UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

 

Commission file number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

(713) 584-1000

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to section 12(b) of the Act:

 

 

Securities registered pursuant to section 12(g) of the Act:

Title of Class: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes o     No þ

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ.

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ     .

 

The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $560,280,000 on March 29, 2007, based on $29.00 per unit, the closing price of the Common Units as reported on The NASDAQ Stock Market LLC on such date.

 

At March 29, 2007, there were 19,320,000 Common Units, 11,528,231 Subordinated Units, and 629,555 General Partner Units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

TABLE OF CONTENTS

 

DESCRIPTION

 

TARGA RESOURCES PARTNERS LP

PART I

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

 

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

 

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” as well as the following risks and uncertainties:

 

 

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

As generally used in the energy industry and in this Annual Report on Form 10-K, the identified terms have the following meanings:

 

 

 

Initial Public Offering

 

On February 14, 2007, Targa Resources Partners LP, together with its subsidiaries (“we,” “us,” “our” or the “Partnership”) completed its initial public offering, or IPO, of common units representing limited partner interests in the Partnership. In the IPO, we issued 19,320,000 common units at a price of $21.00 per unit. We used the net proceeds of the IPO (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units) to pay expenses related to the IPO and our new credit facility and to repay approximately $371.2 million of our outstanding allocated indebtedness. Upon completion of the IPO, we had 19,320,000 common units, 11,528,231 subordinated units, and 629,555 general partner units outstanding. The subordinated units and general partner units are indirectly owned by Targa Resources, Inc., “or Targa”. Our common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS”. This filing reflects the historical financial information of the North Texas System (defined below) which was contributed to us by Targa in connection with the IPO.

 

General

 

The Partnership is a growth-oriented Delaware limited partnership formed on October 26, 2006 by Targa, a leading provider of midstream natural gas and natural gas liquids, or NGLs, services in the United States, to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We currently operate in the Fort Worth Basin in north Texas and are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products.

 

Our operations consist of an extensive network of approximately 3,950 miles of integrated gathering pipelines that gather and compress natural gas received from approximately 2,650 receipt points in the Fort Worth Basin, two natural gas processing plants that compress, treat and process the natural gas and a fractionator that fractionates a portion of our raw NGLs produced in our processing operations into NGL products (together, these assets are the “North Texas System”). We serve a fourteen-county natural gas producing region in the Fort Worth Basin that includes production from the Barnett Shale formation and other

shallower formations including the Bend Conglomerate, Caddo, Atoka, Marble Falls, and other Pennsylvanian and upper Mississippian formations. Our assets include the following:

 

 

 

 

 

 

Strategies

 

Our primary business objective is to increase our cash distribution per unit over time. We intend to accomplish this objective by executing the following strategies:

 

 

 

Strengths

 

We believe that we are well positioned to execute our primary business objective and business strategies successfully because of the following competitive strengths:

 

 

 

Our Relationship with Targa Resources, Inc.

 

We are closely affiliated with Targa, a leading provider of midstream natural gas and NGL services in the United States. Targa was formed in 2004 by its management team, which consists of former members of senior management of several midstream and other diversified energy companies, and Warburg Pincus LLC, or Warburg Pincus, a private equity firm. In April 2004, Targa purchased certain midstream natural gas operations from ConocoPhillips Company, or ConocoPhillips, for $247 million and, in October 2005, Targa purchased substantially all of the midstream assets of Dynegy, Inc. and its affiliates, or Dynegy, for approximately $2.5 billion (the “DMS Acquisition”). These transactions formed a large-scale, integrated midstream energy company with the ability to offer a wide range of midstream services to a diverse group of natural gas and NGL producers and customers. At December 31, 2006, Targa had assets of $3.5 billion, with the North Texas System contributed to us representing $1.1 billion of this amount, and for the year ended December 31, 2006, generated net cash provided by operating activities of $233.3 million.

 

Targa has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets. We expect to have the opportunity to make acquisitions directly from Targa in the future. Targa intends to offer us the opportunity to purchase substantially all of its remaining businesses, although it is not obligated to do so. While Targa believes it will be in its best interest to contribute additional assets to us given its significant ownership of limited and general partner interests in us, Targa constantly evaluates acquisitions and dispositions and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to purchase or construct those assets. Targa has retained such flexibility because it believes it is in the best interests of its shareholders to do so. We cannot say with any certainty which, if any, opportunities to acquire assets from Targa may be made available to us or if we will choose to pursue any such opportunity. Moreover, Targa is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us. In addition, through our relationship with Targa, we have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.

 

Targa has a significant indirect interest in our partnership through its ownership of a 36.6% limited partner interest and a 2% general partner interest in us. On February 14, 2007, we entered into an omnibus agreement with Targa that governs our relationship regarding certain reimbursement and indemnification matters. Please see Item 13 — Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement. In addition, to carry out operations, affiliates of our general partner, which are indirectly

owned by Targa, employ approximately 880 people, some of whom provide direct support to our operations. We do not have any employees. Please see — Employees, included in this Item 1.

 

While our relationship with Targa is a significant advantage, it is also a source of potential conflicts. For example, Targa is not restricted from competing with us. Targa retains substantial midstream assets and may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please see Item 13 — Certain Relationships and Related Transactions, and Director Independence — Conflicts of Interest.

 

Midstream Sector Overview

 

General.  Natural gas gathering and processing is a critical part of the natural gas value chain. Natural gas gathering and processing systems create value by collecting raw natural gas from the wellhead and separating dry gas (primarily methane) from NGLs such as ethane, propane, normal butane, isobutane and natural gasoline. Most natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This “rich,” unprocessed, natural gas is generally not acceptable for transportation in the nation’s interstate transmission pipeline system or for commercial use. Processing plants extract the NGLs, leaving residual dry gas that meets interstate transmission pipeline and commercial quality specifications. Furthermore, they produce marketable NGLs, which, on an energy equivalent basis, usually have a greater economic value as a raw material for petrochemicals and motor gasolines than as a component of the natural gas stream.

 

 

Gathering.  At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw natural gas to a central location for processing and treating. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are often designed to be highly flexible to allow gathering of natural gas at different pressures, flowing natural gas to multiple plants and quickly connecting new producers, and most importantly, scalable to allow for additional production without significant incremental capital expenditures.

 

Compression.  Since wells produce at progressively lower field pressures as they deplete, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to flow

into a higher pressure system. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering natural gas that otherwise would not be produced.

 

Treating and Dehydration.  After gathering, the second process in the midstream value chain is treating and dehydration. Natural gas contains various contaminants, such as water vapor, carbon dioxide and hydrogen sulfide, which can cause significant damage to intrastate and interstate pipelines and therefore render the gas unacceptable for transmission on such pipelines. In addition, end-users will not purchase natural gas with a high level of these contaminants. To meet downstream pipeline and end-user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

 

Processing.  Once the contaminants are removed, the next step involves the separation of pipeline quality residue gas from NGLs, a method known as processing. Most decontaminated rich natural gas is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components. The removal and separation of hydrocarbons during processing is possible because of the differences in physical properties between the components of the raw gas stream. There are four basic types of natural gas processing methods, including cryogenic expansion, lean oil absorption, straight refrigeration and dry bed absorption. Cryogenic expansion represents the latest generation of processing, incorporating extremely low temperatures and high pressures to provide the best processing and most economical extraction.

 

Natural gas is processed not only to remove NGLs that would interfere with pipeline transportation or the end use of the natural gas, but also to separate from the natural gas those hydrocarbon liquids that could have a higher value as NGLs than as natural gas. The principal components of residue gas are methane and ethane but processors typically have the option either to recover ethane from the residue gas stream for processing into NGLs or reject ethane and leave it in the residue gas stream, depending on whether the ethane is more valuable being processed or left in the natural gas stream. The residue gas is sold to industrial, commercial and residential customers and electric utilities. The premium or discount in value between natural gas and separated NGLs is known as the “frac spread.” Because NGLs often serve as substitutes for products derived from crude oil, NGL prices tend to move in relation to crude prices.

 

Natural gas processing occurs under a contractual arrangement between the producer or owner of the raw natural gas stream and the processor. There are many forms of processing contracts which vary in the amount of commodity price risk they carry. The specific commodity exposure to natural gas or NGL prices is highly dependent on the types of contracts. Processing contracts can vary in length from one month to the “life of the field.” Three typical processing contract types are described below:

 

 

 

Fractionation.  Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products. As the temperature of the stream is increased, the lightest component boils off the top of the distillation tower as a gas where it then condenses into a purity liquid that is routed to storage. The heavier components in the mixture are routed to the next tower where the process is repeated until all components have been separated. Described below are the five basic NGL components and their typical uses:

 

 

A typical barrel of NGLs consists of ethane, propane, normal butane, isobutane and natural gasoline.

 

Transportation and Storage.  Once the raw natural gas has been conditioned or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Both the natural gas industry and the NGL industry have hundreds of thousands of miles of intrastate and interstate transmission pipelines in addition to a network of barges, rails, trucks, terminals and storage to deliver natural gas and NGLs to market. The bulk of the NGL storage capacity is located near the refining and petrochemical complexes of the Texas and Louisiana Gulf Coasts, with a second major concentration in central Kansas. Each commodity system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

 

Natural Gas Demand and Production.  Natural gas is a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 23.35 Tcf in 2010. The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 56% of the total natural gas consumed in the United States. In 2005, natural gas represented approximately 36% of all end-user commercial and residential energy requirements. During the last three years, the United States has on average consumed approximately 22.3 Tcf per year, with average annual domestic production of approximately 18.5 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.1 Tcf per year to 20.4 Tcf per year between 2005 and 2015.

 

Our System

 

Gathering Systems

 

Our gathering network consists of approximately 3,950 miles of pipelines that, in aggregate, gather wellhead natural gas from approximately 2,650 meters for transport to the Chico and Shackelford natural gas

processing facilities. The gathering network consists of two distinct systems: the Chico Gathering System which gathers natural gas from Denton, Montague, Wise, Clay, Jack, Palo Pinto and Parker counties on the eastern part of our system; and the Shackelford Gathering System, which gathers natural gas from Jack, Palo Pinto, Archer, Young, Stephens, Eastland, Throckmorton, Shackelford and Haskell counties on the western part of our system. The two gathering systems are connected via a high-pressure 32-mile, 10-inch diameter pipeline, or the Interconnect Pipeline. This interconnection between the gathering systems allows us to deliver natural gas in excess of the Shackelford system’s processing capacity to the Chico plant.

 

Chico Gathering System.  The Chico Gathering System consists of approximately 1,875 miles of primarily low pressure natural gas gathering pipelines. The natural gas that is gathered on the Chico Gathering System is either delivered directly to the Chico plant, where it is compressed for processing, or is compressed in the field at 13 compressor stations and then transported via one of several high-pressure pipelines to the Chico plant.

 

Shackelford Gathering System.  The Shackelford Gathering System consists of approximately 2,090 miles of natural gas gathering pipelines. The western and southern portions of the Shackelford Gathering System gather natural gas that is transported on intermediate-pressure pipelines to the Shackelford plant. The approximately 18 MMcf/d of natural gas gathered from the northern and eastern portions of the Shackelford Gathering System is typically transported on the Interconnect Pipeline to the Chico plant for processing. This natural gas is compressed at 18 compressor stations to achieve sufficient pressure to enter the high pressure Interconnect Pipeline.

 

Processing Plants

 

Chico Processing Plant.  The Chico processing plant is located in Wise County, Texas, approximately 45 miles northwest of Fort Worth, Texas. The Chico processing plant includes a state-of-the-art cryogenic processing train with a nameplate capacity of 150 MMcf/d that was installed in 2002 and that has operated at throughputs of up to 165 MMcf/d. Plant inlet volumes consist of separate high-pressure (830 psig), intermediate-pressure (400 psig) and low-pressure (5 psig) natural gas streams. The intermediate-pressure stream and low pressure stream are compressed to a plant pressure of 830 psig. The three inlet streams are then commingled for processing. The commingled stream is treated, dehydrated and then processed. The Chico plant also includes a residue recompression turbine waste heat recovery system, which increases operating efficiency. The Chico plant also includes an NGL fractionator with the capacity to fractionate up to 11,500 Bbl/d of raw NGL mix. This fractionation capability allows the Chico facility to deliver raw NGL mix to Mont Belvieu primarily through Chevron’s WTLPG Pipeline or separated NGL products to local or other markets via truck.

 

To increase Chico’s processing capacity, we have refurbished a 40 gallon per minute liquid product treater and 50 MMcf/d of the previously idle 100 MMcf/d Chico cryogenic processing train. This stage of expansion of the Chico facility was completed in August 2006. The remaining 50 MMcf/d capacity can be activated quickly and at minimal cost as needed to meet production increases through installation of a refrigeration compressor unit that is currently on site.

 

The expanded Chico plant now has a total effective treating and processing capacity of 215 MMcf/d, which, with the additional refrigeration compression, can be further increased to 265 MMcf/d. Additionally, there could be additional need for CO₂ treating which would require an additional capital investment of approximately $2.5 million. We believe that the current expanded capacity and the additional 50 MMcf/d of available expansion capacity will be able to accommodate anticipated near- and intermediate-term throughput growth.

 

Shackelford Processing Plant.  The Shackelford natural gas processing plant is located in Shackelford County, Texas near Albany, Texas which is approximately 120 miles west of Fort Worth, Texas. The Shackelford plant is a cryogenic plant with a nameplate capacity of 15 MMcf/d, but effective capacity is limited to 13 MMcf/d due to capacity constraints on the residue gas pipeline that serves the facility. Plant inlet volumes are compressed to 720 psig by three inlet compressors before being dehydrated and processed. The Shackelford facility also includes two 40,000 and two 12,600 gallon NGL storage tanks, an iron sponge for hydrogen sulfide removal and inlet scrubbers.

 

 

Market Access

 

Chico System Market Access.  The Chico processing plant’s location in northeastern Wise County provides us and producers with several options for both NGL and residue gas delivery. The primary outlet for NGLs is Chevron’s WTLPG Pipeline which delivers volumes from the Chico plant to Mont Belvieu for fractionation. NGL products produced at the Chico processing facility can also be transported via truck to local or other markets. Currently, approximately 650,000 gallons per day of NGLs are delivered from the Chico processing facility by pipeline and approximately 141,000 gallons per day of NGL products are delivered from the Chico processing facility by truck.

 

Low pressure condensate is composed of heavy hydrocarbons which condense in the gathering system and are collected in low pressure separators associated with field compressors and in low pressure separators upstream of the processing plants. This product is collected and shipped by truck from various locations in the system and sold as condensate at oil related index prices. High pressure condensate is a mix of intermediate and heavy hydrocarbons which condense in the high pressure gathering lines between the compressor stations and the processing plants. This condensate is collected in high pressure separators prior to the plant and sold as NGLs via high pressure trucks which move the product to an injection point on the WTLPG Pipeline at Bridgeport to be shipped to Mont Belvieu. Occasionally, this high pressure condensate product is shipped via truck directly to Mont Belvieu.

 

Our connections to multiple inter and intrastate natural gas pipelines give the Chico plant and its customers the ability to maximize realized prices by accessing major trading hubs and end-use markets throughout the Gulf Coast, Midwest and northeast regions of the United States. Currently, residue gas is shipped via the:

 

 

 

Shackelford System Market Access.  Residue natural gas from the Shackelford processing plant is delivered to the Carthage and Katy hubs on Atmos-Texas and NGLs from the plant are delivered to Mont Belvieu on the WTLPG Pipeline. Condensate from the Shackelford system is handled similarly to the description above for the Chico System.

 

Targa Intrastate Pipeline.  Targa Intrastate Pipeline LLC, or Targa Intrastate, our wholly-owned subsidiary, owns a 41-mile, 6-inch diameter intrastate pipeline that transports natural gas from the Shackelford processing plant to an interconnect with Atmos-Texas and a 1.65 mile, 10-inch diameter intrastate pipeline that transports natural gas through part of the Chico system in Denton County, Texas. Targa Intrastate is regulated by the Texas Railroad Commission, or TRRC.

 

Customers and Contracts

 

We gather and process natural gas for approximately 420 customers. For the year ended December 31, 2006, no customer, other than ConocoPhillips, which represented 33% of our volumes, represented more than 10% of our volumes. This diverse customer base enhances the stability of our volumes while positioning us to benefit from the continued drilling expected in the Fort Worth Basin/Bend Arch, regardless of which producer is driving the activity. Our reputation of providing reliable, high-quality service should allow our system to attract a significant portion of the volumes produced by the new entrants, including the major and large independent exploration and production companies into the Fort Worth Basin, in general, and in the Barnett Shale, in particular.

 

We have a long-term strategic relationship with ConocoPhillips, as a result of its recent acquisition of Burlington Resources, which is the second largest producer in our areas of operation. Subject to limited exceptions, all of ConocoPhillips’ production from leases covering a 30,000 acre area in Wise and Denton counties has been committed to us for gathering and processing through a prior agreement with Burlington Resources entities. ConocoPhillips is under no obligation to deliver minimum volumes or to continue to develop its leasehold position under its agreement with us. This commitment extends through 2015, with a ten year renewal, at ConocoPhillips’ option. Generally, in the event a lease of the dedicated acreage should terminate before the expiration of the primary term of the agreement, then the agreement will be canceled with respect to that leasehold dedication contemporaneously with such termination. Pursuant to the agreement, we process natural gas received under a percent-of-proceeds arrangement and also receive a volume-based fee for the gathering services we provide.

 

We currently have approximately 2,650 receipt points receiving natural gas production from individual wells or groups of wells. Approximately 69% of these receipt points are located on our Chico Gathering System and approximately 31% are located on our Shackelford Gathering System. The natural gas supplied to us is generally dedicated to us under individually negotiated term contracts that provide for the commitment by the producer of all natural gas produced from designated properties. Generally, the initial term of these purchase agreements is for 3 to 10 years or, in some cases, the life of the lease.

 

We process natural gas under a combination of percent-of-proceeds contracts (representing approximately 96% of our natural gas volumes) and keep-whole contracts (representing approximately 4% of our natural gas volumes), each of which exposes us to commodity price risk. In an effort to reduce the variability of our cash flows, as of December 31, 2006, we have hedged the commodity price associated with approximately 90-60% of our expected natural gas, 65-50% of our expected NGL and 95-60% of our expected condensate equity volumes for the years 2007 through 2010.

 

Much of the natural gas gathered historically in the Fort Worth Basin was contracted on a “keep-whole” basis until the late 1990s. In the late 1990s, gatherers and processors began to shift new contracts and renegotiate older contracts from keep-whole to percent-of-proceeds contracts which had relatively less

variability and risk. In addition, the equity gas and NGLs received as fees for reprocessing under percent-of-proceeds contracts may be hedged to provide even less price variability. Due to local producer desires and the competitive situation in the Fort Worth Basin, fee-based contracts have not generally been available at attractive rates relative to available percent-of-proceeds terms. This trend may change in the future and we will continue to evaluate the market for attractive fee-based contract arrangements which may further reduce the variability of our cash flows.

 

Competition

 

Our gathering, processing and fractionation system competes with several systems located in the Fort Worth Basin. Our competitors include but are not limited to gathering and processing systems owned by Devon, Enbridge, J-W Operating, Davis Gas Processing, Hanlon Gas Processing, and Upham Oil and Gas. A number of the gathering and processing competitors in the region are smaller entities with assets serving a particular field, producer or limited area but lack a basin-wide presence. As for the larger competitors, Devon and Enbridge’s operations are the most extensive and are closest in proximity to our area of operations, based on publicly available information. Devon’s processing capacity is greater than ours, while Enbridge’s is approximately the same. Devon almost exclusively gathers and processes its own production. Competition within the Fort Worth Basin may increase as new ventures are formed or as existing competitors expand their operations. Competitive factors include processing and fuel efficiencies, operational costs, commercial terms offered to producers and capital expenditures required for new producer connections, along with the location and available capacity of gathering systems and processing plants.

 

We believe that our ability to offer an integrated package of services and our willingness to remain flexible on the contractual terms we offer producers allows us to compete more effectively for new supplies of natural gas.

 

Safety and Maintenance Regulation

 

We are subject to regulation by the United States Department of Transportation, referred to as DOT, under the Accountable Pipeline and Safety Partnership Act of 1996, referred to as the Hazardous Liquid Pipeline Safety Act, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. The Hazardous Liquid Pipeline Safety Act covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in material compliance with these Hazardous Liquid Pipeline Safety Act regulations.

 

We are also subject to the Natural Gas Pipeline Safety Act of 1968, referred to as NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within 10 years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

 

We currently estimate we will incur costs of approximately $1 million between 2007 and 2010 to implement integrity management program testing along certain segments of our natural gas pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program.

 

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any

significant problems in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

 

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

 

Regulation of Operations

 

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

 

Gathering Pipeline Regulation

 

Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission, or FERC. We believe that our natural gas pipelines meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates.

 

The TRRC, has adopted regulations that generally allow natural gas producers and shippers to file complaints with the TRRC in an effort to resolve grievances relating to pipeline access and rate discrimination. Our natural gas gathering operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

Our gathering and purchasing operations are subject to ratable take and common purchaser statutes in Texas. The Texas ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, Texas common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of

gathering facilities to decide with whom we contract to purchase or gather natural gas. Texas has adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future.

 

On October 30, 2006, the Texas Natural Gas Pipeline Competition Study Advisory Committee submitted a Natural Gas Pipeline Competition Study (“Study”) to the Governor of Texas and the Texas Legislature. The Study recommends, among other things, that the Legislature give the TRRC the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and/or transmission in formal rate proceedings. The Study also recommends that the Legislature give the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchasers, transporters, and gatherers for retaliating against shippers and sellers. We have no way of knowing what portions of the Study, if any, will be adopted by the Legislature and implemented by the TRRC. We cannot predict what effect, if any, the proposed changes, if implemented, might have on our operations.

 

Intrastate Pipeline Regulation

 

Our subsidiary, Targa Intrastate Pipeline Company LLC, or Targa Intrastate, owns and operates a 41-mile, 6-inch diameter intrastate pipeline that transports natural gas from our Shackelford processing plant to an interconnect with Atmos-Texas. Targa Intrastate also owns a 1.65 mile, 10-inch diameter intrastate pipeline that transports natural gas from a third party gathering system into the Chico system in Denton County, Texas. Targa Intrastate is subject to rate regulation under the Texas Utilities Code, as implemented by the TRRC, and has a tariff on file with the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable, and not discriminatory. The rates we charge for intrastate transportation services are deemed just and reasonable under Texas law, unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

 

Sales of Natural Gas and NGLs

 

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation. Our sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. Any such initiatives also could affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of FERC’s regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of FERC regulatory changes to our natural gas sales operations, including impacts related to the availability and reliability of transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

 

Environmental Matters

 

General

 

Our operation of pipelines, plants and other facilities for gathering, treating, transporting or processing natural gas, NGLs and other products is subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment.

 

As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

 

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

 

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat, process and fractionate natural gas. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

 

We or the entities in which we own an interest inspect the pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

 

Air Emissions

 

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to

incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

 

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change entered into force. Pursuant to the Protocol, adopting countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The Bush administration has indicated it will not support ratification of the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the United States for legislation that requires reductions in greenhouse gas emissions, and some states, although not those in which we currently operate, have already adopted regulatory initiatives or legislation to reduce emissions of greenhouse gases. For example, California recently adopted the “California Global Warming Solutions Act of 2006”, which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions would likely adversely impact our future operations, results of operations and financial condition. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

 

Hazardous Substances and Waste

 

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances or solid and hazardous wastes (including petroleum hydrocarbons). These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste, and may impose strict, joint and several liability for the investigation and remediation of areas, at a facility where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses natural gas, we may nonetheless handle “hazardous substances” within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

 

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

 

We currently own or lease, and our predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

 

Water

 

The Federal Water Pollution Control Act of 1972, also referred to as the Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state and federal waters. The CWA can impose substantial civil and criminal penalties for non-compliance. State laws for the control of water pollution may also provide varying civil and criminal penalties and liabilities. In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The EPA has promulgated regulations that require us to have permits in order to discharge certain storm water run-off. The EPA has entered into agreements with certain states in which we operate whereby the permits are issued and administered by the respective states. These permits may require us to monitor and sample the storm water run-off. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

 

Title to Properties and Rights-of-Way

 

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee title owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. Other than a dispute with respect to the validity of a lease for a compressor station site, which we expect will be settled with the lessor, we have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

 

Some of the leases, easements, rights-of-way, permits and licenses transferred to us required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. We believe that we have obtained such third-party consents, permits and authorizations as are sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects as described in this report. With respect to any consents, permits or authorizations that have not yet been obtained, we believe that such consents, permits or authorizations will be obtained within a reasonable period or that the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.

 

Targa holds record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that were not obtained prior to transfer. Such consents and approvals include those required by federal and state agencies or political

subdivisions. Where required consents or approvals have not been obtained, Targa temporarily holds record title to property as nominee for our benefit or, on the basis of expense and difficulty associated with the conveyance of title, Targa affiliates retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from the holding by Targa of title to any part of such assets subject to future conveyance or as our nominee.

 

Employees

 

To carry out its operations, Targa employs approximately 880 people some of whom provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Targa considers its employee relations to be good. We do not have any employees.

 

Available Information

 

We make certain filings with the Securities and Exchange Commission, or SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our annual reports to unitholders, press releases and recent analyst presentations are also available on our website.

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this report. If any of the following risks were actually to occur, then our business, financial condition or results of operations could be materially adversely affected.

 

Risks Related to Our Business

 

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

 

In order to make our cash distributions at our initial distribution rate of $0.3375 per common unit and subordinated unit per complete quarter, or $1.35 per unit per year, we will require available cash of approximately $10.6 million per quarter, or $42.5 million per year, based on common units and subordinated units outstanding at March 30, 2007. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

 

Our cash flow is affected by natural gas and NGL prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.

 

Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of natural gas and NGLs have been volatile and we expect this volatility to continue.

 

Our future cash flow will be materially adversely affected if we experience significant, prolonged pricing deterioration below general price levels experienced over the past few years in our industry.

 

The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

 

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the year ended December 31, 2006, our percent-of-proceeds arrangements accounted for approximately 96% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers for an agreed percentage of the proceeds from the sale of residue gas and NGLs resulting from our processing activities, selling the resulting residue gas and NGLs at market prices. Under these types of arrangements, our revenues and our cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. For additional

information regarding our hedging activities, please see Item 7A. — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.

 

Because of the natural decline in production from existing wells in our operating regions, our success depends on our ability to obtain new sources of supplies of natural gas, which depends on certain factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.

 

Our gathering systems are connected to natural gas wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

 

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development costs and the availability and cost of capital. We believe that rig availability in the Fort Worth Basin has been and will continue to be a limiting factor on the number of wells drilled in that area. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Natural gas prices reached relatively high levels in 2005 and early 2006 but declined substantially through 2006, with NYMEX Henry Hub gas futures contracts closing at $5.84 in December 2006 compared to $11.43 in December 2005. These recent declines in natural gas prices are beginning to have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Reductions in exploration or production activity or shut-ins by producers in the areas in which we operate as a result of a sustained decline in natural gas prices would lead to reduced utilization of our gathering and processing assets.

 

Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If, due to reductions in drilling activity or competition, we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our treating, processing and fractionation facilities would decline, which could reduce our revenue and impair our ability to make distributions to our unitholders.

 

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.

 

We have entered into derivative transactions related to only a portion of our equity volumes. As a result, we will continue to have direct commodity price risk on the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual natural gas, NGL and condensate prices that we realize in our operations. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we

hedge our commodity price risk; we may forego the benefits we would otherwise experience if commodity prices were to change in our favor.

 

Our results of operations are currently realizing a significant benefit from hedge positions entered into in 2006. As of March 26, 2007, we estimate that these hedges will generate approximately $17 million in operating income for the year ending December 31, 2007. If future prices remain comparable to current prices, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through 2010. For additional information regarding our hedging activities, please see Item 7A. — Quantitative and Qualitative Disclosures About Market Risk.

 

We depend on one natural gas producer for a significant portion of our supply of natural gas. The loss of this customer or replacement of its contracts on less favorable terms could result in a decline in our volumes, revenues and cash available for distribution.

 

Our largest natural gas supplier for the years ended December 31, 2006 and 2005 was ConocoPhillips, who accounted for approximately 33% and 36%, respectively, of our supply. The loss of all or even a portion of the natural gas volumes supplied by this customer or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce our revenue or increase our cost for product purchases, impairing our ability to make distributions to our unitholders.

 

If third-party pipelines and other facilities interconnected to our natural gas pipelines and facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

 

We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

 

We depend on our Chico system for a substantial majority of our revenues and if those revenues were reduced, there would be a material adverse effect on our results of operations and ability to make distributions to unitholders.

 

Any significant curtailment of gathering, compressing, treating, processing or fractionation of natural gas on our Chico system could result in our realizing materially lower levels of revenues and cash flow for the duration of such curtailment. For the year ended December 31, 2006, our Chico plant inlet volume accounted for over 90% of our revenues. Operations at our Chico system could be partially curtailed or completely shut down, temporarily or permanently, as a result of:

 

 

The magnitude of the effect on us of any curtailment of operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. We have no control over many of the factors that may lead to a curtailment of operations.

 

In addition, our business interruption insurance is subject to limitations and deductibles. If a significant accident or event occurs at our Chico system that is not fully insured, it could adversely affect our operations and financial condition.

 

We are exposed to the credit risk of Targa and any material nonperformance by Targa could reduce our ability to make distributions to our unitholders.

 

In 2007, we entered into purchase agreements with Targa pursuant to which Targa will purchase all of our natural gas, NGLs and high-pressure condensate for a term of 15 years. We also entered into an omnibus agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. As of January 31, 2007, Moody’s and Standard & Poor’s assigned Targa corporate credit ratings of B1 and B+, respectively, which are speculative ratings. These speculative ratings signify a higher risk that Targa will default on its obligations, including its obligations to us, than does an investment grade credit rating. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.

 

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

 

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

 

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

 

Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transporting of natural gas and NGLs, including:

 

 

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. Our insurance is provided under Targa’s insurance programs. We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, Targa may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Moreover, significant claims by

Targa may limit or eliminate the amount of insurance proceeds available to us. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

As of March 26, 2007, we had approximately $294.5 million of borrowings outstanding under our credit facility. Our level of debt could have important consequences for us, including the following:

 

 

Our ability to service our debt depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

 

Increases in interest rates could adversely affect our business.

 

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of March 26, 2007, we had approximately $294.5 million of debt outstanding under our credit facility at variable interest rates. An increase of 1 percentage point in the interest rates will result in an increase in annual interest expense of $2.9 million. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

 

Restrictions in our credit facility may interrupt distributions to us from our subsidiaries, which may limit our ability to make distributions to you, satisfy our obligations and capitalize on business opportunities.

 

Our credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our credit facility contains covenants requiring us to maintain a ratio of consolidated indebtedness to consolidated EBITDA initially of not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to consolidated interest expense of not less than 2.25 to 1.00. If we fail to meet these tests or otherwise breach the terms of our credit facility our operating subsidiary will be prohibited from making any distribution to us and, ultimately, to you. Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.

 

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.

 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and

regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling, storage, treatment or discharge of waste from our facilities and (3) the federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental regulations, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. In particular, we may incur expenditures in order to maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover these costs from insurance.

 

We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

 

We typically do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

 

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

 

Our natural gas gathering operations are generally exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation;

accordingly, the classification and regulation of some of our intrastate pipelines may be subject to change based on future determinations by FERC, the courts or Congress.

 

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and as a number of such companies have transferred gathering facilities to unregulated affiliates. TRRC has adopted regulations that generally allow natural gas producers and shippers to file complaints with the TRRC in an effort to resolve grievances relating to intrastate pipeline access and rate discrimination. Our natural gas gathering operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business.

 

Our costs may increase because our credit obligations under hedging and other contractual arrangements are not guaranteed by Targa.

 

Prior to our IPO, Targa maintained credit support for our obligations related to derivative financial instruments, such as commodity price hedging contracts. Beginning on February 14, 2007, Targa no longer provides credit support for our obligations under derivative financial instruments and other commercial contracts governing our business or operations. Consequently, we are providing our own credit support arrangements for commercial contracts, which may increase our costs. For example, it could be more costly for us to manage our commodity price risk through certain types of financial hedging arrangements unless we are able to achieve creditworthiness similar to the current creditworthiness of Targa.

 

All of our operations are based in the Fort Worth Basin and we are dependent on drilling activities and our ability to attract and maintain customers in such region.

 

All of our operations are located in the Fort Worth Basin in north Texas. Due to our lack of diversification in industry type and location, an adverse development in the oil and gas production from this area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

Under the terms of our gas sales agreement, Targa manages the sales of our natural gas and pays us the amount it realizes for gas sales less certain costs; however, unexpected volume changes due to production variability or to gathering, plant, or pipeline system disruptions may increase our exposure to commodity price movements.

 

Targa sells our processed natural gas to third parties and other Targa affiliates at our plant tailgate or at interstate pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. Targa attempts to balance sales with volumes supplied from our processing operations, but unexpected volume variations due to production variability or to gathering, plant, or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations, and cash flow.

 

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

 

We currently estimate that we will incur an aggregate cost of approximately $1 million between 2007 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial.

 

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

 

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

 

If we do not make acquisitions on economically acceptable terms, or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

 

Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them,

(2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.

 

Any acquisition involves potential risks, including, among other things:

 

 

If these risks materialize, the acquired assets may inhibit our growth or fail to deliver expected benefits.

 

Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

 

We do not own most of the land on which our pipelines and facilities are located, which could disrupt our operations.

 

We do not own most of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, reduce our revenue and impair our ability to make distributions to our unitholders.

 

We do not have any officers or employees and rely solely on officers of our general partner and employees of Targa.

 

None of the officers of our general partner are employees of our general partner. In February 2007, we entered into an omnibus agreement with Targa, pursuant to which Targa operates our assets and performs other administrative services for us such as accounting, legal, regulatory, corporate development, finance, land and engineering. Affiliates of Targa conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to Targa. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Targa. If the officers of our general partner and the employees of Targa do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

 

If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

 

Targa Resources GP LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general

partner’s efforts to develop and maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

 

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability. Consequently, even if we are profitable, we may not be able to make cash distributions to holders of our common units and subordinated units.

 

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

 

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

 

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

 

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

 

Risks Inherent in an Investment in Us

 

Targa controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.

 

Targa owns and controls our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

 

The credit and business risk profiles of the general partner and its owners may be factors in credit evaluations of a master limited partnership. This is because the general partner can exercise significant influence over the business activities of the partnership, including its cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

 

Targa, the owner of our general partner, has significant indebtedness outstanding and is partially dependent on the cash distributions from their indirect general partner and limited partner equity interests in us to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.

 

Our partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Targa. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

 

 

Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

 

Neither our partnership agreement nor the omnibus agreement between us and Targa prohibits Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Targa is a large, established participant in the midstream energy business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with Targa with respect to commercial activities as well as for acquisition candidates. As a result, competition from Targa could adversely impact our results of operations and cash available for distribution.

 

Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

 

Pursuant to the omnibus agreement we entered into with Targa and Targa Resources GP LLC, our general partner, Targa will receive reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify our general partner. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or our general partner’s board of directors, and will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Targa. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

Our unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Our general partner and its affiliates own 37.4% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our

general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

 

We may issue additional units without your approval, which would dilute your existing ownership interests.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

 

Management of our general partner and Targa beneficially hold 85,700 common units and 11,528,231 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units. This ability may result in lower distributions to holders of our common units in certain situations.

 

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

 

In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its

incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.

 

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.

 

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.

 

We will incur increased costs as a result of being a publicly-traded company.

 

We have a limited history operating as a publicly-traded company. As a publicly-traded company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and The NASDAQ Stock Market LLC, have required changes in corporate governance practices of publicly-traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded company, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

 

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 37.4% of our aggregate outstanding common units.

 

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Texas. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:

 

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us

as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, margin, franchise and other forms of taxation. For example, beginning in 2008, we will be subject to a new entity level tax on the portion of our income that is generated in Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to you. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to you.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this annual report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

Because our unitholders are treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

 

Tax gain or loss on disposition of our common units could be more or less than expected.

 

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

 

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our

taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

 

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

 

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

 

In addition to federal income taxes, you might be subject to return filing requirements and other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, now or in the future, even if you do not live in any of those jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We initially own assets and conduct business in the State of Texas. Currently, Texas does not impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or do business in states that impose a personal income tax. It is your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

None

 

A description of our properties is contained in Item 1 of this annual report.

 

Our principal executive offices are located at 1000 Louisiana Street, Suite 4300, Houston, Texas 77002 and our telephone number is 713-584-1000.

 

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please see Regulation of Operations — Intrastate Pipeline Regulation and Environmental Matters in Item 1 of this annual report.

 

None

 

Market Information

 

Our common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS”. Common units began trading on February 9, 2007, at an initial offering price of $21.00 per common unit. On March 26, 2007, the market price for the common units was $28.10 per unit and there were approximately 10 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

 

We have also issued 11,528,231 subordinated units, for which there is no established public trading market. The subordinated units are held by affiliates of Targa Resources GP LLC, our general partner. Our general partner and its affiliates will receive a quarterly distribution on these units only after sufficient funds have been paid to the common units.

 

Distributions of Available Cash

 

General.  Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ended March 31, 2007, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our general partner.

 

Definition of Available Cash.  Available cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter:

 

 

 

 

Intent to Distribute the Minimum Quarterly Distribution.  We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3375 per unit, or $1.35 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. Minimum quarterly distribution means $0.3375 per common unit per quarter (or with respect to the period commencing on the closing date of our IPO (February 14, 2007) and ending on March 31, 2007, it means the product of $0.3375 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 90). However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the term of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our credit agreement. Please read Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Credit Agreement

for a discussion of the restrictions included in our credit agreement that may restrict our ability to make distributions.

 

General Partner Interest and Incentive Distribution Rights.  Our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 629,555 general partner units. Our general partner has the right, but not the obligation, to contribute a proportional amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportional amount of capital to us to maintain its 2% general partner interest.

 

Our general partner also currently holds rights that entitle it to receive up to a maximum of 50% of the cash we distribute in excess of $0.5063 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on limited partner units that it owns.

 

Sales of Unregistered Units

 

None

 

Repurchase of Equity by Targa Resources Partners LP

 

None

 

Use of Proceeds

 

Our IPO of common units representing limited partnership interests in us commenced on February 1, 2007. Our Registration Statement (File No. 333-138747) on Form S-1, as amended, was declared effective by the SEC on February 8, 2007. We completed our IPO of 19,320,000 common units (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units) representing limited partnership interests in us on February 14, 2007 at a price of $21.00 per unit ($19.7925 per unit after the underwriting discount) for gross proceeds of $405,720,000 ($380,768,220 after underwriting discount and structuring fees).

 

The net proceeds from our IPO were used to (i) pay approximately $5.4 million in expenses associated with the IPO and the transactions related thereto, (ii) pay approximately $4.2 million in expenses related to our credit facility and (iii) pay approximately $371.2 million to Targa to reduce allocated indebtedness owed to Targa.

 

All proceeds received from our IPO have been applied.

 

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

 

The following table shows selected historical financial and operating data of the North Texas System for the periods and as of the dates indicated. The historical financial statements included in this annual report reflect the results of operations of the North Texas System contributed to us by Targa on February 14, 2007. We refer to the historical results of operations of the North Texas System as the results of operations of the Predecessor Business. The selected historical financial data for the year ended December 31, 2002 is derived from the books and records of the Predecessor Business. The selected historical financial data for the years ended December 31, 2003 and 2004, the ten-month period ended October 31, 2005, the two-month period ended December 31, 2005 and the year ended December 31, 2006 are derived from the audited financial statements of the Predecessor Business. The Predecessor Business was acquired by Targa as part of the DMS Acquisition.

 

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical combined financial statements and the accompanying notes included elsewhere in this annual report. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of factors that affect the comparability of the information reflected in the selected financial and operating data.

 

 

 

Non-GAAP Financial Measures

 

EBITDA.  We define EBITDA as net income before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks and others, to assess:

 

 

The economic substance behind management’s use of 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.

 

The GAAP measures most directly comparable to EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because 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 EBITDA may not be comparable to similarly titled measures of other companies. Management compensates for the limitations of EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into management’s decision-making processes.

 

Operating Margin.  We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases, and operating expense. Management reviews operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses operating margin as an important performance measure of the core profitability of our operations.

 

The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these learnings into management’s decision-making processes.

 

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by our management and by external users of our financial statements, including such investors, commercial banks and others, to assess:

 

 

 

 

 

On February 14, 2007, we completed our initial public offering, or IPO, of common units. In the IPO, we issued 19,320,000 common units (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units) representing limited partner interests at a price of $21.00 per unit. We used the net proceeds of the IPO to pay expenses related to the IPO and our credit facility and to repay approximately $371.2 million of our outstanding affiliate indebtedness. Upon completion of the IPO, we had 19,320,000 common units, 11,528,231 subordinated units, and 629,555 general

partner units outstanding. The subordinated units and general partner units are indirectly owned by Targa Resources, Inc.

 

The historical financial statements included in this item reflect the results of operations of the North Texas System contributed to us by Targa at the time of the IPO. We refer to the results of operations of the North Texas System as the results of operations of the Predecessor Business. The Predecessor Business was acquired by Targa as part of the DMS Acquisition.

 

The following discussion analyzes the financial condition and results of operations of the Predecessor Business. In the discussion, the year ended December 31, 2005 is generally presented and evaluated on a combined basis, combining the results of operations reflected in the audited historical financial statements of the Predecessor Business for the 10-months prior to the DMS Acquisition (the “Pre-Acquisition Financial Statements”) and the results of operations reflected in the audited historical financial statements of the Predecessor Business for the two-months after the DMS Acquisition (the “Post-Acquisition Financial Statements”). In certain circumstances, our discussion identifies distinctions in operating and financial results for the Predecessor Business associated with the change of ownership resulting from the DMS Acquisition. You should read the following discussion of the financial condition and results of operations for the Predecessor Business in conjunction with the historical combined financial statements and notes of the Predecessor included under Item 8 of this report.

 

As used in this report, unless we indicate otherwise, the terms “our,” “we,” “us” and similar terms refer to Targa Resources Partners LP, together with our subsidiaries, and the term “Targa” refers to Targa Resources, Inc. and its subsidiaries and affiliates (other than us). In certain circumstances and for ease of reading we discuss the financial results of the Predecessor Business as being “our” financial results during historic periods when this business was owned by Dynegy or Targa, respectively.

 

Overview

 

We are a Delaware limited partnership recently formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. On February 14, 2007, Targa contributed to us the entities holding the North Texas System. The North Texas System consists of two wholly-owned natural gas processing plants and an extensive network of integrated gathering pipelines that serve a 14-county natural gas producing region in the Fort Worth Basin in North Central Texas. This producing region includes production from the Barnett Shale formation and production from shallower formations including the Bend Conglomerate, Caddo, Atoka, Marble Falls, and other Pennsylvanian and upper Mississippian formations (referred to as the “other Fort Worth Basin formations”). The natural gas processing plants consist of the Chico processing and fractionation facilities and the Shackelford processing facility.

 

Factors That Significantly Affect Our Results

 

Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather and transport through our pipeline systems, which we refer to as throughput volume. Throughput volumes and capacity utilization rates generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs.

 

Our processing contract arrangements can have a significant impact on our profitability. We process natural gas under a combination of percent-of-proceeds contracts (representing approximately 96% of our gathered natural gas volumes) and keep-whole contracts (representing approximately 4% of our gathered natural gas volumes), each of which exposes us to commodity price risk. We attempt to mitigate this risk through hedging activities which can materially impact our results of operations. Please see Item 7A. — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.

 

Actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, and the competitive commodity and 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, 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 as well as other market factors. For a more complete discussion of the types of contracts under which we process natural gas, please see Item 1. Business — Midstream Industry Overview.

 

The historical financial statements of the Predecessor Business include certain items that will not materially impact our future results of operations and liquidity and do not fully reflect a number of other items that will materially impact future results of operations and liquidity, including the items described below:

 

Affiliate Indebtedness and Borrowings.  Affiliate indebtedness consists of borrowings incurred by Targa and allocated to us for financial reporting purposes as well as intercompany debt contributed to us together with the North Texas System. Prior to the DMS Acquisition, the Predecessor Business was financed internally and reflected no indebtedness on its balance sheet or ongoing interest expense on its income statement. A substantial portion of the DMS Acquisition was financed through borrowings by Targa. Following the October 31, 2005 DMS Acquisition, a significant portion of Targa’s acquisition borrowings were allocated to the Predecessor Business, resulting in approximately $868.9 million of allocated indebtedness and corresponding levels of interest expense. This indebtedness was incurred by Targa in connection with the DMS Acquisition and the entity holding the North Texas System provided a guarantee of this indebtedness. This indebtedness was also secured by a collateral interest in both the equity of the entity holding the North Texas System as well as its assets. In connection with our IPO, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.

 

On February 14, 2007, we borrowed approximately $294.5 million under our credit facility. The proceeds from this borrowing, together with approximately $371.2 million of net proceeds from the IPO (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units), were used to repay approximately $665.7 million of affiliate indebtedness and the remaining balance of this indebtedness was retired and treated as a capital contribution to us.

 

Impact of Our 2006 Hedging Activities.  In an effort to reduce the variability of our cash flows, as of December 31, 2006, we have hedged the commodity price associated with approximately 90-60% of our expected natural gas, 65-50% of our expected NGL and 95-60% of our expected condensate equity volumes for the years 2007 through 2010 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentage of our expected volumes that are hedged decreases over the term of the hedges. With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. For additional information regarding our hedging activities, please see Item 7A. — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk. These hedging arrangements were not entered into until the second and fourth quarters of 2006; accordingly, there is no impact of our hedging activities in the historical financial statements prior to 2006. In addition, the hedges we entered into in the second and fourth quarters of 2006 were executed at prices that are materially higher than current market prices. Accordingly, our results of operations are realizing a significant benefit from these positions. We expect this benefit to decline through the life of the hedges, which cover decreasing volumes at declining prices through 2010.

 

General and Administrative Expenses.  The Predecessor Business recognized general and administrative expenses as a result of allocations from the consolidated general and administrative expenses of Dynegy and Targa, respectively. Allocated general and administrative expenses were $6.9 million, $8.4 million and $7.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. On February 14, 2007, we entered into an omnibus agreement with Targa pursuant to which our allocated general and administrative expenses are capped at $5.0 million per year for three years, subject to adjustment. For a more complete description of this agreement, see Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement. In addition to these allocated general and administrative expenses, we expect to incur incremental general and administrative expenses as a result of operating as a separate publicly held limited partnership. These direct, incremental general

and administrative expenses are expected to be approximately $2.5 million annually, are not subject to the cap contained in the omnibus agreement and include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, incremental independent auditor fees, registrar and transfer agent fees and independent director compensation. These incremental general and administrative expenditures are not reflected in the historical financial statements of the Predecessor Business.

 

Working Capital Adjustments.  In the historical financial statements of the Predecessor Business, all intercompany transactions, including commodity sales and expense reimbursements, were not cash settled with the Predecessor Business’ respective parent, but were recorded as an adjustment to parent equity on the balance sheet. The primary intercompany transactions between the respective parent and the Predecessor Business are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. Accordingly, the working capital of the Predecessor Business does not reflect any affiliate accounts receivable for intercompany commodity sales or affiliate accounts payable for the personnel and services provided by or paid for by the applicable parent on behalf of the Predecessor Business.

 

Distributions to our Unitholders.  We plan to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and other debt and equity issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs. Historically, the North Texas System has largely relied on internally generated cash flows for these purposes.

 

General Trends and Outlook

 

We expect our business to continue to be affected by the following key trends. Our 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.

 

Natural Gas Supply and Outlook.  Fluctuations in energy prices can affect production rates and investments by third parties in the development of new natural gas reserves. Generally, drilling and production activity will increase as natural gas prices increase. In 2006, the prices we realized for natural gas declined to an average of $5.96 per MMBtu from an average of $7.11 per MMBtu for 2005. For 2005, the prices we realized for natural gas rose from an average of $5.43 per MMBtu for 2004. In part as a result of the prevailing prices during these periods, the Fort Worth Basin has experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. Our largest supplier of natural gas in the Fort Worth Basin is ConocoPhillips, which represented approximately 33% and 36% of the natural gas supplied to our system for the years ended December 31, 2006 and 2005, respectively. We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the Fort Worth Basin/Bend Arch as producers seek to increase their level of natural gas production.

 

Commodity Prices.  Our operating income generally improves in an environment of higher natural gas and NGL prices, primarily as a result of our percent-of-proceeds contracts. For the year ended December 31, 2006, excluding the impact of hedging activities, we sold an average of 74.9 BBtu/d of residue gas at an average price of $5.96 per MMBtu, as compared to 69.5 BBtu/d at an average price of $7.11 per MMBtu for the year ended December 31, 2005, and 59.2 BBtu/d at an average price of $5.43 per MMBtu for the year ended December 31, 2004. For the year ended December 31, 2006, we sold an average of 15.2 MBbl/d of NGLs at an average price of $36.98 per Bbl, as compared to 14.5 MBbl/d at an average price of $33.57 per Bbl for the year ended December 31, 2005, and 13.2 MBbl/d at an average price of $26.71 per Bbl for the year ended December 31, 2004. Additionally, we separately sold condensate during these periods. Our processing profitability is largely dependent upon pricing 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, please see Item 7A.— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.

 

Rising Operating Costs.  The current high levels of natural gas exploration, development and production activities, both in the Fort Worth Basin and more broadly across the United States, is increasing competition for personnel and equipment. This increased competition is placing upward pressure on the prices we pay for labor, supplies, property, plant and equipment. We attempt to recover increased costs from our customers. To the extent we are unable to procure necessary supplies or to recover higher costs, our operating results will be negatively impacted.

 

Our Operations

 

Our results of operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our gathering, processing and pipeline systems; the volumes of NGLs and residue natural gas sold; and the level of natural gas and NGL prices. We generate our revenues and our operating margins principally under percent-of-proceeds contractual arrangements. Under these arrangements, we generally gather natural gas from producers at the wellhead or central delivery points, transport the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on published index market prices. We remit to the producers either an agreed upon percentage of recovered volumes or the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage of the proceeds based on index related prices for the natural gas and NGLs. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs. For the year ended December 31, 2006, our percent-of-proceeds activities accounted for approximately 96% of our natural gas throughput volumes. The balance of our throughput volumes are processed under wellhead purchases and keep-whole contractual arrangements.

 

Our Chico facility includes an NGL fractionator with the capacity to fractionate up to 11,500 Bbl/d of the raw NGL mix that results from the processing of natural gas at Chico. This fractionation capability allows Chico to deliver either raw NGL mix to Mont Belvieu primarily through Chevron’s WTLPG Pipeline or separated NGL products to local and other markets via truck.

 

We sell all of our processed natural gas, NGLs and high pressure condensate to Targa at market-based rates pursuant to natural gas, NGL and condensate purchase agreements. Low-pressure condensate is sold to third parties. For a more complete description of these arrangements, see Item 13. Certain Relationships and Related Transactions and Director Independence and Item 1. Business — Market Access — Chico System Market Access.

 

How We Evaluate Our Operations

 

Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas that we purchase as well as operating and general and administrative costs. 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 natural gas and NGLs, and the natural gas and NGL throughput on our system are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, demand for our products and changes in our customer mix.

 

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) throughput volumes, facility efficiencies and fuel consumption,

(2) operating margin, (3) operating expenses, (4) general and administrative expenses, (5) EBITDA and (6) 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 to offset the natural decline of existing volumes from natural gas wells that are connected to our systems. This is achieved by connecting new wells as well as by capturing supplies currently gathered by third-parties. In addition, we seek to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of 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. This information is tracked through our processing plants to determine customer settlements 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 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 NGL and residue gas produced at the outlet of such plants to monitor the fuel consumption and recoveries of the facilities. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.

 

Operating Margin.  We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases, and operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail below. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis.

 

The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

We compensate for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these learnings into our decision-making processes.

 

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:

 

 

Operating Expenses.  Operating expenses are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repair and maintenance, utilities and contract services compose the most significant portion of our operating expenses. These expenses generally remain relatively stable independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.

 

EBITDA.  EBITDA is another non-GAAP financial measure that is used by us. We define EBITDA as net income before interest, income taxes, depreciation and amortization. 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, to assess:

 

 

The economic substance behind our use of 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.

 

The GAAP measures most directly comparable to EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because 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 EBITDA may not be comparable to similarly titled measures of other companies.

 

We compensate for the limitations of EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into our decision-making processes.

 

 

 

 

Distributable Cash Flow.  Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others 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 can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP 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).

 

The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors.

 

The GAAP measure most directly comparable to distributable cash flow is net income. Our non-GAAP measure of distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You 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 compatible to similarly titled measures of other companies, thereby diminishing its utility.

 

We compensate for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into our decision making processes.

 

 

 

 

Contract Mix

 

We generate revenue based on the contractual arrangements we have with our producer customers. These arrangements can be in many forms which vary in the amount of commodity price risk they carry. Substantially all of our revenues are generated under percent-of-proceeds arrangements pursuant to which we receive a portion of the natural gas and/or NGLs as payment for services. Please see Item 1. Business — Midstream Sector Overview for a more detailed discussion of the contractual arrangements under which we

operate. Set forth below is a table summarizing our average contract mix for the year ended December 31, 2006, including the potential impacts of changes in commodity prices on operating margins:

 

 

At times, producer preferences, competitive forces and other factors cause us to enter into more commodity price sensitive contracts, such as wellhead purchases and keep-whole arrangements. We prefer to enter into contracts with less commodity price sensitivity, including fee-based and percent-of-proceeds arrangements.

 

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.

 

Revenue Recognition.  Our primary types of sales and service activities reported as operating revenue include:

 

 

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

 

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we are paid for our services by keeping a percentage of the NGLs extracted and the residue gas resulting from processing natural gas. In percent-of-proceeds arrangements, we remit either a percentage of the proceeds received from the sales of residue gas and NGLs or a percentage of the residue gas or NGLs at the tailgate of the plant to the producer. Under the terms of percent-of-proceeds and similar contracts, we may purchase the producer’s share of the processed commodities for resale or deliver the commodities to the producer at the tailgate of the plant. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.

 

We generally report revenues gross in the combined statements of operations, in accordance with Emerging Issues Task Force or “EITF” Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based contracts, we act as the principal in these transactions where we receive natural gas or NGLs, take title to the commodities, and incur the risks and rewards of ownership.

 

Use of Estimates.  The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial positions and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. 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 and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

 

Property, Plant, and Equipment.  Property, plant, and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The estimated service lives of our functional asset groups are as follows:

 

 

Expenditures for maintenance and repairs are generally expensed as incurred. However, expenditures to refurbish (i.e., certain repair and maintenance expenses) assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset.

 

Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. From time to time, we utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

 

We may capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

 

In accordance with Statement of Financial Accounting Standards or “SFAS” 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable.

 

We evaluate an asset for recoverability by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our Consolidated Statements of Operations.

 

Price Risk Management (Hedging).  We account for derivative instruments in accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS 133, all derivative instruments not qualifying for the normal purchases and sales exception are recorded on the balance sheet at

fair value. If a derivative does not qualify as a hedge, or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of partners’ capital, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as hedge are classified in the same category as the cash flows from the item being hedged.

 

The relationship between the hedging instrument 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 contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI 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 hedging instrument are reclassified to earnings immediately.

 

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we will assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge effectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.

 

Estimated Useful Lives.  The estimated useful lives of our long-lived assets are used to compute depreciation expense, future asset retirement obligations and in impairment testing. Estimated useful lives are based, among other things, on the assumption that we provide an appropriate level of maintenance capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result.

 

Natural Gas Imbalances.  Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances are valued at the lower of cost or market; gas imbalances are valued at replacement cost. These imbalances are typically settled in the following month with deliveries of natural gas. Certain contracts require cash settlement of imbalances on a current basis. Under these contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

 

Results of Operations

 

The following table and discussion is a summary of our combined results of operations for the three years ended December 31, 2006.