Document


 
 
 
 
 

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, 2016
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 1, 2016, there were 227,783,916 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,
 
2015
 
2016
 
2015
 
2016
Transportation and terminals revenue
$
384,901

 
$
392,240

 
$
738,713

 
$
762,315

Product sales revenue
109,969

 
123,689

 
283,096

 
270,251

Affiliate management fee revenue
3,558

 
2,968

 
6,921

 
6,147

Total revenue
498,428

 
518,897

 
1,028,730

 
1,038,713

Costs and expenses:
 
 
 
 
 
 
 
Operating
142,318

 
134,162

 
249,025

 
257,395

Cost of product sales
94,507

 
95,703

 
230,686

 
209,288

Depreciation and amortization
40,440

 
43,302

 
82,137

 
87,056

General and administrative
37,942

 
34,542

 
73,440

 
75,416

Total costs and expenses
315,207

 
307,709

 
635,288

 
629,155

Earnings of non-controlled entities
24,542

 
15,339

 
34,132

 
32,967

Operating profit
207,763

 
226,527

 
427,574

 
442,525

Interest expense
40,396

 
48,686

 
77,590

 
92,410

Interest income
(334
)
 
(404
)
 
(683
)
 
(765
)
Interest capitalized
(2,946
)
 
(7,130
)
 
(5,053
)
 
(13,266
)
Gain on exchange of interest in non-controlled entity
—

 
(1,244
)
 
—

 
(28,144
)
Other income
(6,539
)
 
(1,925
)
 
(6,260
)
 
(4,195
)
Income before provision for income taxes
177,186

 
188,544

 
361,980

 
396,485

Provision for income taxes
(205
)
 
685

 
953

 
1,556

Net income
$
177,391

 
$
187,859

 
$
361,027

 
$
394,929

Basic net income per limited partner unit
$
0.78

 
$
0.82

 
$
1.59

 
$
1.73

Diluted net income per limited partner unit
$
0.78

 
$
0.82

 
$
1.59

 
$
1.73

Weighted average number of limited partner units outstanding used for basic net income per unit calculation(1)
227,631

 
227,952

 
227,578

 
227,889

Weighted average number of limited partner units outstanding used for diluted net income per unit calculation(1)
227,631

 
227,983

 
227,578

 
227,921


(1) See Note 10–Long-Term Incentive Plan for additional information regarding our weighted average unit calculations.




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,
 
2015
 
2016
 
2015
 
2016
Net income
$
177,391

 
$
187,859

 
$
361,027

 
$
394,929

Other comprehensive income:
 
 

 
 
 

Derivative activity:
 
 
 
 
 
 
 
Net gain (loss) on cash flow hedges(1)
1,936

 
(8,631
)
 
(13,529
)
 
(21,109
)
Reclassification of net loss on cash flow hedges to income(1)  
388

 
388

 
588

 
776

Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
 
 
 
 
 
 
 
Amortization of prior service credit(2)
(928
)
 
(974
)
 
(1,856
)
 
(1,947
)
Amortization of actuarial loss(2)
2,023

 
1,292

 
3,595

 
2,693

Total other comprehensive income (loss)
3,419

 
(7,925
)
 
(11,202
)
 
(19,587
)
Comprehensive income
$
180,810

 
$
179,934

 
$
349,825

 
$
375,342

(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
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MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
 
December 31,
2015
 
June 30,
2016
ASSETS
 
 
(Unaudited)
Current assets:
 
 
 
Cash and cash equivalents
$
28,731

 
$
34,263

Trade accounts receivable
83,893

 
93,329

Other accounts receivable
12,701

 
19,368

Inventory
130,868

 
156,430

Energy commodity derivatives contracts, net
39,243

 
7,359

Energy commodity derivatives deposits
—

 
28,528

Other current assets
43,418

 
46,305

Total current assets
338,854

 
385,582

Property, plant and equipment
6,166,766

 
6,470,356

Less: Accumulated depreciation
1,347,537

 
1,428,426

Net property, plant and equipment
4,819,229

 
5,041,930

Investments in non-controlled entities
765,628

 
850,401

Long-term receivables
20,374

 
18,134

Goodwill
53,260

 
53,260

Other intangibles (less accumulated amortization of $13,709 and $5,676 at December 31, 2015 and June 30, 2016, respectively)
1,856

 
52,337

Tank bottoms
27,533

 
35,492

Other noncurrent assets
14,833

 
11,068

Total assets
$
6,041,567

 
$
6,448,204

 
 
 
 
LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
104,094

 
$
118,484

Accrued payroll and benefits
51,764

 
36,827

Accrued interest payable
51,296

 
62,294

Accrued taxes other than income
51,587

 
45,124

Environmental liabilities
15,679

 
15,572

Deferred revenue
81,627

 
98,562

Accrued product purchases
31,339

 
22,481

Energy commodity derivatives deposits
24,252

 
—

Current portion of long-term debt, net
250,335

 
250,083

Other current liabilities
51,099

 
64,235

Total current liabilities
713,072

 
713,662

Long-term debt, net
3,189,287

 
3,574,898

Long-term pension and benefits
77,551

 
81,863

Other noncurrent liabilities
24,162

 
26,412

Environmental liabilities
15,759

 
13,171

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partner unitholders (227,427 units and 227,784 units outstanding at December 31, 2015 and June 30, 2016, respectively)
2,118,086

 
2,154,135

Accumulated other comprehensive loss
(96,350
)
 
(115,937
)
Total partners’ capital
2,021,736

 
2,038,198

Total liabilities and partners’ capital
$
6,041,567

 
$
6,448,204


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,
 
2015
 
2016
Operating Activities:
 
 
 
Net income
$
361,027

 
$
394,929

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
82,137

 
87,056

Loss on sale and retirement of assets
2,084

 
3,263

Earnings of non-controlled entities
(34,132
)
 
(32,967
)
Distributions of earnings from investments in non-controlled entities
31,243

 
31,080

Equity-based incentive compensation expense
10,539

 
10,059

Amortization of prior service credit and actuarial loss
1,739

 
746

Gain on exchange of interest in non-controlled entity
—

 
(28,144
)
Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable and other accounts receivable
3,096

 
(10,703
)
Inventory
(2,158
)
 
(25,562
)
Energy commodity derivatives contracts, net of derivatives deposits
(1,411
)
 
(17,121
)
Accounts payable
8,406

 
9,125

Accrued payroll and benefits
(14,722
)
 
(14,937
)
Accrued interest payable
6,064

 
10,998

Accrued taxes other than income
(1,023
)
 
(6,463
)
Accrued product purchases
(22,726
)
 
(8,858
)
Deferred revenue
36

 
16,935

Current and noncurrent environmental liabilities
116

 
(2,695
)
Other current and noncurrent assets and liabilities
(15,496
)
 
(9,673
)
Net cash provided by operating activities
414,819

 
407,068

Investing Activities:
 
 
 
Additions to property, plant and equipment, net(1)
(275,848
)
 
(310,133
)
Proceeds from sale and disposition of assets
3,153

 
4,756

Acquisition of business
(54,678
)
 
—

Investments in non-controlled entities
(36,443
)
 
(109,933
)
Distributions in excess of earnings of non-controlled entities
—

 
1,942

Net cash used by investing activities
(363,816
)
 
(413,368
)
Financing Activities:
 
 
 
Distributions paid
(321,239
)
 
(361,605
)
Net commercial paper repayments
(151,960
)
 
(255,966
)
Borrowings under long-term notes
499,589

 
649,187

Debt placement costs
(4,734
)
 
(5,408
)
Net payment on financial derivatives
(42,908
)
 
—

Settlement of tax withholdings on long-term incentive compensation
(17,784
)
 
(14,376
)
Net cash provided (used) by financing activities
(39,036
)
 
11,832

Change in cash and cash equivalents
11,967

 
5,532

Cash and cash equivalents at beginning of period
17,063

 
28,731

Cash and cash equivalents at end of period
$
29,030

 
$
34,263

 
 
 
 
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
$
8,045

 
$
7,092

 
 
 
 
(1)   Additions to property, plant and equipment
$
(268,849
)
 
$
(321,085
)
Changes in accounts payable and other current liabilities related to capital expenditures
(6,999
)
 
10,952

Additions to property, plant and equipment, net
$
(275,848
)
 
$
(310,133
)

See notes to consolidated financial statements.

5
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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, 2016, our asset portfolio, including the assets of our joint ventures, consisted of:

•
our refined products segment, comprised of our 9,700-mile refined products pipeline system with 54 terminals as well as 26 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 22 million barrels, of which approximately 15 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.

Terminology common in our industry includes the following terms, which describe products that we transport, store and distribute through our pipelines and terminals:

•
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, 2015, 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, 2016, the results of operations for the three and six months ended June 30, 2015 and 2016 and cash flows for the six months ended June 30, 2015 and 2016. The results of operations for the six months ended June 30, 2016 are not necessarily indicative of the results to be expected for the full year ending December 31, 2016 as profits from our butane 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 impacts 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 U.S. generally accepted accounting principles (“GAAP”). 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, 2015.

Use of Estimates

The preparation of our consolidated financial statements in conformity with 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.

New Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which is part of the FASB’s initiative to simplify accounting standards. The guidance requires an entity to make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur, and allows equity classification for awards where employees elect to withhold the maximum statutory tax rates in the applicable jurisdictions. The new standard also requires cash paid by employers when directly withholding shares for tax withholding purposes to be classified as a financing activity in the statement of cash flows.

We elected to early adopt ASU 2016-09 during the first quarter of 2016, and this adoption did not have a material impact on our consolidated financial statements. In conjunction with our adoption of this new accounting standard, we have elected to account for equity-based compensation forfeitures as they occur. Additionally, and consistent with our prior accounting policy, we continue to show cash paid when directly withholding shares for tax withholding purposes as a financing activity in our statements of cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This standard requires companies that lease valuable assets like aircraft, real estate, and heavy equipment to recognize on their balance sheets the assets and liabilities generated by contracts longer than a year. The new accounting model for lessors remains largely the same, although some changes have been made to align it with the new lessee model and the new revenue recognition guidance. This update also requires companies to disclose in the footnotes to their financial statements information about the amount, timing and uncertainty for the payments they make for the lease arrangements. Public companies

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



will have to begin applying the standard for fiscal years and quarters that start after December 15, 2018, although early adoption is permitted. We are currently in the process of evaluating the impact this new standard will have on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the industry-specific guidance in U.S. GAAP and produces a single, principles-based method for companies to report revenue in their financial statements. This standard requires companies to make more estimates and use more judgment than under current guidance. In addition, all companies must compile more extensive footnote disclosures about how the revenue numbers were derived. This ASU requires full retrospective, modified retrospective or use of the cumulative effect method during the period of adoption. In July 2015, the FASB extended the effective date of this standard from January 1, 2017 to January 1, 2018. We are currently in the process of evaluating the impact this new standard will have on our financial statements.


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 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 revenue. 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 operations, are reported as product sales revenue on our consolidated statements of income.
For the three and six months ended June 30, 2015 and 2016, product sales revenue included the following (in thousands): 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2016
 
2015
 
2016
Physical sale of petroleum products
$
133,319

 
$
135,459

 
$
302,566

 
$
266,039

Change in value of NYMEX contracts
(23,350
)
 
(11,770
)
 
(19,470
)
 
4,212

Total product sales revenue
$
109,969

 
$
123,689

 
$
283,096

 
$
270,251



3.
Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately as 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”) expense that management does not consider when evaluating the core profitability of our separate operating segments.

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




 
Three Months Ended June 30, 2015
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
238,317

 
$
102,035

 
$
44,549

 
$
—

 
$
384,901

Product sales revenue(1)
109,323

 
—

 
646

 
—

 
109,969

Affiliate management fee revenue
—

 
3,211

 
347

 
—

 
3,558

Total revenue
347,640

 
105,246

 
45,542

 
—

 
498,428

Operating expenses
105,081

 
22,293

 
15,881

 
(937
)
 
142,318

Cost of product sales(1)
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

 
 
Three Months Ended June 30, 2016
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
247,842

 
$
101,340

 
$
43,058

 
$
—

 
$
392,240

Product sales revenue(1)
122,311

 
(28
)
 
1,406

 
—

 
123,689

Affiliate management fee revenue
124

 
2,486

 
358

 
—

 
2,968

Total revenue
370,277

 
103,798

 
44,822

 
—

 
518,897

Operating expenses
98,500

 
20,550

 
16,275

 
(1,163
)
 
134,162

Cost of product sales(1)
94,392

 
1,016

 
295

 
—

 
95,703

Losses (earnings) of non-controlled entities
38

 
(14,711
)
 
(666
)
 
—

 
(15,339
)
Operating margin
177,347

 
96,943

 
28,918

 
1,163

 
304,371

Depreciation and amortization expense
24,971

 
9,062

 
8,106

 
1,163

 
43,302

G&A expenses
20,498

 
9,146

 
4,898

 
—

 
34,542

Operating profit
$
131,878

 
$
78,735

 
$
15,914

 
$
—

 
$
226,527


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



 
Six Months Ended June 30, 2015
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
459,000

 
$
192,901

 
$
86,812

 
$
—

 
$
738,713

Product sales revenue(1)
281,962

 
—

 
1,134

 
—

 
283,096

Affiliate management fee revenue
—

 
6,238

 
683

 
—

 
6,921

Total revenue
740,962

 
199,139

 
88,629

 
—

 
1,028,730

Operating expenses
179,293

 
40,460

 
31,216

 
(1,944
)
 
249,025

Cost of product sales(1)
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

 
 
 
 
 
 
 
 
 
 

 
 
Six Months Ended June 30, 2016
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
472,592

 
$
203,068

 
$
86,655

 
$
—

 
$
762,315

Product sales revenue(1)
266,227

 
1,715

 
2,309

 
—

 
270,251

Affiliate management fee revenue
204

 
5,270

 
673

 
—

 
6,147

Total revenue
739,023

 
210,053

 
89,637

 
—

 
1,038,713

Operating expenses
184,485

 
41,742

 
33,523

 
(2,355
)
 
257,395

Cost of product sales(1)
206,248

 
2,361

 
679

 
—

 
209,288

Losses (earnings) of non-controlled entities
80

 
(31,690
)
 
(1,357
)
 
—

 
(32,967
)
Operating margin
348,210

 
197,640

 
56,792

 
2,355

 
604,997

Depreciation and amortization expense
50,091

 
18,931

 
15,679

 
2,355

 
87,056

G&A expenses
45,859

 
18,926

 
10,631

 
—

 
75,416

Operating profit
$
252,260

 
$
159,783

 
$
30,482

 
$
—

 
$
442,525

 
 
 
 
 
 
 
 
 
 

(1) Includes gains (losses) on related NYMEX contracts. See Note 8–Derivative Financial Instruments.



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



4.
Investments in Non-Controlled Entities

Our investments in non-controlled entities at June 30, 2016 were comprised of:
Entity
 
Ownership Interest
BridgeTex Pipeline Company, LLC (“BridgeTex”)
 
50%
Double Eagle Pipeline LLC (“Double Eagle”)
 
50%
HoustonLink Pipeline Company, LLC (“HoustonLink”)
 
50%
Powder Springs Logistics, LLC (“Powder Springs”)
 
50%
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
 
40%
Seabrook Logistics, LLC (“Seabrook”)
 
50%
Texas Frontera, LLC (“Texas Frontera”)
 
50%

In February 2016, we transferred our 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) to an affiliate of HollyFrontier Corporation. In conjunction with this transaction, we entered into several commercial agreements with affiliates of HollyFrontier Corporation. We recorded these commercial agreements as $43.7 million of intangible assets and $8.3 million of other receivables in our consolidated balance sheets. The intangible assets will be amortized over the 20-year life of the contracts received. The total gain recorded was $28.1 million, which includes $26.9 million recorded in the first quarter of 2016 and an additional $1.2 million recorded in the second quarter of 2016 for proceeds received for a working capital settlement related to the transaction.

The management fees we have recognized from BridgeTex, Osage, Powder Springs, Saddlehorn and Texas Frontera are reported as affiliate management fee revenue on our consolidated statements of income.  In addition, we receive reimbursement from certain of our joint ventures for costs incurred during construction, which we included as reductions to costs and expenses on our consolidated statements of income. During the second quarter of 2016, we received construction cost reimbursements of $0.8 million from Saddlehorn, $0.1 million from Powder Springs, $0.1 million from HoustonLink and $0.1 million from Seabrook. During the six months ended June 2016, we received construction cost reimbursements of $1.2 million from Saddlehorn, $0.1 million from Powder Springs, $0.1 million from HoustonLink and $0.1 million from Seabrook.

We recognized pipeline capacity lease revenue from BridgeTex of $8.5 million and $8.8 million for the three months ended June 30, 2015 and 2016, respectively, and $16.9 million and $17.7 million for the six months ended June 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.

We recognized throughput revenue from Double Eagle of $0.9 million and $0.9 million for the three months ended June 30, 2015 and 2016, respectively, and $1.8 million and $1.6 million for the six months ended June 30, 2015 and 2016, respectively, which we included in transportation and terminals revenue on our consolidated statements of income.  At December 31, 2015 and June 30, 2016, respectively, we recognized a $0.2 million and $0.4 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, HoustonLink, Osage, Saddlehorn and Seabrook are included in our crude oil segment and the financial results from Powder Springs are included in our refined products segment, each 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, 2015
 
$
495,267

 
$
270,361

 
$
765,628

Additional investment
 
7,003

 
102,930

 
109,933

Exchange of investment in non-controlled entity
 
—

 
(25,105
)
 
(25,105
)
Earnings of non-controlled entities:
 
 
 

 
 
Proportionate share of earnings
 
29,234

 
4,890

 
34,124

Amortization of excess investment and capitalized interest
 
(1,019
)
 
(138
)
 
(1,157
)
Earnings of non-controlled entities
 
28,215

 
4,752

 
32,967

Less:
 
 
 
 
 
 
Distributions of earnings from investments in non-controlled entities
 
28,215

 
2,865

 
31,080

Distributions in excess of earnings of non-controlled entities
 
899

 
1,043

 
1,942

Investments at June 30, 2016
 
$
501,371

 
$
349,030

 
$
850,401

 
 
 
 
 
 
 

Summarized financial information of our non-controlled entities for the three and six months ended June 30, 2015 and 2016 follows (in thousands):
 
 
Three Months Ended June 30, 2015
 
Three Months Ended June 30, 2016
 
 
BridgeTex
 
All Others
 
Consolidated
 
BridgeTex
 
All Others
 
Consolidated
Revenue
 
$
61,629

 
$
11,627

 
$
73,256

 
$
48,426

 
$
10,020

 
$
58,446

Net income
 
$
45,619

 
$
4,793

 
$
50,412

 
$
27,219

 
$
4,492

 
$
31,711


 
 
Six Months Ended June 30, 2015
 
Six Months Ended June 30, 2016
 
 
BridgeTex
 
All Others
 
Consolidated
 
BridgeTex
 
All Others
 
Consolidated
Revenue
 
$
98,765

 
$
21,147

 
$
119,912

 
$
99,224

 
$
21,429

 
$
120,653

Net income
 
$
63,656

 
$
7,374

 
$
71,030

 
$
58,467

 
$
9,758

 
$
68,225

 
 
 
 
 
 
 
 
 
 
 
 
 



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



5.
Inventory

Inventory at December 31, 2015 and June 30, 2016 was as follows (in thousands):
 
 
December 31, 2015
 
June 30,
2016
Refined products
$
57,455

 
$
44,809

Crude oil
28,385

 
43,767

Transmix
21,297

 
23,195

Liquefied petroleum gases
17,954

 
38,846

Additives
5,777

 
5,813

Total inventory
$
130,868

 
$
156,430



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, 2015 and 2016 (in thousands):
 
 
Three Months Ended
 
Three Months Ended
 
June 30, 2015
 
June 30, 2016
 
Pension
Benefits
 
Other  Postretirement
Benefits
 
Pension
Benefits
 
Other  Postretirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
4,975

 
$
56

 
$
4,405

 
$
62

Interest cost
2,008

 
109

 
1,933

 
110

Expected return on plan assets
(2,123
)
 
—

 
(2,331
)
 
—

Amortization of prior service credit
—

 
(928
)
 
(45
)
 
(929
)
Amortization of actuarial loss
1,806

 
217

 
1,107

 
185

Net periodic benefit cost (credit)
$
6,666

 
$
(546
)
 
$
5,069

 
$
(572
)
  
 
Six Months Ended
 
Six Months Ended
 
June 30, 2015
 
June 30, 2016
 
Pension
Benefits
 
Other  Postretirement
Benefits
 
Pension
Benefits
 
Other  Postretirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
9,445

 
$
122

 
$
9,093

 
$
123

Interest cost
3,877

 
219

 
3,978

 
220

Expected return on plan assets
(4,019
)
 
—

 
(4,459
)
 
—

Amortization of prior service credit
—

 
(1,856
)
 
(90
)
 
(1,857
)
Amortization of actuarial loss
3,153

 
442

 
2,324

 
369

Net periodic benefit cost (credit)
$
12,456

 
$
(1,073
)
 
$
10,846

 
$
(1,145
)
 
 
 
 
 
 
 
 

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




Contributions estimated to be paid into the plans in 2016 are $22.9 million and $0.6 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 $2.2 million and $2.4 million, respectively, for the three months ended June 30, 2015 and 2016 and $5.0 million and $5.4 million, respectively, for the six months ended June 30, 2015 and 2016.

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, 2015 and 2016 were as follows (in thousands):
 
 
Three Months Ended
 
Three Months Ended
 
 
June 30, 2015
 
June 30, 2016
Gains (Losses) Included in AOCL
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Beginning balance
 
$
(61,910
)
 
$
(2,399
)
 
$
(61,107
)
 
$
(4,689
)
Amortization of prior service credit
 
—

 
(928
)
 
(45
)
 
(929
)
Amortization of actuarial loss
 
1,806

 
217

 
1,107

 
185

Ending balance
 
$
(60,104
)
 
$
(3,110
)
 
$
(60,045
)
 
$
(5,433
)
 
 
Six Months Ended
 
Six Months Ended
 
 
June 30, 2015
 
June 30, 2016
Gains (Losses) Included in AOCL
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Beginning balance
 
$
(63,257
)
 
$
(1,696
)
 
$
(62,279
)
 
$
(3,945
)
Amortization of prior service credit
 
—

 
(1,856
)
 
(90
)
 
(1,857
)
Amortization of actuarial loss
 
3,153

 
442

 
2,324

 
369

Ending balance
 
$
(60,104
)
 
$
(3,110
)
 
$
(60,045
)
 
$
(5,433
)
 
 
 
 
 
 
 
 
 



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



7.
Debt
The carrying amount of our consolidated debt at December 31, 2015 and June 30, 2016 was as follows (in thousands, except as otherwise noted):
 
 
December 31, 2015
 
June 30,
2016
 
Weighted-Average
Interest Rate for the Six Months Ended June 30, 2016 (1)
Commercial paper(2)
 
$
279,801

 
$
23,863

 
0.7%
$250.0 million of 5.65% Notes due 2016(3)
 
250,208

 
250,083

 
5.7%
$250.0 million of 6.40% Notes due 2018
 
254,694

 
253,763

 
5.5%
$550.0 million of 6.55% Notes due 2019
 
562,600

 
560,902

 
5.7%
$550.0 million of 4.25% Notes due 2021
 
553,002

 
552,750

 
4.0%
$250.0 million of 3.20% Notes due 2025
 
247,788

 
247,907

 
3.2%
$650.0 million of 5.00% Notes due 2026(2)
 
—

 
643,978

 
5.0%
$250.0 million of 6.40% Notes due 2037
 
247,230

 
247,286

 
6.4%
$250.0 million of 4.20% Notes due 2042
 
246,142

 
246,201

 
4.2%
$550.0 million of 5.15% Notes due 2043
 
550,819

 
550,863

 
5.1%
$250.0 million of 4.20% Notes due 2045
 
247,338

 
247,385

 
4.6%
Total debt
 
3,439,622

 
3,824,981

 
4.8%
Less: current portion of long-term debt, net
 
250,335

 
250,083

 
 
Long-term debt, net(4)
 
$
3,189,287

 
$
3,574,898

 
 
 
 
 
 
 
 
 

(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, 2016. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

(3)
These borrowings will mature in October 2016 and are reflected in current debt on our consolidated balance sheets at December 31, 2015 and June 30, 2016.

(4)
Long-term debt is presented net of unamortized debt issuance costs of $18.7 million and $22.9 million at December 31, 2015 and June 30, 2016, respectively.

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

The face value of our debt at December 31, 2015 and June 30, 2016 was $3.4 billion and $3.8 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.

2016 Debt Offering

In February 2016, we issued $650.0 million of our 5.00% notes due 2026 in an underwritten public offering. The notes were issued at 99.875% of par. Net proceeds from this offering were approximately $643.8 million, after underwriting discounts and offering expenses of $5.4 million. The net proceeds from this offering were used to repay borrowings outstanding under our commercial paper program and for general partnership purposes, including expansion capital.


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



Other Debt

Revolving Credit Facilities. At June 30, 2016, the total borrowing capacity under our revolving credit facility with a maturity date of October 27, 2020 was $1.0 billion. Any borrowings outstanding under this facility are classified as long-term debt on our consolidated balance sheets. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.000% to 1.625% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.100% and 0.275% depending on our credit ratings. The unused commitment fee was 0.125% at June 30, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and June 30, 2016, respectively, there were no borrowings outstanding under this facility, with $6.3 million 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 this facility.

At June 30, 2016, the total borrowing capacity under our 364-day credit facility was $250.0 million. This credit facility matures on October 25, 2016, subject to a term-out option. We may exercise the term-out option no later than 30 days prior to October 25, 2016 and elect to have all outstanding borrowings converted into a term loan due and payable on October 25, 2018, subject to the payment of a term-out fee. Any borrowings under this credit facility are classified as current debt on our consolidated balance sheets. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.000% to 1.625% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate between 0.080% and 0.225% depending on our credit ratings. The unused commitment fee was 0.100% at June 30, 2016. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of December 31, 2015 and June 30, 2016, respectively, there were no borrowings outstanding under this 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 is classified as long-term debt.


8.
Derivative Financial Instruments

Interest Rate Derivatives

We periodically enter into interest rate derivatives to hedge the fair value of our debt or interest on 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.

As of June 30, 2016, we had 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 anticipate issuing in 2016. The fair value of these contracts at June 30, 2016 was recorded on our consolidated balance sheets as an other current liability of $18.6 million, with the offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

During second quarter 2016, we entered into $100.0 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 anticipate issuing in 2018. The fair values of these contracts at June 30, 2016 were recorded on our balance sheets as an other noncurrent

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



liability of $1.4 million and an other noncurrent asset of $0.4 million, with the net offset recorded to other comprehensive income. We account for these agreements as cash flow hedges.

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 purchases and sales are accounted for using traditional accrual accounting.

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 fair 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 fair 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 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, 2015 and 2016, 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 AOCL 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.


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



We hold petroleum product inventories that we obtain 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 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 a long-term asset on our consolidated balance sheets as tank bottoms. 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.

As outlined in the table below, our open NYMEX contracts at June 30, 2016 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
 
November 2017
NYMEX - Economic Hedges
 
5.8 million barrels of refined products and crude oil
 
Between July 2016 and April 2017
NYMEX - Economic Hedges
 
1.2 million barrels of future purchases of butane
 
Between July 2016 and April 2017

Energy Commodity Derivatives Contracts and Deposits Offsets

At June 30, 2016, we had made margin deposits of $28.5 million for our NYMEX contracts with our counterparties, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheets. 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, 2015 and June 30, 2016 (in thousands):
 
 
December 31, 2015
Description
 
Gross Amounts of Recognized Assets
 
Gross Amounts of Liabilities Offset in the Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Consolidated Balance Sheets(1)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets
 
Net Asset Amount(3)
Energy commodity derivatives
 
$
48,367

 
$
(5,646
)
 
$
42,721

 
$
(24,252
)
 
$
18,469

 
 
 
 
 
 
 
 
 
 
 

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



 
 
June 30, 2016
Description
 
Gross Amounts of Recognized Assets
 
Gross Amounts of Liabilities Offset in the Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Consolidated Balance Sheets(2)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheets
 
Net Asset Amount(3)
Energy commodity derivatives
 
$
9,615

 
$
(2,543
)
 
$
7,072

 
$
28,528

 
$
35,600

 
 
 
 
 
 
 
 
 
 
 

(1)
Net amount includes energy commodity derivative contracts classified as current assets, net, of $39,243 and noncurrent assets of $3,478.
(2)
Net amount includes energy commodity derivative contracts classified as current assets, net, of $7,359 and noncurrent liabilities of $287.
(3)
Amount represents the maximum loss we would incur if all of our counterparties failed to perform on their derivative contracts.

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, 2015 and 2016 were as follows (in thousands):
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
Derivative Losses Included in AOCL
2015
 
2016
 
2015
 
2016
Beginning balance
$
(31,852
)
 
$
(42,216
)
 
$
(16,587
)
 
$
(30,126
)
Net gain (loss) on interest rate contract cash flow hedges
1,936

 
(8,631
)
 
(13,529
)
 
(21,109
)
Reclassification of net loss on cash flow hedges to income
388

 
388

 
588

 
776

Ending balance
$
(29,528
)
 
$
(50,459
)
 
$
(29,528
)
 
$
(50,459
)
Income Statements
The following tables provide a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2015 and 2016 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, 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
)
 
 
 
$
—

 
 
 
Three Months Ended June 30, 2016
 
 
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
 
 
$
(8,631
)
 
 
Interest expense
 
 
$
(388
)
 
 
 
$
—

 

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



 
 
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
)
 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2016
 
 
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
 
 
$
(21,109
)
 
 
Interest expense
 
 
$
(776
)
 
 
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As of June 30, 2016, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $1.2 million.

During 2015 and 2016, 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, 2015 and June 30, 2016 of $27.9 million and $17.5 million, respectively, from these agreements were offset by a cumulative decrease to tank bottoms. 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 months ended June 30, 2015 and 2016, we recognized a gain of $6.5 million and $1.9 million, respectively, and for the six months ended June 30, 2015 and 2016, we recognized a gain of $6.3 million and $4.2 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.
The following table provides a summary of the effect on our consolidated statements of income for the three and six months ended June 30, 2015 and 2016 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 Derivatives
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
Location of Gain (Loss)
Recognized on Derivatives
 
June 30,
 
June 30,
Derivative Instrument
 
 
2015
 
2016
 
2015
 
2016
NYMEX commodity contracts
 
Product sales revenue
 
$
(23,350
)
 
$
(11,770
)
 
$
(19,470
)
 
$
4,212

NYMEX commodity contracts
 
Operating expenses
 
(8,883
)
 
(8,003
)
 
(7,580
)
 
(5,404
)
NYMEX commodity contracts
 
Cost of product sales
 
(856
)
 
3,240

 
(2,080
)
 
2,812

 
 
Total
 
$
(33,089
)
 
$
(16,533
)
 
$
(29,130
)
 
$
1,620

The impact of the derivatives in the above table was reflected as cash from operations on our consolidated statements of cash flows.

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



Balance Sheets
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, 2015 and June 30, 2016 (in thousands):
 
 
December 31, 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
 
$
60

 
Energy commodity derivatives contracts, net
 
$
—

NYMEX commodity contracts
 
Other noncurrent assets
 
3,478

 
Other noncurrent liabilities
 
—

Interest rate contracts
 
Other current assets
 
2,179

 
Other current liabilities
 
653

 
 
Total
 
$
5,717

 
Total
 
$
653

 
 
 
June 30, 2016
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Other noncurrent assets
 
$
—

 
Other noncurrent liabilities
 
$
287

Interest rate contracts
 
Other current assets
 
—

 
Other current liabilities
 
18,595

Interest rate contracts
 
Other noncurrent assets
 
391

 
Other noncurrent liabilities
 
1,379

 
 
Total
 
$
391

 
Total
 
$
20,261

 

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, 2015 and June 30, 2016 (in thousands):
 
 
December 31, 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
 
$
44,829

 
Energy commodity derivatives contracts, net
 
$
5,646

 
 
 
 
 
 
 
 
 
 
 
June 30, 2016
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
9,615

 
Energy commodity derivatives contracts, net
 
$
2,256

 


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



9.
Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $31.4 million and $28.7 million at December 31, 2015 and June 30, 2016, 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 9 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 were $2.9 million and $0.8 million for the three months ended June 30, 2015 and 2016, respectively, and $4.3 million and $4.3 million for the six months ended June 30, 2015 and 2016, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters were $2.6 million at December 31, 2015, of which $0.7 million and $1.9 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets. Receivables from insurance carriers and other third parties related to environmental matters were $1.9 million at June 30, 2016, of which $0.8 million and $1.1 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.
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 directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 11.9 million of our limited partner units. The compensation committee of our general partner’s board of directors administers our LTIP. The estimated units remaining available under the LTIP at June 30, 2016 total 3.0 million.
 

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



Our equity-based incentive compensation expense was as follows (in thousands):
 
Three Months Ended
 
Six Months Ended
 
June 30, 2015
 
June 30, 2015
 
Equity Method
 
Liability Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance-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

Time-based 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

 
Three Months Ended
 
Six Months Ended
 
June 30, 2016
 
June 30, 2016
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance-based awards:
 
 
 
 
 
 
 
 
 
 
 
2014 awards
$
979

 
$
—

 
$
979

 
$
4,388

 
$
—

 
$
4,388

2015 awards
926

 
—

 
926

 
2,471

 
—

 
2,471

2016 awards
1,023

 
—

 
1,023

 
2,143

 
—

 
2,143

Time-based awards
481

 
—

 
481

 
1,057

 
—

 
1,057

Total
$
3,409

 
$
—

 
$
3,409

 
$
10,059

 
$
—

 
$
10,059

 
 
 
 
 
 
 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
3,378

 
 
 
 
 
$
9,986

Operating expense
 
 
 
 
31

 
 
 
 
 
73

Total
 
 
 
 
$
3,409

 
 
 
 
 
$
10,059

 
 
 
 
 
 
 
 
 
 
 
 

In February 2016, 218,046 phantom unit awards were issued pursuant to our LTIP. These grants included both performance-based and time-based phantom unit awards and have a three-year vesting period that will end on December 31, 2018.

In February 2016, we issued 350,552 limited partner units to settle unit award grants to certain employees that vested on December 31, 2015. Further, 6,117 limited partner units were issued during 2016 to settle the equity-based retainers paid to the directors of our general partner.

Basic and Diluted Net Income Per Limited Partner Unit

The difference between our actual limited partner units outstanding and our weighted-average number of limited partner units outstanding used to calculate basic net income per unit is due to the impact of: (i) the phantom

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



units issued to non-employee directors and (ii) the weighted average effect of units actually issued during a period.  The difference between the weighted-average number of limited partner units outstanding used for basic and diluted net income per unit calculations on our consolidated statements of income is primarily the dilutive effect of phantom unit grants associated with our LTIP that have not yet vested.


11.
Distributions
Distributions we paid during 2015 and 2016 were as follows (in thousands, except per unit amounts):
 
Payment Date
 
Per Unit Cash
Distribution
Amount
 
Total Cash Distribution to Limited Partners
02/13/2015
 
 
$
0.6950

 
 
 
$
158,061

 
05/15/2015
 
 
0.7175

 
 
 
163,178

 
Through 06/30/2015
 
 
1.4125

 
 
 
321,239

 
08/14/2015
 
 
0.7400

 
 
 
168,296

 
11/13/2015
 
 
0.7625

 
 
 
173,413

 
Total
 
 
$
2.9150

 
 
 
$
662,948

 
 
 
 
 
 
 
 
 
 
2/12/2016
 
 
$
0.7850

 
 
 
$
178,808

 
5/13/2016
 
 
0.8025

 
 
 
182,797

 
Through 06/30/2016
 
 
1.5875

 
 
 
361,605

 
08/12/2016(1)
 
 
0.8200

 
 
 
186,783

 
Total
 
 
$
2.4075

 
 
 
$
548,388

 
 
 
 
 
 
 
 
 
 

(1) Our general partner’s board of directors declared this cash distribution in July 2016 to be paid on August 12, 2016 to unitholders of record at the close of business on August 1, 2016.


12.
Fair Value

Recurring

Fair Value Methods and Assumptions - Financial Assets and Liabilities.

We used the following methods and assumptions in estimating fair value of 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.


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



•
Long-term receivables. These primarily include lease payments receivable under a direct-financing leasing arrangement. 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, 2015 and June 30, 2016; 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, 2015 and June 30, 2016 based on the three levels established by ASC 820, Fair Value Measurements and Disclosures (in thousands):
 
 
December 31, 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
 
$
42,721

 
$
42,721

 
$
42,721

 
$
—

 
$
—

Interest rate contracts
 
$
1,526

 
$
1,526

 
$
—

 
$
1,526

 
$
—

Long-term receivables
 
$
20,374

 
$
20,021

 
$
—

 
$
—

 
$
20,021

Debt
 
$
(3,439,622
)
 
$
(3,284,791
)
 
$
—

 
$
(3,284,791
)
 
$
—


 
 
June 30, 2016
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
 
$
7,072

 
$
7,072

 
$
7,072

 
$
—

 
$
—

Interest rate contracts
 
$
(19,583
)
 
$
(19,583
)
 
$
—

 
$
(19,583
)
 
$
—

Long-term receivables
 
$
18,134

 
$
19,708

 
$
—

 
$
—

 
$
19,708

Debt
 
$
(3,824,981
)
 
$
(4,161,568
)
 
$
—

 
$
(4,161,568
)
 
$
—




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



13.
Related Party Transactions

Barry R. Pearl is an independent member of our general partner’s board of directors and was also a director of the general partner of Targa Resources Partners, L.P. (“Targa”) through February 29, 2016. In the normal course of business, we purchase butane from subsidiaries of Targa. During Mr. Pearl’s tenure as a director of the general partner of Targa, we made purchases of butane from subsidiaries of Targa of $4.0 million and $12.8 million, respectively, for the three and six month periods ending June 30, 2015, and $4.7 million for the period from January 1, 2016 through February 29, 2016. These purchases were based on the then-current index prices. We had recognized payables to Targa of $2.0 million at December 31, 2015.

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 from this customer of $2.6 million from April 23, 2015 through June 30, 2015 and $4.7 million and $7.7 million, respectively, for the three and six months ended June 30, 2016. We recorded receivables of $1.3 million and $1.3 million from this customer at December 31, 2015 and June 30, 2016, respectively.  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.


14.
Subsequent Events

Recognizable events

No recognizable events occurred subsequent to June 30, 2016.

Non-recognizable events

Cash Distribution. In July 2016, our general partner’s board of directors declared a quarterly distribution of $0.82 per unit to be paid on August 12, 2016 to unitholders of record at the close of business on August 1, 2016. The total cash distributions expected to be paid under this declaration are approximately $186.8 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, 2016, our asset portfolio, including the assets of our joint ventures, consisted of:
•
our refined products segment, comprised of our 9,700-mile refined products pipeline system with 54 terminals as well as 26 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 22 million barrels, of which approximately 15 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, 2015.


Recent Developments

Pasadena Marine Terminal. In July 2016, we announced our plans to construct a new marine terminal along the Houston Ship Channel in Pasadena, Texas to handle refined petroleum products, including various grades of gasoline and diesel fuel, and renewable fuels. The new terminal will be built on recently-acquired land and is supported by a long-term customer commitment. The project is currently estimated to cost approximately $335 million, including the land acquisition. Subject to receipt of necessary permits and regulatory approval, we expect our new Pasadena terminal to be operational in early 2019.

Cash Distribution. In July 2016, the board of directors of our general partner declared a quarterly cash distribution of $0.82 per unit for the period of April 1, 2016 through June 30, 2016. This quarterly cash distribution will be paid on August 12, 2016 to unitholders of record on August 1, 2016. Total distributions expected to be paid under this declaration are approximately $186.8 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”) expense, 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, 2015 compared to Three Months Ended June 30, 2016
 
 
Three Months Ended June 30,
 
Variance
Favorable  (Unfavorable)
 
2015
 
2016
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenue:
 
 
 
 
 
 
 
Refined products
$
238.4

 
$
247.8

 
$
9.4

 
4
Crude oil
102.0

 
101.4

 
(0.6
)
 
(1)
Marine storage
44.5

 
43.0

 
(1.5
)
 
(3)
Total transportation and terminals revenue
384.9

 
392.2

 
7.3

 
2
Affiliate management fee revenue
3.5

 
2.9

 
(0.6
)
 
(17)
Operating expenses:
 
 
 
 
 
 
 
Refined products
105.1

 
98.5

 
6.6

 
6
Crude oil
22.3

 
20.5

 
1.8

 
8
Marine storage
15.9

 
16.3

 
(0.4
)
 
(3)
Intersegment eliminations
(1.0
)
 
(1.1
)
 
0.1

 
10
Total operating expenses
142.3

 
134.2

 
8.1

 
6
Product margin:
 
 
 
 
 
 
 
Product sales revenue
110.0

 
123.8

 
13.8

 
13
Cost of product sales
94.5

 
95.7

 
(1.2
)
 
(1)
Product margin(1)
15.5

 
28.1

 
12.6

 
81
Earnings of non-controlled entities
24.5

 
15.4

 
(9.1
)
 
(37)
Operating margin
286.1

 
304.4

 
18.3

 
6
Depreciation and amortization expense
40.4

 
43.3

 
(2.9
)
 
(7)
G&A expense
37.9

 
34.6

 
3.3

 
9
Operating profit
207.8

 
226.5

 
18.7

 
9
Interest expense (net of interest income and interest capitalized)
37.2

 
41.2

 
(4.0
)
 
(11)
Gain on exchange of interest in non-controlled entity
—

 
(1.2
)
 
1.2

 
n/a
Other income
(6.6
)
 
(2.0
)
 
(4.6
)
 
(70)
Income before provision for income taxes
177.2

 
188.5

 
11.3

 
6
Provision for income taxes
(0.2
)
 
0.7

 
(0.9
)
 
450
Net income
$
177.4

 
$
187.8

 
$
10.4

 
6
Operating Statistics:
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.398

 
$
1.427

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Gasoline
67.2

 
71.1

 
 
 
 
Distillates
36.3

 
36.4

 
 
 
 
Aviation fuel
5.3

 
6.9

 
 
 
 
Liquefied petroleum gases
4.8

 
4.2

 
 
 
 
Total volume shipped
113.6

 
118.6

 
 
 
 
Crude oil:
 
 
 
 
 
 
 
Magellan 100%-owned assets:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.052

 
$
1.360

 
 
 
 
Volume shipped (million barrels)
53.8

 
45.1

 
 
 
 
Crude oil terminal average utilization (million barrels per month)
12.8

 
14.7

 
 
 
 
Select joint venture pipelines:
 
 
 
 
 
 
 
BridgeTex - volume shipped (million barrels)(2)
23.7

 
19.3

 
 
 
 
 
 
 
 
 
 
 
 
Marine storage:
 
 
 
 
 
 
 
Marine terminal average utilization (million barrels per month)
24.3

 
23.0

 
 
 
 

(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 $7.3 million resulting from:
•
an increase in refined products revenue of $9.4 million primarily attributable to increased shipments and higher average tariff rates. Shipments increased 4% in the current period primarily associated with higher gasoline shipments driven by strong demand for gasoline largely attributable to the lower pricing environment, and the average rate per barrel in the current period was favorably impacted by the mid-year 2015 tariff rate increase of 4.6%;
•
a decrease in crude oil revenue of $0.6 million. Increased shipments and rates on the Longhorn pipeline and new leased storage contracts were more than offset by the one-time benefit from a customer buying out of its remaining storage contract in 2015 and decreased revenue from tender deduct barrels largely due to the lower commodity price environment. Overall crude oil shipments declined and average rate per barrel increased due to fewer barrels moving on our lower-priced Houston distribution system tariff structure to their ultimate destination. Instead, customers utilized space available on our capacity lease for shipments from BridgeTex pipeline; and
•
a decrease in marine storage revenue of $1.5 million primarily due to lower ancillary fees resulting from reduced customer activity. Otherwise, revenue from leased storage was relatively unchanged as higher contract rates offset lower utilization.
Operating expenses decreased by $8.1 million primarily resulting from:
•
a decrease in refined products expenses of $6.6 million compared to the 2015 period primarily due to a product release in second quarter 2015 as well as more favorable product overages in the current period (which reduce operating expenses);
•
a decrease in crude oil expenses of $1.8 million primarily due to lower power costs, more favorable product overages in the current period (which reduce operating expenses) and reduced asset replacement costs, partially offset by additional environmental accruals due to a product release in the current period; and
•
a slight increase in marine storage expenses of $0.4 million primarily due to higher asset integrity spending related to the timing of tank inspections and maintenance work.
Product sales revenue resulted from our butane blending activities, transmix fractionation and the sale of product gains from our operations. 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 increased $12.6 million compared to second quarter 2015 due to reduced losses recognized from changes in related NYMEX contracts somewhat offset by lower sales prices as a result of reduced commodity prices. 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 decreased $9.1 million primarily attributable to decreased earnings from BridgeTex Pipeline Company, LLC (“BridgeTex”) due to lower shipments during the current period as customers shipped their minimum commitments. Lower earnings from Osage Pipe Line Company, LLC (“Osage”) due to the transfer of our 50% membership interest in first quarter 2016 were offset by increased shipments on the Double Eagle Pipeline LLC joint venture.
Depreciation and amortization increased $2.9 million primarily due to expansion capital projects recently placed into service.
G&A decreased $3.3 million primarily due to lower expense associated with our long-term incentive plan in the current quarter and a separation fee paid to a former executive in second quarter 2015, partially offset by higher

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deferred board of director fees due to an increasing price in our limited partner units during 2016 compared to a decreasing price during 2015.
Interest expense, net of interest income and interest capitalized, increased $4.0 million in second quarter 2016, primarily because our debt balance was higher in the current period compared to the same period in second quarter 2015, partially offset by higher capitalized interest. Our average outstanding debt increased from $3.3 billion in second quarter 2015 to $3.8 billion in second quarter 2016 primarily due to borrowings for expansion capital expenditures, including $650.0 million of senior notes issued in February 2016. Our weighted-average interest rate of 4.9% in second quarter 2016 was slightly higher than the 4.8% rate incurred in second quarter 2015.
In second quarter 2016, we recognized an additional $1.2 million gain related to the transfer of our 50% membership interest in Osage. See Note 4 – Investments in Non-Controlled Entities of the consolidated financial statements included in Item 1 of Part I of this report for more details regarding this transaction.
Other income decreased $4.6 million due to a less favorable non-cash adjustment for the change in the current period in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms.
Provision for income taxes increased $0.9 million due to favorable accrual adjustments in second quarter 2015 resulting from a reduction in the tax rate.



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Six Months Ended June 30, 2015 compared to Six Months Ended June 30, 2016
 
 
Six Months Ended June 30,
 
Variance
Favorable  (Unfavorable)
 
2015
 
2016
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenue:
 
 
 
 
 
 
 
Refined products
$
459.0

 
$
472.6

 
$
13.6

 
3
Crude oil
192.9

 
203.1

 
10.2

 
5
Marine storage
86.8

 
86.6

 
(0.2
)
 
—
Total transportation and terminals revenue
738.7

 
762.3

 
23.6

 
3
Affiliate management fee revenue
6.9

 
6.1

 
(0.8
)
 
(12)
Operating expenses:
 
 
 
 
 
 
 
Refined products
179.3

 
184.5

 
(5.2
)
 
(3)
Crude oil
40.5

 
41.7

 
(1.2
)
 
(3)
Marine storage
31.2

 
33.5

 
(2.3
)
 
(7)
Intersegment eliminations
(2.0
)
 
(2.3
)
 
0.3

 
15
Total operating expenses
249.0

 
257.4

 
(8.4
)
 
(3)
Product margin:
 
 
 
 
 
 
 
Product sales revenue
283.1

 
270.3

 
(12.8
)
 
(5)
Cost of product sales
230.7

 
209.3

 
21.4

 
9
Product margin(1)
52.4

 
61.0

 
8.6

 
16
Earnings of non-controlled entities
34.1

 
33.0

 
(1.1
)
 
(3)
Operating margin
583.1

 
605.0

 
21.9

 
4
Depreciation and amortization expense
82.1

 
87.1

 
(5.0
)
 
(6)
G&A expense
73.4

 
75.4

 
(2.0
)
 
(3)
Operating profit
427.6

 
442.5

 
14.9

 
3
Interest expense (net of interest income and interest capitalized)
71.9

 
78.4

 
(6.5
)
 
(9)
Gain on exchange of interest in non-controlled entity
—

 
(28.1
)
 
28.1

 
n/a
Other income
(6.3
)
 
(4.3
)
 
(2.0
)
 
(32)
Income before provision for income taxes
362.0

 
396.5

 
34.5

 
10
Provision for income taxes
1.0

 
1.6

 
(0.6
)
 
(60)
Net income
$
361.0

 
$
394.9

 
$
33.9

 
9
Operating Statistics:
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.384

 
$
1.422

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Gasoline
129.4

 
132.2

 
 
 
 
Distillates
73.2

 
72.7

 
 
 
 
Aviation fuel
10.5

 
12.4

 
 
 
 
Liquefied petroleum gases
5.8

 
5.8

 
 
 
 
Total volume shipped
218.9

 
223.1

 
 
 
 
Crude oil:
 
 
 
 
 
 
 
Magellan 100%-owned assets:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.081

 
$
1.403

 
 
 
 
Volume shipped (million barrels)
103.8

 
88.8

 
 
 
 
Crude oil terminal average utilization (million barrels per month)
12.7

 
14.6

 
 
 
 
Select joint venture pipelines:
 
 
 
 
 
 
 
BridgeTex - volume shipped (million barrels)(2)
38.7

 
38.1

 
 
 
 
 
 
 
 
 
 
 
 
Marine storage:
 
 
 
 
 
 
 
Marine terminal average utilization (million barrels per month)
23.9

 
23.2

 
 
 
 

(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 $23.6 million resulting from:
•
an increase in refined products revenue of $13.6 million primarily attributable to higher average tariff rates and increased shipments. The average rate per barrel in the current period was favorably impacted by the mid-year 2015 tariff rate increase of 4.6%. Shipments increased 2% in the current period primarily associated with higher gasoline shipments;
•
an increase in crude oil revenue of $10.2 million primarily due to higher average rates and more shipments on our Longhorn pipeline system and new leased storage contracts. Overall crude oil shipments declined and average rate per barrel increased due to fewer barrels moving on our lower-priced Houston distribution system tariff structure to their ultimate destination. Instead, customers utilized space available on our capacity lease for shipments from BridgeTex pipeline; and
•
a slight decrease in marine storage revenue of $0.2 million as lower ancillary fees resulting from reduced customer activity and lower utilization were largely offset by higher average storage rates.
Operating expenses increased by $8.4 million primarily resulting from:
•
an increase in refined products expenses of $5.2 million primarily due to more product handling costs related to the receipt of off-spec product during 2016, higher costs related to asset replacements, increased personnel costs and less favorable product overages (which reduce operating expenses), partially offset by lower environmental costs, asset integrity spending and property taxes;
•
an increase in crude oil expenses of $1.2 million primarily due to increased personnel costs, additional environmental accruals due to a product release in the current year and higher property taxes, partially offset by more favorable product overages (which reduce operating expenses), and lower power costs; and
•
an increase in marine storage expenses of $2.3 million primarily due to higher asset integrity spending related to the timing of tank maintenance work.
Product margin increased $8.6 million compared to 2015 due to favorable gains recognized from changes in related NYMEX contracts somewhat offset by lower sales prices as a result of reduced commodity prices. 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 decreased $1.1 million primarily attributable to decreased earnings from BridgeTex due to lower shipments during the current period, as well as lower earnings from Osage due to the transfer of our 50% membership interest in first quarter 2016.
Depreciation and amortization increased $5.0 million primarily due to expansion capital projects placed into service.
G&A was $2.0 million higher primarily due to higher deferred board of director fees due to an increasing price in our limited partner units during 2016 compared to a decreasing price during 2015 and higher headcount, partially offset by a separation fee paid to a former executive in 2015.
Interest expense, net of interest income and interest capitalized, increased $6.5 million in 2016, primarily because our debt balance was higher in the current period compared to the same period in 2015, partially offset by higher capitalized interest. Our average outstanding debt increased from $3.2 billion in 2015 to $3.8 billion in 2016 primarily due to borrowings for expansion capital expenditures, including $650.0 million of senior notes issued in February 2016. Our weighted-average interest rate of 4.8% in 2016 was comparable to 2015.
In 2016, we recognized a $28.1 million gain related to the transfer of our 50% membership interest in Osage. See Note 4 – Investments in Non-Controlled Entities of the consolidated financial statements included in Item 1 of Part I of this report for more details regarding this transaction.

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Other income decreased $2.0 million due to a less 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.


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, 2015 and 2016 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):
 
 
Six Months Ended June 30,
 
Increase (Decrease)
 
 
2015
 
2016
 
Net income
 
$
361.0

 
$
394.9

 
$
33.9

Interest expense, net(1)
 
71.9

 
78.4

 
6.5

Depreciation and amortization
 
82.1

 
87.1

 
5.0

Equity-based incentive compensation(2)
 
(7.2
)
 
(4.3
)
 
2.9

Loss on sale and retirement of assets
 
2.1

 
3.3

 
1.2

Gain on exchange of interest in non-controlled entity(3)
 
—

 
(28.1
)
 
(28.1
)
Commodity-related adjustments:
 
 
 
 
 
 
Derivative (gains) losses recognized in the period associated with future product transactions(5)
 
5.6

 
(5.7
)
 
(11.3
)
Derivative gains recognized in previous periods associated with product sales completed in the period(5)
 
91.6

 
36.2

 
(55.4
)
Lower-of-cost-or-market adjustments(6)
 
(39.2
)
 
(1.7
)
 
37.5

Total commodity-related adjustments
 
58.0

 
28.8

 
(29.2
)
Cash distributions received from non-controlled entities in excess of (less than) earnings for the period
 
(2.3
)
 
0.1

 
2.4

Other(4)
 
—

 
2.5

 
2.5

Adjusted EBITDA
 
565.6

 
562.7

 
(2.9
)
Interest expense, net, excluding debt issuance cost amortization(1)
 
(70.6
)
 
(76.9
)
 
(6.3
)
Maintenance capital(7)
 
(39.0
)
 
(59.4
)
 
(20.4
)
DCF
 
$
456.0

 
$
426.4

 
$
(29.6
)
 
 
 
 
 
 
 
(1)
In 2015, we adopted Accounting Standards Update (“ASU”) No. 2015-03, Interest: Simplifying the Presentation of Debt Issuance Costs. Under this new accounting standard, we have reclassified debt issuance cost amortization expense as interest expense. For the purposes of calculating DCF, we have added back debt issuance cost amortization expense included in interest expense of $1.2 million and $1.5 million for the six months ended June 30, 2015 and 2016, respectively.
(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, 2015 and 2016 was $10.6 million and $10.1 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2015 and 2016 of $17.8 million and $14.4 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduces DCF.

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(3)
In February 2016, we transferred our 50% membership interest in Osage to an affiliate of HollyFrontier Corporation (“HFC”). In conjunction with this transaction, we entered into several commercial agreements with affiliates of HFC, which we recorded as intangible assets and other receivables in our consolidated balance sheets.  We recorded a $28.1 million non-cash gain in relation to this transaction.
(4)
In conjunction with the February 2016 Osage transaction, HFC agreed to make certain payments to us until HFC completes a connection to our El Paso terminal. These payments replace distributions we would have received had the Osage transaction not occurred and are, therefore, included in our calculation of DCF.
(5)
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 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 products are physically sold, the net impact of the associated hedges is included in our determination of DCF.
(6)
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.
(7)
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 $414.8 million and $407.1 million for the six months ended June 30, 2015 and 2016, respectively. The $7.7 million decrease from 2015 to 2016 was due to adjustments to non-cash items and changes in our working capital, mostly offset by higher net income related to activities previously described.
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, 2015 and 2016 was $363.8 million and $413.4 million, respectively. During 2016, we incurred $321.1 million for capital expenditures, which included $59.4 million for maintenance capital and $261.7 million for expansion capital. Also during the 2016 period, we contributed capital of $109.9 million in conjunction with our joint venture capital projects, which we account for as investments in non-controlled entities. During 2015, we incurred $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.
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, 2015 was $39.0 million and net cash provided by financing activities for the six months ended June 30, 2016 was $11.8 million. During 2016, we paid cash distributions of $361.6 million to our unitholders. Additionally, we received net proceeds of $649.2 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. Also, in February 2016, the cumulative amounts of the January 2013 equity-based incentive compensation award grants were settled by issuing 350,552 limited partner units and distributing those units to the long-term incentive plan (“LTIP”) participants, resulting in payments of associated tax withholdings of $14.4 million. During 2015, we paid cash distributions of $321.2 million to our unitholders. Additionally, we received net proceeds of $499.6 million from

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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 LTIP participants, resulting in payments of associated tax withholdings of $17.8 million.
The quarterly distribution amount related to our second-quarter 2016 financial results (to be paid in third quarter 2016) is $0.82 per unit.  If we are able to meet management’s targeted distribution growth of 10% for 2016 and the number of outstanding limited partner units remains at 227.8 million, total cash distributions of approximately $755.0 million will be paid to our unitholders related to 2016 earnings. Management believes we will have sufficient DCF 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 DCF; and
•
Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental DCF 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, 2016, our maintenance capital spending was $59.4 million. For 2016, we expect to spend approximately $100.0 million on maintenance capital.

During the first six months of 2016, we spent $261.7 million for organic growth capital and contributed $109.9 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, we expect to spend approximately $850 million during 2016, $250 million during 2017 and $200 million during 2018 to complete our current projects, including construction of our new Pasadena marine terminal.

Liquidity

Cash generated from operations is our primary source of liquidity for funding debt service, maintenance capital expenditures and quarterly distributions to our unitholders. Additional liquidity for purposes other than quarterly distributions, such as expansion capital expenditures and debt repayments, is available through borrowings under our commercial paper program and revolving credit facilities, as well as from other borrowings or issuances of debt or limited partner units (see Note 7 – Debt of the consolidated financial statements included in Item 1 of Part I of this report for detail of our borrowings and debt outstanding at December 31, 2015 and June 30, 2016). If capital markets do not permit us to issue additional debt and equity securities, our business may be adversely affected, and we may not be able to acquire additional assets and businesses, fund organic growth projects or continue paying cash distributions at the current level.


Off-Balance Sheet Arrangements

None.



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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 Changes. 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 are either subject to regulations by the states in which we operate or are deemed competitive by the FERC, in which case these rates can be adjusted at our discretion based on market factors.  The FERC-approved indexing method to be used for the five-year period beginning in July 2016 is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.23%. The change in PPI-FG for 2015 was a reduction of approximately 3.2%. As a result, we decreased our rates by approximately 2.0% in the 40% of our markets that are subject to the FERC’s index methodology on July 1, 2016. In the 60% of our markets that are deemed competitive, we increased our rates by an average of approximately 4.0% on July 1, 2016.

Condensate Splitter. We are constructing a condensate splitter at our terminal in Corpus Christi, Texas based on a commitment from a single customer, an affiliate of Trafigura, AG. The project also includes construction of more than one million barrels of storage, dock improvements and two additional truck rack bays at our terminal as well as pipeline connectivity between our terminal and a nearby facility also used by our customer. Our most recent guidance related to the project had assumed that the condensate splitter and related infrastructure would cost approximately $270 million and be operational during the fourth quarter of 2016. Due to recent construction delays, we currently expect the project to be operational late in the fourth quarter of 2016 and the total cost of the project to be approximately $300 million, approximately one third of which relates to the splitter and the remainder to the related infrastructure. Further delays in the construction, commissioning or testing of the facility could result in additional costs or a delay in our realizing revenues or profits from the project, and in certain circumstances could result in the termination by our customer of its commitment to us as early as first quarter 2017, which could materially reduce the revenues and profits we expect to realize from the project and the value of the splitter.

Election to our General Partner’s Board of Directors. In June 2016, Lori A. Gobillot and Edward J. Guay were elected to our general partner’s board of directors as independent directors.

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 prices of refined products and crude oil that we expect to sell and of butane that we expect to purchase 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. As of and for the six months ended June 30, 2016, our open derivative contracts and the impact of the derivatives we settled during the period were as follows:


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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. These contracts, which we are accounting for as fair value hedges, mature November 2017. Through June 30, 2016, the cumulative amount of gains from these agreements was $17.5 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, 2016 was a gain of $4.2 million, which we recognized as other income on our consolidated statements of income.

Derivative Contracts Not Designated as Hedges – Open
•
NYMEX contracts covering 4.4 million barrels of refined products and crude oil related to our butane blending, fractionation and certain crude oil inventory. These contracts mature between July 2016 and April 2017 and are being accounted for as economic hedges. Through June 30, 2016, the cumulative amount of net unrealized gains associated with these agreements was $4.0 million. We recorded these gains as an adjustment to product sales revenue, of which $8.6 million of net gains was recognized in 2015 and $4.6 million of net losses was recognized in 2016.

•
NYMEX contracts covering 1.4 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 August 2016, are being accounted for as economic hedges. Through June 30, 2016, the cumulative amount of net unrealized gains associated with these agreements was $1.2 million. We recorded these gains as an adjustment to operating expense, all of which was recognized in 2016.

•
NYMEX contracts covering 1.2 million barrels of butane purchases that mature between July 2016 and April 2017, which are being accounted for as economic hedges. Through June 30, 2016, the cumulative amount of net unrealized gains associated with these agreements was $2.1 million. We recorded these gains as an adjustment to cost of product sales, of which $0.8 million of net losses was recognized in 2015 and $2.9 million of net gains was recognized in 2016.

Derivative Contracts Not Designated as Hedges – Settled

•
NYMEX contracts covering 5.5 million barrels of refined products and crude oil related to economic hedges of products from our butane blending, fractionation and certain crude oil inventory activities that we sold during 2016.  We recognized a gain of $8.8 million in 2016 related to these contracts, which we recorded as an adjustment to product sales revenue.

•
NYMEX contracts covering 4.9 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 2016.  We recognized a loss of $6.6 million in 2016 on the settlement of these contracts, which we recorded as an adjustment to operating expense.

•
NYMEX contracts covering 0.7 million barrels related to economic hedges of butane purchases we made during 2016 associated with our butane blending activities.  We recognized a loss of $0.1 million in 2016 on the settlement of these contracts, which we recorded as an adjustment to cost of product sales.


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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, 2015
 
Product Sales Revenue
 
Cost of Product Sales
 
Operating Expense
 
Other Income
 
Net Impact on Net Income
NYMEX gains (losses) recorded on open contracts during the period
$
(10.3
)
 
$
(1.8
)
 
$
(0.4
)
 
$
6.3

 
$
(6.2
)
NYMEX losses recognized on settled contracts during the period
(9.2
)
 
(0.2
)
 
(7.2
)
 
—

 
(16.6
)
Net impact of NYMEX contracts
$
(19.5
)
 
$
(2.0
)
 
$
(7.6
)
 
$
6.3

 
$
(22.8
)

 
Six Months Ended June 30, 2016
 
Product Sales Revenue
 
Cost of Product Sales
 
Operating Expense
 
Other Income
 
Net Impact on Net Income
NYMEX gains (losses) recorded on open contracts during the period
$
(4.6
)
 
$
2.9

 
$
1.2

 
$
4.2

 
$
3.7

NYMEX gains (losses) recognized on settled contracts during the period
8.8

 
(0.1
)
 
(6.6
)
 
—

 
2.1

Net impact of NYMEX contracts
$
4.2

 
$
2.8

 
$
(5.4
)
 
$
4.2

 
$
5.8



Related Party Transactions. See Note 13 – Related Party Transactions in Item 1 of Part I of this report for detail of our related party transactions.


ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates and 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 overages associated with our refined products and crude oil pipelines. We use derivatives such as forward physical contracts and NYMEX 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, 2016, we had commitments under forward purchase and sale contracts used in our butane blending and fractionation activities as follows (in millions):

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Total
 
< 1 Year
 
1 - 3 Years
Forward purchase contracts – notional value
$
104.9

 
$
61.5

 
$
43.4

Forward purchase contracts – barrels
3.2

 
1.9

 
1.3

Forward sales contracts – notional value
$
72.9

 
$
71.7

 
$
1.2

Forward sales contracts – barrels
1.3

 
1.3

 
—

 
We use NYMEX contracts to hedge against changes in the price of petroleum products we expect to sell or purchase. Some of these NYMEX contracts qualify for hedge accounting treatment, and we designate and account for these contracts as either cash flow or fair value hedges. We account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges.

At June 30, 2016, we had open NYMEX contracts representing 6.5 million barrels of petroleum products we expect to sell in the future. Additionally, we had open NYMEX contracts for 1.2 million barrels of butane we expect to purchase in the future. At June 30, 2016, the fair value of our open NYMEX contracts was a net asset of $7.1 million.

At June 30, 2016, open NYMEX contracts, primarily sales contracts, representing 5.8 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 the related petroleum products would result in a $58.0 million decrease in our operating profit and a $10.00 per barrel decrease in the price of these NYMEX contracts would result in a $58.0 million increase in our operating profit.

At June 30, 2016, we had open NYMEX contracts, primarily purchase contracts, representing 1.2 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 $12.0 million increase in our operating profit and a $10.00 per barrel decrease in the price of butane would result in a $12.0 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.

Interest Rate Risk

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

During 2015 and 2016, 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 anticipate issuing in 2016. The fair value of these contracts at June 30, 2016 was a liability of $18.6 million. We account for these agreements as cash flow hedges. A 0.125% decrease in interest rates would result in an increase in the fair value of this liability of approximately $3.1 million. A 0.125% increase in interest rates would result in a decrease of this liability of approximately $3.0 million.

During 2016, we entered into $100.0 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 anticipate issuing in 2018. The fair value of these contracts at June 30, 2016 was a net liability of $1.0 million. We account for these agreements as cash flow hedges. A 0.125% decrease in interest rates would result in an increase in the fair value of this liability of approximately $2.9 million. A 0.125% increase in interest rates would result in a favorable impact of approximately $2.8 million.


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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, 2016 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,” “targets,” “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, lenders or joint venture co-owners;
•
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 of 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 and demand patterns for our facilities due to geopolitical events, the activities of the Organization of the Petroleum Exporting Countries, changes in U.S. trade policies or in laws governing the importing and exporting of petroleum products, 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;
•
our ability to obtain adequate levels of insurance at a reasonable cost, and the potential for losses to exceed the insurance coverage we do obtain;
•
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 to construct, acquire and operate 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 butane 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, trade 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 our customers, vendors, lenders, joint venture co-owners or other 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, and the operation, acquisition and construction of assets related to such activities.
 
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
Clean Water Act Information Requests and Claims. 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 near Texas City, Texas in February 2011 (the "Texas Release").  In April 2012, we received a similar information request from the EPA pursuant to Section 308 of the Clean Water Act regarding a pipeline release near Nemaha, Nebraska in December 2011 (the "Nebraska Release").   In October 2015, we received a letter from the U.S. Department of Justice ("DOJ Letter") stating that the Clean Water Act claims arising out of the Texas Release, the Nebraska Release and a pipeline release near El Dorado, Kansas in May 2015 have all been referred to the U.S. Department of Justice for enforcement.  The DOJ Letter proposed a settlement of Clean Water Act claims related to the three releases in the form of an enforceable commitment from us to take certain yet to be determined steps to prevent future releases and a civil penalty of $2.8 million.  In response to the DOJ Letter, we are engaged in discussions with the U.S. Department of Justice in an effort to settle the Clean Water Act claims on terms that are mutually agreeable.  While the results cannot be predicted with certainty, we believe the ultimate resolution of these matters 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. While the results cannot be reasonably estimated, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.
Lake Calumet Cluster Site, EPA ID No.: ILD000716852 Superfund Site. We have liability at the Lake Calumet Cluster Superfund Site in Chicago, Illinois as a PRP under Sections 107(a) and 113(f)(1) of CERCLA. As a result of the EPA’s Administrative Settlement Agreement and Order for Remedial Investigation/Feasibility Study of June 2013, we are in the process of voluntarily entering the PRP group responsible for the investigation, cleanup and installation of an appropriate clay cap over the site. We have paid $8,000 associated with the Remedial Investigation/Feasibility Study and cleanup costs to date. Our projected portion of the estimated cap installation is $55,000. While the results cannot be predicted with certainty, we believe the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.
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, 2015, 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

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currently deem to be immaterial also could materially adversely affect our business, financial condition or operating results.



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

None.
 

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES

None.
 

ITEM 4.
MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.
OTHER INFORMATION

None.



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ITEM 6.
EXHIBITS

Exhibit Number
 
Description
 
 
 
Exhibit 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 2, 2016.
 
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 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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