SUBSCRIBE TO TMCnet
TMCnet - World's Largest Communications and Technology Community

TMCNet:  TARGA RESOURCES PARTNERS LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

[February 14, 2014]

TARGA RESOURCES PARTNERS LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical financial statements and notes included in Part IV of this Annual Report Overview Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa Resources Corp. Our common units are listed on the NYSE under the symbol "NGLS." In this Annual Report, unless the context requires otherwise, references to "we," "us," "our," or "the Partnership" are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.


Targa Resources GP LLC (the "general partner" or "Targa") is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.

Our midstream natural gas and NGL services footprint was established through several acquisitions from Targa, totaling $3.1 billion, that occurred from 2007 through 2010. In these transactions we acquired (1) natural gas gathering, processing and treating assets in North Texas, West Texas, New Mexico and the Louisiana Gulf Coast and (2) NGL assets consisting of fractionation, transport, storage and terminaling facilities, LSNG treating facilities, pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.

Our Operations We are a leading United States provider of midstream natural gas and NGL services, with a growing presence in crude oil gathering and petroleum terminaling.

We are engaged in the business of: · gathering, compressing, treating, processing and selling natural gas; · storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products; · gathering, storing and terminaling crude oil; and · storing, terminaling and selling refined petroleum products.

We report our operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities are reported in Other.

Our Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Field Gathering and Processing segment's assets are located in North Texas, the Permian Basin of West Texas, New Mexico and in North Dakota. The Coastal Gathering and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as the storing, terminaling, distributing and marketing of NGLs and refined petroleum products. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.

Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for exporting LPGs; and storing and terminaling of refined petroleum products. These assets are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and in Lake Charles, Louisiana.

57 -------------------------------------------------------------------------------- Table of Contents Our Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to us from our Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

Other contains the results of our commodity hedging activities included in operating margin.

2013 Developments Badlands Expansion Program On January 1, 2013, we assumed operational control of the Badlands assets in the Williston Basin of North Dakota and commenced integration activities. The Badlands operational results are included as part of the Field Gathering and Processing segment.

During 2013, we invested approximately $250 million to expand the gathering and processing capabilities of Badlands. We added an additional 20 MMcf/d natural gas processing plant, and increased our crude gathering and natural gas gathering and processing operations substantially with the addition of pipelines and associated oil and gas facilities. During 2014 we anticipate that we will invest another $180 million for further expansion of its gathering and processing assets.

The acquisition agreement also provided for a contingent payment of $50 million conditioned on achieving stipulated crude gathering volumes by mid-2014.

Management does not believe that those thresholds will be achieved during the contingency period. At December 31, 2012, based on a probability-based model measuring the likelihood of meeting the thresholds, we recorded a $15.3 million accrued liability representing the fair value of this contingent consideration.

During 2013, the contingent consideration was re-estimated to be $0, resulting in the elimination of the contingent liability.

Cedar Bayou Fractionators Train 4 In August 2013, we commissioned an additional fractionator, Train 4, at CBF.

This expansion added 100 MBbl/d of fractionation capacity at CBF. The gross cost of Train 4 was approximately $385 million (our net cost was approximately $345 million).

International Export Project In September 2013, we commissioned Phase I of our international export expansion project, which includes facilities both at our Mont Belvieu facility and at our Galena Park Marine Terminal near Houston, Texas. Phase I of this project expanded our export capability to approximately 3.5 to 4 MMBbl per month of propane and/or butane. Included in our Phase I expansion is the capability to export international grade low ethane propane. With the completion of Phase I, we also added capabilities to load VLGC vessels in addition to the small and medium-sized export vessels that we load for export. Construction is underway to further expand our propane and butane international export capacity by approximately 2 MMBbl per month, with an expected completion of Phase II in the third quarter of 2014. We expect that the total cost of both phases of our international export project to be approximately $480 million.

North Texas Longhorn Plant We started construction of a new 200 MMcf/d cryogenic processing plant for North Texas to meet increasing production and continued producer activity, with an anticipated completion in the second quarter of 2014. We expect to invest an estimated $150 million for the plant and associated projects.

58 -------------------------------------------------------------------------------- Table of Contents SAOU High Plains Plant We started construction of a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin, with an anticipated completion date in mid-2014. We expect to invest an estimated $225 million for the plant and associated projects.

Accounts Receivable Securitization Facility In January 2013, we entered into a Securitization Facility that provides up to $200 million of borrowing capacity at commercial paper or LIBOR market index rates plus a margin through January 2014. Under this Securitization Facility, one of our consolidated subsidiaries (Targa Liquids Marketing and Trade LLC or "TLMT") sells or contributes receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or "TRLLC"), a special purpose consolidated subsidiary created for the sole purpose of this Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT or us. Any excess receivables are eligible to satisfy the claims of creditors of TLMT or us.

In December 2013, we entered into an amendment to our Securitization Facility to increase the borrowing capacity to $300 million and extend the termination date to December 12, 2014. As of December 31, 2013, total funding under this Securitization Facility was $279.7 million.

Other Financing Activities In 2012, we filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows the Partnership to issue up to an aggregate of $300 million of debt or equity securities (the "2012 Shelf").

In August 2012, we entered into an Equity Distribution Agreement (the "2012 EDA") with Citigroup Global Markets Inc. ("Citigroup") pursuant to which we may sell, at its option, up to an aggregate of $100 million of its common units through Citigroup, as sales agent, under the 2012 Shelf. During 2012, there were no sales of common units pursuant to this program. During 2013, we issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. Targa contributed $2.0 million to maintain its 2% general partner interest.

In March 2013, we entered into a second EDA under the 2012 Shelf ("March 2013 EDA") with Citigroup, Deutsche Bank Securities Inc. ("Deutsche Bank"), Raymond James & Associates, Inc. ("Raymond James") and UBS Securities LLC ("UBS"), as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $200 million of its debt or equity securities. During 2013, we issued 4,204,751 common units under the March 2013 EDA, receiving net proceeds of $197.5 million. Targa contributed $4.1 million to maintain its 2% general partner interest. The 2012 Shelf expires in August 2015.

In April 2013, we filed with the SEC a universal shelf registration statement (the "April 2013 Shelf"), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expires in April 2016. There was no activity under the April 2013 Shelf during the year ended December 31, 2013.

In May 2013, we privately placed $625.0 million in aggregate principal amount of 4¼% Senior Notes due 2023 (the "4¼% Notes"). The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes.

In June 2013, we redeemed $100 million of the outstanding 6?% Senior Notes due 2022 (the "6?% Notes") at a redemption price of 106.375% plus accrued interest through the redemption date. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

In July 2013, we redeemed the outstanding balance of the 11¼% Senior Notes due 2017 (the "11¼% Notes") at a price of 105.625% plus accrued interest through July 15, 2013. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

59 -------------------------------------------------------------------------------- Table of Contents In July 2013, we filed with the SEC a universal shelf registration statement (the "July 2013 Shelf") that allows us to issue up to an aggregate of $800 million of debt or equity securities. The July 2013 Shelf expires in August 2016.

In August 2013, we entered into an Equity Distribution Agreement under our July 2013 Shelf (the "August 2013 EDA") with Citigroup, Deutsche Bank, Morgan Stanley & Co. LLC, Raymond James, RBC Capital Markets, LLC, UBS and Wells Fargo Securities, LLC, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400 million of our common units. During the year ended December 31, 2013, we issued 4,529,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million, which was used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $4.7 million to us to maintain its 2% general partner interest.

Based upon market conditions and our capital needs, at our option, we can sell additional common units up to an aggregate amount of $172.0 million under this agreement.

During the year ended December 31, 2013, pursuant to both the 2012 Shelf and 2013 Shelf, we issued a total of 11,154,438 common units representing total net proceeds of $517.9 million, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $10.8 million to maintain its 2% general partner interest during this period.

Recent Accounting Pronouncements In January 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under Accounting Standards Codification ("ASC") Topic 815. We currently present our derivative assets and liabilities gross on our statement of financial position. The amendments require disclosure of both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We have provided additional disclosures regarding the gross and net amounts of derivative assets and liabilities in Note 13 of the "Consolidated Financial Statements." In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2012, requires entities to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line item of net income. Our financial statement presentation complies with this standards update.

Factors That Significantly Affect Our Results Our results of operations are substantially impacted by the volumes that move through our gathering, processing and logistics assets, changes in commodity prices, contract terms, the impact of hedging activities and the cost to operate and support assets.

Volumes In our gathering and processing operations, plant inlet volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.

60 -------------------------------------------------------------------------------- Table of Contents Commodity Prices The following table presents selected annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented: Average Quarterly & Illustrative Targa NGL Annual Prices Natural Gas $/MMBtu (1) $/gal (2) Crude Oil $/Bbl (3) 2013 4th Quarter $ 3.61 $ 0.92 $ 97.50 3rd Quarter 3.58 0.86 105.82 2nd Quarter 4.10 0.81 94.23 1st Quarter 3.34 0.86 94.35 2013 Average 3.65 0.86 97.98 2012 4th Quarter $ 3.41 $ 0.88 $ 88.23 3rd Quarter 2.80 0.86 92.20 2nd Quarter 2.21 0.94 93.35 1st Quarter 2.72 1.18 103.03 2012 Average 2.79 0.97 94.20 2011 4th Quarter $ 3.54 $ 1.37 $ 91.88 3rd Quarter 4.20 1.37 89.54 2nd Quarter 4.32 1.36 102.34 1st Quarter 4.11 1.23 94.60 2011 Average 4.04 1.33 94.59 -------------------------------------------------------------------------------- (1) Natural gas prices are based on average quarterly and annual prices from Henry Hub I-FERC commercial index prices.

(2) NGL prices are based on quarterly and annual averages of prices from Mont Belvieu Non-TET monthly commercial index prices. Illustrative Targa NGL contains 44% ethane, 30% propane, 11% natural gasoline, 5% isobutane and 10% normal butane.

(3) Crude oil prices are based on quarterly and annual averages of daily prices from West Texas Intermediate commercial index prices as measured on the NYMEX.

Contract Terms, Contract Mix and the Impact of Commodity Prices Because of the potential for significant volatility of natural gas and NGL prices, the contract mix of our Gathering and Processing division, other than fee-based contracts in Badlands and certain other gathering and processing services, can have a material impact on our profitability, especially those contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of the commodities handled ("equity volumes").

Contract terms in the Gathering and Processing division are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive commodities and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors. For example, our Badlands crude and natural gas contracts are essentially 100% fee-based.

The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. During periods of low relative demand for available fractionation capacity, rates were low and frac-or-pay contracts were not readily available. The current demand for fractionation services has grown resulting in increases in fractionation fees and contract term. In addition, reservation fees are required. Increased demand for export services also supports fee-based contracts. Contracts in the Logistics Assets segment are primarily fee-based arrangements while the Marketing and Distribution segment includes both fee-based and percent-of-proceeds contracts.

61 -------------------------------------------------------------------------------- Table of Contents Impact of Our Commodity Price Hedging Activities In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas equity volumes through 2016 and our NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps. With these arrangements, we have attempted to mitigate some of our exposure to commodity price movements with respect to our forecasted volumes for these periods. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing NGL prices. For additional information regarding our hedging activities, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk- Commodity Price Risk." Operating Expenses Variable costs such as fuel, utilities, power, service and repairs can impact our results as volumes fluctuate through our systems. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company and an indirect wholly-owned subsidiary of Targa. We reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to our assets.

General and Administrative Expenses Our partnership agreement with Targa, our general partner, addresses the reimbursement of costs incurred on our behalf and indemnification matters. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Other than Targa's direct costs of being a separate public reporting company, we reimburse these costs. See "Item 13. Certain Relationships and Related Transactions, and Director Independence." General Trends and Outlook We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our services, commodity prices, volatile capital markets and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Demand for Our Services Fluctuations in energy prices can affect production rates and investments by third parties in the development of oil and natural gas reserves. Generally, drilling and production activity will increase as energy prices increase. We believe that the current strength of oil, condensate and NGL prices as compared to natural gas prices has caused producers in and around our gathering and processing areas of operation to focus their drilling programs on regions rich in liquid forms of hydrocarbons. This focus is reflected in increased drilling permits and higher rig counts in these areas, and we expect these activities to lead to higher natural gas and crude oil volumes in the Field Gathering and Processing segment over the next several years. While we expect demand for NGL products to remain strong, a reduction in demand for NGL products, or a significant increase in NGL product supply relative to this demand, could impact our business. Increases in demand for international grade propane, along with expansion in the petrochemical industry, which relies on ethane as a feedstock, point towards sustained demand for our terminaling and storage services in the Downstream Business. Producer activity in areas rich in oil, condensate and NGLs is currently generating increased demand for our fractionation services and for related fee-based services provided by our Downstream Business. While we expect development activity to remain robust with respect to oil and liquids-rich gas development and production, currently depressed natural gas prices have resulted in reduced activity levels surrounding comparatively dry natural gas reserves, whether conventional or unconventional.

62 -------------------------------------------------------------------------------- Table of Contents Commodity Prices There has been and we believe there will continue to be significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems.

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing, the supply of and market demand for natural gas, NGLs and condensate, which are beyond our control and have been volatile. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigate our exposure to commodity price movements by entering into hedging arrangements. For additional information regarding our hedging activities, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk." Volatile Capital Markets We are dependent on our ability to access the equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are expected to continue to be, volatile and disrupted and weak economic conditions may cause a significant decline in commodity prices. As a result, we may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.

Increased Regulation Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Please read "Risk Factors-Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets." Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations. Please read "Risk Factors-The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other types of risks associated with our business." Distributions to our Unitholders We intend to make cash distributions to our unitholders and our general partner of at least the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of December 31, 2013, such annual minimum amounts would have been approximately $153.3 million.

In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate.

63 -------------------------------------------------------------------------------- Table of Contents For the year ended December 31, 2013 compared to 2012, total distributions paid increased by $112.0 million. For the year ended December 31, 2012 compared to 2011, total distributions increased by $60.1 million. The following table shows the distributions for the years presented: Distributions Limited Distributions Partners General Partner per Limited Date Paid or to Three Months Ended be Paid Common Incentive 2% Total Partner Unit (In millions,except per unit amounts) 2013 February 14, December 31, 2013 2014 $ 84.0 $ 29.5 $ 2.3 $ 115.8 $ 0.7475 November 14, September 30, 2013 2013 79.4 26.9 2.2 108.5 0.7325 June 30, 2013 August 14, 2013 75.8 24.6 2.0 102.4 0.7150 March 31, 2013 May 15, 2013 71.7 22.1 1.9 95.7 0.6975 2012 February 14, December 31, 2012 2013 $ 69.0 $ 20.1 $ 1.8 $ 90.9 $ 0.6800 November 14, September 30, 2012 2012 59.1 16.1 1.5 76.7 0.6625 June 30, 2012 August 14, 2012 57.3 14.4 1.5 73.2 0.6425 March 31, 2012 May 15, 2012 55.5 12.7 1.4 69.6 0.6225 2011 February 14, December 31, 2011 2012 $ 53.7 $ 11.0 $ 1.3 $ 66.0 $ 0.6025 November 14, September 30, 2011 2011 49.4 8.8 1.2 59.4 0.5825 June 30, 2011 August 12, 2011 48.3 7.8 1.2 57.3 0.5700 March 31, 2011 May 13, 2011 47.3 6.8 1.1 55.2 0.5575 How We Evaluate Our Operations Our profitability is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has been increasing the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: - gross margin, operating margin, adjusted EBITDA and distributable cash flow.

Throughput Volumes, Facility Efficiencies and Fuel Consumption Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business' fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems' extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

64 -------------------------------------------------------------------------------- Table of Contents As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses Operating expenses are costs associated with the operation of specific assets.

Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval. We have seen a substantial increase in our total capital spent over the last three years and currently have significant internal growth projects that we closely monitor.

Gross Margin We define gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

We define Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate and NGLs (2) natural gas and crude oil gathering and service fee revenues and (3) settlement gains and losses on commodity hedges, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by us and by external users of our financial statements, including investors and commercial banks, to assess: · the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; · our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and 65-------------------------------------------------------------------------------- Table of Contents · the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Adjusted EBITDA We define Adjusted EBITDA as net income attributable to Targa Resources Partners LP before: interest; income taxes; depreciation and amortization; gains or losses on debt repurchases and redemptions, early debt extinguishments and asset disposals; non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Distributable Cash Flow We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs), and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of noncontrolling interests.

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders.

Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

66 -------------------------------------------------------------------------------- Table of Contents Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP.

It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Non-GAAP Financial Measures The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated: 2013 2012 2011 (In millions) Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income: Gross margin $ 1,177.7 $ 1,004.7 $ 948.1 Operating expenses (376.2 ) (313.0 ) (287.0 ) Operating margin 801.5 691.7 661.1 Depreciation and amortization expenses (271.6 ) (197.3 ) (178.2 ) General and administrative expenses (143.1 ) (131.6 ) (127.8 ) Interest expense, net (131.0 ) (116.8 ) (107.7 ) Income tax expense (2.9 ) (4.2 ) (4.3 ) Loss on sale or disposition of assets (3.9 ) (15.6 ) (0.2 ) Loss on debt redemptions and amendments (14.7 ) (12.8 ) - Change in contingent consideration 15.3 - - Other, net 9.0 (10.2 ) 2.6 Targa Resources Partners LP net income $ 258.6 $ 203.2 $ 245.5 67-------------------------------------------------------------------------------- Table of Contents 2013 2012 2011 (In millions) Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA: Net cash provided by operating activities $ 411.4 $ 465.4 $ 400.9 Net income attributable to noncontrolling (25.1 ) (28.6 ) (41.0 ) interests Interest expense, net (1) 115.5 99.2 95.3 Loss on debt redemptions and amendments (14.7 ) (12.8 ) - Change in contingent consideration (15.3 ) - - Current income tax expense 2.0 2.5 3.5 Other (2) (5.0 ) (6.4 ) 7.9 Changes in operating assets and liabilities which used (provided) cash: Accounts receivable and other assets 230.3 (96.1 ) 150.3 Accounts payable and other liabilities (69.9 ) 91.7 (126.1 ) Targa Resources Partners LP Adjusted EBITDA $ 629.2 $ 514.9 $ 490.8 -------------------------------------------------------------------------------- (1) Net of amortization of debt issuance costs, discount and premium included in interest expense of $15.5 million, $17.6 million and $12.4 million for 2013, 2012 and 2011.

(2) Includes equity earnings from unconsolidated investments - net of distributions, accretion expense associated with asset retirement obligations, amortization of stock-based compensation and gain on sale or disposal of assets.

2013 2012 2011 (In millions)Reconciliation of Net Income attributable to Targa Resources Partners LP to Adjusted EBITDA: Net income attributable to Targa Resources $ 233.5 $ 174.6 $ 204.5 Partners LP Interest expense, net 131.0 116.8 107.7 Income tax expense 2.9 4.2 4.3 Depreciation and amortization expenses 271.6 197.3 178.2 Loss on sale or disposition of assets 3.9 15.6 - Loss on debt redemptions and amendments 14.7 12.8 - Change in contingent consideration (15.3 ) - - Risk management activities (0.5 ) 5.4 7.2 Noncontrolling interests adjustment (1) (12.6 ) (11.8 ) (11.1 ) Targa Resources Partners LP Adjusted EBITDA $ 629.2 $ 514.9 $ 490.8 -------------------------------------------------------------------------------- (1) Noncontrolling interest portion of depreciation and amortization expenses.

2013 2012 2011 (In millions) Reconciliation of Net Income attributable to Targa Resources Partners LP to Distributable Cash flow: Net income attributable to Targa Resources Partners LP $ 233.5 $ 174.6 $ 204.5 Depreciation and amortization expenses 271.6 197.3 178.2 Deferred income tax expense 0.9 1.7 0.8 Amortization in interest expense 15.5 17.6 12.4 Loss on debt redemptions and amendments 14.7 12.8 - Change in contingent consideration (15.3 ) - - Loss on sale or disposition of assets 3.9 15.6 - Risk management activities (0.5 ) 5.4 7.2 Maintenance capital expenditures (79.9 ) (67.6 ) (81.8 ) Other (1) (4.1 ) (3.5 ) 15.4 Targa Resources Partners LP distributable cash $ 440.3 $ 353.9 $ 336.7 flow -------------------------------------------------------------------------------- (1) Includes the noncontrolling interest portion of maintenance capital expenditures, depreciation and amortization expenses.

68 -------------------------------------------------------------------------------- Table of Contents Results of Operations The following table and discussion is a summary of our consolidated results of operations: 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 (In millions, except operating statistics and price amounts) Revenues $ 6,556.2 $ 5,883.6 $ 6,987.1 $ 672.6 11 % $ (1,103.5 ) (16 %) Product purchases 5,378.5 4,878.9 6,039.0 499.6 10 % (1,160.1 ) (19 %) Gross margin (1) 1,177.7 1,004.7 948.1 173.0 17 % 56.6 6 % Operating expenses 376.2 313.0 287.0 63.2 20 % 26.0 9 % Operating margin (2) 801.5 691.7 661.1 109.8 16 % 30.6 5 % Depreciation and amortization expenses 271.6 197.3 178.2 74.3 38 % 19.1 11 % General and administrative expenses 143.1 131.6 127.8 11.5 9 % 3.8 3 % Other operating expense 9.6 19.9 0.2 (10.3 ) (52 %) 19.7 NM Income from operations 377.2 342.9 354.9 34.3 10 % (12.0 ) (3 %) Interest expense, net (131.0 ) (116.8 ) (107.7 ) (14.2 ) 12 % (9.1 ) (8 %) Equity earnings 14.8 1.9 8.8 12.9 NM (6.9 ) (78 %) Loss on debt redemptions and amendments (14.7 ) (12.8 ) - (1.9 ) 15 % (12.8 ) - Loss on mark-to-market derivative instruments - - (5.0 ) - - 5.0 100 % Other 15.2 (7.8 ) (1.2 ) 23.0 NM (6.6 ) NM Income tax expense (2.9 ) (4.2 ) (4.3 ) 1.3 (31 %) 0.1 2 % Net income 258.6 203.2 245.5 55.4 27 % (42.3 ) (17 %) Less: Net income attributable to noncontrolling interests 25.1 28.6 41.0 (3.5 ) (12 %) (12.4 ) (30 %) Net income attributable to Targa Resources Partners LP $ 233.5 $ 174.6 $ 204.5 $ 58.9 34 % $ (29.9 ) (15 %) Financial and operating data: Financial data: Adjusted EBITDA (3) $ 629.2 $ 514.9 $ 490.8 $ 114.3 22 % $ 24.1 5 % Distributable cash flow (4) 440.3 353.9 336.7 86.4 24 % 17.2 5 % Capital expenditures 1,034.5 1,612.9 490.0 (578.4 ) (36 %) 1,122.9 229 % Operating data: Crude oil gathered, MBbl/d 46.9 - - 46.9 - - - Plant natural gas inlet, MMcf/d (5)(6) 2,110.2 2,098.3 2,162.1 11.9 1 % (63.8 ) (3 %) Gross NGL production, MBbl/d 136.8 128.7 123.9 8.1 6 % 4.8 4 % Export volumes, MBbl/d (7) 66.6 31.6 17.2 35.0 111 % 14.4 84 % Natural gas sales, BBtu/d (6) 928.2 927.6 779.3 0.6 0 % 148.3 19 % NGL sales, MBbl/d 316.6 284.5 269.6 32.1 11 % 14.9 6 % Condensate sales, MBbl/d 3.5 3.5 3.0 - 0 % 0.5 17 % -------------------------------------------------------------------------------- (1) Gross margin is a non-GAAP financial measure and is discussed under "Management's Discussion and Analysis of Financial Condition and Results of Operations - How We Evaluate Our Operations" and "Non-GAAP Financial Measures." (2) Operating margin is a non-GAAP financial measure and is discussed under "Management's Discussion and Analysis of Financial Condition and Results of Operations - How We Evaluate Our Operations" and "Non-GAAP Financial Measures." (3) Adjusted EBITDA is net income attributable to Targa Resources LP before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and debt redemptions, early debt extinguishments and asset disposals, non-cash risk management activities related to derivative instruments and changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. This is a non-GAAP financial measure and is discussed under "Management's Discussion and Analysis of Financial Condition and Results of Operations - How We Evaluate Our Operations" and "Non-GAAP Financial Measures." (4) Distributable cash flow is income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. This is a non-GAAP financial measure and is discussed under "Management's Discussion and Analysis of Financial Condition and Results of Operations - How We Evaluate Our Operations" and "Non-GAAP Financial Measures." 69-------------------------------------------------------------------------------- Table of Contents (5) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume.

(6) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(7) Export volumes represent the quantity of NGL products delivered to third party customers at our Galena Park Marine terminal that are destined for international markets.

2013 Compared to 2012 Revenues, including the impact of hedging, increased due to the impact of higher commodity volumes ($446.9 million), higher realized prices on natural gas, condensate, and petroleum products ($261.2 million) and higher fee-based and other revenues ($227.8 million), offset by lower realized prices on NGLs ($263.2 million).

Higher consolidated gross margin in 2013 includes the contribution of our Badlands acquisition. Other favorable gross margin factors were increased volumes from system expansions and higher gas prices in our Field Gathering and Processing segment and higher fractionation fees and increased export activities in our Logistics and Marketing segments. This significant growth in our asset base brought a higher level of operating expenses in 2013. See "-Results of Operations-By Reportable Segment" for additional information regarding changes in the components of gross and operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to tangible and intangible assets acquired in the Badlands acquisition and the timing of major organic investments placed in service including CBF Train 4, Phase I of the international export expansion project, and Badlands expansion.

General and administrative expenses increased, reflecting increased compensation related costs to support our expanding business operations.

Other operating expense in 2013 includes the Versado joint venture cost of repairs less amounts covered by insurance ($4.0 million) related to a fire at the Saunders plant. Other operating expense in 2012 reflects a $15.4 million loss due to a write-off of our investment in the Yscloskey joint venture processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant. Additionally, other operating (income) expense in 2012 includes $3.6 million in costs associated with the clean-up and repairs necessitated by Hurricane Isaac at our Coastal Straddle plants.

The increase in interest expense primarily reflects higher borrowings ($36.2 million), partially offset by the impact of lower effective interest rates ($7.7 million) and increases in capitalized interest attributable to our major expansion projects ($14.4 million).

The increase in equity earnings relates to our investment in GCF, which was profitable in 2013 compared to a loss in 2012 due to a planned shutdown of operations related to the expansion of the facility.

Losses on debt redemptions and amendments during 2013 are attributable to premiums paid and write-off of debt issue costs in connection with the redemption of the outstanding balance of the 11¼% Notes and the redemption of $100 million of the Partnership's 6?% Notes.

The increase in other income was attributable to the elimination of the contingent consideration associated with the Badlands acquisition, reflecting management's current assessment that the stipulated volumetric thresholds will not be met.

Net income attributable to noncontrolling interests declined during 2013, as the impact of lower earnings at our Versado and VESCO joint ventures more than offset the impact of higher earnings at CBF.

2012 Compared to 2011 Revenues, including the impacts of hedging, decreased due to the impact of lower realized prices on commodities ($1,962.9 million), partially offset by higher commodity sales volumes ($769.6 million) and higher fee-based and other revenues ($89.8 million).

70 -------------------------------------------------------------------------------- Table of Contents The increase in gross margin reflects lower revenues more than offset by lower product purchases. See "-Results of Operations-By Reportable Segment" for additional information regarding changes in the components of gross and operating margin on a disaggregated basis.

The increase in operating expenses reflects expansion and acquisition activities. See "-Results of Operations-By Reportable Segment" for additional discussion regarding changes in operating expenses.

The increase in depreciation and amortization expenses is attributable to the impact of new assets placed in service as well as assets associated with business acquisitions.

General and administrative expenses increased due to higher compensation and benefits.

Other operating expense in 2012 relates to the Yscloskey plant closure and Hurricane Isaac clean-up and repair costs as discussed above.

The increase in interest expense primarily reflects higher borrowings ($22.3 million), which was offset by the impact of lower effective interest rates ($3.0 million) and increases in capitalized interest that was attributable to our major expansion projects ($10.2 million).

Lower equity earnings from our non-operated GCF equity investment resulted from the planned shutdown of operations associated with 43 MBbl/d capacity expansion project. GCF operations were also affected by start-up issues associated with the expansion.

Losses on a debt redemption and amendment during 2012 are largely attributable to premiums and write-off of debt issue costs in connection with the redemption of the Partnership's 8¼% Senior Notes due 2016 (the "8¼% Notes") and the amendment to the TRP Revolver. See Note 10 of the "Consolidated Financial Statements" of this Annual Report for additional details.

The mark-to-market loss in 2011 was attributable to interest rate swaps that were de-designated as hedging instruments during the second quarter of that year. Consequently, we discontinued hedge accounting on those swaps, and all subsequent changes in fair value settlements were recorded as mark-to-market losses until September 2011 when we terminated all of our interest rate swaps.

The increase in other expenses is attributable to fees and expenses related to completing the Badlands acquisition.

The decrease in net income attributable to noncontrolling interests reflects the impact of the weaker price environment on our Versado and VESCO joint ventures, as well as the disruption of operations at VESCO due to Hurricane Isaac. These factors were partially offset by increased net income at CBF.

Results of Operations-By Reportable Segment Our operating margins by reportable segment are: Field Coastal Gathering Gathering Marketing and and Logistics and Processing Processing Assets Distribution Other Total (In millions) 2013 $ 270.5 $ 85.4 $ 282.3 $ 141.9 $ 21.4 $ 801.5 2012 231.2 115.1 188.3 116.0 41.1 691.7 2011 287.9 174.3 123.1 113.4 (37.6 ) 661.1 71-------------------------------------------------------------------------------- Table of Contents Gathering and Processing Segments Field Gathering and Processing 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 ($ in millions, except operating statistics and price amounts) Gross margin $ 435.7 $ 357.4 $ 403.6 $ 78.3 22 % $ (46.2 ) (11 %) Operating expenses 165.2 126.2 115.7 39.0 31 % 10.5 9 % Operating margin $ 270.5 $ 231.2 $ 287.9 $ 39.3 17 % $ (56.7 ) (20 %) Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) Sand Hills 155.8 145.2 134.2 10.6 7 % 11.0 8 % SAOU 154.1 124.8 111.0 29.3 23 % 13.8 12 % North Texas System 292.4 244.5 203.5 47.9 20 % 41.0 20 % Versado 156.4 167.4 162.8 (11.0 ) (7 %) 4.6 3 % Badlands (4) 21.4 - - 21.4 - - - 780.1 681.9 611.5 98.2 14 % 70.4 12 % Gross NGL production, MBbl/d (3) Sand Hills 17.5 16.9 15.7 0.6 4 % 1.2 8 % SAOU 22.5 19.2 17.4 3.3 17 % 1.8 10 % North Texas System 31.1 26.8 22.9 4.3 16 % 3.9 17 % Versado 18.9 19.7 18.2 (0.8 ) (4 %) 1.5 8 % Badlands 1.9 - - 1.9 - - - 91.9 82.6 74.2 9.3 11 % 8.4 11 % Crude oil gathered, MBbl/d 46.9 - - 46.9 - - - Natural gas sales, BBtu/d (3) 376.3 325.0 285.5 51.3 16 % 39.5 14 % NGL sales, MBbl/d 71.4 68.5 59.8 2.9 4 % 8.7 15 % Condensate sales, MBbl/d 3.2 3.2 2.8 - 0 % 0.4 14 % Average realized prices (5): Natural gas, $/MMBtu 3.44 2.60 3.80 0.84 32 % (1.20 ) (32 %) NGL, $/gal 0.76 0.87 1.23 (0.11 ) (13 %) (0.36 ) (29 %) Condensate, $/Bbl 92.89 88.49 91.55 4.40 5 % (3.06 ) (3 %) -------------------------------------------------------------------------------- (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the year and the denominator is the number of calendar days during the year.

(2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4) Badlands natural gas inlet represents the total wellhead gathered volume.

(5) Average realized prices exclude the impact of hedging settlements presented in Other.

2013 Compared to 2012 The increase in gross margin was primarily due to the inclusion of Badlands operations in 2013, higher overall throughput volumes and higher natural gas and condensate sales prices partially offset by lower NGL sales prices. The increase in plant inlet volumes was largely attributable to new well connects which increased available supply across each of our areas of operations, offset by the Saunders fire at Versado and by other operational issues and severe cold weather.

The increase in operating expenses was primarily due to the inclusion of Badlands operations in 2013 and additional compression and system maintenance related expenses attributable to increased volumes across our business and system expansions.

72 -------------------------------------------------------------------------------- Table of Contents 2012 Compared to 2011 The decrease in gross margin was primarily due to lower commodity sales prices, partially offset by higher throughput volumes. The increase in plant inlet volumes was largely attributable to new well connects, particularly North Texas, Sand Hills and SAOU, partially offset by pipeline curtailments and operational issues.

The increase in operating expenses was primarily due to additional compression related expenses due to system expansions and higher system maintenance and repair costs.

Coastal Gathering and Processing 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 ($ in millions, except operating statistics and price amounts) Gross margin $ 132.3 $ 162.2 $ 221.6 $ (29.9 ) (18 %) $ (59.4 ) (27 %) Operating expenses 46.9 47.1 47.3 (0.2 ) 0 % (0.2 ) 0 % Operating margin $ 85.4 $ 115.1 $ 174.3 $ (29.7 ) (26 %) $ (59.2 ) (34 %) Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) LOU (4) 350.9 260.6 175.7 90.3 35 % 84.9 48 % VESCO 515.5 479.6 498.5 35.9 7 % (18.9 ) (4 %) Other Coastal Straddles 463.7 676.2 876.4 (212.5 ) (31 %) (200.2 ) (23 %) 1,330.1 1,416.4 1,550.6 (86.3 ) (6 %) (134.2 ) (9 %) Gross NGL production, MBbl/d (3) LOU 10.2 8.6 7.4 1.6 19 % 1.2 16 % VESCO 21.5 22.1 25.9 (0.6 ) (3 %) (3.8 ) (15 %) Other Coastal Straddles 13.2 15.4 16.5 (2.2 ) (14 %) (1.1 ) (7 %) 44.9 46.1 49.8 (1.2 ) (3 %) (3.7 ) (7 %) Natural gas sales, BBtu/d (3) 296.0 298.5 268.4 (2.5 ) (1 %) 30.1 11 % NGL sales, MBbl/d 41.8 42.5 43.5 (0.7 ) (2 %) (1.0 ) (2 %) Condensate sales, MBbl/d 0.4 0.3 0.3 0.1 19 % - 0 % Average realized prices: Natural gas, $/MMBtu 3.73 2.78 4.02 0.95 34 % (1.24 ) (31 %) NGL, $/gal 0.83 0.96 1.31 (0.13 ) (14 %) (0.35 ) (27 %) Condensate, $/Bbl 104.38 103.57 105.10 0.81 1 % (1.53 ) (1 %) -------------------------------------------------------------------------------- (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the year and the denominator is the number of calendar days during the year.

(2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4) Includes volumes from the Big Lake processing plant acquired in July 2012.

2013 Compared to 2012 The decrease in gross margin was primarily due to lower NGL prices, less favorable frac spread and lower throughput volumes at VESCO and the Other Coastal Straddles. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes and the impact of the Yscloskey, Calumet and other third-party plant shutdowns. In addition, volumes were constrained by operational issues at VESCO and LOU. This volume decrease was partially offset by the addition of the Big Lake plant in the third quarter 2012 and 2012 volumes also reflect the shutdown of Coastal Straddle plant operations during Hurricane Isaac. Operational issues at VESCO included the impact of damage to one of the two third-party pipelines that provide NGL takeaway capacity for VESCO which constrained NGL production until repairs were completed in June 2013.

73 -------------------------------------------------------------------------------- Table of Contents Operating expenses were relatively flat.

2012 Compared to 2011 The decrease in gross margin was primarily due to lower commodity sales prices, less favorable frac spread and lower throughput volumes. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes and planned operational outages at VESCO in the second quarter of 2012, as well as the impact of Hurricane Isaac in the third quarter of 2012 and the post-Isaac shutdown of the Yscloskey plant. The volume decreases were partially offset by increased LOU supply volumes, the July 2012 acquisition of the Big Lake plant and gas purchased for processing at VESCO and Lowry. NGL production and sales at LOU increased on higher throughput volumes, partially offset by lower average system liquids content of the natural gas. Natural gas sales volumes increased due to an increase in demand from industrial customers.

Operating expenses were relatively flat as higher system maintenance and repair costs at VESCO were offset by operating cost reductions attributable to the Yscloskey and Calumet plant shutdowns in 2012.

Logistics and Marketing Segments Logistics Assets 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 ($ in millions, except operating statistics) Gross margin $ 408.2 $ 286.0 $ 221.1 $ 122.2 43 % $ 64.9 29 % Operating expenses 125.9 97.7 98.0 28.2 29 % (0.3 ) 0 % Operating margin $ 282.3 $ 188.3 $ 123.1 $ 94.0 50 % $ 65.2 53 % Operating statistics MBbl/d (1): Fractionation volumes 287.6 299.2 268.4 (11.6 ) (4 %) 30.8 11 % LSNG treating volumes 20.1 22.4 15.3 (2.3 ) (10 %) 7.1 46 % Benzene treating volumes 17.5 19.0 - (1.5 ) (8 %) 19.0 - -------------------------------------------------------------------------------- (1) For all volume statistics presented, the numerator is the total volume during the year and the denominator is the number of calendar days during the year.

2013 Compared to 2012 Gross margin increased primarily due to fractionation operations and LPG export activity. The lower year-to-date 2013 fractionation volumes were due to the planned maintenance turnaround at the Cedar Bayou Facility, ethane rejection at certain gas processing plants and pipeline operating issues at non-Partnership facilities. Improvements in 2013 resulted from higher fractionation fees, CBF Train 4 which commenced commercial operations during the third quarter of 2013 and higher contractual capacity reservation fees. Gross margin results also include the impact of higher fuel prices which pass through to operating expenses. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 67 MBbl/d in 2013, compared to 32 MBbl/d for the previous year. The higher volumes reflect a significant increase in ongoing LPG export activity primarily due to our international export expansion project, which was placed into service in September 2013. Terminaling rates per unit volume were also higher and storage revenues increased due to increased rates and new customers. Gross margin for 2013 also benefitted from the renewable fuels project in our Petroleum Logistics business.

The increase in operating expenses primarily reflects increased power and fuel prices (which have a corresponding impact on fractionating and treating fee revenues); expenses related to the start-up and operations of Train 4 at CBF and increased maintenance costs, partially offset by higher system product gains.

74 -------------------------------------------------------------------------------- Table of Contents 2012 Compared to 2011 The increase in gross margin was primarily due to increased export and storage fee revenue, higher treating volumes, increased petroleum logistics activities and higher fractionation volumes. Export and storage fees increased due to higher export shipments. Treating fees increased due to the operational startup of the benzene treating and de-pentanizer units in the first quarter of 2012 and increased hydrotreating fees associated with increased volumes in 2012.

Terminaling gross margin for 2012 improved as a result of the impact of the October 2011 Sound Terminal acquisition. Higher fractionation volumes and fees were primarily attributable to the CBF Train 3 expansion, which came on line in mid-year 2011, partially offset by the impact of lower fuel prices which pass through to expenses.

Operating expenses were essentially flat as favorable system product gains and lower fuel costs (which have a corresponding impact on fractionation revenues) were offset by higher operating costs due to greater hydrotreating, benzene and de-pentanizer unit run-times, higher maintenance activities and the impact of a full twelve months in 2012 of operating costs associated with petroleum logistics operations acquired in April and October of 2011.

Marketing and Distribution 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 (In millions, except operating statistics and price amounts) Gross margin $ 185.2 $ 154.1 $ 156.4 $ 31.1 20 % $ (2.3 ) (1 %) Operating expenses 43.3 38.1 43.0 5.2 14 % (4.9 ) (11 %) Operating margin $ 141.9 $ 116.0 $ 113.4 $ 25.9 22 % $ 2.6 2 % Operating statistics (1): NGL sales, MBbl/d 318.4 289.8 272.5 28.6 10 % 17.3 6 % Average realized prices: NGL realized price, $/gal 0.93 0.98 1.34 (0.05 ) (5 %) (0.36 ) (27 %) -------------------------------------------------------------------------------- (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.

2013 Compared to 2012 Gross margin increased primarily due to significantly higher terminaling fees from LPG export activity (which benefit both the Logistics Assets and Marketing and Distribution segments). The favorable impacts of higher barge and wholesale terminal utilization and of higher wholesale margins were offset by lower natural gas marketing processing opportunities during 2013.

Operating expenses increased primarily due to higher barge and truck utilization and increased terminal operating costs.

2012 Compared to 2011 Gross margin decreased primarily due to a much weaker price environment and lower barge activity in 2012, partially offset by increased LPG export activity, increased trucking activity, favorable short-term wholesale propane marketing opportunities and higher NGL and natural gas sales volumes.

Operating expenses decreased due to lower barge activity, partially offset by increased truck operating costs.

75 -------------------------------------------------------------------------------- Table of Contents Other 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 ($ in millions) Gross margin $ 21.4 $ 41.1 $ (37.6 ) $ (19.7 ) $ 78.7 Operating margin $ 21.4 $ 41.1 $ (37.6 ) $ (19.7 ) $ 78.7 Other contains the financial effects of our hedging program on operating margin.

It typically represents the cash settlements on our derivative contracts. Other also includes deferred gains or losses on previously terminated or de-designated hedge contracts that are reclassified to revenues upon the occurrence of the underlying physical transactions.

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from its percent-of-proceeds or liquids processing arrangements by entering into derivative instruments.

The following table provides a breakdown of our hedge revenue by product: 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 ($ in millions) Natural gas $ 11.2 $ 33.8 $ 21.2 $ (22.6 ) $ 12.6 NGL 12.8 9.1 (53.1 ) 3.7 62.2 Crude oil (2.6 ) (1.8 ) (5.7 ) (0.8 ) 3.9 $ 21.4 $ 41.1 $ (37.6 ) $ (19.7 ) $ 78.7 Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices.

Liquidity and Capital Resources Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include weather, commodity prices (particularly for natural gas and NGLs) and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under the TRP Revolver, borrowings under the Securitization Facility, the issuance of additional common units and access to debt markets. The capital markets continue to experience volatility. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. We continually monitor our liquidity and the credit markets, as well as events and circumstances surrounding each of the lenders to the TRP Revolver and Securitization Facility.

76 -------------------------------------------------------------------------------- Table of Contents As of January 31, 2014, our liquidity consisted of the following: January 31, 2014 (In millions) Cash on hand $ 133.4 Total availability under the TRP Revolver 1,200.0 Total availability under the Securitization Facility 270.5 1,603.9 Less: Outstanding borrowings under the TRP Revolver (365.0 ) Outstanding borrowings under the Securitization Facility (270.5 ) Outstanding letters of credit under the TRP Revolver (95.3 ) Total liquidity $ 873.1 In addition to amounts in the table above, the TRP Revolver allows us to request an additional $300.0 million in commitment increases. We may also issue additional equity or debt securities under our outstanding shelf registration statements to assist us in meeting future liquidity and capital spending requirements (see Notes 10 and 11 of the "Consolidated Financial Statements").

The April 2013 Shelf provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expires in April 2016. As of February 10, 2014, there had been no activity under the April 2013 Shelf.

The July 2013 Shelf allows us to issue up to an aggregate of $800 million of debt or equity securities. The July 2013 Shelf expires in August 2016. As of February 10, 2014, we have the ability to sell additional debt or equity securities up to an aggregate amount of $515.3 million under the July 2013 Shelf.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy certain counterparty credit requirements. While our credit ratings have improved over time, these letters of credit reflect our non-investment grade status, as assigned to us by Moody's Investors Service, Inc. and Standard & Poor's Corporation and counterparties' views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of December 31, 2013, we had $86.8 million in letters of credit outstanding.

Risk Management We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas equity volumes through 2016 and our NGL and condensate equity volumes through 2014. See "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk." The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Our risk management position has moved from a net asset position of $22.2 million at December 31, 2012 to a net liability position of $4.3 million at December 31, 2013. Aggregate forward prices for commodities are above the fixed prices we currently expect to receive on those derivative contracts, creating this net liability position. We account for derivatives that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income ("OCI") until the underlying hedged transactions settle.

77 -------------------------------------------------------------------------------- Table of Contents Working Capital Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced with receivables from NGL customers offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

For 2013, our working capital increased $88.0 million, primarily due to the international export project which requires higher levels of accounts receivable and inventory, partially offset by an increase in accounts payable related to third party propane purchases. Other changes included decreases in affiliate payables due to the timing of reimbursements between Targa and us, decreases in the cash balance, and decreases in current liabilities due to the reversal of the Badlands contingent liability, partially offset by increased gas plant producer settlement payables due to higher commodity prices and higher volumes.

Our net risk management working capital position also decreased due to changes in the forward prices of commodities.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from equity offerings and debt offerings should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.

Cash Flow The following table and discussion summarize our consolidated cash flows provided by or used in operating activities, investing activities and financing activities: 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 (In millions) Net cash provided by (used in): Operating activities $ 411.4 $ 465.4 $ 400.9 $ (54.0 ) $ 64.5 Investing activities (1,026.3 ) (1,593.8 ) (506.1 ) 567.5 (1,087.7 ) Financing activities 604.4 1,140.8 84.5 (536.4 ) 1,056.3 Cash Flow from Operating Activities Our Consolidated Statement of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented.

78 -------------------------------------------------------------------------------- Table of Contents The following table displays our operating cash flows using the direct method as a supplement to the presentation in our financial statements: 2013 2012 2011 2013 vs. 2012 2012 vs. 2011 (In millions) Cash flows from operating activities: Cash received from customers $ 6,388.3 $ 5,948.9 $ 6,916.0 $ 439.4 $ (967.1 ) Cash received from (paid to) derivative counterparties 20.9 47.3 (56.6 ) (26.4 ) 103.9 Cash outlays for: Product purchases (5,364.8 ) (4,972.9 ) (5,960.1 ) (391.9 ) 987.2 Operating expenses (377.3 ) (339.6 ) (286.1 ) (37.7 ) (53.5 ) General and administrative expenses (145.3 ) (117.8 ) (124.1 ) (27.5 ) 6.3 Cash distributions from equity investment (1) 12.0 1.8 8.3 10.2 (6.5 ) Interest paid, net of amounts capitalized (2) (119.1 ) (92.5 ) (92.7 ) (26.6 ) 0.2 Income taxes paid (2.3 ) (2.2 ) (2.5 ) (0.1 ) 0.3 Other cash receipts (payments) (1.0 ) (7.6 ) (1.3 ) 6.6 (6.3 ) Net cash provided by operating activities $ 411.4 $ 465.4 $ 400.9 $ (54.0 ) $ 64.5 -------------------------------------------------------------------------------- (1) Excludes $0.5 million included in investing activities for 2012 related to distributions from GCF that exceeded cumulative equity earnings. We did not have distributions that exceeded cumulative equity earnings for 2013 and 2011 (2) Net of capitalized interest paid of $28.0 million, $13.6 million and $3.4 million included in investing activities for 2013, 2012 and 2011.

Higher natural gas prices, higher plant throughput volumes and increased export activities contributed to increased cash collections in 2013 compared to 2012, as well as higher cash payments to producers and for commodity products. The change in cash received related to derivatives reflects higher aggregate commodity prices paid to counterparties compared to the aggregate fixed price we received on those derivative contracts. The decrease in other cash payments during 2013 was mainly attributable to the fees related to the Badlands acquisition paid in 2012.

Lower aggregate commodity prices were the primary factor in the changes in cash from customers, cash from derivative contracts, and cash paid for purchases in 2012 compared to 2011. In 2012, our derivative settlements were a net cash inflow, as opposed to a net outflow for 2011. The change in cash received from derivative counterparties reflects lower commodity prices compared to the higher fixed price we received on those derivative contracts. The increase in cash payments in other cash receipts (payments) during 2012 was mainly attributable to the fees related to the Badlands acquisition.

Cash Flow from Investing Activities The decrease in net cash used in investing activities for 2013 compared to 2012 was primarily due to a decrease in outlays for business acquisitions of $996.2 million and the absence of capital calls in 2013 at GCF ($16.8 million), partially offset by an increase in current capital expansion projects of $413.9 million and the purchase of material and supplies of $17.7 million related to our Badlands expansion.

The increase in net cash used in investing activities for 2012 compared to 2011 was primarily due to an increase in outlays for business acquisitions of $839.7 million and current capital expansion projects of $289.0 million, partially offset by lower maintenance capital expenditures of $5.8 million.

Cash Flow from Financing Activities The decrease in net cash provided by financing activities for 2013 compared to 2012 was primarily due to a reduction in net borrowing under the TRP Revolver ($347.0 million), lower long-term issuance of Senior Notes ($375.0 million) and an increase in distributions to owners ($111.6 million), offset by higher net borrowings under the Securitization Facility of $279.7 million.

The increase in net cash provided by financing activities for 2012 compared to 2011 was primarily due to increased long-term debt borrowings of $874.3 million and proceeds from our issuance of common units of $250.4 million, partially offset by an increase in distributions to owners of $47.1 million.

79-------------------------------------------------------------------------------- Table of Contents Our primary financing activities during the periods are summarized in the following tables.

2013 Financing Activity Source (Use) Use of proceeds (In millions) May Issuance of the 4¼% Notes in $ 618.1 Redeem borrowings under 11¼% May 2013 Notes; reduce outstanding borrowings under TRP Revolver and for general Partnership purposes June Redemption of $100.0 million (106.4 ) face - 6?% Notes July Redemption of $72.7 million (76.8 ) face - 11¼% Note Various Net repayments under TRP (225.0 ) Revolver Various Sale of common units - 2012 and 517.9 Redeem borrowings under 6?% 2013 EDAs Notes, reduce outstanding borrowings under TRP Revolver and general Partnership purposes Various General partner contributions 10.8 to maintain 2% interest Reduce outstanding borrowings under the TRP Revolver and for Various Net borrowings under the 279.7 general Partnership purposes Securitization Facility 2012 Financing Activity Source (Use) Use of proceeds (In millions) January Sale of common units in a $ 164.9 Reduce outstanding borrowings public offering under the TRP Revolver and for general Partnership purposes January Issuance of the 6?% Notes 400.0 October Issuance of the 5¼% Senior 400.0 Redeem remaining 8¼% Senior Notes due 2023 Notes and reduce borrowings under the TRP Revolver November/ Sale of common units in a 378.6 Partially fund the Badlands December public offering acquisition December Issuance of additional 5¼% 200.0 Partially fund the Badlands Senior Notes due 2023 acquisition Various Net borrowings under TRP 122.0 Revolver Reduce outstanding borrowings under the TRP Revolver and for Various General partner contributions 11.4 general Partnership purposes to maintain 2% interest 2011 Financing Activity Source (Use) Use of proceeds (In millions) January/ Sale of common units in a $ 298.0 Reduce outstanding borrowings February public offering under the TRP Revolver and for general Partnership purposes February Issuance of 6?% Notes 318.8 February Exchanged $158.6 million 158.6 Reduce outstanding borrowings principal amount of our 6?% under the11¼% Notes Notes for $158.6 million principal amount of our 11¼% Notes Various General partner contributions 6.3 Reduce outstanding borrowings to maintain 2% interest under the TRP Revolver and for general Partnership purposes Distributions to our Unitholders We distribute all available cash from our operating surplus. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Notes 10 and 11 of the "Consolidated Financial Statements" included in this Annual Report.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of December 31, 2013, such annual minimum amount would have been approximately $153.3 million.

In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate. The quarterly distribution per limited partner unit to be paid in February 2014 for the fourth quarter of 2013 is $0.7475 per limited partner unit.

80 -------------------------------------------------------------------------------- Table of Contents The following table details the distributions declared and/or paid during 2013, 2012 and 2011: Distributions Limited Distributions Partners General Partner per Limited Date Paid or toThree Months Ended be Paid Common Incentive 2% Total Partner Unit (In millions, except per unit amounts) 2013 February 14, December 31, 2013 2014 $ 84.0 $ 29.5 $ 2.3 $ 115.8 $ 0.7475 November 14, September 30, 2013 2013 79.4 26.9 2.2 108.5 0.7325 June 30, 2013 August 14, 2013 75.8 24.6 2.0 102.4 0.7150 March 31, 2013 May 15, 2013 71.7 22.1 1.9 95.7 0.6975 2012 February 14, December 31, 2012 2013 $ 69.0 $ 20.1 $ 1.8 $ 90.9 $ 0.6800 November 14, September 30, 2012 2012 59.1 16.1 1.5 76.7 0.6625 June 30, 2012 August 14, 2012 57.3 14.4 1.5 73.2 0.6425 March 31, 2012 May 15, 2012 55.5 12.7 1.4 69.6 0.6225 2011 February 14, December 31, 2011 2012 $ 53.7 $ 11.0 $ 1.3 $ 66.0 $ 0.6025 November 14, September 30, 2011 2011 49.4 8.8 1.2 59.4 0.5825 June 30, 2011 August 12, 2011 48.3 7.8 1.2 57.3 0.5700 March 31, 2011 May 13, 2011 47.3 6.8 1.1 55.2 0.5575 Capital Requirements Our capital requirements relate to capital expenditures, which are classified as expansion expenditures, maintenance expenditures or business acquisitions.

Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

2013 2012 2011 Capital expenditures : (In millions) Business acquisitions, net of cash acquired $ - $ 996.2 $ 156.5 Expansion (1) 954.6 540.7 251.7 Maintenance 79.9 76.0 81.8 Gross additions 1,034.5 1,612.9 490.0 Transfers from materials and supplies to property, plant and equipment (20.5 ) - - Change in capital project payables and accruals (0.4 ) (34.4 ) (4.8 ) Cash outlays for capital projects $ 1,013.6 $ 1,578.5 $ 485.2 -------------------------------------------------------------------------------- (1) Excludes our investment in GCF of $16.8 million and $21.2 million for 2012 and 2011, which is accounted for as an equity investment. We did not have additional investment in GCF for 2013. Cash calls for expansion are reflected in Investment in unconsolidated affiliate in cash flows from investing activities on our Consolidated Statements of Cash Flows in our "Consolidated Financial Statements." We estimate that our total growth capital expenditures for 2014 will be approximately $650 million on a gross basis, and maintenance capital expenditures net to our interest will be approximately $90 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under the TRP Revolver and the Securitization Facility and proceeds from issuances of additional equity and debt offerings. Major organic growth projects for 2014 include: · International Exports. We have commenced construction of Phase II of our international export expansion project at our Mont Belvieu facility and the Galena Park Marine Terminal. Phase II will further expand our propane and butane international export capacity by approximately 2 MMBbl per month, with an expected completion during the third quarter of 2014. We expect that the total cost of both phases of our international export project to be approximately $480 million.

81-------------------------------------------------------------------------------- Table of Contents · Badlands expansion program. During 2014, we anticipate that we will invest another $180 million for further expansion of our gathering and processing assets in North Dakota.

· North Texas Longhorn plant. We have started construction of a new 200 MMcf/d cryogenic processing plant for North Texas to meet increasing production and continued producer activity, with an anticipated completion in mid-2014. We expect to invest an estimated $180 million for the plant and associated projects.

· SAOU High Plains plant. We have started construction of a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin, with an anticipated completion date in mid-2014. We expect to invest an estimated $225 million for the plant and associated projects.

Additionally, we expect to have other growth capital expenditures in 2014 related to the continued build out of our gathering and processing systems and logistics capabilities.

Credit Facilities and Long-Term Debt The following table summarizes our debt obligation as of December 31, 2013 (in millions): Partnership Obligations Senior secured revolving credit facility, due October 2017 $ 395.0 Senior unsecured notes, 7?% fixed rate, due July 2018 250.0 Senior unsecured notes, 6?% fixed rate, due July 2021 483.6 Unamortized discount (28.0 ) Senior unsecured notes, 6?% fixed rate, due August 2022 300.0 Senior unsecured notes, 5¼% fixed rate, due May 2023 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 625.0 Accounts receivable Securitization Facility, due January 2014 279.7 Total long-term debt $ 2,905.3 Compliance with Debt Covenants As of December 31, 2013, we were in compliance with the covenants contained in our various debt agreements.

Revolving Credit Agreement In October 2012, we entered into a Second Amended and Restated Credit Agreement that amends and replaces our existing variable rate Senior Secured Credit Facility due July 2015 (the "Previous Revolver") to provide for the TRP Revolver due October 3, 2017. The TRP Revolver increased available commitments to $1.2 billion from $1.1 billion and allows us to request up to an additional $300.0 million in commitment increases.

For 2013, we had gross borrowings under our TRP Revolver of $1,613.0 million, and repayments totaling $1,838.0 million, for a net decrease for the year ended December 31, 2013 of $225.0 million. The TRP Revolver balance at December 31, 2013 was $395.0 million.

The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America's prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75%. The Eurodollar rate is equal to LIBOR plus an applicable margin ranging from 1.75% to 2.75%.

82 -------------------------------------------------------------------------------- Table of Contents We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% times the actual daily average unused portion of the TRP Revolver.

Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75%.

The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries.

The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).

Senior Unsecured Notes In February 2011, we exchanged $158.6 million principal amount of our 6?% Senior Notes due 2021 (the "6?% Notes") plus payments of $28.6 million including $0.9 million of accrued interest for $158.6 million aggregate principal amount of our 11¼% Notes. The holders of the exchanged Notes are subject to the provisions of the 6?% Notes described below. The debt covenants related to the remaining $72.7 million of face value of the 11¼% Notes were removed. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.

In January 2012, we privately placed $400.0 million in aggregate principal amount of our 6?% Notes. The 6?% Notes resulted in approximately $395.5 million of net proceeds, which were used to reduce the borrowings under the TRP Revolver and for general partnership purposes.

In October 2012, $400.0 million in aggregate principal amount of our 5¼% Notes were issued at 99.5% of the face amount, resulting in gross proceeds of $398.0 million. An additional $200.0 million in aggregate principal amount of our 5¼% Notes were issued in December 2012 at 101.0% of the face amount, resulting in gross proceeds of $202.0 million. Both issuances are treated as a single class of debt securities and have identical terms.

In November 2012, we redeemed the outstanding 8¼% Notes at a redemption price of 104.125% plus accrued interest through the redemption date. The redemption resulted in an $11.1 million loss, including the write off of unamortized debt issue costs.

In May 2013, we privately placed $625.0 million in aggregate principal amount of the 4¼% Notes. The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes.

In June 2013, the Partnership redeemed $100 million of the outstanding 6?% Notes at a redemption price of 106.375% plus accrued interest through the redemption date. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

In July 2013, we redeemed the outstanding 11¼% Notes at a price of 105.625% plus accrued interest through the redemption date. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

83 -------------------------------------------------------------------------------- Table of Contents The terms of our senior unsecured notes outstanding as of December 31, 2013 were as follows: Per Annum Note Issue Issue Date Interest Rate Due Date Dates Interest Paid "7?% Notes" August 2010 7?% October 15, 2018 April & October 15th "6?% Notes" February 2011 6?% February 1, 2021 February & August 1st "6?% Notes" January 2012 6?% August 1, 2022 February & August 1st "5¼% Notes" Oct / Dec 2012 5¼% May 1, 2023 May & November 1st "4¼% Notes" May 2013 4¼% November 15, 2023 May & November 15th All issues of unsecured senior notes are obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by a majority of our assets and our Securitization Facility, which is secured by accounts receivable pledged under it, to the extent of the value of the collateral securing that indebtedness.

Interest on all issues of senior unsecured notes is payable semi-annually in arrears.

Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Corporation and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.

Accounts Receivable Securitization Facility In January 2013, we entered into a Securitization Facility that provides up to $200 million of borrowing capacity at commercial paper or LIBOR market index rates plus a margin through January 2014. Under this Securitization Facility, one of our consolidated subsidiaries (TLMT) sells or contributes receivables, without recourse, to another of our consolidated subsidiaries (TRLLC), a special purpose consolidated subsidiary created for the sole purpose of this Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT or us. Any excess receivables are eligible to satisfy the claims of creditors of TLMT or us.

In December 2013, we entered into an amendment to our Securitization Facility to increase the borrowing capacity to $300 million and extend the termination date to December 12, 2014. As of December 31, 2013, total funding under this Securitization Facility was $279.7 million.

Off-Balance Sheet Arrangements We currently have no off-balance sheet arrangements as defined by the SEC. See "Contractual Obligations" below and "Commitments and Contingencies" included under Note 16 of our "Consolidated Financial Statements" for a discussion of our commitments and contingencies.

84 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations The following is a summary of certain contractual obligations over the next several years, including the disclosures related to debt and lease obligations, contained in Notes 10 and 16 of the "Consolidated Financial Statements" of this Annual Report.

Payments Due By Period Less Than More Than Contractual Obligations Total 1 Year 1-3 Years 3-5 Years 5 Years (In millions, except volumetric information) Debt obligations (1) $ 2,933.3 $ 279.7 $ - $ 645.0 $ 2,008.6 Interest on debt obligations (2) 937.3 106.3 227.0 252.0 352.0 Operating leases (3) 42.3 8.0 15.2 10.7 8.4 Pipeline capacity and throughput agreements (4), (8) 152.3 19.1 34.8 32.8 65.6 Land site lease and right-of-way (5) 7.9 1.7 3.2 3.0 - Commodities (6), (8) 495.0 495.0 - - - Purchase commitments (7), (8) 240.9 236.8 4.1 - - $ 4,809.0 $ 1,146.6 $ 284.3 $ 943.5 $ 2,434.6 Commodity volumetric commitments: Natural Gas (MMBtu) 40.9 40.9 - - - NGL and petroleum products (millions of gallons) 235.6 235.6 - - - -------------------------------------------------------------------------------- (1) Represents scheduled future maturities of consolidated debt obligations for the periods indicated.

(2) Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2013 rates for floating debt.

(3) Includes minimum payments on lease obligations for office space, railcars and tractors.

(4) Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.

(5) Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates through 2099.

(6) Includes natural gas and NGL purchase commitments.

(7) Includes commitments for capital expenditures and operating expenses.

(8) A purchase obligation mean an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms including: fixed, minimum or variable price provisions; and the approximate timing of the transaction.

Critical Accounting Policies and Estimates The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Property, Plant and Equipment and Intangibles In general, depreciation and amortization is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. Amortization expense attributable to intangible assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively. Examples of such circumstances include: • changes in energy prices; • changes in competition; 85-------------------------------------------------------------------------------- Table of Contents • changes in laws and regulations that limit the estimated economic life of an asset; • changes in technology that render an asset obsolete; • changes in expected salvage values; and • changes in the forecast life of applicable resources basins.

We evaluate long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. There have been no material changes impacting long-lived assets.

Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate and petroleum products; • services related to compressing, gathering, treating, and processing of natural gas; • services related to gathering, storing and terminaling of crude oil; and • services related to NGL fractionation, terminaling and storage, transportation and treating.

We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable; (2) delivery has occurred or services have been rendered; (3) the price is fixed or determinable and (4) collectability is reasonably assured.

Price Risk Management (Hedging) Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities. We are exposed to the credit risk of our counterparties in these derivative financial instruments. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument.

Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

86 -------------------------------------------------------------------------------- Table of Contents The estimated fair value of our derivative financial instruments was a net liability of $4.3 million as of December 31, 2013, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by the counterparties' credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which is immaterial for all periods covered by this Annual Report. We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty, less any liability from our master netting arrangements. Ignoring our adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of our commodity-based financial instruments that are in an asset position, we estimate that our operating income would decrease by $0.3 million in the year of the bankruptcy.

Use of Estimates When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Recent Accounting Pronouncements For a discussion of recent accounting pronouncements that will affect us, see "Recent Accounting Pronouncements" included under Note 3 of our "Consolidated Financial Statements." 87-------------------------------------------------------------------------------- Table of Contents

[ Back To Technology News's Homepage ]

OTHER NEWS PROVIDERS







Technology Marketing Corporation

800 Connecticut Ave, 1st Floor East, Norwalk, CT 06854 USA
Ph: 800-243-6002, 203-852-6800
Fx: 203-866-3326

General comments: tmc@tmcnet.com.
Comments about this site: webmaster@tmcnet.com.

STAY CURRENT YOUR WAY

© 2014 Technology Marketing Corporation. All rights reserved.