MMP - 2014.3.31.10Q


 
 
 
 
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ________________________________________
FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2014
OR
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File No.: 1-16335
 _________________________________________
 Magellan Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
73-1599053
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)

One Williams Center, P.O. Box 22186, Tulsa, Oklahoma 74121-2186
(Address of principal executive offices and zip code)
(918) 574-7000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.
Large accelerated filer  x        Accelerated filer  £      Non-accelerated filer  £        Smaller reporting company  £
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).    Yes  £    No  x

As of May 5, 2014, there were 227,068,257 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 March 31,
 
2013
 
2014
Transportation and terminals revenue
$
227,271

 
$
317,637

Product sales revenue
201,711

 
296,063

Affiliate management fee revenue
3,439

 
4,906

Total revenue
432,421

 
618,606

Costs and expenses:
 
 
 
Operating
65,181

 
73,497

Cost of product sales
160,398

 
198,040

Depreciation and amortization
36,332

 
37,511

General and administrative
30,056

 
34,935

Total costs and expenses
291,967

 
343,983

Earnings of non-controlled entities
2,051

 
466

Operating profit
142,505

 
275,089

Interest expense
31,723

 
36,416

Interest income
(22
)
 
(391
)
Interest capitalized
(3,451
)
 
(5,310
)
Debt placement fee amortization expense
540

 
599

Income before provision for income taxes
113,715

 
243,775

Provision for income taxes
748

 
1,221

Net income
$
112,967

 
$
242,554

Basic and diluted net income per limited partner unit
$
0.50

 
$
1.07

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation
226,705

 
227,141












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 March 31,
 
2013
 
2014
Net income
$
112,967

 
$
242,554

Other comprehensive income:
 
 

Derivative activity:
 
 
 
Net loss on cash flow hedges(1)
(4,560
)
 
(3,613
)
Reclassification of net loss (gain) on cash flow hedges to income(1)
4,367

 
(26
)
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
 
 
 
Amortization of actuarial loss(2)
1,330

 
824

Amortization of prior service credit(2)
(851
)
 
(895
)
Total other comprehensive income (loss)
286

 
(3,710
)
Comprehensive income
$
113,253

 
$
238,844

(1) See Note 8–Derivative Financial Instruments for details of the amount of gain/loss recognized in accumulated other comprehensive loss ("AOCL") on derivatives and the amount of gain/loss reclassified from AOCL into income.
(2) These AOCL components are included in the computation of net periodic pension cost (see Note 6–Employee Benefit Plans).



























See notes to consolidated financial statements.

3
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
 
December 31,
2013
 
March 31,
2014
ASSETS
 
 
(Unaudited)
Current assets:
 
 
 
Cash and cash equivalents
$
25,235

 
$
196,630

Trade accounts receivable
116,295

 
101,292

Other accounts receivable
6,462

 
12,202

Inventory
187,224

 
210,235

Energy commodity derivatives deposits
14,782

 
12,714

Other current assets
46,735

 
33,969

Total current assets
396,733

 
567,042

Property, plant and equipment
4,986,750

 
5,017,786

Less: Accumulated depreciation
1,070,492

 
1,104,191

Net property, plant and equipment
3,916,258

 
3,913,595

Investments in non-controlled entities
360,852

 
487,295

Long-term receivables
2,730

 
30,365

Goodwill
53,260

 
53,260

Other intangibles (less accumulated amortization of $8,809 and $9,489 at December 31, 2013 and March 31, 2014, respectively)
7,290

 
6,610

Debt placement costs (less accumulated amortization of $9,113 and $9,712 at December 31, 2013 and March 31, 2014, respectively)
17,505

 
19,554

Tank bottom inventory
61,915

 
62,635

Other noncurrent assets
4,269

 
3,426

Total assets
$
4,820,812

 
$
5,143,782

LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
76,326

 
$
73,417

Accrued payroll and benefits
42,243

 
27,691

Accrued interest payable
44,935

 
50,129

Accrued taxes other than income
38,574

 
31,095

Environmental liabilities
12,147

 
13,631

Deferred revenue
63,164

 
64,612

Accrued product purchases
63,033

 
43,055

Energy commodity derivatives contracts, net
6,737

 
3,421

Current portion of long-term debt
249,971

 
249,988

Other current liabilities
41,146

 
47,111

Total current liabilities
638,276

 
604,150

Long-term debt
2,435,316

 
2,691,288

Long-term pension and benefits
51,637

 
55,736

Other noncurrent liabilities
21,802

 
19,660

Environmental liabilities
26,339

 
23,462

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partner unitholders (226,679 units and 227,068 units outstanding at December 31, 2013 and March 31, 2014, respectively)
1,666,946

 
1,772,700

Accumulated other comprehensive loss
(19,504
)
 
(23,214
)
Total partners’ capital
1,647,442

 
1,749,486

Total liabilities and partners' capital
$
4,820,812

 
$
5,143,782



See notes to consolidated financial statements.

4
Table of Contents


MAGELLAN MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
 
Three Months Ended
 
March 31,
 
2013
 
2014
Operating Activities:
 
 
 
Net income
$
112,967

 
$
242,554

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
36,332

 
37,511

Debt placement fee amortization expense
540

 
599

Loss on sale, retirement and impairment of assets
1,791

 
1,205

Earnings of non-controlled entities
(2,051
)
 
(466
)
Distributions from investments in non-controlled entities
676

 
384

Equity-based incentive compensation expense
4,856

 
5,088

Changes in employee benefit plan assets and benefit obligations
479

 
(71
)
Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable and other accounts receivable
(16,833
)
 
15,022

Inventory
16,736

 
(23,011
)
Energy commodity derivatives contracts, net of derivatives deposits
1,311

 
(529
)
Accounts payable
11,310

 
2,960

Accrued payroll and benefits
(10,713
)
 
(14,552
)
Accrued interest payable
(4,653
)
 
5,194

Accrued taxes other than income
(5,798
)
 
(7,479
)
Accrued product purchases
6,273

 
(19,978
)
Deferred revenue
10,647

 
1,448

Current and noncurrent environmental liabilities
(1,469
)
 
(1,393
)
Other current and noncurrent assets and liabilities
4,540

 
25,588

Net cash provided by operating activities
166,941

 
270,074

Investing Activities:
 
 
 
Property, plant and equipment:
 
 
 
Additions to property, plant and equipment
(89,947
)
 
(70,295
)
Proceeds from sale and disposition of assets
25

 
42

Increase in accounts payable related to capital expenditures
(11,863
)
 
(5,219
)
Investments in non-controlled entities
(47,020
)
 
(127,698
)
Distributions in excess of earnings of non-controlled entities
188

 
687

Net cash used by investing activities
(148,617
)
 
(202,483
)
Financing Activities:
 
 
 
Distributions paid
(113,340
)
 
(132,835
)
Borrowings under long-term notes
—

 
257,713

Debt placement costs
—

 
(2,648
)
Net payment on financial derivatives
—

 
(3,613
)
Settlement of tax withholdings on long-term incentive compensation
(12,259
)
 
(14,813
)
Net cash provided (used) by financing activities
(125,599
)
 
103,804

Change in cash and cash equivalents
(107,275
)
 
171,395

Cash and cash equivalents at beginning of period
328,278

 
25,235

Cash and cash equivalents at end of period
$
221,003

 
$
196,630

Supplemental non-cash investing and financing activities:
 
 
 
Issuance of limited partner units in settlement of equity-based incentive plan awards
$
6,404

 
$
7,315






See notes to consolidated financial statements.

5
Table of Contents




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


1.
Organization, Description of Business and Basis of Presentation
Organization
Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P. together with its subsidiaries. We are a Delaware limited partnership and our limited partner units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly-owned Delaware limited liability company, serves as our general partner.

Description of Business

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil.  As of March 31, 2014, our asset portfolio including the assets of our joint ventures consisted of:

•
our refined products segment, including our 9,500-mile refined products pipeline system with 54 terminals as well as 27 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;

•
our crude oil segment, comprised of approximately 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million barrels, of which 12 million is 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 27 million barrels.

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

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

•
blendstocks, which 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, which 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, which are used as feedstocks by refineries and petrochemical facilities;

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

•
ammonia, which 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
Table of Contents




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, 2013 which is derived from our audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2014, the results of operations for the three months ended March 31, 2013 and 2014 and cash flows for the three months ended March 31, 2013 and 2014. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year ending December 31, 2014.
Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.


2.
Product Sales Revenue
The amounts reported as product sales revenue on our consolidated statements of income include revenue from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange ("NYMEX") contracts. We use NYMEX contracts to hedge against changes in the price of refined products we expect to sell from our business activities where we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment and we designate and account for these as either cash flow or fair value hedges. The effective portion of the fair value changes in contracts designated as cash flow hedges are recognized as adjustments to product sales when the hedged product is physically sold. Ineffectiveness in the contracts designated as cash flow hedges is recognized as an adjustment to product sales in the period the ineffectiveness occurs. We account for NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges, with the period changes in fair value recognized as product sales, except for those agreements that economically hedge the inventories associated with our pipeline system overages (the period changes in the fair value of these agreements are charged to operating expense). See Note 8 – Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.
For the three months ended March 31, 2013 and 2014, product sales revenue included the following (in thousands): 
 
Three Months Ended March 31,
 
2013
 
2014
Physical sale of petroleum products
$
207,880

 
$
293,240

NYMEX contract adjustments:
 
 
 
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment and the effective portion of gains and losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our butane blending and fractionation activities(1) 
(6,158
)
 
2,823

Other
(11
)
 
—

Total NYMEX contract adjustments
(6,169
)
 
2,823

Total product sales revenue
$
201,711

 
$
296,063

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

7
Table of Contents




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





3.
Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenue from affiliates and external customers, operating expenses, cost of product sales and earnings of non-controlled entities. Transactions between our business segments are conducted and recorded on the same basis as transactions with third-party entities.
We believe that investors benefit from having access to the same financial measures used by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles ("GAAP") measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables below. Operating profit includes depreciation and amortization expense and general and administrative ("G&A") expenses that management does not consider when evaluating the core profitability of our separate operating segments.


 
Three Months Ended March 31, 2013
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
165,359

 
$
23,228

 
$
38,684

 
$
—

 
$
227,271

Product sales revenue
199,415

 
—

 
2,296

 
—

 
201,711

Affiliate management fee revenue
—

 
3,159

 
280

 
—

 
3,439

Total revenue
364,774

 
26,387

 
41,260

 
—

 
432,421

Operating expenses
46,281

 
5,107

 
14,553

 
(760
)
 
65,181

Cost of product sales
158,298

 
—

 
2,100

 
—

 
160,398

Earnings of non-controlled entities
—

 
(1,375
)
 
(676
)
 
—

 
(2,051
)
Operating margin
160,195

 
22,655

 
25,283

 
760

 
208,893

Depreciation and amortization expense
21,353

 
7,469

 
6,750

 
760

 
36,332

G&A expenses
21,202

 
4,127

 
4,727

 
—

 
30,056

Operating profit
$
117,640

 
$
11,059

 
$
13,806

 
$
—

 
$
142,505


 

8
Table of Contents




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



 
Three Months Ended March 31, 2014
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
210,236

 
$
67,903

 
$
39,498

 
$
—

 
$
317,637

Product sales revenue
293,710

 
—

 
2,353

 
—

 
296,063

Affiliate management fee revenue
—

 
4,595

 
311

 
—

 
4,906

Total revenue
503,946

 
72,498

 
42,162

 
—

 
618,606

Operating expenses
51,157

 
9,058

 
14,086

 
(804
)
 
73,497

Cost of product sales
197,756

 
—

 
284

 
—

 
198,040

Losses (earnings) of non-controlled entities
—

 
180

 
(646
)
 
—

 
(466
)
Operating margin
255,033

 
63,260

 
28,438

 
804

 
347,535

Depreciation and amortization expense
23,172

 
6,463

 
7,072

 
804

 
37,511

G&A expenses
23,019

 
5,994

 
5,922

 
—

 
34,935

Operating profit
$
208,842

 
$
50,803

 
$
15,444

 
$
—

 
$
275,089





4.
Investments in Non-Controlled Entities

We own a 50% interest in Texas Frontera, LLC ("Texas Frontera"), which owns approximately one million barrels of refined products storage at our Galena Park, Texas terminal. The storage capacity owned by this joint venture is leased to an affiliate of Texas Frontera under a long-term lease agreement. We receive management fees from Texas Frontera, which we report as affiliate management fee revenue on our consolidated statements of income.

We own a 50% interest in Osage Pipe Line Company, LLC ("Osage"), which owns a 135-mile crude oil pipeline in Oklahoma and Kansas that we operate. We receive management fees from Osage, which we report as affiliate management fee revenue on our consolidated statements of income. Our initial investment in Osage included an excess net investment amount of $21.7 million. Excess investment is the amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment. The unamortized excess net investment amount at March 31, 2014 was $15.0 million.

We own a 50% interest in Double Eagle Pipeline LLC ("Double Eagle") which transports condensate from the Eagle Ford shale formation in South Texas via a 195-mile pipeline to our terminal in Corpus Christi, Texas. Double Eagle is operated by an affiliate of the other 50% member of Double Eagle. We receive throughput revenue from Double Eagle that is included in our transportation and terminals revenue on our consolidated statements of income. For the three months ended March 31, 2014, we received throughput revenue of $0.5 million. We recorded a $0.2 million and $0.3 million trade accounts receivable from Double Eagle at December 31, 2013 and March 31, 2014, respectively.

We own a 50% interest in BridgeTex Pipeline Company, LLC ("BridgeTex"), which is in the process of constructing a 450-mile pipeline with related infrastructure to transport crude oil from Colorado City, Texas for delivery to Houston and Texas City, Texas refineries. This pipeline is expected to begin service in mid-2014. We receive construction management fees from BridgeTex, which we report as affiliate management fee revenue on our consolidated statements of income.


9
Table of Contents




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



During 2013, we received $4.8 million from BridgeTex as a deposit for the purchase of emission reduction credits, which, pending governmental approval, we expect to transfer to BridgeTex during the second quarter of 2014. Also in 2013, we received $1.4 million from BridgeTex for the purchase of easement rights from us, of which $0.7 million was recorded as a reduction of operating expense and $0.7 million was recorded as an adjustment to our investment in BridgeTex, which will be amortized as a reduction of operating expense over the weighted average depreciable lives of the BridgeTex assets.

The operating results from Texas Frontera are included in our marine storage segment and the operating results from Osage, Double Eagle and BridgeTex are included in our crude oil segment as earnings of non-controlled entities.

A summary of our investments in non-controlled entities follows (in thousands):
 
 
BridgeTex
 
All Others
 
Consolidated
Investment at December 31, 2013
 
$
246,875

 
$
113,977

 
$
360,852

Additional investment
 
126,748

 
950

 
127,698

Other adjustment to investment
 
—

 
(650
)
 
(650
)
Earnings (losses) of non-controlled entities:
 
 
 

 
 
Proportionate share of earnings (loss)
 
(20
)
 
674

 
654

Amortization of excess investment and capitalized interest
 
—

 
(188
)
 
(188
)
Earnings (losses) of non-controlled entities
 
(20
)
 
486

 
466

Less:
 
 
 
 
 
 
Distributions of earnings from investments in non-controlled entities
 
—

 
384

 
384

Distributions in excess of earnings of non-controlled entities
 
—

 
687

 
687

Investment at March 31, 2014
 
$
373,603

 
$
113,692

 
$
487,295

 
 
 
 
 
 
 

Summarized financial information of our non-controlled entities as of and for the three months ended March 31, 2014 follows (in thousands):

10
Table of Contents




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



 
 
BridgeTex
 
All Others
 
Consolidated
Current assets
 
$
78,654

 
$
19,204

 
$
97,858

Noncurrent assets
 
634,188

 
176,514

 
810,702

Total assets
 
$
712,842

 
$
195,718

 
$
908,560

Current liabilities
 
101,712

 
3,224

 
104,936

Noncurrent liabilities
 
—

 
96

 
96

Total liabilities
 
$
101,712

 
$
3,320

 
$
105,032

Equity
 
$
611,130

 
$
192,398

 
$
803,528

 
 
 
 
 
 
 
Revenue
 
$
—

 
$
6,755

 
$
6,755

Net income (loss)
 
$
(40
)
 
$
1,347

 
$
1,307


5.
Inventory

Inventory at December 31, 2013 and March 31, 2014 was as follows (in thousands):
 
 
December 31, 2013
 
March 31,
2014
Refined products
$
77,144

 
$
76,229

Liquefied petroleum gases
23,476

 
33,398

Transmix
72,156

 
79,127

Crude oil
7,188

 
15,852

Additives
7,260

 
5,629

Total inventory
$
187,224

 
$
210,235



6.
Employee Benefit Plans
We sponsor two union pension plans for certain union employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension and postretirement benefit plans for the three months ended March 31, 2013 and 2014 (in thousands):

11
Table of Contents




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



 
 
Three Months Ended
 
Three Months Ended
 
March 31, 2013
 
March 31, 2014
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
3,576

 
$
77

 
$
3,352

 
$
67

Interest cost
1,350

 
115

 
1,659

 
114

Expected return on plan assets
(1,470
)
 
—

 
(1,697
)
 
—

Amortization of prior service cost (credit)(1)
77

 
(928
)
 
33

 
(928
)
Amortization of actuarial loss(1)
1,022

 
308

 
629

 
195

Net periodic benefit cost (credit)
$
4,555

 
$
(428
)
 
$
3,976

 
$
(552
)
 
(1) These amounts are included in our Consolidated Statements of Comprehensive Income and Consolidated Statements of Cash Flows as changes in employee benefit plan assets and benefit obligations.


7.
Debt
Consolidated debt at December 31, 2013 and March 31, 2014 was as follows (in thousands, except as otherwise noted):
 
 
 
 
 
 
 
December 31, 2013
 
March 31,
2014
 
Weighted-Average
Interest Rate for Three Months Ending
March 31, 2014 (1)
Revolving credit facility
 
$
—

 
$
—

 
—%
$250.0 million of 6.45% Notes due 2014
 
249,971

 
249,988

 
6.3%
$250.0 million of 5.65% Notes due 2016
 
251,183

 
251,076

 
5.7%
$250.0 million of 6.40% Notes due 2018
 
259,346

 
258,829

 
5.4%
$550.0 million of 6.55% Notes due 2019
 
571,515

 
570,613

 
5.7%
$550.0 million of 4.25% Notes due 2021
 
557,213

 
556,988

 
4.0%
$250.0 million of 6.40% Notes due 2037
 
248,998

 
249,003

 
6.4%
$250.0 million of 4.20% Notes due 2042
 
248,377

 
248,384

 
4.2%
$550.0 million of 5.15% Notes due 2043
 
298,684

 
556,395

 
5.2%
Total debt
 
$
2,685,287

 
$
2,941,276

 
5.2%
 
 
 
 
 
 
 

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

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

The face value of our debt at December 31, 2013 and March 31, 2014 was $2.7 billion and $2.9 billion, respectively. The difference between the face value and carrying value of the 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.


12
Table of Contents




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



2014 Debt Offering

In March 2014, we issued an additional $250.0 million of our 5.15% notes due October 15, 2043 in an underwritten public offering. The notes were issued at 103.1% of par. We used the net proceeds from this offering of approximately $255.1 million, after underwriting discounts and offering expenses of $2.6 million, to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital.

Other Debt

6.45% Notes due 2014. The maturity date of our $250.0 million of 6.45% notes is June 1, 2014. The carrying amount of these notes was recorded as current portion of long-term debt on our consolidated balance sheets as of December 31, 2013 and March 31, 2014.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in November 2018, is $1.0 billion. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at March 31, 2014. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of March 31, 2014, there were no borrowings outstanding under this facility and $5.6 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets, but decrease our borrowing capacity under the facility.


8.
Derivative Financial Instruments

Interest Rate Derivatives

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

In first quarter 2014, we entered into $200.0 million of interest rate swap agreements to hedge against the variability of future interest payments on an anticipated debt issuance. We accounted for these agreements as cash flow hedges. When we issued the $250.0 million of 5.15% notes due 2043 later in the first quarter of 2014, we settled the associated interest rate swap agreements for a loss of $3.6 million. The loss was recorded to other comprehensive income and will be recognized into earnings as an adjustment to our periodic interest expense accruals over the life of the associated notes. This loss was also reported as net payment on financial derivatives in the financing activities of our consolidated statements of cash flows.

During 2012, we terminated and settled certain interest rate swap agreements and realized a gain of $11.0 million, which was recorded to other comprehensive income. The purpose of these swaps was to hedge against the variability of future interest payments on the refinancing of our debt that matures in 2014. If management were to determine that it was probable this forecasted transaction would not occur, the $11.0 million gain we have recorded to other comprehensive income would be reclassified into earnings.


13
Table of Contents




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



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 forward purchase and sale contracts, NYMEX contracts and butane futures agreements to help manage price changes, which has the effect of locking in most of the product margin realized from our butane blending activities that we choose to hedge.

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. As of March 31, 2014, we had commitments under these forward purchase and sale contracts as follows (in millions):
 
Notional Value
 
Barrels
Forward purchase contracts
$
73.4


1.3
Forward sale contracts
$
25.2


0.2

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

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

Period changes in the fair value of NYMEX agreements that are considered economic hedges, the effective portion of changes in the fair value of cash flow hedges that are reclassified from accumulated other comprehensive income/loss and any ineffectiveness associated with hedges related to our commodity activities are recognized currently in earnings as adjustments to product sales.

We also use exchange-traded butane futures agreements, 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.

Additionally, we currently hold petroleum product inventories that we obtained from overages on our pipeline systems. We use NYMEX contracts that are not designated as hedges for accounting purposes to help manage price

14
Table of Contents




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



changes related to these overage inventory barrels. Period changes in the fair value of these agreements are recognized currently in earnings as adjustments to operating expense.

As outlined in the table below, our open NYMEX contracts and butane futures agreements at March 31, 2014 were as follows:
Type of Contract/Accounting Methodology
 
Product Represented by the Contract and Associated Barrels
 
Maturity Dates
NYMEX - Fair Value Hedges
 
0.7 million barrels of crude oil
 
Between April 2014 and November 2016
NYMEX - Economic Hedges
 
2.2 million barrels of refined products and crude oil
 
Between April 2014 and January 2015
Butane Futures Agreements - Economic Hedges
 
0.1 million barrels of butane
 
Between April 2014 and January 2015

Energy Commodity Derivatives Contracts and Deposits Offsets

At March 31, 2014, we had made margin deposits of $12.7 million related to our NYMEX contracts, which were recorded as a current asset under energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the combined fair values of our open NYMEX contracts and our open butane futures agreements against our margin deposits under a master netting arrangement; however, we have elected to disclose the combined fair values of our open NYMEX and butane futures agreements 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 and butane futures 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, 2013 and March 31, 2014 (in thousands):

 
 
December 31, 2013
Description
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts of Assets Offset in the Consolidated Balance Sheet
 
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet(1)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
 
Net Asset Amount
Energy commodity derivatives
 
$
(7,167
)
 
$
2,665

 
$
(4,502
)
 
$
14,782

 
$
10,280

 
 
 
 
 
 
 
 
 
 
 

 
 
March 31, 2014
Description
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts of Assets Offset in the Consolidated Balance Sheet
 
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet(2)
 
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
 
Net Asset Amount
Energy commodity derivatives
 
$
(3,439
)
 
$
1,534

 
$
(1,905
)
 
$
12,714

 
$
10,809

 
 
 
 
 
 
 
 
 
 
 
(1) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $6,737 and noncurrent assets of $2,235.
(2) Net amount includes energy commodity derivative contracts classified as current liabilities, net, of $3,421 and noncurrent assets of $1,516.


15
Table of Contents




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



Impact of Derivatives on Income Statement, Balance Sheet, Cash Flows and AOCL

The changes in derivative activity included in AOCL for the three months ended March 31, 2013 and 2014 were as follows (in thousands):
 
 
Three Months Ended March 31,
Derivative Gains (Losses) Included in AOCL
2013
 
2014
Beginning balance
$
14,126

 
$
13,627

Net loss on cash flow hedges
(4,560
)
 
(3,613
)
Reclassification of net loss (gain) on cash flow hedges to income
4,367

 
(26
)
Ending balance
$
13,933

 
$
9,988


During 2014, we had open NYMEX contracts on 0.7 million barrels of crude oil that were designated as fair value hedges. These agreements hedge against the change in value of our crude oil linefill and tank bottom inventories. Because there was no ineffectiveness recognized on these hedges, the cumulative losses of $9.6 million from the agreements as of March 31, 2014 were fully offset by a cumulative increase of $9.6 million to tank bottom inventory and a cumulative increase of less than $0.1 million to our crude oil linefill, which is reported in other current assets; therefore, there was no net impact from these agreements on our results of operations.
The following tables provide a summary of the effect on our consolidated statements of income for the three months ended March 31, 2013 and 2014 of the effective portion of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2013
Derivative Instrument
 
Amount of Loss Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate contracts
 
 
$
—

 
 
Interest expense
 
 
$
41

 
NYMEX commodity contracts
 
 
(4,560
)
 
 
Product sales revenue
 
 
(4,408
)
 
Total cash flow hedges
 
 
$
(4,560
)
 
 
Total
 
 
$
(4,367
)
 
 
 
Three Months Ended March 31, 2014
Derivative Instrument
 
Amount of Loss Recognized in AOCL on Derivative
 
Location of Gain Reclassified from AOCL into Income
 
Amount of Gain Reclassified from AOCL into Income
Interest rate contracts
 
 
$
(3,613
)
 
 
Interest expense
 
 
$
26

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2013 or 2014. As of March 31, 2014, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.4 million.

16
Table of Contents




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



The following table provides a summary of the effect on our consolidated statements of income for the three months ended March 31, 2013 and 2014 of derivatives accounted for under ASC 815; Derivatives and Hedging—Overall, that were not designated as hedging instruments (in thousands):
 
 
 
 
 
Amount of Gain (Loss) Recognized on Derivative
 
 
 
 
Three Months Ended
Derivative Instrument
 
Location of Gain (Loss)
Recognized on Derivative
 
March 31, 2013
 
March 31, 2014
NYMEX commodity contracts
 
Product sales revenue
 
$
(1,761
)
 
$
2,823

NYMEX commodity contracts
 
Operating expenses
 
(1,886
)
 
365

Butane futures agreements
 
Cost of product sales
 
(781
)
 
144

 
 
Total
 
$
(4,428
)
 
$
3,332

The impact of the derivatives in the above table was reflected as cash from operations on our consolidated statements of cash flows.
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, 2013 and March 31, 2014 (in thousands):
 
 
December 31, 2013
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
—

 
Energy commodity derivatives contracts, net
 
$
146

NYMEX commodity contracts
 
Other noncurrent assets
 
2,235

 
Other noncurrent liabilities
 
—

 
 
Total
 
$
2,235

 
Total
 
$
146

 
 
 
March 31, 2014
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
—

 
Energy commodity derivatives contracts, net
 
$
170

NYMEX commodity contracts
 
Other noncurrent assets
 
1,516

 
Other noncurrent liabilities
 
—

 
 
Total
 
$
1,516

 
Total
 
$
170

 

17
Table of Contents




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



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, 2013 and March 31, 2014 (in thousands):

 
 
December 31, 2013
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
48

 
Energy commodity derivatives contracts, net
 
$
7,021

Butane futures agreements
 
Energy commodity derivatives contracts, net
 
382

 
Energy commodity derivatives contracts, net
 
—

 
 
Total
 
$
430

 
Total
 
$
7,021

 
 
 
 
 
 
 
 
 
 
 
March 31, 2014
 
 
Asset Derivatives
 
Liability Derivatives
Derivative Instrument
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
NYMEX commodity contracts
 
Energy commodity derivatives contracts, net
 
$
—

 
Energy commodity derivatives contracts, net
 
$
3,217

Butane futures agreements
 
Energy commodity derivatives contracts, net
 
18

 
Energy commodity derivatives contracts, net
 
52

 
 
Total
 
$
18

 
Total
 
$
3,269

 

9.
Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $38.5 million and $37.1 million at December 31, 2013 and March 31, 2014, respectively. We have classified environmental liabilities as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be paid over the next 10 years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expenses for the three months ended March 31, 2013 and 2014 were $0.7 million and $0.3 million, respectively.

Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 2013 were $4.8 million, of which $2.1 million and $2.7 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet. Receivables from insurance carriers and other third parties related to environmental matters at March 31, 2014 were $4.7 million, of which $2.1 million and $2.6 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheet.
Other

In January 2014, we placed into operation a 36-mile pipeline we constructed in Texas and New Mexico at a cost of approximately $35.0 million.  We entered into a long-term throughput and deficiency agreement with a

18
Table of Contents




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



customer on this pipeline, which contains minimum volume/payment commitments. This agreement is being accounted for as a direct financing lease under which, in addition to transportation revenue, we will receive capital recovery payments of approximately $19.3 million over the next 41 months.
We are a party to various other claims, legal actions and complaints arising in the ordinary course of business, including without limitation those disclosed in Item 1, Legal Proceedings of Part II of this report on Form 10-Q. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our results of operations, financial position or cash flows.

10.
Long-Term Incentive Plan
We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 9.4 million of our limited partner units. The estimated units available under the LTIP at March 31, 2014 total 1.8 million. The compensation committee of our general partner’s board of directors administers our LTIP.
 
Our equity-based incentive compensation expense was as follows (in thousands):
 
Three Months Ended
 
March 31, 2013
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
2010 awards
$
121

 
$
73

 
$
194

2011 awards
983

 
1,147

 
2,130

2012 awards
881

 
611

 
1,492

2013 awards
726

 
189

 
915

Retention awards
125

 
—

 
125

Total
$
2,836

 
$
2,020

 
$
4,856

 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
4,485

Operating expense
 
 
 
 
371

Total
 
 
 
 
$
4,856

 

19
Table of Contents




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



 
Three Months Ended
 
March 31, 2014
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
2012 awards
1,022

 
924

 
1,946

2013 awards
1,181

 
548

 
1,729

2014 awards
904

 
—

 
904

Retention awards
509

 
—

 
509

Total
$
3,616

 
$
1,472

 
$
5,088

 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
4,974

Operating expense
 
 
 
 
114

Total
 
 
 
 
$
5,088


On February 3, 2014, 178,184 phantom unit awards were issued pursuant to our long-term incentive plan. These grants included both performance-based and retention awards and have a three-year vesting period that will end on December 31, 2016.

On February 3, 2014, we issued 388,819 limited partner units, of which 387,216 were issued to settle unit award grants to certain employees that vested on December 31, 2013 and 1,603 were issued to settle the equity-based retainer paid to a member of our general partner's board of directors.

11.
Distributions
Distributions we paid during 2013 and 2014 were as follows (in thousands, except per unit amounts):
 
Payment Date
 
Per Unit Cash
Distribution
Amount
 
Total Cash Distribution to Limited Partners
02/14/2013
 
 
$
0.5000

 
 
 
$
113,340

 
05/15/2013
 
 
0.5075

 
 
 
115,040

 
08/14/2013
 
 
0.5325

 
 
 
120,707

 
11/14/2013
 
 
0.5575

 
 
 
126,374

 
Total
 
 
$
2.0975

 
 
 
$
475,461

 
 
 
 
 
 
 
 
 
 
02/14/2014
 
 
$
0.5850

 
 
 
$
132,835

 
5/15/2014(1)
 
 
0.6125

 
 
 
139,079

 
Total
 
 
$
1.1975

 
 
 
$
271,914

 
 
 
 
 
 
 
 
 
 
(1) Our general partner's board of directors declared this cash distribution on April 24, 2014 to be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014.
 


20
Table of Contents




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



12.
Fair Value

Fair Value Methods and Assumptions - Financial Assets and Liabilities

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

•
Cash and cash equivalents. Cash equivalents include money market and mutual fund accounts and commercial paper. The carrying amounts reported on our consolidated balance sheets approximate fair value due to the short-term maturity or variable rates of these instruments.

•
Energy commodity derivatives deposits. This asset represents short-term deposits we have made associated with our energy commodity derivatives contracts. The carrying amount reported on our consolidated balance sheets approximates fair value as the deposits change daily in relation to the associated contracts and are held in separate accounts.

•
Energy commodity derivatives contracts. These include NYMEX futures and exchange-traded butane 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.

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

•
Debt. The fair value of our publicly traded notes was based on the prices of those notes at December 31, 2013 and March 31, 2014; 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 approximates fair value due to the variable rates of that instrument.

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, 2013 and March 31, 2014, based on the three levels established by ASC 820; Fair Value Measurements and Disclosures. The carrying values of cash and cash equivalents (classified as Level 1) and energy commodity derivatives deposits approximate fair value because of the short-term nature or variable rates of these instruments; therefore, these items are not presented in the following tables (in thousands).

21
Table of Contents




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



 
 
As of December 31, 2013
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 (liabilities)
 
$
(4,502
)
 
$
(4,502
)
 
$
(4,502
)
 
$
—

 
$
—

Long-term receivables
 
$
2,730

 
$
2,658

 
$
—

 
$
—

 
$
2,658

Debt
 
$
(2,685,287
)
 
$
(2,815,210
)
 
$
—

 
$
(2,815,210
)
 
$
—


 
 
As of March 31, 2014
Assets (Liabilities)
 
 
 
 
 
Fair Value Measurements using:
 
Carrying Amount
 
Fair Value
 
Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Energy commodity derivatives contracts (liabilities)
 
$
(1,905
)
 
$
(1,905
)
 
$
(1,905
)
 
$
—

 
$
—

Long-term receivables
 
$
30,365

 
$
30,992

 
$
—

 
$
—

 
$
30,992

Debt
 
$
(2,941,276
)
 
$
(3,186,457
)
 
$
—

 
$
(3,186,457
)
 
$
—



13.
Related Party Transactions

Barry R. Pearl is an independent member of our general partner's board of directors and is also a director of Targa Resources Partners, L.P. ("Targa"). In the normal course of business, we purchase butane from subsidiaries of Targa. For the three months ended March 31, 2013 and 2014, we made purchases of butane from subsidiaries of Targa of $14.2 million and $12.2 million, respectively. These purchases were made on the same terms as comparable third-party transactions. There were no amounts payable to Targa at December 31, 2013 or March 31, 2014, respectively.

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


22
Table of Contents




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




14.
Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

In April 2014, we initiated a commercial paper program pursuant to which we may issue short-term, unsecured commercial paper notes of up to $1.0 billion. Borrowings under the program are backed by and may not exceed the available capacity on our revolving credit facility. We expect to use the net proceeds of issuances of the notes for general partnership purposes. We currently have no notes issued under this program.

In April 2014, our general partner's board of directors declared a quarterly distribution of $0.6125 per unit to be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. The total cash distributions expected to be paid are $139.1 million.

23
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 March 31, 2014, our asset portfolio including the assets of our joint ventures consisted of:
•
our refined products segment, including our 9,500-mile refined products pipeline system with 54 terminals as well as 27 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;

•
our crude oil segment, comprised of approximately 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million barrels, of which 12 million is 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 27 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, 2013.

Recent Developments

Condensate Splitter. In March 2014, we announced our plans to construct a condensate splitter at our terminal in Corpus Christi, Texas under a fee-based, take-or-pay agreement with a third-party customer. 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 our customer's nearby facility. The splitter will be capable of processing 50,000 barrels per day of condensate. We expect the condensate splitter and related infrastructure to cost approximately $250 million and to be operational during the second half of 2016, subject to receipt of necessary permits and authorizations.

Little Rock Pipeline. In May 2014, we announced plans to transport refined products from our Ft. Smith, Arkansas terminal to Little Rock, Arkansas. We have entered into an agreement with a third party to utilize an existing pipeline for a portion of the route, which we will extend to our Ft. Smith terminal and to the Little Rock market with approximately 50 miles of newly-constructed pipeline. We further plan to make enhancements to our pipeline system to accommodate additional volumes. The Little Rock pipeline project is expected to cost approximately $150 million and be operational in early 2016, subject to receipt of regulatory and other approvals.

Commercial Paper Program. In April 2014, we initiated a commercial paper program pursuant to which we may issue short-term, unsecured commercial paper notes of up to $1.0 billion. Borrowings under the program are backed by and may not exceed available capacity on our revolving credit facility. We expect to use the net proceeds of issuances of the notes for general partnership purposes. We currently have no notes issued under this program.

Cash Distribution. In April 2014, the board of directors of our general partner declared a quarterly cash distribution of $0.6125 per unit for the period of January 1, 2014 through March 31, 2014. This quarterly cash distribution will be paid on May 15, 2014 to unitholders of record on May 8, 2014. Total distributions expected to be paid under this declaration are approximately $139.1 million.


24
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 table, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in this table. Product margin is a non-GAAP measure; however, its components of product sales and 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.
 

25
Table of Contents



Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2014
 
 
Three Months Ended March 31,
 
Variance
Favorable  (Unfavorable)
 
2013
 
2014
 
$ Change
 
% Change
Financial Highlights ($ in millions, except operating statistics)
 
 
 
 
 
 
 
Transportation and terminals revenue:
 
 
 
 
 
 
 
Refined products
$
165.4

 
$
210.2

 
$
44.8

 
27
Crude oil
23.2

 
67.9

 
44.7

 
193
Marine storage
38.7

 
39.5

 
0.8

 
2
Total transportation and terminals revenue
227.3

 
317.6

 
90.3

 
40
Affiliate management fee revenue
3.4

 
4.9

 
1.5

 
44
Operating expenses:
 
 
 
 
 
 
 
Refined products
46.3

 
51.2

 
(4.9
)
 
(11)
Crude oil
5.1

 
9.1

 
(4.0
)
 
(78)
Marine storage
14.6

 
14.1

 
0.5

 
3
Intersegment eliminations
(0.8
)
 
(0.8
)
 
—

 
—
Total operating expenses
65.2

 
73.6

 
(8.4
)
 
(13)
Product margin:
 
 
 
 
 
 
 
Product sales revenue
201.7

 
296.1

 
94.4

 
47
Cost of product sales
160.4

 
198.0

 
(37.6
)
 
(23)
Product margin(1)
41.3

 
98.1

 
56.8

 
138
Earnings of non-controlled entities
2.1

 
0.5

 
(1.6
)
 
(76)
Operating margin
208.9

 
347.5

 
138.6

 
66
Depreciation and amortization expense
36.3

 
37.5

 
(1.2
)
 
(3)
G&A expense
30.1

 
34.9

 
(4.8
)
 
(16)
Operating profit
142.5

 
275.1

 
132.6

 
93
Interest expense (net of interest income and interest capitalized)
28.3

 
30.7

 
(2.4
)
 
(8)
Debt placement fee amortization expense
0.5

 
0.6

 
(0.1
)
 
(20)
Income before provision for income taxes
113.7

 
243.8

 
130.1

 
114
Provision for income taxes
0.7

 
1.2

 
(0.5
)
 
(71)
Net income
$
113.0

 
$
242.6

 
$
129.6

 
115
Operating Statistics:
 
 
 
 
 
 
 
Refined products:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
1.136

 
$
1.356

 
 
 
 
Volume shipped (million barrels):
 
 
 
 
 
 
 
Gasoline
53.6

 
59.8

 
 
 
 
Distillates
33.8

 
37.5

 
 
 
 
Aviation fuel
4.5

 
5.0

 
 
 
 
Liquefied petroleum gases
1.1

 
1.5

 
 
 
 
Total volume shipped
93.0

 
103.8

 
 
 
 
Crude oil:
 
 
 
 
 
 
 
Transportation revenue per barrel shipped
$
0.313

 
$
1.113

 
 
 
 
Volume shipped (million barrels)
15.9

 
41.8

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

 
12.1

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

 
22.7

 
 
 
 

(1) Product margin does not include depreciation or amortization expense.




26
Table of Contents


Transportation and terminals revenue increased $90.3 million resulting from:
•
an increase in refined products revenue of $44.8 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products revenue increased $34.7 million primarily due to a 3% increase in transportation volumes and higher rates. Shipments were higher primarily due to increased demand for gasoline and distillates. The average rate per barrel was impacted by the mid-year 2013 tariff rate increase and more long-haul shipments (which are at a higher rate);
•
an increase in crude oil revenue of $44.7 million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately 85% of the increase. Our Longhorn pipeline began delivering crude oil in mid-April 2013 and averaged approximately 200,000 barrels per day during first quarter 2014; and
•
an increase in marine storage revenue of $0.8 million primarily due to new storage placed into service at our Galena Park, Texas terminal since early 2013.
Affiliate management fee revenue increased $1.5 million due to higher construction management fees related to BridgeTex Pipeline Company, LLC ("BridgeTex"). The construction management fees we receive are designed to reimburse us for our costs of providing services to BridgeTex during its construction.
Operating expenses increased by $8.4 million resulting from:
•
an increase in refined products expenses of $4.9 million primarily due to $4.3 million of expenses related to the pipeline systems we acquired in the second half of 2013. Otherwise, higher property taxes, power expenses and personnel costs related to our other pipeline segments were primarily offset by higher product overages (which reduce operating expenses);
•
an increase in crude oil expenses of $4.0 million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service in the current period, including higher power expenses, personnel costs and pipeline rental fees to access product from third-party origination sources, partially offset by more favorable product overages (which reduce operating expenses); and
•
a decrease in marine storage expenses of $0.5 million primarily due to lower asset integrity costs in the current period.
Product sales revenue primarily resulted from our butane blending activities, product gains from our independent terminals and transmix fractionation. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the price of petroleum products we expect to sell in the future. Product sales revenue also included the period change in the mark-to-market value of these contracts that are not designated as hedges for accounting purposes, the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment and any ineffectiveness of NYMEX contracts that qualify for hedge accounting treatment. We use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. The period change in the mark-to-market value of these futures agreements, which were not designated as hedges, are included as adjustments to cost of product sales. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts. Product margin increased $56.8 million primarily attributable to higher margins from our butane blending activities as a result of lower butane costs and higher sales volumes. The increased volume was primarily attributable to selling additional volume carried over from our fourth quarter 2013 blending activities as well as more blending opportunities during first quarter 2014.
Earnings of non-controlled entities decreased $1.6 million primarily due to lower weighted-average tariffs and higher depreciation costs.
Depreciation and amortization expense increased $1.2 million primarily due to expansion capital projects placed into service since first quarter 2013.
G&A expense increased $4.8 million primarily due to higher compensation costs resulting from an increase in employee headcount and the timing of recognizing our employee bonus accrual, higher equity-based compensation

27
Table of Contents


costs due to a higher price for our limited partner units and higher prospecting and legal costs primarily related to expansion projects.
Interest expense, net of interest income and interest capitalized, increased $2.4 million. Our average outstanding debt increased from $2.4 billion in first quarter 2013 to $2.8 billion in first quarter 2014 primarily due to borrowings for expansion capital expenditures, including $300.0 million of 5.15% senior notes issued in October 2013 and $250.0 million of 5.15% senior notes issued in March 2014. Our weighted-average interest rate was unchanged at 5.2%.
 
 
 
 
 
 
 
 

Distributable Cash Flow

Distributable cash flow ("DCF") and adjusted EBITDA are non-GAAP measures. Management uses DCF as a basis for recommending to our general partner's board of directors the amount of cash distributions to be paid each period. Management also uses DCF (adjusted) as a performance measure in determining equity-based compensation. 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 three months ended March 31, 2013 and 2014 to net income, which is its nearest comparable GAAP financial measure, follows (in millions):
 
 
Three Months Ended March 31,
 
Increase
 
 
2013
 
2014
 
(Decrease)
Net income
 
$
113.0

 
$
242.6

 
$
129.6

Interest expense, net
 
28.3

 
30.7

 
2.4

Depreciation and amortization(1)
 
36.9

 
38.1

 
1.2

Equity-based incentive compensation expense(2)
 
(7.4
)
 
(9.7
)
 
(2.3
)
Asset retirements and impairments
 
1.8

 
1.2

 
(0.6
)
Commodity-related adjustments:
 
 
 

 
 
Derivative (gains) losses recognized in the period associated with future product transactions(3)
 
2.3

 
(0.1
)
 
(2.4
)
Derivative gains (losses) recognized in previous periods associated with products sold in the period(4)
 
(5.2
)
 
(5.3
)
 
(0.1
)
Lower-of-cost-or-market adjustments
 
(2.0
)
 
—

 
2.0

Total commodity-related adjustments
 
(4.9
)
 
(5.4
)
 
(0.5
)
Other
 
(1.4
)
 
0.4

 
1.8

Adjusted EBITDA
 
166.3

 
297.9

 
131.6

Interest expense, net
 
(28.3
)
 
(30.7
)
 
(2.4
)
Maintenance capital(5)
 
(14.1
)
 
(14.0
)
 
0.1

DCF
 
$
123.9

 
$
253.2

 
$
129.3

 
 
 
 
 
 
 
(1)
Depreciation and amortization includes debt placement fee amortization.
(2)
Because we intend to satisfy vesting of units under our equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back to net income to calculate DCF. Total equity-based incentive compensation expense for the three months ended March 31, 2013 and 2014 was $4.9 million and $5.1 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in 2013 and 2014 of $12.3 million and $14.8 million, respectively, for equity-based incentive compensation units that vested at the previous year end, which reduce DCF.

28
Table of Contents


(3)
Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes of these derivatives are recognized currently in earnings. These amounts represent the gains or losses from economic hedges in our earnings for the period associated with products that had not yet been physically sold as of the period-end date.
(4)
When we physically sell products that we have economically hedged (but were not designated as hedges for accounting purposes), we include in our DCF calculations the full amount of the change in fair value of the associated derivative agreement.
(5)
Maintenance capital expenditure projects are not undertaken primarily to generate incremental DCF (i.e. incremental returns to our unitholders), while expansion capital projects are undertaken primarily to generate incremental DCF. For this reason, we deduct maintenance capital expenditures to determine DCF.

Current period DCF increased $129.3 million over the prior year. The change in net income and depreciation and amortization is discussed in detail in Results of Operations above, the change in equity-based compensation is discussed in footnote 2 to the table above and a discussion of our maintenance capital expenditures is provided in Capital Requirements below. The change in DCF from commodity-related adjustments is primarily due to the impact of product price changes during each period on economic hedges that do not qualify for hedge accounting treatment.

A reconciliation of DCF to cash distributions paid is as follows (in millions):

 
 
Three Months Ended
 
 
March 31
 
 
2013
 
2014
Distributable cash flow
 
$
123.9

 
$
253.2

Less: Cash reserves approved by our general partner
 
10.6

 
120.4

Total cash distributions paid
 
$
113.3

 
$
132.8




Liquidity and Capital Resources

Cash Flows and Capital Expenditures
Net cash provided by operating activities was $166.9 million and $270.1 million for the three months ended March 31, 2013 and 2014, respectively. The $103.2 million increase from 2013 to 2014 was primarily attributable to:
•
a $129.6 million increase in net income; and
•
a $31.8 million increase resulting from a $15.0 million decrease in trade accounts receivable and other accounts receivable in 2014 versus a $16.8 million increase during 2013, primarily due to timing of payments from our customers.
These increases were partially offset by:
•
a $39.7 million decrease resulting from a $23.0 million increase in inventory in 2014 versus a $16.7 million decrease in inventory in 2013 principally due to increased inventories from product overages on our pipeline system; and
•
a $26.3 million decrease resulting from a $20.0 million decrease in accrued product purchases in 2014 versus a $6.3 million increase in accrued product purchases in 2013, primarily due to the timing of invoices paid to vendors and suppliers.
Net cash used by investing activities for the three months ended March 31, 2013 and 2014 was $148.6 million and $202.5 million, respectively. During 2014, we spent $70.3 million for capital expenditures, which included $14.0 million for maintenance capital and $56.3 million for expansion capital. Also during 2014, we contributed capital of $127.7 million in conjunction with our joint venture capital projects (primarily BridgeTex) which we account for as investments in non-controlled entities. During 2013, we spent $89.9 million for capital expenditures,

29
Table of Contents


which included $14.1 million for maintenance capital and $75.8 million for expansion capital. Also during 2013, we contributed capital of $47.0 million in conjunction with our joint venture capital projects which we account for as investments in non-controlled entities.
Net cash provided (used) by financing activities for the three months ended March 31, 2013 and 2014 was $(125.6) million and $103.8 million, respectively. During first quarter 2014, we paid cash distributions of $132.8 million to our unitholders. Additionally, we received net proceeds of $257.7 million from borrowings under notes, which were used to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital. Also, in January 2014, the cumulative amounts of the January 2011 equity-based incentive compensation award grants were settled by issuing 387,216 limited partner units and distributing those units to the long-term incentive plan ("LTIP") participants, resulting in payments of associated tax withholdings of $14.8 million. During the first three months of 2013, we paid cash distributions of $113.3 million to our unitholders. Also, in January 2013, the cumulative amounts of the January 2010 equity-based incentive compensation award grants were settled by issuing 476,682 limited partner units and distributing those units to the LTIP participants, resulting in payments of associated tax withholdings of $12.3 million.
The quarterly distribution amount related to our first-quarter 2014 financial results (to be paid in second quarter 2014) is $0.6125 per unit.  If we meet management's targeted distribution growth of 20% for 2014 and the number of outstanding limited partner units remains at 227.1 million, total cash distributions of approximately $593.8 million will be paid to our unitholders related to 2014 financial results. Management believes we will have sufficient distributable cash flow to fund these distributions.

Capital Requirements

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

For the three months ended March 31, 2014, our maintenance capital spending was $14.0 million. For 2014, we expect to spend approximately $77.0 million on maintenance capital.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities and to acquire new assets. During the first three months of 2014, we spent $56.3 million for organic growth capital and $127.7 million for capital projects in conjunction with our joint ventures. Based on the progress of expansion projects already underway, including the expansion of our Longhorn crude oil pipeline, construction of a condensate splitter at Corpus Christi and our investment in the BridgeTex pipeline, we expect to spend approximately $700.0 million for expansion capital during 2014, with an additional $325.0 million in 2015 and $75.0 million in 2016 to complete our current projects.

Liquidity

Consolidated debt at December 31, 2013 and March 31, 2014 was as follows (in millions):

30
Table of Contents


 
 
December 31,
2013
 
March 31,
2014
 
Weighted-Average
Interest Rate for Three Months Ending
March 31, 2014 (1)
Revolving credit facility
$
—

 
$
—

 
—%
$250.0 of 6.45% Notes due 2014
250.0

 
250.0

 
6.3%
$250.0 of 5.65% Notes due 2016
251.2

 
251.1

 
5.7%
$250.0 of 6.40% Notes due 2018
259.3

 
258.8</