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. ("Targa" or "Parent"). 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") 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.

We acquired Targa's ownership interests in the following assets, liabilities and operations on the dates indicated (collectively, the "dropdown transactions"):

· February 2007 - North Texas System;

· October 2007 - SAOU and LOU;

· September 2009 - Downstream Business;

· April 2010 - Sand Hills and Straddle Assets;

· August 2010 - Versado; and

· September 2010 - Venice Operations.

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions as our "predecessors."

Our Operations

We are a leading provider of midstream natural gas, NGLs, terminaling and crude oil gathering services in the United States. We are engaged in the business of:

· gathering, compressing, treating, processing and selling natural gas;

· storing, fractionating, treating, transporting and selling NGLs and NGL products;

· gathering, storage 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. The Field Gathering and Processing segment's assets are located in North Texas and the Permian Basin of West Texas and New Mexico. With the Badlands acquisition on December 31, 2012, the Field Gathering and Processing segment's assets now include the Badlands crude oil and natural gas gathering, terminaling and processing assets in North Dakota as well. However, because the Badlands acquisition closed on December 31, 2012, the Badlands assets had no operational impact for 2012 other than transaction costs related to the acquisition. 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 raw NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations.

The Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. These assets are generally connected to and supplied, in part, by our Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.

The 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; and (4) 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 commodity hedging activities included in operating margin.

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, 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.

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       Crude Oil
   Annual Prices       Natural Gas $/MMBtu (1)         NGL $/gal (2)          $/Bbl (3)
       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

       2010
4th Quarter           $                    3.80     $               1.13     $     85.26
3rd Quarter                                4.38                     0.94           76.21
2nd Quarter                                4.09                     1.00           78.05
1st Quarter                                5.30                     1.13           78.88
2010 Average          $                    4.39     $               1.05     $     79.60

(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 significant volatility of natural gas and NGL prices, the
contract mix of our gathering and processing segment can also have a significant
impact on our profitability, especially those contracts that create exposure to
changes in energy prices ("equity volumes"). Set forth below is a table
summarizing the mix of our gathering and processing contracts for 2012 and the
potential impacts of commodity prices on operating margins:
                                         Percent of
            Contract Type                Throughput        Impact of Commodity Prices
Percent-of-Proceeds/Percent-of-Liquids      43%       Decreases in natural gas and or NGL
                                                      prices generate decreases in
                                                      operating margins.

Fee-Based                                    3%       No direct impact from commodity
                                                      price movements.

Wellhead Purchases/Keep-whole               21%       Increases in natural gas prices
                                                      relative to NGL prices generate
                                                      decreases in operating margin.

Hybrid                                      33%       In periods of favorable processing
                                                      economics (1), similar to
                                                      percent-of-liquids or to wellhead
                                                      purchases/keep-whole in some
                                                      circumstances, if economically
                                                      advantageous to the processor. In
                                                      periods of unfavorable processing
                                                      economics, similar to fee-based.

Negotiated contract terms are based upon a variety of factors, including natural gas 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 natural gas and NGL prices may change as a result of producer preferences, competition, 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.

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. Currently, demand for fractionation services is near existing industry capacity, rates have increased, contract lengths have increased and reservation fees are required. These fractionation 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.

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 2015 and our NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate 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.

General and Administrative Expenses

Our Omnibus Agreement with Targa, our general partner and others addresses the reimbursement of costs incurred on our behalf and indemnification matters. Under the Omnibus Agreement (as amended), which initial term expires in April 2013, Targa will provide general and administrative and other services to us associated with (1) our existing assets and any future Targa conveyances and (2) subject to mutual agreement, our future acquisitions from third parties. Since October 1, 2010, after the final conveyance of assets to us by Targa, substantially all of Targa's general and administrative costs have been and will continue to be allocated to us, other than Targa's direct costs of being a separate public reporting company. The Partnership agreement will govern these matters after the Omnibus Agreement expires. See "Item 13. Certain Relationships and Related Transactions, and Director Independence - Omnibus Agreement."

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, and for the provision of various general and administrative services for our benefit. 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.

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 inlet volumes in the Field Gathering and Processing segment over the next several years. While we expect demand for our 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.

Commodity Prices

Current forward commodity prices as of December 31, 2012 show natural gas and crude oil prices strengthening while NGL prices remain relatively flat. Various industry commodity price forecasts based on fundamental analysis may differ significantly from forward market prices. Both are subject to change due to multiple factors. 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. Recent weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which caused a reduction in profitability of our processing operations. 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 and of NGLs 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 that we gather, process and fractionate." 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 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, 2012, such annual minimum amounts would have been approximately $137.9 million. In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate.

For the year ended December 31, 2012 compared to 2011, total distributions increased by $60.1 million. For the year ended December 31, 2011 compared to 2010, total distributions increased by $61.3 million. The following table shows the distributions for 2012, 2011 and 2010:

                                                                Distributions
                                        Limited Partners           General Partner                           Distributions per
Three Months Ended     Date Paid             Common            Incentive           2%          Total        limited partner unit

                                                                 (In millions, except per unit amounts)
       2012
December 31, 2012  February 14, 2013   $             69.0     $      20.1      $     1.8     $    90.9     $               0.6800
September 30, 2012 November 14, 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
December 31, 2011  February 14, 2012   $             53.7     $      11.0      $     1.3     $    66.0     $               0.6025
September 30, 2011 November 14, 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

       2010
December 31, 2010  February 14, 2011   $             46.4     $       6.0      $     1.1     $    53.5     $               0.5475

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 crude oil, natural gas, NGLs and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of crude oil, wellhead natural gas and mixed NGLs that we purchase as well as operating and 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, is resulting in an increasing percentage of assets that generate fee-based revenues. Fixed fees for services such as fractionation, storage and terminaling 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 crude oil, natural gas 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 of crude oil and natural gas 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.

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 . . .