News Column

MAGELLAN MIDSTREAM PARTNERS LP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 5, 2014

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of June 30, 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 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

BridgeTex Pipeline. BridgeTex Pipeline Company, LLC ("BridgeTex") is in the final stages of construction. Tank construction at the Colorado City origin point is complete and pipeline linefill activities are underway on portions of the pipeline. Pipeline shipments are expected to begin in September to deliver up to 300,000 barrels per day of crude oil from the Permian Basin to the Houston area. Pipeline Tariff Increase. The Federal Energy Regulatory Commission ("FERC") regulates the rates charged on interstate common carrier pipeline operations primarily through an indexing methodology, which establishes the maximum amount by which tariffs can be adjusted each year. Approximately 40% of our refined products tariffs are subject to this indexing methodology while the remaining 60% of our refined products tariffs can be adjusted at our discretion based on competitive factors. The current FERC-approved indexing method is the annual change in the producer price index for finished goods ("PPI-FG") plus 2.65%. Based on this indexing methodology, we increased virtually all of our refined products tariffs by 3.9% on July 1, 2014. Further, pursuant to our customer contracts, we increased our tariffs on the Longhorn crude oil pipeline by 5% on July 1, 2014. 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. Cash Distribution. In July 2014, the board of directors of our general partner declared a quarterly cash distribution of $0.64 per unit for the period of April 1, 2014 through June 30, 2014. This quarterly cash distribution will be paid on August 14, 2014 to unitholders of record on August 4, 2014. Total distributions expected to be paid under this declaration are approximately $145.3 million. 25



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Table of Contents Results of Operations We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles ("GAAP") measure, but the components of operating margin are computed using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the following tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative ("G&A") expenses, which management does not focus on when evaluating the core profitability of our separate operating segments. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in these tables. Product margin is a non-GAAP measure; however, its components of product sales 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. 26



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Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2014 Variance Three Months Ended June 30, Favorable (Unfavorable) 2013 2014 $ Change % Change Financial Highlights ($ in millions, except operating statistics) Transportation and terminals revenue: Refined products $ 202.3$ 232.5$ 30.2 15 Crude oil 41.2 79.6 38.4 93 Marine storage 38.9 41.5 2.6 7 Total transportation and terminals revenue 282.4 353.6 71.2 25 Affiliate management fee revenue 3.6 5.2 1.6 44 Operating expenses: Refined products 66.5 97.3 (30.8 ) (46) Crude oil 4.0 11.8 (7.8 ) (195) Marine storage 7.6 16.5 (8.9 ) (117) Intersegment eliminations (0.7 ) (0.8 ) 0.1 14 Total operating expenses 77.4 124.8 (47.4 ) (61) Product margin: Product sales revenue 157.9 137.6 (20.3 ) (13) Cost of product sales 115.3 109.1 6.2 5 Product margin(1) 42.6 28.5 (14.1 ) (33) Earnings of non-controlled entities 0.7 1.9 1.2 171 Operating margin 251.9 264.4 12.5 5 Depreciation, amortization and impairments 34.2 46.9 (12.7 ) (37) G&A expense 33.2 39.3 (6.1 ) (18) Operating profit 184.5 178.2 (6.3 ) (3)



Interest expense (net of interest income and interest capitalized) 28.4

30.0 (1.6 ) (6) Debt placement fee amortization expense 0.6 0.6 - - Income before provision for income taxes 155.5 147.6 (7.9 ) (5) Provision for income taxes 1.9 1.4 0.5 26 Net income $ 153.6$ 146.2$ (7.4 ) (5) Operating Statistics: Refined products: Transportation revenue per barrel shipped $ 1.366$ 1.409 Volume shipped (million barrels): Gasoline 59.1 63.7 Distillates 35.5 40.5 Aviation fuel 5.0 6.1 Liquefied petroleum gases 2.2 3.7 Total volume shipped 101.8 114.0 Crude oil: Transportation revenue per barrel shipped $ 0.771$ 1.243 Volume shipped (million barrels) 28.1 46.9



Crude oil terminal average utilization (million barrels per month) 12.6

12.3 Marine storage: Marine terminal average utilization (million barrels per month) 22.8 22.7



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

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Transportation and terminals revenue increased $71.2 million resulting from: • an increase in refined products revenue of $30.2 million. Excluding the

pipeline systems we acquired in the second half of 2013 (under Item 1,

see Note 5-Business Combinations for a discussion of these systems),

refined products revenue increased $20.4 million primarily due to a 5% increase in transportation volumes and higher ancillary revenues due to



increased activity. Shipments were higher primarily due to increased

demand for gasoline and distillates; • an increase in crude oil revenue of $38.4 million primarily due to crude oil deliveries on our Longhorn pipeline, which represented approximately 90% of the increase. Our Longhorn pipeline began delivering crude oil in mid-April 2013, averaging approximately 90 thousand barrels per day during 2013 from its start date. In second



quarter 2014, barrels per day increased to an average of approximately

250,000; and • an increase in marine storage revenue of $2.6 million primarily due to higher storage rates and fees related to increased activity. Affiliate management fee revenue increased $1.6 million due to higher construction management fees related to 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 $47.4 million resulting from: • an increase in refined products expenses of $30.8 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products expenses increased approximately $23.9 million primarily due to a favorable adjustment in second quarter 2013 of an accrual for potential air emission fees at our East Houston, Texas facility and less favorable product overages, which reduce operating expenses and



vary between periods due to operating conditions, metering inaccuracies

or other events that result in volume gains or losses during the shipment process; • an increase in crude oil expenses of $7.8 million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service as a result of higher shipments in the current period, including higher power expenses, asset integrity and personnel costs, partially offset by more favorable product overages, which reduce operating expenses; and



• an increase in marine storage expenses of $8.9 million primarily due to

a favorable adjustment in second quarter 2013 of an accrual for potential air emission fees at our Galena Park, Texas facility and higher 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 decreased $14.1 million primarily attributable to unrealized losses recognized on NYMEX contracts in the current quarter compared to unrealized gains recognized in second quarter 2013, partially offset by higher butane blending volumes. Earnings of non-controlled entities increased $1.2 million primarily due to higher earnings related to Double Eagle Pipeline LLC ("Double Eagle"), which began operations in May 2013. 28



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Depreciation, amortization and impairments increased $12.7 million primarily due to an asset impairment of $9.4 million in second quarter 2014 related to a certain pipeline terminal and related assets that management is considering selling, as well as expansion capital projects placed into service since second quarter 2013. G&A expense increased $6.1 million primarily due to higher equity-based compensation costs and deferred board of director awards reflecting a higher price for our limited partner units and higher personnel costs resulting from an increase in employee headcount. Interest expense, net of interest income and interest capitalized, increased $1.6 million. Our average outstanding debt increased from $2.4 billion in second quarter 2013 to $3.0 billion in second 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 decreased from 5.2% in second quarter 2013 to 5.0% in second quarter 2014. 29



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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2014

Six Months Ended June 30, Variance Favorable (Unfavorable) 2013 2014 $ Change % Change Financial Highlights ($ in millions, except operating statistics) Transportation and terminals revenue: Refined products $ 367.7$ 442.7 $ 75.0 20 Crude oil 64.4 147.5 83.1 129 Marine storage 77.6 81.0 3.4 4 Total transportation and terminals revenue 509.7 671.2 161.5 32 Affiliate management fee revenue 7.0 10.1 3.1 44 Operating expenses: Refined products 112.8 148.5 (35.7 ) (32) Crude oil 9.1 20.9 (11.8 ) (130) Marine storage 22.2 30.6 (8.4 ) (38) Intersegment eliminations (1.5 ) (1.6 ) 0.1 7 Total operating expenses 142.6 198.4 (55.8 ) (39) Product margin: Product sales revenue 359.6 433.7 74.1 21 Product purchases 275.7 307.1 (31.4 ) (11) Product margin(1) 83.9 126.6 42.7 51 Earnings of non-controlled entities 2.8 2.4 (0.4 ) (14) Operating margin 460.8 611.9 151.1 33 Depreciation, amortization and impairments 70.5 84.4 (13.9 ) (20) G&A expense 63.3 74.2 (10.9 ) (17) Operating profit 327.0 453.3 126.3 39



Interest expense (net of interest income and interest capitalized) 56.7

60.7 (4.0 ) (7) Debt placement fee amortization expense 1.1 1.2 (0.1 ) (9) Income before provision for income taxes 269.2 391.4 122.2 45 Provision for income taxes 2.6 2.6 - - Net income $ 266.6$ 388.8 $ 122.2 46 Operating Statistics: Refined products: Transportation revenue per barrel shipped $ 1.256$ 1.384 Volume shipped (million barrels): Gasoline 112.7 123.5 Distillates 69.3 78.0 Aviation fuel 9.5 11.1 Liquefied petroleum gases 3.3 5.2 Total volume shipped 194.8 217.8 Crude oil: Transportation revenue per barrel shipped $ 0.605$ 1.182 Volume shipped (million barrels) 44.0 88.7



Crude oil terminal average utilization (million barrels per month) 12.5

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



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

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Transportation and terminals revenue increased $161.5 million resulting from: • an increase in refined products revenue of $75.0 million. Excluding the

pipeline systems we acquired in the second half of 2013 (under Item 1,

see Note 5-Business Combinations for a discussion of these systems),

refined products revenue increased $55.1 million primarily due to a 4% increase in transportation volumes, higher average rates and higher ancillary revenues due to increased activity. Shipments were higher primarily due to increased demand for gasoline and distillates. The average rate per barrel in the current period was impacted by the mid-year 2013 tariff rate increase and more long-haul shipments at a higher rate; • an increase in crude oil revenue of $83.1 million primarily due to crude oil deliveries on our Longhorn pipeline, which represented approximately 90% of the increase. Our Longhorn pipeline began delivering crude oil in mid-April 2013, averaging approximately 90 thousand barrels per day during 2013 from its start date. For the six months ended 2014, barrels per day increased to an average of approximately 225,000; and • an increase in marine storage revenue of $3.4 million primarily due to higher storage rates and fees related to increased activity. Affiliate management fee revenue increased $3.1 million due to higher construction management fees related to 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 $55.8 million resulting from: • an increase in refined products expenses of $35.7 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products expenses increased approximately $24.6 million primarily due to a favorable adjustment in 2013 of an accrual for potential air emission fees at our East Houston facility as well as additional costs in the current year for property taxes, power and personnel costs and lower product overages, which reduce operating expenses; • an increase in crude oil expenses of $11.8 million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service resulting from higher shipments 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



• an increase in marine storage expenses of $8.4 million primarily due to

a favorable adjustment in 2013 of an accrual for potential air emission

fees at our Galena Park facility, and higher asset integrity costs in

the current period.

Product margin increased $42.7 million primarily attributable to higher margins from our butane blending activities as a result of lower butane costs and higher sales volumes, partially offset by lower sales prices. The increased volume was primarily attributable to selling gasoline production volumes carried over from our fourth quarter 2013 blending activities as well as capturing additional blending opportunities in the current period. Depreciation, amortization and impairments increased $13.9 million primarily due to an asset impairment of $9.4 million in 2014 related to a certain pipeline terminal and related assets that management is considering selling, as well as expansion capital projects placed into service since 2013. G&A expense increased $10.9 million primarily due to higher equity-based compensation costs and deferred board of director awards reflecting a higher price for our limited partner units and higher personnel costs resulting from an increase in employee headcount. Interest expense, net of interest income and interest capitalized, increased $4.0 million. Our average outstanding debt increased from $2.4 billion in 2013 to $2.9 billion in 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 31



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million of 5.15% senior notes issued in March 2014. Our weighted-average interest rate decreased from 5.2% in 2013 to 5.1% in 2014.

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 six months ended June 30, 2013 and 2014 to net income, which is its nearest comparable GAAP financial measure, follows (in millions): Six Months Ended June 30, Increase 2013 2014 (Decrease) Net income $ 266.6$ 388.8$ 122.2 Interest expense, net, and provision for income taxes 59.3 63.3 4.0 Depreciation, amortization and impairments(1) 71.6 85.6 14.0 Equity-based incentive compensation expense(2) (2.0 ) (2.1 ) (0.1 ) Asset retirements 2.3 3.3 1.0 Commodity-related adjustments: Derivative (gains) losses recognized in the period associated with future product transactions(3) (6.9 ) 14.4 21.3 Derivative losses recognized in previous periods associated with products sold in the period(4) (5.7 ) (8.1 ) (2.4 ) Lower-of-cost-or-market adjustments 0.1 - (0.1 ) Total commodity-related adjustments (12.5 ) 6.3 18.8 Other (0.9 ) 1.9 2.8 Adjusted EBITDA 384.4 547.1 162.7 Interest expense, net, and provision for income taxes (59.3 ) (63.3 ) (4.0 ) Maintenance capital(5) (33.0 ) (34.8 ) (1.8 ) DCF $ 292.1$ 449.0$ 156.9 (1) Depreciation, amortization and impairments include debt placement fee amortization. The 2014 amount includes a $9.4 million impairment of a



certain terminal and related assets. See Note 13 - Fair Value Measurements

for further discussion of this matter. (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 six months ended June 30, 2013 and 2014 was

$10.3 million and $12.7 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.

(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. 32



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A reconciliation of DCF to cash distributions paid is as follows (in millions): Six Months Ended June 30, 2013 2014 Distributable cash flow $ 292.1$ 449.0



Less: Cash reserves approved by our general partner 63.7 177.1 Total cash distributions paid

$ 228.4$ 271.9



Liquidity and Capital Resources

Cash Flows and Capital Expenditures Net cash provided by operating activities was $339.7 million and $477.4 million for the six months ended June 30, 2013 and 2014, respectively. The $137.7 million increase from 2013 to 2014 was primarily attributable to: • a $136.1 million increase in net income and non-cash depreciation,



amortization and impairments; and

• a $17.3 million increase resulting from a $25.5 million decrease in

trade accounts receivable and other accounts receivable in 2014 versus an $8.2 million decrease during 2013, primarily due to timing of payments from our customers. These increases were partially offset by a $15.7 million decrease resulting from a $1.7 million increase in inventory in 2014 versus a $14.0 million decrease in inventory in 2013 principally due to increased inventories from product overages on our pipeline system. Net cash used by investing activities for the six months ended June 30, 2013 and 2014 was $307.8 million and $437.3 million, respectively. During the first six months of 2014, we spent $149.1 million for capital expenditures, which included $34.8 million for maintenance capital and $114.3 million for expansion capital. Also so far in 2014, we contributed capital of $285.9 million in conjunction with our joint venture capital projects (primarily BridgeTex) which we account for as investments in non-controlled entities. During the first six months of 2013, we spent $181.2 million for capital expenditures, which included $33.0 million for maintenance capital and $148.2 million for expansion capital. Also during the 2013 period, we contributed capital of $99.7 million in conjunction with our joint venture capital projects which we account for as investments in non-controlled entities. Net cash used by financing activities for the six months ended June 30, 2013 and 2014 was $240.6 million and $64.5 million, respectively. During the first six months of 2014, we paid cash distributions of $271.9 million to our unitholders. Additionally, we received net proceeds of $257.7 million from borrowings under notes and $221.0 million from borrowings under our commercial paper program, which were used in part to repay our 6.45% notes due June 1, 2014, 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 six months of 2013, we paid cash distributions of $228.4 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 second-quarter 2014 financial results (to be paid in third quarter 2014) is $0.64 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 33



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$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 six months ended June 30, 2014, our maintenance capital spending was $34.8 million. For 2014, we expect to spend approximately $77.0 million on maintenance capital.

During the first six months of 2014, we spent $114.3 million for organic growth capital and $285.9 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, Texas and pipeline segment to Little Rock, Arkansas and our investment in the BridgeTex pipeline, we expect to spend approximately $775.0 million for expansion capital and joint venture capital contributions during 2014, with an additional $350.0 million in 2015 and $75.0 million in 2016 to complete our current projects.



Liquidity

Consolidated debt at December 31, 2013 and June 30, 2014 was as follows (in millions): Weighted-Average Interest Rate for Six Months Ending December 31, June 30, June 30, 2013 2014 2014 (1) Commercial paper(2) $ - $ 221.0 0.3% Revolving credit facility(2) - -



1.3%

$250.0 of 6.45% Notes due 2014(2) 250.0 -



6.3%

$250.0 of 5.65% Notes due 2016 251.2 251.0



5.7%

$250.0 of 6.40% Notes due 2018 259.3 258.3



5.4%

$550.0 of 6.55% Notes due 2019 571.5 569.7



5.7%

$550.0 of 4.25% Notes due 2021 557.2 556.8



4.0%

$250.0 of 6.40% Notes due 2037 249.0 249.0



6.4%

$250.0 of 4.20% Notes due 2042 248.4 248.4



4.2%

$550.0 of 5.15% Notes due 2043 298.7 556.4 5.1% Total debt $ 2,685.3$ 2,910.6 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. 34



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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 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.

Interest Rate Derivatives. 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 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. 35



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Off-Balance Sheet Arrangements

None. Environmental Our operations are subject to federal, state and local environmental laws and regulations. We have accrued liabilities for estimated costs at our facilities and properties. We record liabilities when environmental costs are probable and can be reasonably estimated. The determination of amounts recorded for environmental liabilities involves significant judgments and assumptions by management. Due to the inherent uncertainties involved in determining environmental liabilities, it is reasonably possible that the actual amounts required to extinguish these liabilities could be materially different from those we have recognized. Other Items Condensate Splitter. In March 2014, we announced 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. Commodity Derivative Agreements. Certain of the business activities in which we engage result in our owning various commodities which exposes us to commodity price risk. We use NYMEX contracts and butane futures agreements to help manage this commodity price risk. We use NYMEX contracts to hedge against changes in the price of refined products we expect to sell in future periods. We use and account for those NYMEX contracts that qualify for hedge accounting treatment as either cash flow or fair value hedges, and we use and account for those NYMEX contracts that do not qualify for hedge accounting treatment as economic hedges. We use butane futures agreements to economically hedge against changes in the price of butane we expect to purchase in the future as part of our butane blending activity. As of June 30, 2014, our open derivative contracts were as follows:



Open Derivative Contracts Designated as Hedges

• NYMEX contracts covering 0.7 million barrels of crude oil to hedge against

future price changes of crude oil linefill and tank bottom inventory. These contracts, which we are accounting for as fair value hedges, mature between July 2014 and November 2016. Through June 30, 2014,



the cumulative amount of losses from these agreements was $14.9 million.

The cumulative losses from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. As a result, none of these cumulative losses have impacted our consolidated income statement. 36



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Open Derivative Contracts Not Designated as Hedges • NYMEX contracts covering 3.0 million barrels of refined products related

to our butane blending and fractionation activities. These contracts mature between July 2014 and April 2015 and are being accounted for as economic hedges. Through June 30, 2014, the cumulative amount of net



unrealized losses associated with these agreements was $12.2 million. We

recorded these losses as an adjustment to product sales revenue, all of which was recognized in 2014.



• NYMEX contracts covering 0.4 million barrels of refined products and crude

oil related to inventory we carry that resulted from pipeline product

overages. These contracts, which mature in July 2014, are being accounted

for as economic hedges. Through June 30, 2014, the cumulative amount of

net unrealized gains associated with these agreements was $0.4 million. We

recorded these gains as an adjustment to operating expenses, all of which

was recognized in 2014.



• Butane futures agreements to purchase 0.9 million barrels of butane that

mature between September 2014 and April 2015, which are being accounted

for as economic hedges. Through June 30, 2014, the cumulative amount of

net unrealized gains associated with these agreements was $0.6 million. We

recorded these gains as an adjustment to cost of product sales, all of which was recognized in 2014.



Settled Derivative Contracts

• We settled NYMEX contracts covering 4.8 million barrels of refined

products related to economic hedges of products from our butane blending

and fractionation activities that we sold during 2014. We recognized a

loss of $1.6 million in 2014 related to these contracts, which we recorded

as an adjustment to product sales revenue. • We settled NYMEX contracts covering 2.9 million barrels of refined



products and crude oil related to economic hedges of product inventories

from product overages on our pipeline system that we sold during 2014. We recognized a loss of $4.3 million in 2014 on the settlement of these contracts, which we recorded as an adjustment to operating expense.



• We settled butane futures agreements covering 0.1 million barrels related

to economic hedges of butane purchases we made during 2014 associated with

our butane blending activities. We recognized a gain of $0.2 million in

the current period on the settlement of these contracts, which we recorded

as an adjustment to cost of product sales.

Impact of Commodity Derivatives on Results of Operations

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

Six Months Ended June 30, 2013 Net Impact on Results of Product Sales Cost of Product Sales Operating Expense Operations NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period $ 1.0 $ (0.9 ) $ 1.9 $ 2.0 NYMEX gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods 5.2 0.1 (0.4 ) 4.9 Net impact of NYMEX contracts $ 6.2 $ (0.8 ) $ 1.5 $ 6.9 37



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Table of Contents Six Months Ended June 30, 2014 Cost of Product Net Impact on Results Product Sales Sales Operating Expense of Operations NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period $ (1.6 ) $ 0.2 $ (4.3 ) $ (5.7 ) NYMEX gains (losses) recorded during the period that were associated with products that will be sold or purchased in future periods (12.2 ) 0.6 0.4 (11.2 ) Net impact of NYMEX contracts $ (13.8 ) $ 0.8 $



(3.9 ) $ (16.9 )

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 June 30, 2013 and 2014, we made purchases of butane from subsidiaries of Targa of $0.4 million and $1.6 million, respectively. For the six months ended June 30, 2013 and 2014, we made purchases of butane from subsidiaries of Targa of $14.6 million and $13.8 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 June 30, 2014. 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 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, 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 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. 38



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Table of Contents New Accounting Pronouncements In June 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This ASU finalizes the Emerging Issues Task Force's Proposed ASU No. EITF-13D of the same name, and seeks to resolve the diversity in practice that exists when accounting for share-based payments. This ASU requires that a performance target that affects vesting and can be achieved after the requisite service period to be accounted for as a performance condition. The new standard is effective for annual and interim periods after December 15, 2015. We do not expect that our adoption of this standard will have a material impact on our results of operation, financial position or cash flows. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which eliminates the industry-specific guidance in U.S. GAAP and produces a single, principles-based way for companies to report revenue in their financial statements. The new standard requires companies to make more estimates and use more judgment than under current guidance. In addition, all companies must compile more extensive footnote disclosures about how the revenue numbers were derived. This ASU is effective for periods beginning January 1, 2017 and requires either a full retrospective or modified retrospective adoption. We have not yet determined which adoption method we will employ. Early adoption of this standard is not allowed. We are currently in the process of evaluating the impact this new standard will have on our financial statements.



In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of

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Components of an Entity. This standard will limit the number of disposals of assets that should be presented as discontinued operations to those disposals that represent a strategic shift in operations and have a major effect on the organization's operations and financial results. Expanded disclosures will be required to provide more information about the assets, liabilities, income and expenses of discontinued operations as well as significant asset disposals that do not meet the criterion for discontinued operations treatment. This ASU will take effect for annual financial statements with fiscal years beginning on or after December 15, 2014. We do not expect the adoption of this standard to impact our results of operations, financial position or cash flows. 40



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