million related to this matter, which we believe is the most likely outcome based on our discussions with the TCEQ. This accrual was recorded as a long-term environmental liability at March 31, 2012.

MF Global Holdings Ltd. Bankruptcy

In October 2011, MF Global Holdings Ltd., the parent of MF Global Inc. (“MF Global”), filed for bankruptcy protection under Chapter 11 of the U.S. bankruptcy laws, and a trustee was appointed to oversee the liquidation of MF Global under the Securities Investor Protection Act ("SIPA").  At that time, MF Global served as our sole clearing agent for NYMEX futures contracts. 

The Chicago Mercantile Exchange (“CME”) requires us to maintain adequate margin against our NYMEX positions, which our clearing agent is required to hold on our behalf in a segregated account.  In October 2011, MF Global disclosed to the CME that it had a “significant shortfall” in its segregated customer accounts.  We transferred our existing trading positions at MF Global to a new clearing agent in November 2011, and all of our NYMEX activity is now being conducted with our new clearing agent. 

As of the date of transfer of our account, MF Global owed us $29.4 million; however, we have subsequently received $21.2 million as partial payment on our account.  We have submitted a claim with the Trustee for the SIPA liquidation of MF Global for $8.2 million, which represents the remaining amount owed to us by MF Global.  At this point it is uncertain what additional funds MF Global will have available for distribution to its former customers as well as how the claims against MF Global's remaining assets may be prioritized. As of March 31, 2012, we have not reserved any of the receivable balance owed to us by MF Global.

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $49.6 million and $47.5 million at December 31, 2011 and March 31, 2012, 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 expenses were $3.9 million and $2.5 million for the three months ended March 31, 2011 and 2012, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 2011 were $7.7 million, of which $5.2 million and $2.5 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

14

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


March 31, 2012 were $7.7 million, of which $4.8 million and $2.9 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 $6.8 million as of March 31, 2012. 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 results of operations, financial position or cash flows.

9.
Long-Term Incentive Plan
We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and, as of March 31, 2012, 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 March 31, 2012 total 1.2 million. The compensation committee of our general partner’s board of directors administers the LTIP.
 
Our equity-based incentive compensation expense was as follows (in thousands):
 
 
Three Months Ended
March 31, 2011
 
Equity
Method
 
Liability
Method
 
Total
2009 awards
$
927

 
$
622

 
$
1,549

2010 awards
950

 
354

 
1,304

2011 awards
562

 
145

 
707

Retention awards
190

 

 
190

Total
$
2,629

 
$
1,121

 
$
3,750

 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
3,657

Operating expense
 
 
 
 
93

Total
 
 
 
 
$
3,750

 

15

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
Three Months Ended
March 31, 2012
 
Equity
Method
 
Liability
Method
 
Total
2010 awards
$
522

 
$
408

 
$
930

2011 awards
743

 
273

 
1,016

2012 awards
561

 
151

 
712

Retention awards
185

 

 
185

Total
$
2,011

 
$
832

 
$
2,843

 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
2,505

Operating expense
 
 
 
 
338

Total
 
 
 
 
$
2,843

 
In January 2012, the cumulative amounts of the 2009 LTIP awards were settled by issuing 361,383 limited partner units and distributing those units to the LTIP participants. The minimum tax withholdings associated with this settlement and employer taxes of $13.0 million and $1.3 million, respectively, were paid in January 2012.

In January 2012, the compensation committee of our general partner's board of directors approved 131,687 phantom unit awards pursuant to our LTIP. These awards have a three-year vesting period that will end on December 31, 2014.


10.
Distributions
Distributions we paid during 2011 and 2012 were as follows (in thousands, except per unit amounts):
 
Payment Date
 
Per Unit Cash
Distribution
Amount
 
Total Cash Distribution to Limited Partners
2/14/2011
 
 
$
0.7575

 
 
 
$
85,398

 
5/13/2011
 
 
0.7700

 
 
 
86,807

 
8/12/2011
 
 
0.7850

 
 
 
88,498

 
11/14/2011
 
 
0.8000

 
 
 
90,189

 
Total
 
 
$
3.1125

 
 
 
$
350,892

 
 
 
 
 
 
 
 
 
 
2/14/2012
 
 
$
0.8150

 
 
 
$
92,177

 
5/15/2012(a)
 
 
0.8400

 
 
 
95,004

 
Total
 
 
$
1.6550

 
 
 
$
187,181

 
 
 
 
 
 
 
 
 
 
(a)
Our general partner's board of directors declared this cash distribution on April 24, 2012 to be paid on May 15, 2012 to unitholders of record at the close of business on May 8, 2012.
 

11.
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. 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.

16

MAGELLAN MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Energy commodity derivatives contracts. These include NYMEX and butane 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 7 - Derivative Financial Instruments for further disclosures regarding these contracts.
Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2011 and March 31, 2012. The carrying amount of borrowings, if any, under our revolving credit facility approximates fair value due to the variable rates of that instrument.
 
The following table reflects the carrying amounts and fair values of our financial instruments as of December 31, 2011 and March 31, 2012 (in thousands):
Assets (Liabilities)
December 31, 2011
 
March 31, 2012
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Cash and cash equivalents
$
209,620

 
$
209,620

 
$
151,642

 
$
151,642

Energy commodity derivatives deposits
$
26,917

 
$
26,917

 
$
41,667

 
$
41,667

Long-term receivables
$
2,534

 
$
2,510

 
$
2,852

 
$
2,816

Energy commodity derivatives contracts (current)
$
4,914

 
$
4,914

 
$
(4,654
)
 
$
(4,654
)
Energy commodity derivatives contracts (noncurrent)
$
(6,457
)
 
$
(6,457
)
 
$
(11,744
)
 
$
(11,744
)
Debt
$
(2,151,775
)
 
$
(2,389,700
)
 
$
(2,150,107
)
 
$
(2,387,630
)
Fair Value Measurements
The following tables summarize the recurring fair value measurements of our long-term receivables, NYMEX commodity contracts and debt as of December 31, 2011 and March 31, 2012, 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, 2011 using:
Total
 
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Long-term receivables
$
2,510

 
$

 
$

 
$
2,510

Energy commodity derivatives contracts (current)
$
4,914

 
$
4,914

 
$

 
$

Energy commodity derivatives contracts (noncurrent)
$
(6,457
)
 
$
(6,457
)
 
$

 
$

Debt
$
(2,389,700
)
 
$
(2,389,700
)
 
$

 
$


Assets (Liabilities)
 
 
Fair Value Measurements as of
March 31, 2012 using:
Total
 
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Long-term receivables
$
2,816

 
$

 
$

 
$
2,816

Energy commodity derivatives contracts (current)
$
(4,654
)
 
$
(4,654
)
 
$

 
$

Energy commodity derivatives contracts (noncurrent)
$
(11,744
)
 
$
(11,744
)
 
$

 
$

Debt
$
(2,387,630
)
 
$
(2,387,630
)
 
$

 
$





12.
Related Party Transactions

We own a 50% interest in Osage Pipe Line Company, LLC and receive a management fee for the operation of its crude

17


oil pipeline. We received operating fees from this company of $0.2 million for each of the three months ended March 31, 2011 and 2012. We reported these fees as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which is in the process of constructing 0.8 million barrels of refined products storage at our Galena Park, Texas terminal. Upon completion, these tanks will be leased to an affiliate of Texas Frontera under a long-term lease agreement. Additionally, we have agreed to construct certain infrastructure assets at our Galena Park terminal which will allow for the operation of the tanks under construction by Texas Frontera. During first quarter 2012, the construction funding requests sent to us from Texas Frontera were $2.5 million, of which we paid $1.5 million in cash and $1.0 million was applied against our capital spending for the infrastructure assets under construction.

We own a 50% interest in Double Eagle Pipeline LLC ("Double Eagle"), which is in the process of constructing a 140-mile pipeline that will connect to an existing pipeline segment owned by an affiliate of Double Eagle. Once completed, Double Eagle will transport condensate from the Eagle Ford shale formation to our terminal in Corpus Christi, Texas. During first quarter 2012, we paid construction funding requests to Double Eagle of $2.0 million.

Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase petroleum products from subsidiaries of Targa. For the three months ended March 31, 2011 and 2012, we made purchases of petroleum products from subsidiaries of Targa of $0.3 million and $12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions.

In January 2011, our former chief executive officer, Don R. Wellendorf, retired. In conjunction with Mr. Wellendorf's retirement, our general partner's board of directors engaged Mr. Wellendorf as a consultant to us for a period of twelve months beginning in February 2011 for consideration of $0.3 million and an agreement that certain of his previously-awarded phantom unit awards that would otherwise have been forfeited would not be forfeited.


13.
Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

Quarterly distribution. In April 2012, our general partner's board of directors declared a quarterly distribution of $0.84 per unit to be paid on May 15, 2012 to unitholders of record at the close of business on May 8, 2012. The total cash distributions to be paid are $95.0 million (see Note 10—Distributions for details).



18


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

Introduction
We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of petroleum products. As of March 31, 2012, our three operating segments included:
petroleum pipeline system, comprised of approximately 9,600 miles of pipeline and 50 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, 2011.

Recent Developments

Pipeline Conversion to Crude Service. In March 2012, we announced our intention to expand the capacity of our Crane-to-Houston crude oil pipeline from 135,000 to 225,000 barrels per day. The expanded pipeline capacity is fully-committed with long-term agreements. We had previously announced the initiation of a project to reverse and convert to crude oil service our pipeline from Crane, Texas to our East Houston, Texas terminal, with an expected initial capacity of 135,000 barrels per day and a cost of $245.0 million. The project is now estimated to cost $375.0 million based on the expanded scope. Subject to receiving the necessary permits and regulatory approvals, we expect the reversed pipeline to begin transporting crude oil at partial capacity by early 2013, increasing to its full 225,000 barrel per day capacity by mid-2013.

Unitholder Elections. In April 2012, at our annual meeting of limited partners, our limited partners:

Elected Robert G. Croyle and Barry R. Pearl to serve as Class I directors of our general partner's board of directors until the 2015 annual meeting of limited partners;

Approved, on an advisory basis, the compensation of our named executive officers (as described in our proxy statement dated February 24, 2012); and

Ratified the appointment of Ernst & Young LLP to audit our 2012 financial statements.

Collective Bargaining Agreement with the United Steel Workers ("USW"). During first quarter 2012, we reached agreement with the USW which represents approximately 250 employees assigned to our petroleum pipeline system.   The current collective bargaining agreement with the USW will be effective through January 31, 2015.

Cash Distribution. In April 2012, the board of directors of our general partner declared a quarterly cash distribution of $0.84 per unit for the period of January 1, 2012 through March 31, 2012. This quarterly cash distribution will be paid on May 15, 2012 to unitholders of record on May 8, 2012. Total distributions to be paid under this declaration are approximately $95.0 million.


Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, which management does not focus on when evaluating the core profitability of our operations. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-

19


related activities, is provided in this table. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.


Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2012
 
 
Three Months  Ended
March 31,
 
Variance
Favorable  (Unfavorable)
 
2011
 
2012
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenues:
 
 
 
 
 
 
 
Petroleum pipeline system
$
144.1

 
$
148.7

 
$
4.6

 
3
Petroleum terminals
55.2

 
63.2

 
8.0

 
14
Ammonia pipeline system
7.0

 
6.3

 
(0.7
)
 
(10)
Intersegment eliminations
(0.9
)
 
(0.6
)
 
0.3

 
33
Total transportation and terminals revenues
205.4

 
217.6

 
12.2

 
6
Affiliate management fee revenue
0.2

 
0.2

 

 
Operating expenses:
 
 
 
 
 
 
 
Petroleum pipeline system
37.7

 
46.6

 
(8.9
)
 
(24)
Petroleum terminals
22.0

 
20.2

 
1.8

 
8
Ammonia pipeline system
3.3

 
2.5

 
0.8

 
24
Intersegment eliminations
(0.6
)
 
(0.8
)
 
0.2

 
33
Total operating expenses
62.4

 
68.5

 
(6.1
)
 
(10)
Product margin:
 
 
 
 
 
 
 
Product sales revenues
237.3

 
275.7

 
38.4

 
16
Product purchases
211.2

 
248.6

 
(37.4
)
 
(18)
Product margin(a)
26.1

 
27.1

 
1.0

 
4
Equity earnings
1.4

 
1.6

 
0.2

 
14
Operating margin
170.7

 
178.0

 
7.3

 
4
Depreciation and amortization expense
29.4

 
31.5

 
(2.1
)
 
(7)
G&A expense
24.6

 
23.7

 
0.9

 
4
Operating profit
116.7

 
122.8

 
6.1

 
5
Interest expense (net of interest income and interest capitalized)
25.8

 
28.2

 
(2.4
)
 
(9)
Debt placement fee amortization expense
0.4

 
0.5

 
(0.1
)
 
(25)
Income before provision for income taxes
90.5

 
94.1

 
3.6

 
4
Provision for income taxes
0.4

 
0.6

 
(0.2
)
 
(50)
Net income
$
90.1

 
$
93.5

 
$
3.4

 
4
Operating Statistics:
 
 
 
 
 
 
 
Petroleum pipeline system:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.043

 
$
1.056

 
 
 
 
Volume shipped (million barrels):(b)
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Gasoline
52.4

 
45.9

 
 
 
 
Distillates
29.6

 
29.8

 
 
 
 
Aviation fuel
5.1

 
5.6

 
 
 
 
Liquefied petroleum gases
0.9

 
1.0

 
 
 
 
Crude oil
7.0

 
14.9

 
 
 
 
Total volume shipped
95.0

 
97.2

 
 
 
 
Petroleum terminals:
 
 
 
 
 
 
 
Storage terminal average utilization (million barrels per month)
30.0

 
34.8

 
 
 
 
Inland terminal throughput (million barrels)
27.6

 
28.1

 
 
 
 
Ammonia pipeline system:
 
 
 
 
 
 
 
Volume shipped (thousand tons)
221

 
189

 
 
 
 

(a) Product margin does not include depreciation or amortization expense.
(b) Excludes capacity leases.



20


Transportation and terminals revenues increased $12.2 million, primarily resulting from:
an increase in petroleum pipeline system revenues of $4.6 million resulting from:
a 2% increase in transportation volumes primarily due to an increase in crude volumes resulting from more refinery supply being diverted to our south Texas crude pipelines due to one of our customer's increasing their usage of domestic crude oil, partially offset by lower gasoline shipments due to weak gasoline demand in the current quarter;
a 1% increase in the average tariff as the 7% rate increase we implemented on July 1, 2011 was mostly offset by more shorter-haul movements, in part due to significantly higher crude volumes, as described above, which are at a lower rate than our other pipeline shipments; and
increased demand for pipeline capacity and storage leases.
an increase in petroleum terminals revenues of $8.0 million primarily due to leasing newly-constructed tanks placed into service since first quarter 2011, such as the new crude oil storage we built in Cushing, Oklahoma; and
a decrease in ammonia pipeline system revenues of $0.7 million primarily because of lower shipments.
Operating expenses increased $6.1 million, resulting from:
an increase in petroleum pipeline system expenses of $8.9 million primarily due to higher asset integrity costs, property taxes and asset retirements due to replaced assets;
a decrease in petroleum terminals expenses of $1.8 million primarily due to insurance reimbursements for maintenance work necessary following historical hurricane-related damage; and
a decrease in ammonia pipeline system expenses of $0.8 million primarily due to lower environmental accruals in the current quarter.
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 swap agreements to hedge against changes in the price of butane 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 increased $1.0 million between periods primarily due to higher profits from our petroleum products blending activities mostly due to higher product prices, partially offset by higher unrealized losses on NYMEX contracts and lower terminal product gains, principally due to lower volume of product sales.
Depreciation and amortization expense increased $2.1 million primarily due to expansion capital projects placed into service since first quarter 2011.
G&A expense decreased $0.9 million primarily due to lower equity-based incentive compensation expense.
Interest expense, net of interest income and interest capitalized, increased $2.4 million. Our average debt outstanding increased to $2.2 billion for first quarter 2012 from $1.9 billion for first quarter 2011 principally due to borrowings for expansion capital expenditures, including $250.0 million of 4.25% senior notes issued in August 2011. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.3% in first quarter 2012 from 5.5% in first quarter 2011.


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 our general partner's 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 three months ended March 31, 2011 and 2012 to net income, which is its nearest comparable GAAP financial measure, was as follows (in thousands):

21


 
 
Three Months Ended March 31,
 
Increase
 
 
2011
 
2012
 
(Decrease)
Net income
 
$
90,065

 
$
93,524

 
$
3,459

Interest expense, net
 
25,805

 
28,224

 
2,419

Depreciation and amortization(1)
 
29,748

 
32,029

 
2,281

Equity-based incentive compensation expense(2)
 
(3,660
)
 
(10,156
)
 
(6,496
)
Asset retirements and impairments
 
1,830

 
5,407

 
3,577

Commodity-related adjustments:
 
 
 

 
 
Derivative losses recognized in the period associated with future product transactions(3)
 
23,971

 
13,162

 
(10,809
)
Derivative gains (losses) recognized in previous periods associated with products sold in the period(4)
 
(9,606
)
 
3,163

 
12,769

Lower-of-cost-or-market adjustments

 

 
(1,017
)
 
(1,017
)
Houston-to-El Paso cost of sales adjustments(5)

 
(5,844
)
 
1,039

 
6,883

Total commodity-related adjustments
 
8,521

 
16,347

 
7,826

Other
 
(138
)
 
520

 
658

Adjusted EBITDA
 
152,171

 
165,895

 
13,724

Interest expense, net
 
(25,805
)
 
(28,224
)
 
(2,419
)
Maintenance capital
 
(8,650
)
 
(11,958
)
 
(3,308
)
Distributable cash flow
 
$
117,716

 
$
125,713

 
$
7,997

 
 
 
 
 
 
 
(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 three months ended March 31, 2011 and 2012 was $3.7 million and $2.8 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2011 and 2012 of $7.4 million and $13.0 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 that have not been designated as hedges for accounting purposes. These amounts represent the gains or losses from 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 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 by $8.0 million. The change in net income and depreciation and amortization is discussed in detail in Results of Operations above, the change in equity-based compensation is discussed in footnote 2 to the table above and a discussion of our maintenance capital expenditures is provided in Capital Requirements below. The change in distributable cash flow from commodity-related adjustments is primarily due to the impact of product price changes during each period on economic hedges that do not qualify for hedge accounting treatment.



Liquidity and Capital Resources

Cash Flows and Capital Expenditures
Net cash provided by operating activities was $147.4 million and $89.7 million for the three months ended March 31, 2011 and 2012, respectively. The $57.7 million decrease from 2011 to 2012 was primarily attributable to:
a $29.6 million decrease resulting from a $7.7 million increase in accrued product purchases in 2012 versus a $37.3 million increase in accrued product purchases in 2011 primarily due to the timing of invoices paid to vendors and suppliers;
a $19.5 million decrease resulting from a $16.9 million decrease in accounts payable in 2012 versus a $2.6 million increase in accounts payable in 2011 primarily due to the timing of invoices paid to vendors and suppliers;

22


a $14.4 million decrease due to the elimination of restricted cash resulting from our purchase of a private group's investment in a Cushing, Oklahoma storage project ("MCO") during first quarter 2011. 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 $14.1 million decrease resulting from a $22.8 million increase in accounts receivable and other accounts receivable in 2012 versus an $8.7 million increase during 2011 primarily due to timing of payments from our customers.
These decreases were partially offset by:
a $26.9 million increase primarily resulting from higher levels of inventory purchases in 2011 as compared to 2012; specifically, an $18.7 million decrease in inventory in 2012 versus an $8.2 million increase in inventory in 2011.
Net cash used by investing activities for the three months ended March 31, 2011 and 2012 was $97.9 million and $41.9 million, respectively. During 2012, we spent $37.1 million for capital expenditures, which included $12.0 million for maintenance capital and $25.1 million for expansion capital. During 2011, we spent $50.2 million for capital expenditures, which included $8.7 million for maintenance capital and $41.5 million for expansion capital. Also during first quarter 2011, we acquired a private investment group's common equity in MCO for $40.5 million and spent $7.4 million to acquire the remaining undivided interest in our Southlake, Texas terminal.
Net cash used by financing activities for the three months ended March 31, 2011 and 2012 was $28.4 million and $105.9 million, respectively. During 2012, we paid cash distributions of $92.2 million to our unitholders. During the first quarter of 2011, we paid cash distributions of $85.4 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 $62.0 million.
The quarterly distribution amount related to our first-quarter 2012 financial results (to be paid in second quarter 2012) is $0.84 per unit. If we meet management's targeted distribution growth of 9% for 2012 and the number of outstanding limited partner units remains at 113.1 million, total cash distributions of approximately $391.0 million will be paid to our unitholders related to 2012.
In January 2012, the cumulative amounts of the January 2009 equity-based incentive compensation award grants were settled by issuing 361,383 limited partner units and distributing those units to the participants. Associated tax withholdings of $13.0 million and employer taxes of $1.3 million were paid in January 2012.

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 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 three months ended March 31, 2011 and 2012, our maintenance capital spending was $8.7 million and $12.0 million, respectively. For 2012, we expect to incur maintenance capital expenditures for our existing businesses of approximately $70.0 million.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During the first three months of 2012, we spent $25.1 million for organic growth capital and $3.7 million for growth projects in conjunction with our joint venture partners. Based on the progress of expansion projects already underway, including the reversal and conversion of our Crane-to-Houston pipeline to crude oil, we expect to spend approximately $500.0 million for expansion capital during 2012, with an additional $180.0 million in 2013 to complete these projects.

Liquidity

Consolidated debt at December 31, 2011 and March 31, 2012 was as follows (in thousands):

23


 
 
December 31,
2011
 
March 31,
2012
 
Weighted-Average
Interest Rate  at
March 31, 2012 (1)
Revolving credit facility
$

 
$

 
$250.0 million of 6.45% Notes due 2014
249,844

 
249,859

 
6.3%
$250.0 million of 5.65% Notes due 2016
252,037

 
251,930

 
5.6%
$250.0 million of 6.40% Notes due 2018
263,477

 
262,962

 
5.3%
$550.0 million of 6.55% Notes due 2019
578,521

 
577,665

 
5.6%
$550.0 million of 4.25% Notes due 2021
558,932

 
558,723

 
4.0%
$250.0 million of 6.40% Notes due 2037
248,964

 
248,968

 
6.4%
Total debt
$
2,151,775

 
$
2,150,107

 
5.3%
 
(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 revolving credit facility and notes detailed in the table above are senior indebtedness.

The face value of our debt at December 31, 2011 and March 31, 2012 was $2.1 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.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in October 2016, is $800.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.875% to 1.75% based on our credit ratings and amounts outstanding under the facility. Additionally, an unused commitment fee is assessed at a rate from 0.125% to 0.3%, depending on our credit ratings, which was 0.2% at March 31, 2012. Borrowings under this facility may be used for general purposes, including capital expenditures. As of March 31, 2012, there were no borrowings outstanding under this facility and $5.0 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.


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 Liability

Section 185 of the Clean Air Act ("CAA 185") requires states under certain conditions to collect annual fees from major source facilities located in severe or extreme nonattainment ozone areas. 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 administer and enforce 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” to implement the requirements of CAA 185. The initial Failure to Attain 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. The initial Failure to Attain Rule was rejected by a federal court decision in July 2011. The TCEQ is now considering a new rule.


24


Management believes it is probable that the TCEQ will move forward with a new CAA 185 rule making process.  A number of potential alternative outcomes exist, including the possibility no CAA 185 fees will be assessed to us.  However, management 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 $10.8 million related to this matter, most of which was recorded in 2011, which we believe is the most likely outcome based on our discussions with the TCEQ. This accrual was recorded as a long-term environmental liability at March 31, 2012.

Stationary Engine Emission Standards

The EPA had set a May 2013 compliance date for the reduction of carbon monoxide from the exhausts of large stationary engines.  The EPA rule generally anticipates the installation of catalytic converters to the engine exhaust to achieve compliance; however, engine replacements may be required if it is determined that catalytic converters will not achieve the required level of emission reductions.  A portion of our petroleum pipeline system uses engines to provide power to our pipeline pumps that are subject to the EPA rule, and our maintenance capital estimates include funding to comply with the EPA rule.  Initial efforts to reduce emissions with catalytic converters have not been successful so far, but we have received a one-year extension to modify or replace these engines.  If we are not able to modify or replace these engines by May 2014, sections of our petroleum pipeline system could experience capacity reductions or we could be assessed penalties until the required emission reductions are achieved.


Other Items

Derivative Agreements. Certain of the business activities in which we engage result in our owning various commodities, which exposes us to commodity price risk. We use NYMEX contracts and butane swap agreements to help manage this commodity price risk. We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell in future periods. We use and account for those NYMEX contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We use butane swap agreements to hedge against changes in the price of butane we expect to purchase in the future as part of our petroleum products blending activity. As of March 31, 2012, our open derivative contracts were as follows:

Open Derivative Contracts Designated as Hedges

NYMEX contracts covering 0.7 million barrels of crude oil to hedge against future price changes of crude linefill and tank bottom inventory. These contracts, which we are accounting for as fair value hedges, mature between June 2012 and November 2013. Through March 31, 2012, the cumulative amount of unrealized losses from these agreements was $11.6 million. The unrealized losses from these fair value hedges were recorded as adjustments to the asset being hedged and, as a result, none of these unrealized losses impacted product sales.

Open Derivative Contracts Not Designated as Hedges
NYMEX contracts covering 1.9 million barrels of petroleum products related to our petroleum products blending, fractionation and Houston-to-El Paso linefill management activities. These contracts mature between April and December 2012 and are being accounted for as economic hedges. Through March 31, 2012, the cumulative amount of net unrealized losses associated with these agreements was $6.6 million, of which $1.6 million of net gains were recognized in 2011 and $8.2 million of net losses were recognized in 2012.

NYMEX contracts covering 0.5 million barrels of petroleum products related to our pipeline product overages that mature between April and June 2012. Through March 31, 2012, the cumulative amount of unrealized gains associated with these agreements was $1.7 million. We recorded these gains as a decrease in operating expenses, all of which was recognized during 2012.

Butane swap positions to purchase 25 thousand barrels of butane that mature August 2012. Through March 31, 2012, the cumulative amount of unrealized losses associated with these agreements was less than $0.1 million. We recorded these losses as an increase in product purchases, all of which was recognized in 2012.

Settled Derivative Contracts


25


Additionally, related to physical product sales during 2012, we recognized losses of $23.8 million on NYMEX contracts that did not qualify for hedge accounting treatment that settled during 2012.

The following tables provide a summary of the mark-to-market gains and losses associated with NYMEX contracts and butane swap agreements and the accounting periods in which the gains and losses were recognized in our consolidated statements of income for the periods ended March 31, 2011 and 2012 (in millions):
 
2011
 
NYMEX losses recorded in first quarter 2011 that were associated with physical product sales during first quarter 2011
$
(14.9
)
NYMEX losses recorded in first quarter 2011 that were associated with future physical product sales
(23.4
)
Total NYMEX losses which impacted product sales revenues during the three months ended March 31, 2011
$
(38.3
)
 
 
2012
 
NYMEX losses recorded in first quarter 2012 that were associated with physical product sales during first quarter 2012
$
(23.8
)
NYMEX losses recorded in first quarter 2012 that were associated with future physical product sales
(8.2
)
Total NYMEX losses which impacted product sales revenues during the three months ended March 31, 2012
$
(32.0
)
 
 

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 $6.8 million as of March 31, 2012. 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.

Related Party Transactions. We own a 50% interest in Osage Pipe Line Company, LLC and receive a management fee for the operation of its crude oil pipeline. We received operating fees from this company of $0.2 million for each of the three months ended March 31, 2011 and 2012. We reported these fees as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which is in the process of constructing 0.8 million barrels of refined products storage at our Galena Park, Texas terminal. Upon completion, these tanks will be leased to an affiliate of Texas Frontera under a long-term lease agreement. Additionally, we have agreed to construct certain infrastructure assets at our Galena Park terminal which will allow for the operation of the tanks under construction by Texas Frontera. During first quarter 2012, the construction funding requests sent to us from Texas Frontera were $2.5 million, of which we paid $1.5 million in cash and $1.0 million was applied against our capital spending for the infrastructure assets under construction.

We own a 50% interest in Double Eagle Pipeline LLC ("Double Eagle"), which is in the process of constructing a 140-mile pipeline that will connect to an existing pipeline segment owned by an affiliate of Double Eagle. Once completed, Double Eagle will transport condensate from the Eagle Ford shale formation to our terminal in Corpus Christi, Texas. During first quarter 2012, we paid construction funding requests to Double Eagle of $2.0 million.

Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase petroleum products from subsidiaries of Targa. For the three months ended March 31, 2011 and 2012, we made purchases of petroleum products from subsidiaries of Targa of $0.3 million and $12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions.

In January 2011, our former chief executive officer, Don R. Wellendorf, retired. In conjunction with Mr. Wellendorf's retirement, our general partner's board of directors engaged Mr. Wellendorf as a consultant to us for a period of twelve months beginning in February 2011 for consideration of $0.3 million and an agreement that certain of his previously-awarded phantom unit awards that would otherwise have been forfeited would not be forfeited.



26


ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates. We have established policies to monitor and control these market risks. We also enter into derivative agreements to help manage our exposure to commodity price and interest rate risks. 

Commodity Price Risk

We use derivatives to help us manage commodity price risk. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2012, we had commitments under forward purchase and sales contracts used in our blending and fractionation activities as follows (in millions):
 
Amount
 
Barrels
Forward purchase contracts
$
55.3

 
0.6
Forward sales contracts
$
44.4

 
0.3
 
We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell from activities in which 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, or are otherwise undesignated as cash flow or fair value hedges, as economic hedges. We also use butane swap agreements to hedge against changes in the price of butane that we expect to purchase in future periods. At March 31, 2012, we had open NYMEX contracts representing 3.1 million barrels of petroleum products we expect to sell in the future. Additionally, we had open butane swap positions of 25 thousand barrels of butane we expect to purchase in the future.

At March 31, 2012, the fair value of our open NYMEX contracts was a net liability of $16.4 million and the fair value of our butane swap agreements was a liability of less than $0.1 million. Combined, the net liability was $16.4 million, of which $4.7 million was recorded as a current liability to energy commodity derivatives contracts and $11.7 million was recorded as other noncurrent liabilities on our consolidated balance sheet.

At March 31, 2012, open NYMEX contracts representing 2.4 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 $2.4 million decrease in our operating profit and a $1.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $2.4 million increase in our operating profit. However, the increases or decreases in operating profit we recognize from our open NYMEX contracts will be substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

At March 31, 2012, we had no variable rate debt outstanding, including on our revolving credit facility. Our revolving credit facility has total borrowing capacity of $800.0 million, from which we could borrow in the future. To the extent we borrow funds under this facility in any future period, those borrowings would bear interest at LIBOR plus a spread ranging from 0.875% to 1.75% based on our credit ratings and amounts outstanding under the facility.


ITEM 4.
CONTROLS AND PROCEDURES
We performed 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) as of the end of the period covered by the date of this report. We performed this evaluation 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

27


Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended March 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


Forward-Looking Statements

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as "anticipates," "believes," "continue," "could," "estimates," "expects," "forecasts," "goal," "guidance," "intends," "may," "might," "plans," "potential," "projects," "scheduled," "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 U.S.;
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, including without limitation, solar power, wind power and geothermal energy, 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;
changes in supply patterns for our storage terminals due to geopolitical events;
our ability to manage interest rate and commodity price exposures;
changes in our tariff rates implemented by the Federal Energy Regulatory Commission, the U.S. Surface Transportation Board or state regulatory agencies;
shut-downs or cutbacks at refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;
the effect of weather patterns and other natural phenomena, including climate change, on our operations and demand for our services;
an increase in the competition our operations encounter;
the occurrence of natural disasters, terrorism, operational hazards, equipment failures, system failures 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 growth projects or to complete identified growth projects on time and at projected costs;
our ability to make and integrate acquisitions and successfully complete our business strategy;
uncertainty of estimates, including accruals and costs of environmental remediation;
actions by rating agencies concerning our credit ratings;
our ability to receive all necessary approvals, consents and permits by applicable governmental entities within the time-line anticipated by project schedules for new or modified assets;
our ability to obtain all necessary approvals, consents and permits required to operate our assets;
our ability to promptly obtain all necessary materials and supplies required for construction, and to construct facilities without labor or contractor problems;
risks inherent in the use of information systems in our business and implementation of new software and hardware;

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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 become subject, including tax withholding issues, safety, security, 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, 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;
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.



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PART II
OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

In July 2011, we received an information request from the U.S. Environmental Protection Agency ("EPA"), pursuant to Section 308 of the Clean Water Act, regarding a pipeline release in February 2011 near Texas City, Texas.  We have accrued $0.1 million for potential monetary sanctions related to this matter.  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.

In March 2012, we received a Notice of Probable Violation from the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration for alleged violations related to the operation and maintenance of certain pipelines in Oklahoma and Texas. We have accrued approximately $0.1 million for potential monetary sanctions related to this matter. 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.

In April 2012, we received an information request from the EPA pursuant to Section 308 of the Clean Water Act, regarding a pipeline release in December 2011 near Nemaha, Nebraska. We have accrued $0.6 million for potential monetary sanctions related to this matter. 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, 2011, 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.
MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.
OTHER INFORMATION

None.
 

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ITEM 6.
EXHIBITS

Exhibit Number
 
Description
 
 
 
Exhibit 10.1*
 
Description of Magellan 2012 Annual Incentive Program (filed as Exhibit 10(b) to Form 10-K filed February 28, 2012).
 
 
 
Exhibit 10.2*
 
Magellan GP, LLC Non-Management Director Compensation Program effective January 1, 2012 (filed as Exhibit 10(c) to Form 10-K filed February 28, 2012).