MMP - 2014.6.30.10Q


 
 
 
 
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ________________________________________
FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 August 4, 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.
 
 
15.
 
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,
 
2013
 
2014
 
2013
 
2014
Transportation and terminals revenue
$
282,462

 
$
353,568

 
$
509,733

 
$
671,205

Product sales revenue
157,922

 
137,657

 
359,633

 
433,720

Affiliate management fee revenue
3,528

 
5,221

 
6,967

 
10,127

Total revenue
443,912

 
496,446

 
876,333

 
1,115,052

Costs and expenses:
 
 
 
 
 
 
 
Operating
77,415

 
124,874

 
142,596

 
198,371

Cost of product sales
115,328

 
109,103

 
275,726

 
307,143

Depreciation, amortization and impairments
34,186

 
46,897

 
70,518

 
84,408

General and administrative
33,262

 
39,309

 
63,318

 
74,244

Total costs and expenses
260,191

 
320,183

 
552,158

 
664,166

Earnings of non-controlled entities
736

 
1,955

 
2,787

 
2,421

Operating profit
184,457

 
178,218

 
326,962

 
453,307

Interest expense
31,720

 
37,265

 
63,443

 
73,681

Interest income
(13
)
 
(406
)
 
(35
)
 
(797
)
Interest capitalized
(3,243
)
 
(6,843
)
 
(6,694
)
 
(12,153
)
Debt placement fee amortization expense
540

 
602

 
1,080

 
1,201

Income before provision for income taxes
155,453

 
147,600

 
269,168

 
391,375

Provision for income taxes
1,813

 
1,340

 
2,561

 
2,561

Net income
$
153,640

 
$
146,260

 
$
266,607

 
$
388,814

Basic and diluted net income per limited partner unit
$
0.68

 
$
0.64

 
$
1.18

 
$
1.71

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation
226,864

 
227,288

 
226,785

 
227,215












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,
 
2013
 
2014
 
2013
 
2014
Net income
$
153,640

 
$
146,260

 
$
266,607

 
$
388,814

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)
(41
)
 
(153
)
 
4,326

 
(179
)
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
 
 
 
 
 
 
 
Amortization of prior service credit(2)
(851
)
 
(928
)
 
(1,702
)
 
(1,823
)
Amortization of actuarial loss(2)
1,354

 
1,192

 
2,684

 
2,016

Settlement cost(2)
—

 
1,569

 
—

 
1,569

Total other comprehensive income (loss)
462

 
1,680

 
748

 
(2,030
)
Comprehensive income
$
154,102

 
$
147,940

 
$
267,355

 
$
386,784

(1) See Note 9–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 7–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
 
June 30,
2014
ASSETS
 
 
(Unaudited)
Current assets:
 
 
 
Cash and cash equivalents
$
25,235

 
$
731

Trade accounts receivable
116,295

 
91,691

Other accounts receivable
6,462

 
11,404

Inventory
187,224

 
188,942

Energy commodity derivatives deposits
14,782

 
29,070

Other current assets
46,735

 
36,620

Total current assets
396,733

 
358,458

Property, plant and equipment
4,986,750

 
5,089,277

Less: Accumulated depreciation
1,070,492

 
1,146,550

Net property, plant and equipment
3,916,258

 
3,942,727

Investments in non-controlled entities
360,852

 
645,090

Long-term receivables
2,730

 
30,028

Goodwill
53,260

 
53,260

Other intangibles (less accumulated amortization of $8,809 and $10,168 at December 31, 2013 and June 30, 2014, respectively)
7,290

 
5,931

Debt placement costs (less accumulated amortization of $9,113 and $7,820 at December 31, 2013 and June 30, 2014, respectively)
17,505

 
19,191

Tank bottom inventory
61,915

 
67,668

Other noncurrent assets
4,269

 
1,906

Total assets
$
4,820,812

 
$
5,124,259

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

 
$
72,050

Accrued payroll and benefits
42,243

 
30,809

Accrued interest payable
44,935

 
45,973

Accrued taxes other than income
38,574

 
34,895

Environmental liabilities
12,147

 
12,747

Deferred revenue
63,164

 
69,338

Accrued product purchases
63,033

 
37,755

Energy commodity derivatives contracts, net
6,737

 
11,140

Current portion of long-term debt
249,971

 
—

Other current liabilities
41,146

 
31,919

Total current liabilities
638,276

 
346,626

Long-term debt
2,435,316

 
2,910,496

Long-term pension and benefits
51,637

 
54,046

Other noncurrent liabilities
21,802

 
28,167

Environmental liabilities
26,339

 
21,919

Commitments and contingencies

 

Partners’ capital:
 
 
 
Limited partner unitholders (226,679 units and 227,068 units outstanding at December 31, 2013 and June 30, 2014, respectively)
1,666,946

 
1,784,539

Accumulated other comprehensive loss
(19,504
)
 
(21,534
)
Total partners’ capital
1,647,442

 
1,763,005

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

 
$
5,124,259



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,
 
2013
 
2014
Operating Activities:
 
 
 
Net income
$
266,607

 
$
388,814

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, amortization and impairments
70,518

 
84,408

Debt placement fee amortization expense
1,080

 
1,201

Loss on sale and retirement of assets
2,298

 
3,310

Earnings of non-controlled entities
(2,787
)
 
(2,421
)
Distributions from investments in non-controlled entities
1,302

 
1,713

Equity-based incentive compensation expense
10,282

 
12,753

Changes in employee benefit plan assets and benefit obligations
982

 
1,762

Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable and other accounts receivable
8,167

 
25,486

Inventory
13,984

 
(1,718
)
Energy commodity derivatives contracts, net of derivatives deposits
(4,628
)
 
(4,133
)
Accounts payable
(322
)
 
486

Accrued payroll and benefits
(4,429
)
 
(11,434
)
Accrued interest payable
(633
)
 
1,038

Accrued taxes other than income
(2,737
)
 
(3,679
)
Accrued product purchases
(22,885
)
 
(25,278
)
Deferred revenue
7,815

 
6,174

Current and noncurrent environmental liabilities
(12,850
)
 
(3,820
)
Other current and noncurrent assets and liabilities
7,909

 
2,694

Net cash provided by operating activities
339,673

 
477,356

Investing Activities:
 
 
 
Property, plant and equipment:
 
 
 
Additions to property, plant and equipment
(181,165
)
 
(149,138
)
Proceeds from sale and disposition of assets
2,305

 
107

Decrease in accounts payable related to capital expenditures
(30,044
)
 
(4,112
)
Investments in non-controlled entities
(99,667
)
 
(285,945
)
Distributions in excess of earnings of non-controlled entities
750

 
1,765

Net cash used by investing activities
(307,821
)
 
(437,323
)
Financing Activities:
 
 
 
Distributions paid
(228,380
)
 
(271,914
)
Net commercial paper borrowings
—

 
220,977

Borrowings under long-term notes
—

 
257,713

Payments on notes
—

 
(250,000
)
Debt placement costs
—

 
(2,887
)
Net payment on financial derivatives
—

 
(3,613
)
Settlement of tax withholdings on long-term incentive compensation
(12,259
)
 
(14,813
)
Net cash used by financing activities
(240,639
)
 
(64,537
)
Change in cash and cash equivalents
(208,787
)
 
(24,504
)
Cash and cash equivalents at beginning of period
328,278

 
25,235

Cash and cash equivalents at end of period
$
119,491

 
$
731

 
 
 
 
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 June 30, 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 active crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million barrels, of which 12 million barrels 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
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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, 2013 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, 2014, the results of operations for the three and six months ended June 30, 2013 and 2014 and cash flows for the six months ended June 30, 2013 and 2014. The results of operations for the six months ended June 30, 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 in which we acquire or produce petroleum products. Some of these NYMEX contracts qualify for hedge accounting treatment, and we designate and account for these as either cash flow or fair value hedges. The effective portion of the fair value changes in contracts designated as cash flow hedges are recognized as adjustments to product sales when the hedged product is physically sold. 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 9 – Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.
For the three and six months ended June 30, 2013 and 2014, product sales revenue included the following (in thousands): 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2013
 
2014
 
2013
 
2014
Physical sale of petroleum products
$
145,580

 
$
154,310

 
$
353,460

 
$
447,550

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) 
12,342

 
(16,666
)
 
6,184

 
(13,843
)
Other
—

 
13

 
(11
)
 
13

Total NYMEX contract adjustments
12,342

 
(16,653
)
 
6,173

 
(13,830
)
Total product sales revenue
$
157,922

 
$
137,657

 
$
359,633

 
$
433,720

(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 June 30, 2013
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
202,397

 
$
41,158

 
$
38,907

 
$
—

 
$
282,462

Product sales revenue
156,321

 
—

 
1,601

 
—

 
157,922

Affiliate management fee revenue
—

 
3,239

 
289

 
—

 
3,528

Total revenue
358,718

 
44,397

 
40,797

 
—

 
443,912

Operating expenses
66,456

 
4,027

 
7,694

 
(762
)
 
77,415

Cost of product sales
114,460

 
—

 
868

 
—

 
115,328

Earnings of non-controlled entities
—

 
(110
)
 
(626
)
 
—

 
(736
)
Operating margin
177,802

 
40,480

 
32,861

 
762

 
251,905

Depreciation, amortization and impairments

21,224

 
5,104

 
7,096

 
762

 
34,186

G&A expenses
23,292

 
4,915

 
5,055

 
—

 
33,262

Operating profit
$
133,286

 
$
30,461

 
$
20,710

 
$
—

 
$
184,457

 

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



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

 
$
79,556

 
$
41,523

 
$
—

 
$
353,568

Product sales revenue
136,334

 
—

 
1,323

 
—

 
137,657

Affiliate management fee revenue
—

 
4,902

 
319

 
—

 
5,221

Total revenue
368,823

 
84,458

 
43,165

 
—

 
496,446

Operating expenses
97,302

 
11,867

 
16,544

 
(839
)
 
124,874

Cost of product sales
108,817

 
—

 
286

 
—

 
109,103

Earnings of non-controlled entities
—

 
(888
)
 
(1,067
)
 
—

 
(1,955
)
Operating margin
162,704

 
73,479

 
27,402

 
839

 
264,424

Depreciation, amortization and impairments

32,083

 
6,725

 
7,250

 
839

 
46,897

G&A expenses
25,374

 
7,697

 
6,238

 
—

 
39,309

Operating profit
$
105,247

 
$
59,057

 
$
13,914

 
$
—

 
$
178,218



 
Six Months Ended June 30, 2013
 
(in thousands)
 
Refined Products
 
Crude Oil
 
Marine Storage
 
Intersegment
Eliminations
 
Total
Transportation and terminals revenue
$
367,756

 
$
64,386

 
$
77,591

 
$
—

 
$
509,733

Product sales revenue
355,736

 
—

 
3,897

 
—

 
359,633

Affiliate management fee revenue
—

 
6,398

 
569

 
—

 
6,967

Total revenue
723,492

 
70,784

 
82,057

 
—

 
876,333

Operating expenses
112,737

 
9,134

 
22,247

 
(1,522
)
 
142,596

Cost of product sales
272,758

 
—

 
2,968

 
—

 
275,726

Earnings of non-controlled entities
—

 
(1,485
)
 
(1,302
)
 
—

 
(2,787
)
Operating margin
337,997

 
63,135

 
58,144

 
1,522

 
460,798

Depreciation, amortization and impairments

42,577

 
12,573

 
13,846

 
1,522

 
70,518

G&A expenses
44,494

 
9,042

 
9,782

 
—

 
63,318

Operating profit
$
250,926

 
$
41,520

 
$
34,516

 
$
—

 
$
326,962



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



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

 
$
147,459

 
$
81,021

 
$
—

 
$
671,205

Product sales revenue
430,044

 
—

 
3,676

 
—

 
433,720

Affiliate management fee revenue
—

 
9,497

 
630

 
—

 
10,127

Total revenue
872,769

 
156,956

 
85,327

 
—

 
1,115,052

Operating expenses
148,459

 
20,925

 
30,630

 
(1,643
)
 
198,371

Cost of product sales
306,573

 
—

 
570

 
—

 
307,143

Earnings of non-controlled entities
—

 
(708
)
 
(1,713
)
 
—

 
(2,421
)
Operating margin
417,737

 
136,739

 
55,840

 
1,643

 
611,959

Depreciation, amortization and impairments

55,255

 
13,188

 
14,322

 
1,643

 
84,408

G&A expenses
48,393

 
13,691

 
12,160

 
—

 
74,244

Operating profit
$
314,089

 
$
109,860

 
$
29,358

 
$
—

 
$
453,307




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.

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. In addition to our equity ownership in 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 and six months ended June 30, 2014, we received throughput revenue of $0.8 million and $1.3 million, respectively. We recorded a $0.2 million and $0.3 million trade accounts receivable from Double Eagle at December 31, 2013 and June 30, 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 the third quarter of 2014. We receive construction management fees from BridgeTex, which we report as affiliate management fee revenue on our consolidated statements of income.

We received $4.8 million from BridgeTex in 2013 as a deposit for the purchase of emission reduction credits, which were necessary for the operation of BridgeTex's tanks in East Houston, Texas. In second quarter 2014, we transferred these emission reduction credits to BridgeTex and recorded $2.4 million as a reduction of operating

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



expense. We recorded the remaining $2.4 million as an adjustment to our investment in BridgeTex, which will be amortized to earnings of non-controlled entities over the weighted average depreciable lives of the BridgeTex assets.

Also during 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 to earnings of non-controlled entities 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
 
281,803

 
4,142

 
285,945

Other adjustment to investment
 
—

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

 
 
Proportionate share of earnings (loss)
 
(140
)
 
2,936

 
2,796

Amortization of excess investment and capitalized interest
 
—

 
(375
)
 
(375
)
Earnings (losses) of non-controlled entities
 
(140
)
 
2,561

 
2,421

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

 
1,713

 
1,713

Distributions in excess of earnings of non-controlled entities
 
—

 
1,765

 
1,765

Investment at June 30, 2014
 
$
528,538

 
$
116,552

 
$
645,090

 
 
 
 
 
 
 


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Summarized financial information of our non-controlled entities as of and for the six months ended June 30, 2014 follows (in thousands):
 
 
BridgeTex
 
All Others
 
Consolidated
Current assets
 
$
60,296

 
$
20,128

 
$
80,424

Noncurrent assets
 
907,337

 
184,876

 
1,092,213

Total assets
 
$
967,633

 
$
205,004

 
$
1,172,637

Current liabilities
 
107,742

 
6,410

 
114,152

Noncurrent liabilities
 
—

 
98

 
98

Total liabilities
 
$
107,742

 
$
6,508

 
$
114,250

Equity
 
$
859,891

 
$
198,496

 
$
1,058,387

 
 
 
 
 
 
 
Revenue
 
$
—

 
$
18,464

 
$
18,464

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

 
$
5,591


5.
Business Combinations

During 2013, we acquired certain refined petroleum products pipelines and terminals from Plains All American Pipeline, L.P. We have accounted for this acquisition as a business combination under the acquisition method of accounting in accordance with Accounting Standards Codification ("ASC") 805, Business Combinations. The acquisition was completed in two parts, as follows:

•
New Mexico/Texas System. In July 2013, we acquired approximately 250 miles of common carrier pipeline that transports refined petroleum products from El Paso, Texas north to Albuquerque, New Mexico and transports products south to the U.S.–Mexico border for delivery within Mexico via a third-party pipeline for $57.0 million. We funded this acquisition with cash on hand.

•
Rocky Mountain System. In November 2013, we acquired approximately 550 miles of common carrier pipeline that distributes refined petroleum products in Colorado, South Dakota and Wyoming for $135.0 million. The system includes four terminals with nearly 1.7 million barrels of storage. We funded this acquisition primarily with proceeds from our debt offering in October 2013.

We completed our valuation process of this 2013 business combination during the current quarter, and there were no changes to our preliminary purchase price allocation amounts since December 31, 2013 (as reported in our 2013 annual report on Form 10-K).


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6.
Inventory

Inventory at December 31, 2013 and June 30, 2014 was as follows (in thousands):
 
 
December 31, 2013
 
June 30,
2014
Refined products
$
77,144

 
$
35,331

Liquefied petroleum gases
23,476

 
57,103

Transmix
72,156

 
80,619

Crude oil
7,188

 
10,302

Additives
7,260

 
5,587

Total inventory
$
187,224

 
$
188,942



7.
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 and six months ended June 30, 2013 and 2014 (in thousands):
 
 
Three Months Ended
 
Three Months Ended
 
June 30, 2013
 
June 30, 2014
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
3,374

 
$
67

 
$
3,352

 
$
47

Interest cost
1,334

 
91

 
2,030

 
139

Expected return on plan assets
(1,645
)
 
—

 
(1,490
)
 
—

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

 
(928
)
 
—

 
(928
)
Amortization of actuarial loss(1)
1,145

 
209

 
930

 
262

Settlement cost(1)
—

 
—

 
1,569

 
—

Net periodic benefit cost (credit)
$
4,285

 
$
(561
)
 
$
6,391

 
$
(480
)
 

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Six Months Ended
 
Six Months Ended
 
June 30, 2013
 
June 30, 2014
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
 
Pension
Benefits
 
Other  Post-
Retirement
Benefits
Components of net periodic benefit costs:
 
 
 
 
 
 
 
Service cost
$
6,950

 
$
144

 
$
6,704

 
$
114

Interest cost
2,684

 
206

 
3,689

 
253

Expected return on plan assets
(3,115
)
 
—

 
(3,187
)
 
—

Amortization of prior service cost (credit)(1)
154

 
(1,856
)
 
33

 
(1,856
)
Amortization of actuarial loss(1)
2,167

 
517

 
1,559

 
457

Settlement cost(1)
—

 
—

 
1,569

 
—

Net periodic benefit cost (credit)
$
8,840

 
$
(989
)
 
$
10,367

 
$
(1,032
)

(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.

Contributions estimated to be paid into the plans in 2014 are $21.1 million and $0.7 million for the pension and postretirement benefit plans, respectively.


8.
Debt
Consolidated debt at December 31, 2013 and June 30, 2014 was as follows (in thousands, except as otherwise noted):
 
 
December 31, 2013
 
June 30,
2014
 
Weighted-Average
Interest Rate for Six Months Ending
June 30, 2014 (1)
Commercial paper(2)
 
$
—

 
$
220,977

 
0.3%
Revolving credit facility(2)
 
—

 
—

 
1.3%
$250.0 million of 6.45% Notes due 2014(2)
 
249,971

 
—

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

 
250,970

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

 
258,313

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

 
569,704

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

 
556,763

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

 
249,007

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

 
248,391

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

 
556,371

 
5.1%
Total debt
 
$
2,685,287

 
$
2,910,496

 
5.1%
 
 
 
 
 
 
 

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

(2)
These borrowings were outstanding for only a portion of the six month period ending June 30, 2014. The weighted-average interest rate for these borrowings was calculated based on the number of days the borrowings were outstanding during the noted period.

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

The face value of our debt at December 31, 2013 and June 30, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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.

2014 Debt Offering

In March 2014, we issued $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 $255.0 million, after underwriting discounts and offering expenses of $2.7 million, to repay borrowings outstanding under our revolving credit facility and for general partnership purposes, including expansion capital.

Other Debt

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in November 2018, is $1.0 billion. Borrowings outstanding under the facility are classified as long-term debt on our consolidated balance sheets. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 1.0% to 1.75% based on our credit ratings. Additionally, an unused commitment fee is assessed at a rate from 0.10% to 0.28%, depending on our credit ratings. The unused commitment fee was 0.125% at June 30, 2014. Borrowings under this facility may be used for general partnership purposes, including capital expenditures. As of June 30, 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.

Commercial Paper Program. In April 2014, we initiated a commercial paper program. The maturities of the 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. We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis; therefore, we have elected to classify our commercial paper borrowings outstanding as long-term debt on our consolidated balance sheets.

In second quarter 2014, proceeds from commercial paper borrowings were used in part to repay our 6.45% senior notes due June 1, 2014.


9.
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 $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 is being recognized into earnings as an adjustment to our periodic interest expense

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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 as a deferred cash flow hedging gain. The purpose of these swaps was to hedge against the variability of future interest payments on the refinancing of our debt that matured in June 2014. We recognized ineffectiveness of $0.2 million in earnings on this deferred hedging gain in second quarter 2014 due to timing of our debt refinancing.

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 June 30, 2014, we had commitments under these forward purchase and sale contracts as follows (in millions):
 
Notional Value
 
Barrels
Forward purchase contracts
$
137.7


2.4
Forward sale contracts
$
8.8


0.1

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 is recorded to accumulated other comprehensive income/loss and reclassified to earnings when the forecasted transaction occurs. Any ineffectiveness is recognized currently in earnings.
    Fair Value Hedge
 
To hedge against changes in the fair value of a recognized asset or liability.
 
The effective portion of changes in the value of the hedge is recorded as adjustments to the asset or liability being hedged. Any ineffectiveness 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 value of these agreements are recognized currently in earnings.

Period changes in the fair value of NYMEX agreements that are accounted for as economic hedges, other than those economic hedges of our pipeline product overages (see discussion of these below), the effective portion of changes in the fair value of cash flow hedges that are reclassified from accumulated other comprehensive income/

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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 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 June 30, 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 July 2014 and November 2016
NYMEX - Economic Hedges
 
3.4 million barrels of refined products and crude oil
 
Between July 2014 and April 2015
Butane Futures Agreements - Economic Hedges
 
0.9 million barrels of butane
 
Between September 2014 and April 2015

Energy Commodity Derivatives Contracts and Deposits Offsets

At June 30, 2014, we had made margin deposits of $29.1 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 June 30, 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

 
 
 
 
 
 
 
 
 
 
 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
 
June 30, 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
 
$
(16,577
)
 
$
1,920

 
$
(14,657
)
 
$
29,070

 
$
14,413

 
 
 
 
 
 
 
 
 
 
 
(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 $11,140 and noncurrent liabilities of $3,517.

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

The changes in derivative activity included in AOCL for the three and six months ended June 30, 2013 and 2014 were as follows (in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Derivative Gains (Losses) Included in AOCL
2013
 
2014
 
2013
 
2014
Beginning balance
$
13,933

 
$
9,988

 
$
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
(41
)
 
(153
)
 
4,326

 
(179
)
Ending balance
$
13,892

 
$
9,835

 
$
13,892

 
$
9,835


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 $14.9 million from the agreements as of June 30, 2014 were fully offset by a cumulative increase of $14.7 million to tank bottom inventory and a cumulative increase of $0.2 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 and six months ended June 30, 2013 and 2014 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, 2013
 
 
Amount of Gain Recognized in AOCL on Derivative
 
Location of Gain Reclassified from AOCL into  Income
 
Amount of Gain Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
—

 
 
Interest expense
 
 
$
41

 
 
 
$
—

 
 
 
Three Months Ended June 30, 2014
 
 
Amount of Gain (Loss) Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into  Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
—

 
 
Interest expense
 
 
$
(30
)
 
 
 
$
183

 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)




 
 
Six Months Ended June 30, 2013
 
 
Amount of Gain (Loss) Recognized in AOCL on Derivative
 
Location of Gain (Loss) Reclassified from AOCL into  Income
 
Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument
 
 
 
Effective Portion
 
Ineffective Portion
Interest rate contracts
 
 
$
—

 
 
Interest expense
 
 
$
82

 
 
 
$
—

 
NYMEX commodity contracts
 
 
(4,560
)
 
 
Product sales revenue
 
 
(4,408
)
 
 
 
—

 
Total cash flow hedges
 
 
$
(4,560
)
 
 
Total
 
 
$
(4,326
)
 
 
 
$
—

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

 

As of June 30, 2014, the net loss estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.3 million.
The following table provides a summary of the effect on our consolidated statements of income for the three months ended June 30, 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
 
 
Location of Gain (Loss)
Recognized on Derivative
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Derivative Instrument
 
 
2013
 
2014
 
2013
 
2014
NYMEX commodity contracts
 
Product sales revenue
 
$
12,342

 
$
(16,653
)
 
$
10,581

 
$
(13,830
)
NYMEX commodity contracts
 
Operating expenses
 
3,348

 
(4,268
)
 
1,462

 
(3,903
)
Butane futures agreements
 
Cost of product sales
 
20

 
632

 
(761
)
 
776

 
 
Total
 
$
15,710

 
$
(20,289
)
 
$
11,282

 
$
(16,957
)
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 June 30, 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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
 
June 30, 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
 
$
34

 
Energy commodity derivatives contracts, net
 
$
—

NYMEX commodity contracts
 
Other noncurrent assets
 
—

 
Other noncurrent liabilities
 
3,517

 
 
Total
 
$
34

 
Total
 
$
3,517

 
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 June 30, 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

 
 
 
 
 
 
 
 
 
 
 
June 30, 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
 
$
1,184

 
Energy commodity derivatives contracts, net
 
$
12,971

Butane futures agreements
 
Energy commodity derivatives contracts, net
 
702

 
Energy commodity derivatives contracts, net
 
89

 
 
Total
 
$
1,886

 
Total
 
$
13,060

 

10.
Commitments and Contingencies

Environmental Liabilities

Liabilities recognized for estimated environmental costs were $38.5 million and $34.7 million at December 31, 2013 and June 30, 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 and six months ended June 30, 2013 were $(9.4) million and $(8.7) million, respectively, and both of these amounts include a $10.6 million favorable adjustment to a Clean Air Act – Section 185 liability in second quarter 2013. Environmental expenses for the three and six months ended June 30, 2014 were $0.1 million and $0.4 million, respectively.


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



Environmental Receivables

Receivables from insurance carriers and other third parties related to environmental matters at December 31, 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 June 30, 2014 were $4.6 million, of which $2.1 million and $2.5 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 $36.4 million.  We entered into a long-term throughput and deficiency agreement with a customer on this pipeline, which contains minimum volume/payment commitments. This agreement is being accounted for as a direct financing lease.
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.

11.
Long-Term Incentive Plan
We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate payout of 9.4 million of our limited partner units. The estimated units available under the LTIP at June 30, 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
 
Six Months Ended
 
June 30, 2013
 
June 30, 2013
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
 
 
 
 
 
 
2010 awards
$
—

 
$
—

 
$
—

 
$
121

 
$
73

 
$
194

2011 awards
2,120

 
1,076

 
3,196

 
3,103

 
2,223

 
5,326

2012 awards
826

 
370

 
1,196

 
1,707

 
981

 
2,688

2013 awards
733

 
198

 
931

 
1,459

 
387

 
1,846

Retention awards
103

 
—

 
103

 
228

 
—

 
228

Total
$
3,782

 
$
1,644

 
$
5,426

 
$
6,618

 
$
3,664

 
$
10,282

 
 
 
 
 
 
 
 
 
 
 
 
Allocation of LTIP expense on our consolidated statements of income:
G&A expense
 
 
 
 
$
5,317

 
 
 
 
 
$
9,802

Operating expense
 
 
 
 
109

 
 
 
 
 
480

Total
 
 
 
 
$
5,426

 
 
 
 
 
$
10,282

 

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



 
Three Months Ended
 
Six Months Ended
 
June 30, 2014
 
June 30, 2014
 
Equity
Method
 
Liability
Method
 
Total
 
Equity
Method
 
Liability
Method
 
Total
Performance/market-based awards:
 
 
 
 
 
 
 
 
 
 
 
2012 awards
$
1,022

 
$
1,617

 
$
2,639

 
$
2,044

 
$
2,541

 
$
4,585

2013 awards
2,195

 
1,305

 
3,500

 
3,376

 
1,853

 
5,229

2014 awards
1,228

 
—

 
1,228

 
2,132

 
—

 
2,132

Retention awards
298

 
—

 
298

 
807

 
—

 
807

Total
$
4,743

 
$
2,922

 
$
7,665

 
$
8,359

 
$
4,394

 
$
12,753

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

 
 
 
 
 
$
12,460

Operating expense
 
 
 
 
179

 
 
 
 
 
293

Total
 
 
 
 
$
7,665

 
 
 
 
 
$
12,753


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.

12.
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

 
Through 06/30/2013
 
 
1.0075

 
 
 
228,380

 
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

 
05/15/2014
 
 
0.6125

 
 
 
139,079

 
Through 06/30/2014
 
 
1.1975

 
 
 
271,914

 
8/14/2014(1)
 
 
0.6400

 
 
 
145,324

 
Total
 
 
$
1.8375