MMP - 2015.6.30.10Q


 
 
 
 
 

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 June 30, 2015
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 August 5, 2015, there were 227,427,247 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol "MMP."
 
 
 
 
 

Table of Contents


TABLE OF CONTENTS
PART I
FINANCIAL INFORMATION
 
ITEM 1.
CONSOLIDATED FINANCIAL STATEMENTS
 
 
 
 
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
 
 
1.
 
 
2.
 
 
3.
 
 
4.
 
 
5.
 
 
6.
 
 
7.
 
 
8.
 
 
9.
 
 
10.
 
 
11.
 
 
12.
 
 
13.
 
 
14.
 
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
 
 
 
 
 
 
 
 
 
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4.
CONTROLS AND PROCEDURES
PART II
OTHER INFORMATION
ITEM 1.
ITEM 1A.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
 

1
Table of Contents


PART I
FINANCIAL INFORMATION

ITEM 1.
CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit amounts)
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2015
 
2014
 
2015
Transportation and terminals revenue
$
353,568

 
$
374,016

 
$
671,205

 
$
719,616

Product sales revenue
137,657

 
109,969

 
433,720

 
283,096

Affiliate management fee revenue
5,221

 
3,558

 
10,127

 
6,921

Total revenue
496,446

 
487,543

 
1,115,052

 
1,009,633

Costs and expenses:
 
 
 
 
 
 
 
Operating
124,874

 
131,433

 
198,371

 
229,928

Cost of product sales
109,103

 
94,507

 
307,143

 
230,686

Depreciation and amortization
46,897

 
40,440

 
84,408

 
82,137

General and administrative
39,309

 
37,942

 
74,244

 
73,440

Total costs and expenses
320,183

 
304,322

 
664,166

 
616,191

Earnings of non-controlled entities
1,955

 
24,542

 
2,421

 
34,132

Operating profit
178,218

 
207,763

 
453,307

 
427,574

Interest expense
37,265

 
39,756

 
73,681

 
76,363

Interest income
(406
)
 
(334
)
 
(797
)
 
(683
)
Interest capitalized
(6,843
)
 
(2,946
)
 
(12,153
)
 
(5,053
)
Debt placement fee amortization expense
602

 
640

 
1,201

 
1,227

Other income
—

 
(6,539
)
 
—

 
(6,260
)
Income before provision for income taxes
147,600

 
177,186

 
391,375

 
361,980

Provision for income taxes
1,340

 
(205
)
 
2,561

 
953

Net income
$
146,260

 
$
177,391

 
$
388,814

 
$
361,027

Basic and diluted net income per limited partner unit
$
0.64

 
$
0.78

 
$
1.71

 
$
1.59

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation
227,288

 
227,631

 
227,215

 
227,578











See notes to consolidated financial statements.

2
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited, in thousands)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2015
 
2014
 
2015
Net income
$
146,260

 
$
177,391

 
$
388,814

 
$
361,027

Other comprehensive income:
 
 

 
 
 

Derivative activity:
 
 
 
 
 
 
 
Net gain (loss) on cash flow hedges(1)
—

 
1,936

 
(3,613
)
 
(13,529
)
Reclassification of net loss (gain) on cash flow hedges to income(1)  
(153
)
 
388

 
(179
)
 
588

Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
 
 
 
 
 
 
 
Amortization of prior service credit(2)
(928
)
 
(928
)
 
(1,823
)
 
(1,856
)
Amortization of actuarial loss(2)
1,192

 
2,023

 
2,016

 
3,595

Settlement cost(2)
1,569

 
—

 
1,569

 
—

Total other comprehensive income (loss)
1,680

 
3,419

 
(2,030
)
 
(11,202
)
Comprehensive income
$
147,940

 
$
180,810

 
$
386,784

 
$
349,825

(1) See Note 8–Derivative Financial Instruments for details of the amount of gain/loss recognized in accumulated other comprehensive loss ("AOCL") for derivative financial instruments and the amount of gain/loss reclassified from AOCL into income.
(2) See Note 6–Employee Benefit Plans for details of the changes in employee benefit plan assets and benefit obligations recognized in AOCL.

























See notes to consolidated financial statements.

3
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
 
December 31,
2014
 
June 30,
2015
ASSETS
 
 
(Unaudited)
Current assets:
 
 
 
Cash and cash equivalents
$
17,063

 
$
29,030

Trade accounts receivable (less allowance for doubtful accounts of $0 and $20 at December 31, 2014 and June 30, 2015, respectively)
84,465

 
84,715

Other accounts receivable
15,711

 
12,447

Inventory
157,762

 
159,920

Energy commodity derivatives contracts, net
87,151

 
—

Energy commodity derivatives deposits
6,184

 
5,696

Other current assets
34,331

 
40,893

Total current assets
402,667

 
332,701

Property, plant and equipment
5,533,935

 
5,832,338

Less: Accumulated depreciation
1,204,601

 
1,278,865

Net property, plant and equipment
4,329,334

 
4,553,473

Investments in non-controlled entities
613,867

 
666,451

Long-term receivables
28,611

 
25,614

Goodwill
53,260

 
53,260

Other intangibles (less accumulated amortization of $11,526 and $12,885 at December 31, 2014 and June 30, 2015, respectively)
4,573

 
3,214

Debt placement costs (less accumulated amortization of $8,952 and $10,179 at December 31, 2014 and June 30, 2015, respectively)
18,084

 
21,591

Tank bottoms and linefill
42,585

 
47,204

Other noncurrent assets
24,304

 
28,548

Total assets
$
5,517,285

 
$
5,732,056

LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
97,131

 
$
95,810

Accrued payroll and benefits
48,298

 
33,576

Accrued interest payable
45,973

 
52,037

Accrued taxes other than income
47,888

 
46,865

Environmental liabilities
10,564

 
14,581

Deferred revenue
71,142

 
71,178

Accrued product purchases
44,355

 
21,629

Energy commodity derivatives contracts, net
5,413

 
2,860

Energy commodity derivatives deposits
84,463

 
—

Other current liabilities
80,928

 
44,669

Total current liabilities
536,155

 
383,205

Long-term debt
2,982,895

 
3,326,936

Long-term pension and benefits
75,155

 
79,807

Other noncurrent liabilities
29,069

 
23,843

Environmental liabilities
25,778

 
21,877

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partner unitholders (227,068 units and 227,427 units outstanding at December 31, 2014 and June 30, 2015, respectively)
1,949,773

 
1,989,130

Accumulated other comprehensive loss
(81,540
)
 
(92,742
)
Total partners’ capital
1,868,233

 
1,896,388

Total liabilities and partners' capital
$
5,517,285

 
$
5,732,056


See notes to consolidated financial statements.

4
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
Six Months Ended
 
June 30,
 
2014
 
2015
Operating Activities:
 
 
 
Net income
$
388,814

 
$
361,027

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
84,408

 
82,137

Debt placement fee amortization expense
1,201

 
1,227

Loss on sale and retirement of assets
3,310

 
2,084

Earnings of non-controlled entities
(2,421
)
 
(34,132
)
Distributions from investments in non-controlled entities
1,713

 
31,243

Equity-based incentive compensation expense
12,753

 
10,539

Amortization of prior service credit, actuarial loss and pension settlement
1,762

 
1,739

Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable and other accounts receivable
25,486

 
3,096

Inventory
(1,718
)
 
(2,158
)
Energy commodity derivatives contracts, net of derivatives deposits
(4,133
)
 
(1,411
)
Accounts payable
486

 
8,406

Accrued payroll and benefits
(11,434
)
 
(14,722
)
Accrued interest payable
1,038

 
6,064

Accrued taxes other than income
(3,679
)
 
(1,023
)
Accrued product purchases
(25,278
)
 
(22,726
)
Deferred revenue
6,174

 
36

Current and noncurrent environmental liabilities
(3,820
)
 
116

Other current and noncurrent assets and liabilities
2,694

 
(16,723
)
Net cash provided by operating activities
477,356

 
414,819

Investing Activities:
 
 
 
Additions to property, plant and equipment, net(1)
(153,250
)
 
(275,848
)
Proceeds from sale and disposition of assets
107

 
3,153

Acquisition of business
—

 
(54,678
)
Investments in non-controlled entities
(285,945
)
 
(36,443
)
Distributions in excess of earnings of non-controlled entities
1,765

 
—

Net cash used by investing activities
(437,323
)
 
(363,816
)
Financing Activities:
 
 
 
Distributions paid
(271,914
)
 
(321,239
)
Net commercial paper borrowings (repayments)
220,977

 
(151,960
)
Borrowings under long-term notes
257,713

 
499,589

Payments on notes
(250,000
)
 
—

Debt placement costs
(2,887
)
 
(4,734
)
Net payment on financial derivatives
(3,613
)
 
(42,908
)
Settlement of tax withholdings on long-term incentive compensation
(14,813
)
 
(17,784
)
Net cash used by financing activities
(64,537
)
 
(39,036
)
Change in cash and cash equivalents
(24,504
)
 
11,967

Cash and cash equivalents at beginning of period
25,235

 
17,063

Cash and cash equivalents at end of period
$
731

 
$
29,030

 
 
 
 
Supplemental non-cash investing and financing activities:
 
 
 
Contribution of property, plant and equipment to a non-controlled entity
$
—

 
$
13,252

Issuance of limited partner units in settlement of equity-based incentive plan awards
$
7,315

 
$
8,045

 
 
 
 
(1)  Additions to property, plant and equipment
$
(149,138
)
 
$
(268,849
)
Changes in accounts payable and other current liabilities related to capital expenditures
(4,112
)
 
(6,999
)
Additions to property, plant and equipment, net
$
(153,250
)
 
$
(275,848
)

See notes to consolidated financial statements.

5
Table of Contents




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


1.
Organization, Description of Business 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.

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil.  As of June 30, 2015, our asset portfolio, including the assets of our joint ventures, consisted of:

•
our refined products segment, comprised of our 9,500-mile refined products pipeline system with 52 terminals as well as 28 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;

•
our crude oil segment, comprised of approximately 1,600 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 21 million barrels, of which 13 million barrels are used for leased storage; and

•
our marine storage segment, consisting of five marine terminals located along coastal waterways with an aggregate storage capacity of approximately 26 million barrels.

Products transported, stored or distributed through our pipelines and terminals include:

•
refined products are the output from refineries and are primarily used as fuels by consumers. Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil.  Collectively, diesel fuel and heating oil are referred to as distillates;

•
liquefied petroleum gases, or LPGs are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;

•
blendstocks are blended with refined products to change or enhance their characteristics such as increasing a gasoline's octane or oxygen content. Blendstocks include alkylates, oxygenates and natural gasoline;

•
heavy oils and feedstocks are used as burner fuels or feedstocks for further processing by refineries and petrochemical facilities. Heavy oils and feedstocks include No. 6 fuel oil and vacuum gas oil;

•
crude oil and condensate are used as feedstocks by refineries and petrochemical facilities;

•
biofuels, such as ethanol and biodiesel, are increasingly required by government mandates; and

•
ammonia is primarily used as a nitrogen fertilizer.

Except for ammonia, we use the term petroleum products to describe any, or a combination, of the above-noted products.
 

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



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, 2014 which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of June 30, 2015, the results of operations for the three and six months ended June 30, 2014 and 2015 and cash flows for the six months ended June 30, 2014 and 2015. The results of operations for the six months ended June 30, 2015 are not necessarily indicative of the results to be expected for the full year ending December 31, 2015 as profits from our blending activities are realized largely during the first and fourth quarters of each year. Additionally, gasoline demand, which drives transportation volumes and revenues on our pipeline systems, generally trends higher during the summer driving months. Further, the volatility of commodity prices impact the profits from our commodity activities and, to a lesser extent, the volume of petroleum products we ship on our pipelines.

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, 2014.

Use of Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the U.S. ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our consolidated financial statements, as well as their impact on the reported amounts of revenue and expense during the reporting periods. Actual results could differ from those estimates.


2.
Product Sales Revenue
The amounts reported as product sales revenue on our consolidated statements of income include revenue from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange ("NYMEX") contracts. See Note 8 – Derivative Financial Instruments for a discussion of our commodity hedging strategies and how our NYMEX contracts impact product sales revenues. All of the petroleum products inventory we physically sell associated with our butane blending and fractionation activities as well as the barrels from product gains we obtain from our independent terminals are reported as product sales on our consolidated statements of income. The physical sale of the petroleum products inventory from product gains obtained from our pipeline operations and crude terminal activities are reported as adjustments to operating expense.

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



For the three and six months ended June 30, 2014 and 2015, product sales revenue included the following (in thousands): 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2015
 
2014
 
2015
Physical sale of petroleum products
$
154,310

 
$
133,319

 
$
447,550

 
$
302,566

NYMEX contract adjustments:
 
 
 
 
 
 
 
Change in value of NYMEX contracts that were not designated as hedging instruments associated with our butane blending and fractionation activities
(16,666
)
 
(23,350
)
 
(13,843
)
 
(19,470
)
Other
13

 
—

 
13

 
—

Total NYMEX contract adjustments
(16,653
)
 
(23,350
)
 
(13,830
)
 
(19,470
)
Total product sales revenue
$
137,657

 
$
109,969

 
$
433,720

 
$
283,096





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 revenue from affiliates and external customers, operating expenses, cost of product sales and earnings of non-controlled 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 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 consider when evaluating the core profitability of our separate operating segments.

On May 1, 2015, we acquired a refined products terminal in Atlanta, Georgia for net cash consideration of $54.7 million. As this acquired business is not significant to our consolidated operating results and financial position, pro forma financial information and the purchase price allocation of acquired assets and liabilities have not been presented. The results of the acquired operations subsequent to the acquisition date have been included in the accompanying consolidated financial statements and in the tables below in our refined products operating segment.



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



 
Three Months Ended June 30, 2014
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
232,489

 
$
79,556

 
$
41,523

 
$
—

 
$
353,568

Product sales revenue
136,334

 
—

 
1,323

 
—

 
137,657

Affiliate management fee revenue
—

 
4,902

 
319

 
—

 
5,221

Total revenue
368,823

 
84,458

 
43,165

 
—

 
496,446

Operating expenses
97,302

 
11,867

 
16,544

 
(839
)
 
124,874

Cost of product sales
108,817

 
—

 
286

 
—

 
109,103

Earnings of non-controlled entities
—

 
(888
)
 
(1,067
)
 
—

 
(1,955
)
Operating margin
162,704

 
73,479

 
27,402

 
839

 
264,424

Depreciation and amortization expense
32,083

 
6,725

 
7,250

 
839

 
46,897

G&A expenses
25,374

 
7,697

 
6,238

 
—

 
39,309

Operating profit
$
105,247

 
$
59,057

 
$
13,914

 
$
—

 
$
178,218

 
 
Three Months Ended June 30, 2015
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
233,711

 
$
95,756

 
$
44,549

 
$
—

 
$
374,016

Product sales revenue
109,323

 
—

 
646

 
—

 
109,969

Affiliate management fee revenue
—

 
3,211

 
347

 
—

 
3,558

Total revenue
343,034

 
98,967

 
45,542

 
—

 
487,543

Operating expenses
100,475

 
16,014

 
15,881

 
(937
)
 
131,433

Cost of product sales
94,326

 
—

 
181

 
—

 
94,507

Losses (earnings) of non-controlled entities
43

 
(23,905
)
 
(680
)
 
—

 
(24,542
)
Operating margin
148,190

 
106,858

 
30,160

 
937

 
286,145

Depreciation and amortization expense
23,962

 
8,264

 
7,277

 
937

 
40,440

G&A expenses
23,893

 
9,031

 
5,018

 
—

 
37,942

Operating profit
$
100,335

 
$
89,563

 
$
17,865

 
$
—

 
$
207,763




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



 
Six Months Ended June 30, 2014
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
442,725

 
$
147,459

 
$
81,021

 
$
—

 
$
671,205

Product sales revenue
430,044

 
—

 
3,676

 
—

 
433,720

Affiliate management fee revenue
—

 
9,497

 
630

 
—

 
10,127

Total revenue
872,769

 
156,956

 
85,327

 
—

 
1,115,052

Operating expenses
148,459

 
20,925

 
30,630

 
(1,643
)
 
198,371

Cost of product sales
306,573

 
—

 
570

 
—

 
307,143

Earnings of non-controlled entities
—

 
(708
)
 
(1,713
)
 
—

 
(2,421
)
Operating margin
417,737

 
136,739

 
55,840

 
1,643

 
611,959

Depreciation and amortization expense
55,255

 
13,188

 
14,322

 
1,643

 
84,408

G&A expenses
48,393

 
13,691

 
12,160

 
—

 
74,244

Operating profit
$
314,089

 
$
109,860

 
$
29,358

 
$
—

 
$
453,307

 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
450,488

 
$
182,316

 
$
86,812

 
$
—

 
$
719,616

Product sales revenue
281,962

 
—

 
1,134

 
—

 
283,096

Affiliate management fee revenue
—

 
6,238

 
683

 
—

 
6,921

Total revenue
732,450

 
188,554

 
88,629

 
—

 
1,009,633

Operating expenses
170,781

 
29,875

 
31,216

 
(1,944
)
 
229,928

Cost of product sales
229,960

 
—

 
726

 
—

 
230,686

Losses (earnings) of non-controlled entities
98

 
(32,829
)
 
(1,401
)
 
—

 
(34,132
)
Operating margin
331,611

 
191,508

 
58,088

 
1,944

 
583,151

Depreciation and amortization expense
47,409

 
16,493

 
16,291

 
1,944

 
82,137

G&A expenses
46,492

 
17,117

 
9,831

 
—

 
73,440

Operating profit
$
237,710

 
$
157,898

 
$
31,966

 
$
—

 
$
427,574

 
 
 
 
 
 
 
 
 
 

4.
Investments in Non-Controlled Entities

Recently-Formed Company

Seabrook Logistics, LLC ("Seabrook") was formed in second quarter 2015 to construct, own and operate crude oil storage and pipeline infrastructure in the Houston Gulf Coast area. We hold a 50% equity ownership interest in Seabrook, with LBC Tank Terminals, LLC holding the other 50% equity ownership interest. The assets to be constructed and owned by Seabrook include over 700,000 barrels of crude oil storage located adjacent to LBC's existing terminal in Seabrook, Texas. In addition, Seabrook will construct and own an 18-inch diameter pipeline, which will connect Seabrook's storage facilities to an existing third-party pipeline that will transport crude oil to a Houston-area refinery. Subject to the receipt of permits and regulatory approvals, the new storage facility and pipeline infrastructure are expected to be operational in the first quarter of 2017.

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




Our investments in non-controlled entities at June 30, 2015 were comprised of:
Entity
 
Ownership Interest
BridgeTex Pipeline Company, LLC ("BridgeTex")
 
50%
Double Eagle Pipeline LLC ("Double Eagle")
 
50%
Osage Pipe Line Company, LLC ("Osage")
 
50%
Powder Springs Logistics, LLC ("Powder Springs")
 
50%
Saddlehorn Pipeline Company, LLC ("Saddlehorn")
 
40%
Seabrook Logistics, LLC
 
50%
Texas Frontera, LLC ("Texas Frontera")
 
50%

The management fees we have recognized or will recognize from BridgeTex, Osage, Powder Springs, Saddlehorn, Seabrook and Texas Frontera are or will be reported as affiliate management fee revenue on our consolidated statements of income. 

At December 31, 2014 and June 30, 2015, we recognized liabilities of $2.2 million and $1.1 million, respectively, to BridgeTex primarily for pre-paid construction management fees. For the three and six months ended June 30, 2015, we recognized pipeline capacity lease revenue from BridgeTex of $8.5 million and $16.9 million, respectively, which we included in transportation and terminals revenue on our consolidated statements of income. We recognized a $2.6 million receivable from BridgeTex at December 31, 2014 (no receivable was recognized at June 30, 2015).

We recognized throughput revenue from Double Eagle for the three months ended June 30, 2014 and 2015 of $0.8 million and $0.9 million, respectively, and for the six months ended June 30, 2014 and 2015 of $1.3 million and $1.8 million, respectively, which we included in transportation and terminals revenue.  At December 31, 2014 and June 30, 2015, respectively, we recognized a $0.3 million trade accounts receivable from Double Eagle.

The financial results from Texas Frontera are included in our marine storage segment, the financial results from BridgeTex, Double Eagle, Osage, Saddlehorn and Seabrook are or will be included in our crude oil segment and the financial results from Powder Springs are included in our refined products segment as earnings/losses of non-controlled entities.


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



A summary of our investments in non-controlled entities follows (in thousands):
 
 
BridgeTex
 
All Others
 
Consolidated
Investments at December 31, 2014
 
$
489,348

 
$
124,519

 
$
613,867

Additional investment
 
16,609

 
33,086

 
49,695

Earnings of non-controlled entities:
 
 
 

 
 
Proportionate share of earnings
 
31,828

 
3,699

 
35,527

Amortization of excess investment and capitalized interest
 
(1,020
)
 
(375
)
 
(1,395
)
Earnings of non-controlled entities
 
30,808

 
3,324

 
34,132

Less:
 
 
 
 
 
 
Distributions of earnings from investments in non-controlled entities
 
30,332

 
911

 
31,243

Investments at June 30, 2015
 
$
506,433

 
$
160,018

 
$
666,451

 
 
 
 
 
 
 

Summarized financial information of our non-controlled entities for the three and six months ended June 30, 2014 and 2015 follows (in thousands):
 
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2015
 
 
BridgeTex
 
All Others
 
Consolidated
 
BridgeTex
 
All Others
 
Consolidated
Revenue
 
$
—

 
$
11,709

 
$
11,709

 
$
61,629

 
$
11,627

 
$
73,256

Net income (loss)
 
$
(240
)
 
$
4,524

 
$
4,284

 
$
45,619

 
$
4,793

 
$
50,412


 
 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2015
 
 
BridgeTex
 
All Others
 
Consolidated
 
BridgeTex
 
All Others
 
Consolidated
Revenue
 
$
—

 
$
18,464

 
$
18,464

 
$
98,765

 
$
21,147

 
$
119,912

Net income (loss)
 
$
(280
)
 
$
5,871

 
$
5,591

 
$
63,656

 
$
7,374

 
$
71,030




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



5.
Inventory

Inventory at December 31, 2014 and June 30, 2015 was as follows (in thousands):
 
 
December 31, 2014
 
June 30,
2015
Refined products
$
67,055

 
$
33,862

Liquefied petroleum gases
37,642

 
39,942

Transmix
36,867

 
47,513

Crude oil
10,015

 
32,501

Additives
6,183

 
6,102

Total inventory
$
157,762

 
$
159,920



6.
Employee Benefit Plans
We sponsor two pension plans for certain union employees and a pension plan primarily for non-union employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three and six months ended June 30, 2014 and 2015 (in thousands):
 
 
Three Months Ended
 
Three Months Ended
 
June 30, 2014
 
June 30, 2015
 
Pension
Benefits
 
Other  Postretirement
Benefits
 
Pension
Benefits
 
Other  Postretirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
3,352

 
$
47

 
$
4,975

 
$
56

Interest cost
2,030

 
139

 
2,008

 
109

Expected return on plan assets
(1,490
)
 
—

 
(2,123
)
 
—

Amortization of prior service credit
—

 
(928
)
 
—

 
(928
)
Amortization of actuarial loss
930

 
262

 
1,806

 
217

Settlement cost
1,569

 
—

 
—

 
—

Net periodic benefit cost (credit)
$
6,391

 
$
(480
)
 
$
6,666

 
$
(546
)
 

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



 
 
Six Months Ended
 
Six Months Ended
 
June 30, 2014
 
June 30, 2015
 
Pension
Benefits
 
Other  Postretirement
Benefits
 
Pension
Benefits
 
Other  Postretirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
6,704

 
$
114

 
$
9,445

 
$
122

Interest cost
3,689

 
253

 
3,877

 
219

Expected return on plan assets
(3,187
)
 
—

 
(4,019
)
 
—

Amortization of prior service cost (credit)
33

 
(1,856
)
 
—

 
(1,856
)
Amortization of actuarial loss
1,559

 
457

 
3,153

 
442

Settlement cost
1,569

 
—

 
—

 
—

Net periodic benefit cost (credit)
$
10,367

 
$
(1,032
)
 
$
12,456

 
$
(1,073
)
 
 
 
 
 
 
 
 

Contributions estimated to be paid into the plans in 2015 are $21.1 million and $1.1 million for the pension and other postretirement benefit plans, respectively.

We match our employees' qualifying contributions to our defined contribution plan, resulting in expense to us. Expenses related to the defined contribution plan were $2.0 million and $2.2 million, respectively, for the three months ended June 30, 2014 and 2015, and $4.6 million and $5.0 million, respectively, for the six months ended June 30, 2014 and 2015.

Amounts Included in AOCL

The changes in AOCL related to employee benefit plan assets and benefit obligations for the three and six months ended June 30, 2014 and 2015 were as follows (in thousands):
 
 
Three Months Ended
 
Three Months Ended
 
 
June 30, 2014
 
June 30, 2015
Gains (Losses) Included in AOCL
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Beginning balance
 
$
(35,522
)
 
$
2,320

 
$
(61,910
)
 
$
(2,399
)
Amortization of prior service credit
 
—

 
(928
)
 
—

 
(928
)
Amortization of actuarial loss
 
930

 
262

 
1,806

 
217

Settlement cost
 
1,569

 
—

 
—

 
—

Ending balance
 
$
(33,023
)
 
$
1,654

 
$
(60,104
)
 
$
(3,110
)
 
 
Six Months Ended
 
Six Months Ended
 
 
June 30, 2014
 
June 30, 2015
Gains (Losses) Included in AOCL
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Beginning balance
 
$
(36,184
)
 
$
3,053

 
$
(63,257
)
 
$
(1,696
)
Amortization of prior service cost (credit)
 
33

 
(1,856
)
 
—

 
(1,856
)
Amortization of actuarial loss
 
1,559

 
457

 
3,153

 
442

Settlement cost
 
1,569

 
—

 
—

 
—

Ending balance
 
$
(33,023
)
 
$
1,654

 
$
(60,104
)
 
$
(3,110
)

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



7.
Debt
Consolidated debt at December 31, 2014 and June 30, 2015 was as follows (in thousands, except as otherwise noted):
 
 
December 31, 2014
 
June 30,
2015
 
Weighted-Average
Interest Rate for the Six Months Ended June 30, 2015 (1)
Commercial paper(2)
 
$
296,942

 
$
144,982

 
0.5%
$250.0 million of 5.65% Notes due 2016
 
250,758

 
250,546

 
5.7%
$250.0 million of 6.40% Notes due 2018
 
257,280

 
256,248

 
5.4%
$550.0 million of 6.55% Notes due 2019
 
567,868

 
566,006

 
5.7%
$550.0 million of 4.25% Notes due 2021
 
556,304

 
555,837

 
4.0%
$250.0 million of 3.20% Notes due 2025(2)
 
—

 
249,687

 
3.2%
$250.0 million of 6.40% Notes due 2037
 
249,017

 
249,026

 
6.4%
$250.0 million of 4.20% Notes due 2042
 
248,406

 
248,421

 
4.2%
$550.0 million of 5.15% Notes due 2043
 
556,320

 
556,270

 
5.1%
$250.0 million of 4.20% Notes due 2045(2)
 
—

 
249,913

 
4.6%
Total debt
 
$
2,982,895

 
$
3,326,936

 
4.8%
 
 
 
 
 
 
 

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

(2)
These borrowings were outstanding for only a portion of the six month period ending June 30, 2015. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

All of the instruments detailed in the table above are senior indebtedness.

The face value of our debt at December 31, 2014 and June 30, 2015 was $2.9 billion and $3.3 billion, respectively. The difference between the face value and carrying value of our debt outstanding is the unamortized portion of terminated fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

2015 Debt Offerings

In March 2015, we issued $250.0 million of our 3.20% notes due 2025 in an underwritten public offering. The notes were issued at 99.871% of par. Net proceeds from this offering were $247.6 million, after underwriting discounts and offering expenses of $2.1 million.

Also in March 2015, we issued $250.0 million of our 4.20% notes due 2045 in an underwritten public offering. The notes were issued at 99.965% of par. Net proceeds from this offering were $247.3 million, after underwriting discounts and offering expenses of $2.6 million.

The net proceeds from these offerings were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in November 2018, is $1.0 billion. Borrowings outstanding under the facility are classified as long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread

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



ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at June 30, 2015. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of June 30, 2015, there were no borrowings outstanding under this facility; however, $5.6 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.

Commercial Paper Program. The maturities of our commercial paper notes vary, but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The commercial paper we can issue is limited by the amounts available under our revolving credit facility up to an aggregate principal amount of $1.0 billion and, therefore, is classified as long-term debt.


8.
Derivative Financial Instruments

Interest Rate Derivatives

We periodically enter into interest rate derivatives to economically hedge debt, interest or expected debt issuances, and we have historically designated these derivatives as cash flow or fair value hedges for accounting purposes. Adjustments resulting from discontinued hedges continue to be recognized in accordance with their historic hedging relationships.

In first quarter 2015, we entered into a $50.0 million forward-starting interest rate swap agreement to hedge against the risk of variability of future interest payments on a portion of debt we anticipate issuing in 2016. The fair value of this contract at June 30, 2015 was recorded on our balance sheet as an other noncurrent asset of $2.9 million with an offset to other comprehensive income. We account for this agreement as a cash flow hedge.

In third and fourth quarter of 2014, we entered into $250.0 million of forward-starting interest rate swap agreements to hedge against the risk of variability of future interest payments on a portion of debt we anticipated issuing in 2015. We accounted for these agreements as cash flow hedges. When we issued the $250.0 million of 4.20% notes due 2045 in first quarter 2015, we settled the associated interest rate swap agreements for a loss of $42.9 million. The loss was recorded to other comprehensive income ($26.5 million and $16.4 million recorded in 2014 and 2015, respectively) and will be recognized into earnings as an adjustment to our periodic interest expense accruals over the life of the associated notes. This loss was also reported as a net payment on financial derivatives in the financing activities of our consolidated statements of cash flows in 2015.

Commodity Derivatives

Hedging Strategies

Our butane blending activities produce gasoline products, and we can reasonably estimate the timing and quantities of sales of these products. We use a combination of NYMEX and forward purchase and sale contracts to help manage commodity price changes, which is intended to mitigate the risk of decline in the product margin realized from our butane blending activities that we choose to hedge. Further, certain of our other commercial operations generate petroleum products. We use NYMEX contracts to hedge against future price changes for some of these commodities.

We account for the forward physical purchase and sale contracts we use in our butane blending and fractionation activities as normal purchases and sales. Forward contracts that qualify for and are elected as normal

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



purchases and sales are accounted for using traditional accrual accounting. As of June 30, 2015, we had commitments under these forward purchase and sale contracts as follows (in millions):
 
Notional Value
 
Barrels
Forward purchase contracts
$
118.3


3.5
Forward sale contracts
$
11.4


0.1

The NYMEX contracts that we enter into fall into one of three hedge categories:
Hedge Category
 
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 is 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 is recorded as adjustments to the asset or liability being hedged. Any ineffectiveness and amounts excluded from the assessment of hedge effectiveness 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 under Accounting Standards Codification ("ASC") 815, Derivatives and Hedging.
 
Changes in the fair value of these agreements are recognized currently in earnings.

During the three and six months ended June 30, 2014 and 2015, none of the commodity hedging contracts we entered into qualified for or were designated as cash flow hedges.

Period changes in the fair value of NYMEX agreements that are accounted for as economic hedges (other than those economic hedges of our butane purchases and our pipeline product overages as discussed below), the effective portion of changes in the fair value of cash flow hedges that are reclassified from accumulated other comprehensive income/loss and any ineffectiveness associated with hedges related to our commodity activities are recognized currently in earnings as adjustments to product sales.

We also use NYMEX contracts, which are not designated as hedges for accounting purposes, to hedge against changes in the price of butane we expect to purchase in the future. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to cost of product sales.

We currently hold petroleum product inventories that we obtained from overages on our pipeline systems. We use NYMEX contracts that are not designated as hedges for accounting purposes to help manage price changes related to these overage inventory barrels. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to operating expense.

Additionally, we hold crude oil barrels that we use for operational purposes which we classify as long-term assets on our balance sheet and which are reported as tank bottom and linefill assets. We use NYMEX contracts to hedge against changes in the price of these crude oil barrels. We record the effective portion of the gains or losses for those contracts that qualify as fair value hedges as adjustments to the assets being hedged and the ineffective portions as well as amounts excluded from the assessment of hedge effectiveness as adjustments to other income or expense.

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




As outlined in the table below, our open NYMEX contracts at June 30, 2015 were as follows:
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 December 2015 and November 2016
NYMEX - Economic Hedges
 
5.6 million barrels of refined products and crude oil(1)
 
Between July 2015 and December 2016
NYMEX - Economic Hedges
 
1.3 million barrels of future purchases of butane
 
Between September 2015 and December 2016

(1) Of the 5.6 million barrels of products we have economically hedged at June 30, 2015, we had open agreements which swap the pricing on 1.6 million of those barrels from New York Harbor to Platts Group 3 or Platts Gulf Coast, which are the geographic locations where these barrels will be sold.

Energy Commodity Derivatives Contracts and Deposits Offsets

At June 30, 2015, we had made margin deposits of $5.7 million for our NYMEX contracts with one of our counterparties, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the combined fair values of our open NYMEX contracts against our margin deposits under a master netting arrangement for each counterparty; however, we have elected to present the combined fair values of our open NYMEX contracts separately from the related margin deposits on our consolidated balance sheets. Additionally, we have the right to offset the fair values of our NYMEX agreements together for each counterparty, which we have elected to do, and we report the combined net balances on our consolidated balance sheets. A schedule of the derivative amounts we have offset and the deposit amounts we could offset under a master netting arrangement are provided below as of December 31, 2014 and June 30, 2015 (in thousands):
 
 
December 31, 2014
Description
 
Gross Amounts of Recognized Assets
 
Gross Amounts of Liabilities Offset in the Consolidated Balance Sheet
 
Net Amounts of Assets Presented in the Consolidated Balance Sheet(1)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
 
Net Asset Amount(3)
Energy commodity derivatives
 
$
106,764

 
$
(10,622
)
 
$
96,142

 
$
(78,279
)
 
$
17,863

 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2015
Description
 
Gross Amounts of Recognized Assets
 
Gross Amounts of Liabilities Offset in the Consolidated Balance Sheet
 
Net Amounts of Assets Presented in the Consolidated Balance Sheet(2)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
 
Net Asset Amount(3)
Energy commodity derivatives
 
$
26,262

 
$
(12,636
)
 
$
13,626

 
$
5,696

 
$
19,322

 
 
 
 
 
 
 
 
 
 
 
(1)
Net amount includes energy commodity derivative contracts classified as current assets, net, of $87,151, current liabilities of $5,413 and noncurrent assets of $14,404.
(2)
Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $2,860 and noncurrent assets of $16,486.
(3)
This represents the maximum amount of loss we would incur if all of our counterparties failed to perform on their derivative contracts.


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



Impact of Derivatives on Our Financial Statements

Comprehensive Income

The changes in derivative activity included in AOCL for the three and six months ended June 30, 2014 and 2015 were as follows (in thousands):
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
Derivative Gains (Losses) Included in AOCL
2014
 
2015
 
2014
 
2015
Beginning balance
$
9,988

 
$
(31,852
)
 
$
13,627

 
$
(16,587
)
Net gain (loss) on interest rate contract cash flow hedges
—

 
1,936

 
(3,613
)
 
(13,529
)
Reclassification of net loss (gain) on cash flow hedges to income
(153
)
 
388

 
(179
)
 
588

Ending balance
$
9,835

 
$
(29,528
)
 
$
9,835

 
$
(29,528
)
The following tables provide a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2014 and 2015 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 June 30, 2014
 
 
Amount of Loss Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into  Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
—

 
 
Interest expense
 
 
$
(30
)
 
 
 
$
183

 
 
 
Three Months Ended June 30, 2015
 
 
Amount of Gain Recognized in AOCL on Derivative
 
Location of Loss Reclassified from AOCL into  Income
 
Amount of Loss Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
1,936

 
 
Interest expense
 
 
$
(388
)
 
 
 
$
—

 
 
 
Six Months Ended June 30, 2014
 
 
Amount of Loss Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into  Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
(3,613
)
 
 
Interest expense
 
 
$
(4
)
 
 
 
$
183

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
 
Amount of Loss Recognized in AOCL on Derivative
 
Location of Loss Reclassified from AOCL into  Income
 
Amount of Loss Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
(13,529
)
 
 
Interest expense
 
 
$
(588
)
 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

As of June 30, 2015, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $1.5 million.

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



Income Statement
The following table provides a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2014 and 2015 of derivatives accounted for under ASC 815, Derivatives and Hedging, that were not designated as hedging instruments (in thousands):
 
 
 
 
Amount of Gain (Loss) Recognized on Derivative
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
Location of Gain (Loss)
Recognized on Derivative
 
June 30,
 
June 30,
Derivative Instrument
 
 
2014
 
2015
 
2014
 
2015
NYMEX commodity contracts
 
Product sales revenue
 
$
(16,653
)
 
$
(23,350
)
 
$
(13,830
)
 
$
(19,470
)
NYMEX commodity contracts
 
Operating expenses
 
(4,268
)
 
(8,883
)
 
(3,903
)
 
(7,580
)
NYMEX commodity contracts
 
Cost of product sales
 
632

 
(856
)
 
776

 
(2,080
)
 
 
Total
 
$
(20,289
)
 
$
(33,089
)
 
$
(16,957
)
 
$
(29,130
)
The impact of the derivatives in the above table was reflected as cash from operations on our consolidated statements of cash flows.

During 2014 and 2015, 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 cumulative gains at December 31, 2014 and June 30, 2015 of $13.3 million and $8.7 million, respectively, from the agreements were offset by a cumulative decrease to tank bottoms and linefill. The differential between the current spot price and forward price is excluded from the assessment of hedge effectiveness for these fair value hedges. For the three and six months ended June 30, 2015, we recognized a gain of $6.5 million and $6.3 million, respectively, for the amounts we excluded from the assessment of effectiveness of these fair value hedges, which we reported as other income on our consolidated statements of income.
Balance Sheet
The following tables provide a summary of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, which are presented on a net basis in our consolidated balance sheets, that were designated as hedging instruments as of December 31, 2014 and June 30, 2015 (in thousands):
 
 
December 31, 2014
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
360

 
Energy commodity derivatives contracts, net
 
$
—

NYMEX commodity contracts
 
Other noncurrent assets
 
14,404

 
Other noncurrent liabilities
 
—

Interest rate contracts
 
Other current assets
 
—

 
Other current liabilities
 
26,478

 
 
Total
 
$
14,764

 
Total
 
$
26,478

 

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



 
 
June 30, 2015
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
316

 
Energy commodity derivatives contracts, net
 
$
—

NYMEX commodity contracts
 
Other noncurrent assets
 
16,089

 
Other noncurrent liabilities
 
—

Interest rate contracts
 
Other noncurrent assets
 
2,901

 
Other noncurrent liabilities
 
—

 
 
Total
 
$
19,306

 
Total
 
$
—

 

The following tables provide a summary of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, which are presented on a net basis in our consolidated balance sheets, that were not designated as hedging instruments as of December 31, 2014 and June 30, 2015 (in thousands):
 
 
December 31, 2014
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
92,000

 
Energy commodity derivatives contracts, net
 
$
10,622

 
 
 
 
 
 
 
 
 
 
 
June 30, 2015
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
9,460

 
Energy commodity derivatives contracts, net
 
$
12,636

NYMEX commodity contracts
 
Other noncurrent assets
 
397

 
Other noncurrent liabilities
 
—

 
 
Total
 
$
9,857

 
Total
 
$
12,636

 

9.
Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $36.3 million and $36.5 million at December 31, 2014 and June 30, 2015, 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 expenditures recognized as a result of changes in our environmental liabilities are generally included in operating expenses on our consolidated statements of income. Environmental expenses for the three and six months ended June 30, 2014 were $0.1 million and $0.4 million, respectively. Environmental expenses for the three and six months ended June 30, 2015 were $2.9 million and $4.3 million, respectively.


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



Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 2014 were $5.1 million, of which $1.3 million and $3.8 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet. Receivables from insurance carriers and other third parties related to environmental matters at June 30, 2015 were $4.9 million, of which $1.0 million and $3.9 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet.
Other
We are a party to various other claims, legal actions and complaints arising in the ordinary course of business, including without limitation those disclosed in Item 1, Legal Proceedings of Part II of this report on Form 10-Q. 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.

10.
Long-Term Incentive Plan
We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 9.4 million of our limited partner units. The estimated units available under the LTIP at June 30, 2015 total 1.0 million. The compensation committee of our general partner’s board of directors administers our LTIP.
 
Our equity-based incentive compensation expense was as follows (in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30, 2014
 
June 30, 2014
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
 
 
 
 
 
 
2012 awards
$
1,022

 
$
1,617

 
$
2,639

 
$
2,044

 
$
2,541

 
$
4,585

2013 awards
2,195

 
1,305

 
3,500

 
3,376

 
1,853

 
5,229

2014 awards
1,228

 
—

 
1,228

 
2,132

 
—

 
2,132

Retention awards
298

 
—

 
298

 
807

 
—

 
807

Total
$
4,743

 
$
2,922

 
$
7,665

 
$
8,359

 
$
4,394

 
$
12,753

 
 
 
 
 
 
 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
7,486

 
 
 
 
 
$
12,460

Operating expense
 
 
 
 
179

 
 
 
 
 
293

Total
 
 
 
 
$
7,665

 
 
 
 
 
$
12,753


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



 
Three Months Ended
 
Six Months Ended
 
June 30, 2015
 
June 30, 2015
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
 
 
 
 
 
 
2013 awards
$
3,054

 
$
876

 
$
3,930

 
$
4,573

 
$
1,091

 
$
5,664

2014 awards
860

 
—

 
860

 
2,483

 
—

 
2,483

2015 awards
941

 
—

 
941

 
1,960

 
—

 
1,960

Retention awards
57

 
—

 
57

 
432

 
—

 
432

Total
$
4,912

 
$
876

 
$
5,788

 
$
9,448

 
$
1,091

 
$
10,539

 
 
 
 
 
 
 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
5,684

 
 
 
 
 
$
10,373

Operating expense
 
 
 
 
104

 
 
 
 
 
166

Total
 
 
 
 
$
5,788

 
 
 
 
 
$
10,539

 
 
 
 
 
 
 
 
 
 
 
 

In February 2015, 166,189 phantom unit awards were issued pursuant to our LTIP. These grants included both performance-based and retention awards and have a three-year vesting period.

In January 2015, we issued 354,529 limited partner units to settle unit award grants to certain employees that vested on December 31, 2014. Further, 4,461 limited partner units were issued during 2015 to settle the equity-based retainer paid to certain members of our general partner's board of directors.


11.
Distributions
Distributions we paid during 2014 and 2015 were as follows (in thousands, except per unit amounts):
 
Payment Date
 
Per Unit Cash
Distribution
Amount
 
Total Cash Distribution to Limited Partners
02/14/2014
 
 
$
0.5850

 
 
 
$
132,835

 
05/15/2014
 
 
0.6125

 
 
 
139,079

 
Through 06/30/2014
 
 
1.1975

 
 
 
271,914

 
08/14/2014
 
 
0.6400

 
 
 
145,324

 
11/14/2014
 
 
0.6675

 
 
 
151,568

 
Total
 
 
$
2.5050

 
 
 
$
568,806

 
 
 
 
 
 
 
 
 
 
2/13/2015
 
 
$
0.6950

 
 
 
$
158,061

 
5/15/2015
 
 
0.7175

 
 
 
163,178

 
Through 06/30/2015
 
 
1.4125

 
 
 
321,239

 
08/14/2015(1)
 
 
0.7400

 
 
 
168,296

 
Total
 
 
$
2.1525

 
 
 
$
489,535

 

(1) Our general partner's board of directors declared this cash distribution on July 23, 2015 to be paid on August 14, 2015 to unitholders of record at the close of business on August 7, 2015.
 


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



12.
Fair Value

Recurring

Fair Value Methods and Assumptions - Financial Assets and Liabilities.

We used the following methods and assumptions in estimating fair value for our financial assets and liabilities:

•
Energy commodity derivatives contracts. These include NYMEX futures 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 8 – Derivative Financial Instruments for further disclosures regarding these contracts.

•
Interest rate contracts. These include forward-starting interest rate swap agreements to hedge against the risk of variability of interest payments on future debt. These contracts are carried at fair value on our consolidated balance sheets and are valued based on an assumed exchange, at the end of each period, in an orderly transaction with a market participant in the market in which the financial instrument is traded. The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves. See Note 8 – Derivative Financial Instruments for further disclosures regarding these contracts.

•
Long-term receivables. These include lease payments receivable under a direct-financing leasing arrangement and insurance receivables. Fair value was determined by estimating the present value of future cash flows using current market rates.

•
Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2014 and June 30, 2015; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility and our commercial paper program approximates fair value due to the frequent repricing of these obligations.

Fair Value Measurements - Financial Assets and Liabilities

The following tables summarize the carrying amounts, fair values and recurring fair value measurements recorded or disclosed as of December 31, 2014 and June 30, 2015, based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):

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



 
 
As of December 31, 2014
Assets (Liabilities)
 
 
 
 
 
Fair Value Measurements using:
 
Carrying Amount
 
Fair Value
 
Quoted Prices  in Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Energy commodity derivatives contracts – assets
 
$
96,142

 
$
96,142

 
$
96,142

 
$
—

 
$
—

Interest rate contracts – liabilities
 
$
(26,478
)
 
$
(26,478
)
 
$
—

 
$
(26,478
)
 
$
—

Long-term receivables
 
$
28,611

 
$
30,200

 
$
—

 
$
—

 
$
30,200

Debt
 
$
(2,982,895
)
 
$
(3,212,462
)
 
$
—

 
$
(3,212,462
)
 
$
—


 
 
As of June 30, 2015
Assets (Liabilities)
 
 
 
 
 
Fair Value Measurements using:
 
Carrying Amount
 
Fair Value
 
Quoted Prices in Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Energy commodity derivatives contracts – assets
 
$
13,626

 
$
13,626

 
$
13,626

 
$
—

 
$
—

Interest rate contracts – assets
 
$
2,901

 
$
2,901

 
$
—

 
$
2,901

 
$
—

Long-term receivables
 
$
25,614

 
$
26,413

 
$
—

 
$
—

 
$
26,413

Debt
 
$
(3,326,936
)
 
$
(3,426,312
)
 
$
—

 
$
(3,426,312
)
 
$
—



13.
Related Party Transactions

Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of the general partner of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase butane from subsidiaries of Targa. For the three months ended June 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $1.6 million and $4.0 million, respectively. For the six months ended June 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $13.8 million and $12.8 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $0.2 million at December 31, 2014 and June 30, 2015, respectively.

Stacy P. Methvin was elected as an independent member of our general partner's board of directors on April 23, 2015 and is also a director of one of our customers.  We received tariff revenue of $2.6 million from April 23, 2015 through June 30, 2015, and have recorded a $1.3 million receivable from this customer at June 30, 2015.  The tariff revenue we recognized from this customer was in the normal course of business, with rates determined in accordance with published tariffs. 

See Note 4 – Investments in Non-Controlled Entities for a discussion of affiliate joint venture transactions we account for under the equity method.



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



14.
Subsequent Events

Recognizable events

No recognizable events occurred subsequent to June 30, 2015.

Non-recognizable events

In July 2015, our general partner's board of directors declared a quarterly distribution of $0.74 per unit to be paid on August 14, 2015 to unitholders of record at the close of business on August 7, 2015. The total cash distributions expected to be paid under this declaration are approximately $168.3 million.

26
Table of Contents


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

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of June 30, 2015, our asset portfolio, including the assets of our joint ventures, consisted of:
•
our refined products segment, comprised of our 9,500-mile refined products pipeline system with 52 terminals as well as 28 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;

•
our crude oil segment, comprised of approximately 1,600 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 21 million barrels, of which 13 million barrels are used for leased storage; and

•
our marine storage segment, consisting of five marine terminals located along coastal waterways with an aggregate storage capacity of approximately 26 million barrels.

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, 2014.

Recent Developments

Seabrook Logistics, LLC ("Seabrook"). Seabrook was formed in second quarter 2015 to construct, own and operate crude oil storage and pipeline infrastructure in the Houston Gulf Coast area. We hold a 50% equity ownership interest in Seabrook, with LBC Tank Terminals, LLC holding the other 50% equity ownership interest. The assets to be constructed and owned by Seabrook include over 700,000 barrels of crude oil storage located adjacent to LBC's existing terminal in Seabrook, Texas. In addition, Seabrook will construct and own an 18-inch pipeline, which will connect Seabrook's storage facilities to an existing third-party pipeline that will transport crude oil to a Houston-area refinery. The project is currently estimated to cost approximately $95 million, of which our 50% share will be $47.5 million, and is supported by a long-term storage and transportation commitment with a major refiner. Subject to the receipt of permits and regulatory approvals, the new storage facility and pipeline infrastructure are expected to be operational in the first quarter of 2017.

Executive Officer Changes. Aaron L. Milford, who previously served as our vice president of crude oil business development, was promoted to Senior Vice President and Chief Financial Officer on May 18, 2015, following the resignation of Michael P. Osborne from these positions.

Cash Distribution. In July 2015, the board of directors of our general partner declared a quarterly cash distribution of $0.74 per unit for the period of April 1, 2015 through June 30, 2015. This quarterly cash distribution will be paid on August 14, 2015 to unitholders of record on August 7, 2015. Total distributions expected to be paid under this declaration are approximately $168.3 million.



27
Table of Contents


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 tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in these tables. Product margin is a non-GAAP measure; however, its components of product sales revenue and cost of product sales are determined in accordance with GAAP. Our butane blending, fractionation and other commodity-related activities generate significant product revenue. We believe the product margin from these activities, which takes into account the related cost of product sales, better represents its importance to our results of operations.
 

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Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2015
 
 
Three Months Ended June 30,
 
Variance
Favorable  (Unfavorable)
 
2014
 
2015
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenue:
 
 
 
 
 
 
 
Refined products
$
232.5

 
$
233.7

 
$
1.2

 
1
Crude oil
79.6

 
95.8

 
16.2

 
20
Marine storage
41.5

 
44.5

 
3.0

 
7
Total transportation and terminals revenue
353.6

 
374.0

 
20.4

 
6
Affiliate management fee revenue
5.2

 
3.5

 
(1.7
)
 
(33)
Operating expenses:
 
 
 
 
 
 
 
Refined products
97.3

 
100.5

 
(3.2
)
 
(3)
Crude oil
11.8

 
16.0

 
(4.2
)
 
(36)
Marine storage
16.5

 
15.9

 
0.6

 
4
Intersegment eliminations
(0.8
)
 
(1.0
)
 
0.2

 
25
Total operating expenses
124.8

 
131.4

 
(6.6
)
 
(5)
Product margin:
 
 
 
 
 
 
 
Product sales revenue
137.6

 
110.0

 
(27.6
)
 
(20)
Cost of product sales
109.1

 
94.5

 
14.6

 
13
Product margin(1)
28.5

 
15.5

 
(13.0
)
 
(46)
Earnings of non-controlled entities
1.9

 
24.5

 
22.6

 
n/m
Operating margin
264.4

 
286.1

 
21.7

 
8
Depreciation and amortization expense
46.9

 
40.4

 
6.5

 
14
G&A expense
39.3

 
37.9

 
1.4

 
4
Operating profit
178.2

 
207.8

 
29.6

 
17
Interest expense (net of interest income and interest capitalized)
30.0

 
36.6

 
(6.6
)
 
(22)
Debt placement fee amortization expense
0.6

 
0.6

 
—

 
—
Other income
—

 
(6.6
)
 
6.6

 
n/a
Income before provision for income taxes
147.6

 
177.2

 
29.6

 
20
Provision for income taxes
1.4

 
(0.2
)
 
1.6

 
114
Net income
$
146.2

 
$
177.4

 
$
31.2

 
21
Operating Statistics:
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.409

 
$
1.398

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Gasoline
63.7

 
67.2

 
 
 
 
Distillates
40.5

 
36.3

 
 
 
 
Aviation fuel
6.1

 
5.3

 
 
 
 
Liquefied petroleum gases
3.7

 
4.8

 
 
 
 
Total volume shipped
114.0

 
113.6

 
 
 
 
Crude oil:
 
 
 
 
 
 
 
Magellan 100%-owned assets:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.243

 
$
1.052

 
 
 
 
Volume shipped (million barrels)
46.9

 
53.8

 
 
 
 
Crude oil terminal average utilization (million barrels per month)
12.3

 
12.8

 
 
 
 
Select joint venture pipelines:
 
 
 
 
 
 
 
BridgeTex - volume shipped (million barrels)(2)
—

 
23.7

 
 
 
 
 
 
 
 
 
 
 
 
Marine storage:
 
 
 
 
 
 
 
Marine terminal average utilization (million barrels per month)
22.7

 
24.3

 
 
 
 

(1) Product margin does not include depreciation or amortization expense.
(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned 50% by us.

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Transportation and terminals revenue increased $20.4 million resulting from:
•
an increase in refined products revenue of $1.2 million primarily attributable to higher revenue from our independent terminals and higher leased storage revenue, partially offset by lower transportation revenues. Our independent terminal revenue increased because of a recently acquired terminal as well as increased demand at our other locations and our lease storage revenues increased because of new lease contracts, including leases on recently-constructed tanks. Transportation revenue was slightly lower primarily due to more shorter-haul shipments (which have a lower rate). Overall volumes were relatively flat as higher gasoline demand across our system was more than offset by lower shipments of distillates due to reduced demand from drilling activities and wet agricultural conditions in areas served by our assets in the current period;
•
an increase in crude oil revenue of $16.2 million primarily due to revenue received in second quarter 2015 from BridgeTex Pipeline Company, LLC ("BridgeTex") for capacity on our Houston area crude oil distribution system, higher terminalling revenue resulting from the one-time benefit from a customer buying out of its remaining storage agreement in 2015 and new leased storage contracts. Transportation revenue was slightly lower in the current period due to reduced average tariffs resulting from a lower volume of spot shipments on the Longhorn pipeline system, which ship at a higher rate, and more short-haul movements on our Houston-area crude oil distribution system in 2015; and
•
an increase in marine storage revenue of $3.0 million primarily due to improved storage utilization and higher rates at our marine facilities.
Affiliate management fee revenue decreased $1.7 million due to lower construction management fees related to BridgeTex now that the pipeline is operational.
Operating expenses increased by $6.6 million primarily resulting from:
•
an increase in refined products expenses of $3.2 million primarily due to higher asset integrity spending, additional environmental accruals due to a product release in the current period and additional property taxes, partially offset by more favorable product overages (which reduce operating expense);
•
an increase in crude oil expenses of $4.2 million primarily due to less favorable product overages (which reduce operating expense) and higher pipeline capacity rental fees and power costs associated with moving additional volume in the current period; and
•
a decrease in marine storage expenses of $0.6 million primarily due to lower asset integrity spending.
Product sales revenue primarily resulted from our butane blending activities, transmix fractionation and product gains from our independent terminals. 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, and we use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. See Note 8 –Derivative Financial Instruments in Item 1 – Consolidated Financial Statements for a discussion of our hedging strategies and how our use of NYMEX contracts and butane futures agreements impacts our product margin. Product margin decreased $13.0 million primarily due to higher unrealized losses on our NYMEX contracts, which were partially offset by higher realized margins from our butane blending and fractionation activities. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.
Earnings of non-controlled entities increased $22.6 million primarily due to our share of earnings from BridgeTex, which began operations in late 2014.
Depreciation and amortization decreased $6.5 million primarily due to the $9.4 million acceleration of depreciation for pipeline, terminal and related assets during second quarter 2014 that we later sold, partially offset by increased depreciation expense in the current year for expansion capital projects.

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G&A expense decreased $1.4 million primarily due to lower costs associated with deferred board of director fees resulting from a decrease in the price of our limited partner units in the second quarter of 2015 partially offset by higher personnel costs from an increase in employee headcount.  A separation fee paid to a former executive in the current quarter was largely offset by the forfeiture of his unvested equity-based awards.
Interest expense, net of interest income and interest capitalized, increased $6.6 million in second quarter 2015, primarily because our debt balance was higher in the current period compared to the same period in 2014 and lower capitalized interest since we are no longer capitalizing interest expense for the BridgeTex pipeline construction project that is now operational. Our average outstanding debt increased from $2.9 billion in second quarter 2014 to $3.3 billion in second quarter 2015 primarily due to borrowings for expansion capital expenditures, including $250.0 million of 3.2% senior notes and $250.0 million of 4.2% senior notes issued in March 2015. Our weighted-average interest rate decreased from 5.0% in second quarter 2014 to 4.8% in second quarter 2015 due to the impact of our commercial paper borrowings and March 2015 debt issuances, which are both at lower rates than the debt we retired in mid-2014.
Other income included a $6.6 million favorable non-cash adjustment for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms and linefill assets.
Provision for income taxes was $1.6 million favorable due to a reduction in the franchise tax rate for the state of Texas.



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Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2015
 
 
Six Months Ended June 30,
 
Variance
Favorable  (Unfavorable)
 
2014
 
2015
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenue:
 
 
 
 
 
 
 
Refined products
$
442.7

 
$
450.5

 
$
7.8

 
2
Crude oil
147.5

 
182.3

 
34.8

 
24
Marine storage
81.0

 
86.8

 
5.8

 
7
Total transportation and terminals revenue
671.2

 
719.6

 
48.4

 
7
Affiliate management fee revenue
10.1

 
6.9

 
(3.2
)
 
(32)
Operating expenses:
 
 
 
 
 
 
 
Refined products
148.5

 
170.8

 
(22.3
)
 
(15)
Crude oil
20.9

 
29.9

 
(9.0
)
 
(43)
Marine storage
30.6

 
31.2

 
(0.6
)
 
(2)
Intersegment eliminations
(1.6
)
 
(2.0
)
 
0.4

 
25
Total operating expenses
198.4

 
229.9

 
(31.5
)
 
(16)
Product margin:
 
 
 
 
 
 
 
Product sales revenue
433.7

 
283.1

 
(150.6
)
 
(35)
Cost of product sales
307.1

 
230.7

 
76.4

 
25
Product margin(1)
126.6

 
52.4

 
(74.2
)
 
(59)
Earnings of non-controlled entities
2.4

 
34.1

 
31.7

 
n/m
Operating margin
611.9

 
583.1

 
(28.8
)
 
(5)
Depreciation and amortization expense
84.4

 
82.1

 
2.3

 
3
G&A expense
74.2

 
73.4

 
0.8

 
1
Operating profit
453.3

 
427.6

 
(25.7
)
 
(6)
Interest expense (net of interest income and interest capitalized)
60.7

 
70.7

 
(10.0
)
 
(16)
Debt placement fee amortization expense
1.2

 
1.2

 
—

 
—
Other income
—

 
(6.3
)
 
6.3

 
n/a
Income before provision for income taxes
391.4

 
362.0

 
(29.4
)
 
(8)
Provision for income taxes
2.6

 
1.0

 
1.6

 
62
Net income
$
388.8

 
$
361.0

 
$
(27.8
)
 
(7)
Operating Statistics:
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.384

 
$
1.384

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Gasoline
123.5

 
129.4

 
 
 
 
Distillates
78.0

 
73.2

 
 
 
 
Aviation fuel
11.1

 
10.5

 
 
 
 
Liquefied petroleum gases
5.2

 
5.8

 
 
 
 
Total volume shipped
217.8

 
218.9

 
 
 
 
Crude oil:
 
 
 
 
 
 
 
Magellan 100%-owned assets:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.182

 
$
1.081

 
 
 
 
Volume shipped (million barrels)
88.7

 
103.8

 
 
 
 
Crude oil terminal average utilization (million barrels per month)
12.2

 
12.7

 
 
 
 
Select joint venture pipelines:
 
 
 
 
 
 
 
BridgeTex - volume shipped (million barrels)(2)
—

 
38.7

 
 
 
 
 
 
 
 
 
 
 
 
Marine storage:
 
 
 
 
 
 
 
Marine terminal average utilization (million barrels per month)
22.7

 
23.9

 
 
 
 

(1) Product margin does not include depreciation or amortization expense.
(2) These volumes reflect the total shipments for the BridgeTex pipeline, which is owned 50% by us.


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Transportation and terminals revenue increased $48.4 million resulting from:
•
an increase in refined products revenue of $7.8 million primarily attributable to higher revenue from our independent terminals, higher leased storage revenue and higher transportation revenue. Our independent terminal revenue increased because of a recently acquired terminal as well as increased demand at our other locations, and our leased storage revenue increased because of new lease storage contracts, including leases on recently constructed tanks. Transportation revenue was favorable due to slightly higher volumes as increased demand for gasoline in the markets we serve was partially offset by lower shipments of distillates due to reduced demand from drilling activities and wet agricultural conditions in the areas served by our assets in the current period;
•
an increase in crude oil revenue of $34.8 million primarily due to revenue received in 2015 from BridgeTex for capacity on our Houston area crude oil distribution system and higher crude oil deliveries on our Longhorn pipeline. Shipments on our Longhorn pipeline averaged approximately 250,000 barrels per day in 2015, an increase of approximately 25,000 barrels per day over the same period in 2014. Additionally, terminalling revenue was higher resulting from new leased storage contracts and the one-time benefit from a customer buying out of its remaining storage agreement in 2015; and
•
an increase in marine storage revenue of $5.8 million primarily due to improved storage utilization and higher storage rates at our marine facilities.
Affiliate management fee revenue decreased $3.2 million due to lower construction management fees related to BridgeTex now that the pipeline is operational.
Operating expenses increased by $31.5 million primarily resulting from:
•
an increase in refined products expenses of $22.3 million primarily due to higher asset integrity spending, additional environmental accruals due to product releases in the current period, additional property taxes and less favorable product overages (which reduce operating expense) as a result of the lower commodity prices in 2015; and
•
an increase in crude oil expenses of $9.0 million primarily due to less favorable product overages (which reduce operating expense) and higher pipeline capacity rental fees and power costs associated with moving additional volume in 2015; and
•
a slight increase in marine storage expenses of $0.6 million.
Product margin decreased $74.2 million primarily due to higher unrealized losses on our NYMEX contracts, which were partially offset by higher realized margins from our butane blending and fractionation activities.
Earnings of non-controlled entities increased $31.7 million primarily due to our share of earnings from BridgeTex, which began operations in late 2014.
Depreciation and amortization decreased $2.3 million primarily due to the $9.4 million acceleration of depreciation for pipeline, terminal and related assets during 2014 that we later sold, largely offset by increased depreciation expense in the current year for expansion capital projects and a $1.8 million charge recognized in 2015 to impair an office/warehouse building.
G&A expense decreased $0.8 million primarily due to lower costs associated with deferred board of director fees resulting from a decrease in the price of our limited partner units in 2015 partially offset by higher personnel costs from an increase in employee headcount.  A separation fee paid to a former executive in the current quarter was largely offset by the forfeiture of his unvested equity-based awards.
Interest expense, net of interest income and interest capitalized, increased $10.0 million in 2015 primarily due to lower capitalized interest since we are no longer capitalizing interest expense for the BridgeTex pipeline construction project that is now operational. Our average outstanding debt increased from $2.9 billion in 2014 to $3.2 billion in 2015 primarily due to borrowings for expansion capital expenditures, including $250.0 million of 3.20% senior notes and $250.0 million of 4.20% senior notes issued in March 2015. Our weighted-average interest

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rate decreased from 5.1% in 2014 to 4.8% in 2015 due to the impact of our commercial paper borrowings and March 2015 debt issuances, which are both at lower rates than the debt we retired in mid-2014.
Other income included $6.3 million of favorable non-cash adjustments for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms and linefill assets.
Provision for income taxes was $1.6 million favorable due to a reduction in the franchise tax rate for the state of Texas.


Distributable Cash Flow

We calculate the non-GAAP measures of distributable cash flow ("DCF") and adjusted EBITDA in the table below. Management uses DCF as a basis for recommending to our general partner's board of directors the amount of cash distributions to be paid to our limited partners each period. Management also uses DCF as a basis for determining the payouts for the performance-based awards issued under our equity-based compensation plan. Adjusted EBITDA is an important measure that we and the investment community use to assess the financial results of an entity. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of DCF and adjusted EBITDA for the six months ended June 30, 2014 and 2015 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):
 
 
Six Months Ended June 30,
 
Increase (Decrease)
 
 
2014
 
2015
 
Net income
 
$
388.8

 
$
361.0

 
$
(27.8
)
Interest expense, net, and provision for income taxes
 
63.3

 
71.6

 
8.3

Depreciation and amortization expense(1)
 
85.6

 
83.4

 
(2.2
)
Equity-based incentive compensation expense(2)
 
(2.1
)
 
(7.2
)
 
(5.1
)
Asset retirements
 
3.3

 
2.1

 
(1.2
)
Commodity-related adjustments:
 
 
 
 
 
 
Derivative losses recognized in the period associated with future product transactions(3)
 
14.4

 
5.6

 
(8.8
)
Derivative gains (losses) recognized in previous periods associated with product sales completed in the period(4)
 
(8.1
)
 
91.6

 
99.7

Lower-of-cost-or-market adjustments(5)
 
—

 
(39.2
)
 
(39.2
)
Total commodity-related adjustments
 
6.3

 
58.0

 
51.7

Cash distributions of non-controlled entities in excess of /(less than) earnings
 
1.9

 
(2.3
)
 
(4.2
)
Adjusted EBITDA
 
547.1

 
566.6

 
19.5

Interest expense, net, and provision for income taxes
 
(63.3
)
 
(71.6
)
 
(8.3
)
Maintenance capital(6)
 
(34.8
)
 
(39.0
)
 
(4.2
)
DCF
 
$
449.0

 
$
456.0

 
$
7.0

 
 
 
 
 
 
 
(1)
Depreciation and amortization expense 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 DCF purposes. Total equity-based incentive compensation expense for the six months ended June 30, 2014 and 2015 was $12.7 million and $10.6 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2014 and 2015 of $14.8 million and $17.8 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduce DCF.

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(3)
Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in earnings. In addition, we have designated certain derivatives we use to hedge our crude oil tank bottoms and linefill assets as fair value hedges and the change in the differential between the current spot price and forward price on these hedges is recognized currently in earnings. We exclude the net impact of both of these adjustments from our determination of DCF until the hedged products are physically sold. In the period in which these hedged products are physically sold, the net impact of the associated hedges is included in our determination of DCF.
(4)
When we physically sell products that we have economically hedged (but were not designated as hedges for accounting purposes), we include in our DCF calculations the full amount of the gain or loss realized on the economic hedges in the period that the underlying product sales occur.
(5)
We add the amount of lower-of-cost-or-market (“LCM”) adjustments on inventory and firm purchase commitments we recognize in each applicable period to determine DCF as these are non-cash charges against income.  In subsequent periods when we physically sell or purchase the related products, we deduct the LCM adjustments previously recognized to determine DCF.
(6)
Maintenance capital expenditure projects maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders). For this reason, we deduct maintenance capital expenditures to determine DCF.


Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Operating Activities. Operating cash flows consist of net income adjusted for certain non-cash items and changes in certain assets and liabilities.
Net cash provided by operating activities was $477.4 million and $414.8 million for the six months ended June 30, 2014 and 2015, respectively. The $62.6 million decrease from 2014 to 2015 was due to lower net income related to activities previously described and changes in our working capital and adjustments to non-cash items. Changes in our working capital were primarily due to timing of payments from our customers.
Investing Activities. Investing cash flows consist primarily of capital expenditures, investments in non-controlled entities and acquisitions.
Net cash used by investing activities for the six months ended June 30, 2014 and 2015 was $437.3 million and $363.8 million, respectively. During 2015, we spent $268.8 million for capital expenditures, which included $39.0 million for maintenance capital and $229.8 million for expansion capital. Also during the 2015 period, we acquired a refined products terminal in the Atlanta, Georgia market for $54.7 million and contributed capital of $36.4 million in conjunction with our joint venture capital projects which we account for as investments in non-controlled entities. During 2014, we spent $149.1 million for capital expenditures, which included $34.8 million for maintenance capital and $114.3 million for expansion capital. Also during the 2014 period, we contributed capital of $285.9 million in conjunction with our joint venture capital projects (primarily BridgeTex) which we account for as investments in non-controlled entities.
Financing Activities. Financing cash flows consist primarily of distributions to our unitholders and borrowings and repayments under long-term notes and our commercial paper program.
Net cash used by financing activities for the six months ended June 30, 2014 and 2015 was $64.5 million and $39.0 million, respectively. During 2015, we paid cash distributions of $321.2 million to our unitholders. Additionally, we received net proceeds of $499.6 million from borrowings under long-term notes, which were used in part to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital. In connection with the borrowings under long-term notes, we paid $42.9 million in settlement of associated interest rate swap agreements. Also, in January 2015, the cumulative amounts of the January 2012 equity-based incentive compensation award grants were settled by issuing 354,529 limited partner units and distributing those units to the long-term incentive plan ("LTIP") participants, resulting in payments of associated tax withholdings of $17.8 million. During 2014, we paid cash distributions of $271.9 million to our unitholders. Additionally, we received net proceeds of $257.7 million from borrowings under notes, which were used to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital. Also, in January 2014, the cumulative amounts of the January 2011 equity-based incentive compensation

35
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award grants were settled by issuing 387,216 limited partner units and distributing those units to the LTIP participants, resulting in payments of associated tax withholdings of $14.8 million.
The quarterly distribution amount related to our second-quarter 2015 financial results (to be paid in third quarter 2015) is $0.74 per unit.  If we meet management's targeted distribution growth of 15% for 2015 and the number of outstanding limited partner units remains unchanged at 227.4 million, total cash distributions of approximately $683.4 million will be paid to our unitholders related to 2015 financial results. Management believes we will have sufficient distributable cash flow to fund these distributions.

Capital Requirements

Our businesses require continual investments to maintain, upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending consists primarily of:
•
Maintenance capital expenditures. These expenditures include costs required to maintain equipment reliability and safety and to address environmental or other regulatory requirements rather than to generate incremental distributable cash flow; and
•
Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental distributable cash flow and include costs to acquire additional assets to grow our business and to expand or upgrade our existing facilities, which we refer to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the six months ended June 30, 2015, our maintenance capital spending was $39.0 million. For 2015, we expect to spend approximately $85.0 million on maintenance capital.

During the first six months of 2015, we spent $229.8 million for organic growth capital and $36.4 million for capital projects in conjunction with our joint ventures. Additionally, we spent $54.7 million on a refined products terminal acquired in the Atlanta, Georgia market. Based on the progress of expansion projects already underway, we expect to spend approximately $850 million for expansion capital and joint venture capital contributions during 2015, with an additional $550 million in 2016 to complete our current projects. These spending estimates include our contributions for our 40% interest in Saddlehorn Pipeline Company, LLC ("Saddlehorn").

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Table of Contents



Liquidity

Consolidated debt at December 31, 2014 and June 30, 2015 was as follows (in thousands, except as otherwise noted):
 
 
December 31, 2014
 
June 30,
2015
 
Weighted-Average
Interest Rate for the Six Months Ended June 30, 2015 (1)
Commercial paper(2)
 
$
296,942

 
$
144,982

 
0.5%
$250.0 million of 5.65% Notes due 2016
 
250,758

 
250,546

 
5.7%
$250.0 million of 6.40% Notes due 2018
 
257,280

 
256,248

 
5.4%
$550.0 million of 6.55% Notes due 2019
 
567,868

 
566,006

 
5.7%
$550.0 million of 4.25% Notes due 2021
 
556,304

 
555,837

 
4.0%
$250.0 million of 3.20% Notes due 2025(2)
 
—

 
249,687

 
3.2%
$250.0 million of 6.40% Notes due 2037
 
249,017

 
249,026

 
6.4%
$250.0 million of 4.20% Notes due 2042
 
248,406

 
248,421

 
4.2%
$550.0 million of 5.15% Notes due 2043
 
556,320

 
556,270

 
5.1%
$250.0 million of 4.20% Notes due 2045(2)
 
—

 
249,913

 
4.6%
Total debt
 
$
2,982,895

 
$
3,326,936

 
4.8%
 
 
 
 
 
 
 

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

(2)
These borrowings were outstanding for only a portion of the six month period ending June 30, 2015. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

All of the instruments detailed in the table above are senior indebtedness.

The face value of our debt at December 31, 2014 and June 30, 2015 was $2.9 billion and $3.3 billion, respectively. The difference between the face value and carrying value of our debt outstanding is the unamortized portion of terminated fair value hedges and the unamortized discounts and premiums on debt issuances. Realized gains and losses on fair value hedges and note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of those notes.

2015 Debt Offerings

In March 2015, we issued $250.0 million of our 3.20% notes due 2025 in an underwritten public offering. The notes were issued at 99.871% of par. Net proceeds from this offering were $247.6 million, after underwriting discounts and offering expenses of $2.1 million.

Also in March 2015, we issued $250.0 million of our 4.20% notes due 2045 in an underwritten public offering. The notes were issued at 99.965% of par. Net proceeds from this offering were $247.3 million, after underwriting discounts and offering expenses of $2.6 million.

The net proceeds from these offerings were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in November 2018, is $1.0 billion. Borrowings outstanding under the facility are classified as long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee is assessed at a

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Table of Contents


rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at June 30, 2015. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of June 30, 2015, there were no borrowings outstanding under this facility; however, $5.6 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.

Commercial Paper Program. The maturities of our commercial paper notes vary, but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The commercial paper we can issue is limited by the amounts available under our revolving credit facility up to an aggregate principal amount of $1.0 billion and, therefore, is classified as long-term debt.


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.


Other Items

Pipeline Tariff Increase. The Federal Energy Regulatory Commission ("FERC") regulates the rates charged on interstate common carrier pipeline operations primarily through an indexing methodology, which establishes the maximum amount by which tariffs can be adjusted each year. Approximately 40% of our refined products tariffs are subject to this indexing methodology while the remaining 60% of our refined products tariffs can be adjusted at our discretion based on competitive factors. The current FERC-approved indexing method is the annual change in the producer price index for finished goods ("PPI-FG") plus 2.65%. Based on this indexing methodology, we increased virtually all of our tariffs by 4.6% on July 1, 2015. In 2016, a new index will be established by the FERC. Any change in the current indexing methodology will impact our rates in the future.

Collective Bargaining Agreement with the United Steel Workers ("USW"). During second quarter 2015, we reached agreement with the USW, which represents approximately 230 employees assigned to our refined products segment. The current collective bargaining agreement with the USW will be effective through January 31, 2019.

Commodity 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 forward physical commodity contracts and NYMEX contracts to help manage this commodity price risk. We use forward physical contracts to purchase butane and sell refined products. We account for these forward physical contracts as normal purchase and sale contracts, using traditional accrual accounting.  We use NYMEX contracts to hedge against changes in the price of refined products and crude oil that 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 NYMEX contracts to economically hedge against changes in the price of butane we expect to purchase in the future as part of our butane blending activities. As of and for the six months ended June 30, 2015, our open derivative contracts and the impact of the derivatives we settled during the period were as follows:

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Open Derivative Contracts Designated as Hedges

•
NYMEX contracts covering 0.7 million barrels of crude oil to hedge against future price changes of crude oil tank bottoms and linefill. These contracts, which we are accounting for as fair value hedges, mature between December 2015 and November 2016. Through June 30, 2015, the cumulative amount of gains from these agreements was $8.7 million. The cumulative gains from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. We exclude the differential between the current spot price and forward price from our assessment of hedge effectiveness for these fair value hedges. The net change in the amounts excluded from our assessment of hedge effectiveness during the six months ended June 30, 2015 was a gain of $6.3 million, which we recognized as other income on our consolidated statement of income.

Open Derivative Contracts Not Designated as Hedges
•
NYMEX contracts covering 4.7 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between July 2015 and December 2016 and are being accounted for as economic hedges. Through June 30, 2015, the cumulative amount of net unrealized losses associated with these agreements was $5.8 million. We recorded these losses as an adjustment to product sales revenue, of which $4.5 million of net gains was recognized in 2014 and $10.3 million of net losses was recognized in 2015.

•
NYMEX contracts covering 0.9 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature between July and December 2015, are being accounted for as economic hedges. Through June 30, 2015, the cumulative amount of net unrealized gains associated with these agreements was $4.9 million. We recorded these gains as an adjustment to operating expense, of which $5.3 million of net gains was recognized in 2014 and $0.4 million of net losses was recognized in 2015.

•
NYMEX contracts covering 1.3 million barrels of butane purchases that mature between September 2015 and December 2016, which are being accounted for as economic hedges. Through June 30, 2015, the cumulative amount of net unrealized losses associated with these agreements was $1.8 million. We recorded these losses as an adjustment to cost of product sales, all of which was recognized in 2015.

Settled Derivative Contracts

•
We settled NYMEX contracts covering 5.7 million barrels of refined products related to economic hedges of products from our butane blending and fractionation activities that we sold during 2015.  We recognized a loss of $9.2 million in 2015 related to these contracts, which we recorded as an adjustment to product sales revenue.

•
We settled NYMEX contracts covering 3.0 million barrels of refined products and crude oil related to economic hedges of product inventories from product overages on our pipeline system that we sold during 2015.  We recognized a loss of $7.2 million in 2015 on the settlement of these contracts, which we recorded as an adjustment to operating expense.

•
We settled NYMEX contracts covering 0.5 million barrels related to economic hedges of butane purchases we made during 2015 associated with our butane blending activities.  We recognized a loss of $0.2 million in 2015 on the settlement of these contracts, which we recorded as an adjustment to cost of product sales.


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Table of Contents


Impact of Commodity Derivatives on Results of Operations

The following tables provide a summary of the positive and (negative) impacts of the mark-to-market gains and losses associated with NYMEX contracts on our results of operations for the respective periods presented (in millions):

 
Six Months Ended June 30, 2014
 
Product Sales Revenue
 
Cost of Product Sales
 
Operating Expense
 
Other Expense
 
Net Impact on Net Income
NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period
$
(1.6
)
 
$
0.2

 
$
(4.3
)
 
$
—

 
$
(5.7
)
NYMEX gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods
(12.2
)
 
0.6

 
0.4

 
—

 
(11.2
)
Net impact of NYMEX contracts
$
(13.8
)
 
$
0.8

 
$
(3.9
)
 
$
—

 
$
(16.9
)

 
Six Months Ended June 30, 2015
 
Product Sales Revenue
 
Cost of Product Sales
 
Operating Expense
 
Other Income
 
Net Impact on Net Income
NYMEX losses recognized during the period that were associated with economic hedges of physical product sales or purchases during the period
$
(9.2
)
 
$
(0.2
)
 
$
(7.2
)
 
$
—

 
$
(16.6
)
NYMEX gains (losses) recorded during the period that were associated with products that will be sold or purchased in future periods
(10.3
)
 
(1.8
)
 
(0.4
)
 
6.3

 
(6.2
)
Net impact of NYMEX contracts
$
(19.5
)
 
$
(2.0
)
 
$
(7.6
)
 
$
6.3

 
$
(22.8
)


Related Party Transactions. Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of the general partner of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase butane from subsidiaries of Targa. For the three months ended June 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $1.6 million and $4.0 million, respectively. For the six months ended June 30, 2014 and 2015, we made purchases of butane from subsidiaries of Targa of $13.8 million and $12.8 million, respectively. These purchases were based on the then-current index prices. We had recognized payables to Targa of $0.9 million and $0.2 million at December 31, 2014 and June 30, 2015, respectively.

Stacy P. Methvin was elected as an independent member of our general partner's board of directors on April 23, 2015 and is also a director of one of our customers.  We received tariff revenue of $2.6 million from this customer from April 23, 2015 through June 30, 2015, and have recorded a $1.3 million receivable from this customer at June 30, 2015.  We receive tariff revenue from this customer in the normal course of business, with rates determined in accordance with published tariffs. 

The management fees we have recognized or will recognize from BridgeTex, Osage Pipe Line Company LLC ("Osage"), Powder Springs Logistics, LLC ("Powder Springs"), Saddlehorn and Texas Frontera, LLC ("Texas Frontera") are reported as affiliate management fee revenue on our consolidated statements of income. 

At December 31, 2014 and June 30, 2015, we recognized liabilities of $2.2 million and $1.1 million, respectively, to BridgeTex primarily for pre-paid construction management fees. For the three and six months ended

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June 30, 2015, we recognized pipeline capacity lease revenue from BridgeTex of $8.5 million and $16.9 million, respectively, which we included in transportation and terminals revenue on our consolidated statements of income. We recognized a $2.6 million receivable from BridgeTex at December 31, 2014 (no receivable was recognized at June 30, 2015).

We recognized throughput revenue from Double Eagle Pipeline LLC ("Double Eagle") for the three months ended June 30, 2014 and 2015 of $0.8 million and $0.9 million, respectively, and for the six months ended June 30, 2014 and 2015 of $1.3 million and $1.8 million, respectively, which we included in transportation and terminals revenue.  At December 31, 2014 and June 30, 2015, respectively, we recognized a $0.3 million trade accounts receivable from Double Eagle.

The financial results from Texas Frontera are included in our marine storage segment, the financial results from BridgeTex, Double Eagle, Osage, Saddlehorn and Seabrook are or will be included in our crude oil segment and the financial results from Powder Springs are included in our refined products segment as earnings/losses of non-controlled entities.


New Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board ("FASB") extended the effective date of Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers, from January 1, 2017 to January 1, 2018.

In April 2015, the FASB issued ASU No. 2015-03, Interest: Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Under this update, the costs for issuing debt will be included on the balance sheet as a direct deduction from the debt's value. The amendments will not affect the recognition and measurement of the costs for issuing debt. The amendments will have to be applied for reporting periods that start after December 15, 2015, with early adoption permitted. We plan to adopt this ASU in fourth quarter 2015. Our adoption will not have a material impact on our results of operations, financial position or cash flows.

In April 2015, the FASB issued ASU 2015-04, Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets. For an entity that has a significant event in an interim period that calls for a re-measurement of defined benefit plan assets and obligations (i.e., a partial settlement), the amendments in this ASU provide a practical expedient that permits the entity to re-measure defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. This ASU is effective for reporting periods beginning after December 15, 2015. Our adoption of this standard is not expected to have a material impact on our results of operations, financial position or cash flows.

In April 2015, the FASB issued ASU 2015-05, Intangibles-Goodwill and Other-Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement. Where an entity has entered into a cloud computing arrangement, this update requires the entity to capitalize the software license element of arrangements that include a software license. Where the cloud computing arrangement does not include a software license, the arrangement is to be accounted for as a service contract. This ASU is effective for reporting periods beginning after December 15, 2015. Our adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. This ASU eliminates all references to and guidance concerning the classification and presentation of extraordinary items and emphasizes that the nature and effects of an event or transaction deemed unusual in nature or that is expected to occur infrequently should be disclosed on the face of the income statement as a separate component of income from continuing operations, or, alternatively, in notes to the financial statements. The changes are effective for fiscal years, including quarterly reports, beginning after December 15, 2015, with early application permitted (provided it is applied from the beginning of the fiscal year of initial adoption). The new guidance may be applied

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either prospectively or retrospectively. Our adoption of this ASU will not have a material impact on our results of operations, financial position or cash flows.


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 use derivative agreements to help manage our exposure to commodity price and interest rate risks. 

Commodity Price Risk

Our commodity price risk primarily arises from our butane blending and fractionation activities, and from managing product imbalances associated with our refined products and crude oil pipelines. We use derivatives such as forward physical contracts, NYMEX petroleum products contracts and butane futures contracts to help us manage commodity price risk.

Forward physical contracts that qualify for and are elected as normal purchases and sales are accounted for using traditional accrual accounting. As of June 30, 2015, we had commitments under forward purchase and sale contracts used in our butane blending and fractionation activities as follows (in millions):
 
Notional Value
 
Barrels
Forward purchase contracts
$
118.3

 
3.5
Forward sale contracts
$
11.4

 
0.1
 
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 as economic hedges. We also use NYMEX contracts to hedge against changes in the price of butane that we expect to purchase in future periods. At June 30, 2015, we had open NYMEX contracts representing 6.3 million barrels of petroleum products we expect to sell in the future. Additionally, we had open NYMEX contracts for 1.3 million barrels of butane we expect to purchase in the future. At June 30, 2015, the fair value of our open NYMEX contracts was an asset of $13.6 million.

At June 30, 2015, open NYMEX contracts representing 5.6 million barrels of petroleum products did not qualify for hedge accounting treatment. A $10.00 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 $56.0 million decrease in our operating profit and a $10.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $56.0 million increase in our operating profit.

At June 30, 2015, we had open NYMEX contracts representing 1.3 million barrels of butane we expect to purchase in the future. Relative to these agreements, a $10.00 per barrel increase in the price of butane would result in a $13.0 million increase in our operating profit and a $10.00 per barrel decrease in the price of butane would result in a $13.0 million decrease in our operating profit.

The increases or decreases in operating profit we recognize from our open NYMEX forward sales and price swap contracts would be substantially offset by higher or lower product sales revenue or cost of product sales when the physical sale or purchase of those products occur. 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 and the resulting hedges may not eliminate all price risks.


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Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk.

In first quarter 2015, we entered into a $50.0 million forward-starting interest rate swap agreement to hedge against the risk of variability of future interest payments on a portion of debt we anticipate issuing in 2016. The fair value of this contract at June 30, 2015 was an asset of $2.9 million. We account for this agreement as a cash flow hedge. A 0.125% decrease in the interest rates would result in a decrease in the fair value of this asset of approximately $0.5 million. A 0.125% increase in the interest rates would result in an increase in the fair value of this asset of approximately $0.5 million.

At June 30, 2015, we had $145.0 million of commercial paper notes outstanding which represents variable rate debt. We can issue up to $1.0 billion of commercial paper, limited by the amounts available under our revolving credit facility. Considering the amount of commercial paper borrowings outstanding at June 30, 2015, our annual interest expense would change by $0.2 million if rates charged by our commercial paper lenders changed by 0.125%.


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 Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



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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," "projected," "scheduled," "should," "will" 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 products, crude oil, liquefied petroleum gases and ammonia in the U.S.;
•
price fluctuations for refined products, crude oil, liquefied petroleum gases and ammonia and expectations about future prices for these products;
•
decreases in the production of crude oil in the basins served by our pipelines;
•
changes in general economic conditions, interest rates and price levels;
•
changes in the financial condition of our customers, vendors, derivatives counterparties, joint venture co-owners 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, refinance our existing obligations when due and maintain adequate liquidity;
•
development of alternative energy sources, including but not limited to natural gas, solar power, wind power and geothermal energy, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, as well as regulatory developments or other trends that could affect demand for our services;
•
changes in the throughput or interruption in service on refined products or crude oil pipelines owned and operated by third parties and connected to our assets;
•
changes in demand for storage in our refined products, crude oil or marine terminals;
•
changes in supply patterns for our facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries, changes in U.S. trade policies, technological developments or other factors;
•
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, oil wells, petrochemical plants, ammonia production facilities or other customers or 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;
•
not being adequately insured or having losses that exceed our insurance coverage;
•
our ability to obtain insurance and to manage the increased cost of available insurance;
•
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;

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•
our ability to identify expansion projects or to complete identified expansion projects on time and at projected costs;
•
our ability to make and integrate accretive acquisitions and joint ventures and successfully execute our business strategy;
•
uncertainty of estimates, including accruals and costs of environmental remediation;
•
our ability to cooperate with and rely on our joint venture co-owners;
•
actions by rating agencies concerning our credit ratings;
•
our ability to timely obtain and maintain all necessary approvals, consents and permits required to operate our existing assets and any new or modified assets;
•
our ability to promptly obtain all necessary services, materials, labor, supplies and rights-of-way required for construction of our growth projects, and to complete construction without significant delays, disputes or cost overruns;
•
risks inherent in the use and security of information systems in our business and implementation of new software and hardware;
•
changes in laws and regulations that govern product quality specifications or renewable fuel obligations 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 or our customers are or become subject, including tax withholding requirements, safety, security, employment, hydraulic fracturing, derivatives transactions 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;
•
petroleum product supply disruptions;
•
global and domestic repercussions from terrorist activities, including cyber attacks, and the government's response thereto; and
•
other factors and uncertainties inherent in the transportation, storage and distribution of petroleum products and ammonia.
 
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

2011 EPA Clean Water Act Information Request for Pipeline Release in Texas. In July 2011, we received an information request from the Environmental Protection Agency ("EPA") pursuant to Section 308 of the Clean Water Act regarding a pipeline release in February 2011 in Texas.  We have accrued $0.3 million for potential monetary sanctions related to this matter.  While the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

2012 EPA Clean Water Act Information Request for Pipeline Release in Nebraska. 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 in Nebraska. We have accrued $1.4 million for potential monetary sanctions related to this matter. While the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

U.S. Oil Recovery, EPA ID No.: TXN000607093 Superfund Site. We have liability at the U.S. Oil Recovery Superfund Site in Pasadena, Texas as a potential responsible party ("PRP") under Section 107(a) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended ("CERCLA"). As a result of the EPA’s Administrative Settlement Agreement and Order on Consent for Removal Action, filed August 25, 2011, EPA Region 6, CERCLA Docket No. 06-10-11, we voluntarily entered into the PRP group responsible for the site investigation, stabilization and subsequent site cleanup. We have paid $15,000 associated with the assessment phase. Until this assessment phase has been completed, we cannot reasonably estimate our proportionate share of the remediation costs associated with this site.

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 future results of operations, financial position 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, 2014, 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 could materially adversely affect our business, financial condition and/or operating results.

We have updated our risk factors as follows since issuing our Annual Report on Form 10-K:

We are exposed to counterparty risk. Nonpayment, commitment termination or nonperformance by our customers, vendors, lenders or derivative counterparties could materially reduce our revenue, impair our liquidity, increase our expenses or otherwise negatively impact our results of operations, financial position or cash flows and our ability to pay cash distributions.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, we frequently undertake capital expenditures based on commitments from customers upon which we expect to realize the expected return on those expenditures, including take-or-pay commitments from our

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customers, and nonperformance by our customers of those commitments or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us.

We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis, at the prices we expect and as required by contract could result in significant disruptions, costs to our operation, or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results and cash flows.

We also rely to a significant degree on the banks that lend to us under our commercial paper program and revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk.

Any take-or-pay commitment terminations or substantial increase in the nonpayment or nonperformance by our customers, vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position and cash flows and our ability to pay cash distributions.



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
—
Separation and Release of Claims Agreement dated as of May 18, 2015 between Magellan Midstream Holdings GP, LLC and Michael P. Osborne.
 
 
 
Exhibit 12
—
Ratio of earnings to fixed charges.
 
 
 
Exhibit 31.1
—
Certification of Michael N. Mears, principal executive officer.
 
 
 
Exhibit 31.2
—
Certification of Aaron L. Milford, principal financial officer.
 
 
Exhibit 32.1
—
Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
 
 
 
Exhibit 32.2
—
Section 1350 Certification of Aaron L. Milford, Chief Financial Officer.
 
 
 
Exhibit 101.INS
—
XBRL Instance Document.
 
 
 
Exhibit 101.SCH
—
XBRL Taxonomy Extension Schema.
 
 
 
Exhibit 101.CAL
—
XBRL Taxonomy Extension Calculation Linkbase.
 
 
 
Exhibit 101.DEF
—
XBRL Taxonomy Extension Definition Linkbase.
 
 
 
Exhibit 101.LAB
—
XBRL Taxonomy Extension Label Linkbase.
 
 
 
Exhibit 101.PRE
—
XBRL Taxonomy Extension Presentation Linkbase.
 
 







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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on August 6, 2015.
 
MAGELLAN MIDSTREAM PARTNERS, L.P.
 
 
 
By:
 
Magellan GP, LLC,
 
 
its general partner
 
 
 
/s/ Aaron L. Milford
Aaron L. Milford
Chief Financial Officer
(Principal Accounting and Financial Officer)



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INDEX TO EXHIBITS
 
 
 
Exhibit Number
 
Description
 
 
 
Exhibit 10.1
—
Separation and Release of Claims Agreement dated as of May 18, 2015 between Magellan Midstream Holdings GP, LLC and Michael P. Osborne.
 
 
 
Exhibit 12
—
Ratio of earnings to fixed charges.
 
 
 
Exhibit 31.1
—
Certification of Michael N. Mears, principal executive officer.
 
 
 
Exhibit 31.2
—
Certification of Aaron L. Milford, principal financial officer.
 
 
Exhibit 32.1
—
Section 1350 Certification of Michael N. Mears, Chief Executive Officer.
 
 
 
Exhibit 32.2
—
Section 1350 Certification of Aaron L. Milford, Chief Financial Officer.
 
 
 
Exhibit 101.INS
—
XBRL Instance Document.
 
 
 
Exhibit 101.SCH
—
XBRL Taxonomy Extension Schema.
 
 
 
Exhibit 101.CAL
—
XBRL Taxonomy Extension Calculation Linkbase.
 
 
 
Exhibit 101.DEF
—
XBRL Taxonomy Extension Definition Linkbase.
 
 
 
Exhibit 101.LAB
—
XBRL Taxonomy Extension Label Linkbase.
 
 
 
Exhibit 101.PRE
—
XBRL Taxonomy Extension Presentation Linkbase.
 
 
 

    







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