þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the fiscal year ended December 31, 2006 | ||
or
|
||
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the transition period from to |
Delaware
(State or other jurisdiction of incorporation or organization) |
65-1295427
(I.R.S. Employer Identification No.) |
|
1000 Louisiana St,
Suite 4300
Houston, Texas (Address of principal executive offices) |
77002
(Zip Code) |
Title of Each Class
|
Name of Each Exchange on Which Registered
|
|
Common Units Representing Limited
Partnership Interests
|
The NASDAQ Stock Market LLC |
2
| our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; | |
| our use of derivative financial instruments to hedge commodity and interest rate risks; | |
| the level of creditworthiness of counterparties to transactions; | |
| the amount of collateral required to be posted from time to time in our transactions; | |
| changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry; | |
| the timing and extent of changes in commodity prices, interest rates and demand for our services; | |
| weather and other natural phenomena; | |
| industry changes, including the impact of consolidations and changes in competition; | |
| our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products; | |
| our ability to grow through acquisitions or internal growth projects; | |
| the extent of success in connecting natural gas supplies to gathering and processing systems; and | |
| general economic, market and business conditions. |
3
BBtu
|
Billion British thermal units | |
Btu
|
British thermal unit, a measure of heating value | |
/d
|
Per day | |
Bbl
|
Barrel | |
MBbl
|
Thousand barrels | |
Mcf
|
Thousand cubic feet | |
MMBtu
|
Million British thermal units | |
MMcf
|
Million cubic feet |
Price Index Definitions
|
||
IF-NGPL MC
|
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent | |
IF-WAHA
|
Inside FERC Gas Market Report, West Texas Waha | |
MB-OPIS
|
Oil Price Information Service, Mont Belvieu, Texas | |
NY-WTI
|
NYMEX, West Texas Intermediate Crude Oil |
Item 1. | Business |
4
| the Chico system, located in the northeast part of the Fort Worth Basin, which consists of: |
| approximately 1,875 miles of natural gas gathering pipelines with approximately 1,830 active connections to producing wells and central delivery points; | |
| a cryogenic natural gas processing plant with throughput capacity of approximately 215 MMcf/d that can be increased by another 50 MMcf/d as may be required to meet production needs through the installation of an additional refrigeration compressor unit that is on site (for the years ended December 31, 2006 and 2005, the average daily plant inlet volume was 149.7 MMcf/d and 145.0 MMcf/d, respectively); and | |
| an 11,500 Bbl/d fractionator located at the processing plant that enables us, based on market conditions, to either fractionate a portion of our raw NGL mix into separate NGL products for sale into local and other markets or deliver raw NGL mix to Mont Belvieu for fractionation primarily through Chevrons WTLPG Pipeline; |
| the Shackelford system, located on the western side of the Fort Worth Basin, which consists of: |
| approximately 2,090 miles of natural gas gathering pipelines with approximately 820 active connections to producing wells and central delivery points; and | |
| a cryogenic natural gas processing plant with throughput capacity of approximately 13 MMcf/d (for the years ended December 31, 2006 and 2005, the average daily plant inlet volume was 12.1 MMcf/d and 12.2 MMcf/d, respectively); and |
| a 32-mile, 10-inch diameter natural gas pipeline connecting the Shackelford and Chico systems, which we refer to as the Interconnect Pipeline, that is used primarily to send natural gas gathered in excess of the Shackelford systems processing capacity to the Chico plant. |
| Increasing the profitability of our existing assets. We are currently evaluating opportunities to increase the profitability of our existing operations by connecting and processing new supplies of natural gas, improving operating efficiencies and increasing processing yields, adding processing capacity, increasing throughput at our Chico fractionator, increasing volumes of low pressure gas to be gathered and processed, continuing electronic flow measurement conversion of our meters, decontaminating condensate and shipping pipeline quality condensate to Mont Belvieu. | |
| Managing our contract mix to optimize profitability. The majority of our operating margin is generated pursuant to percent-of-proceeds or similar arrangements which, if unhedged, benefit us in increasing commodity price environments and expose us to a reduction in profitability in decreasing commodity price environments. We believe that appropriately managed, our current contract mix allows us to optimize our profitability over time. Although we expect to maintain primarily percent-of-proceeds arrangements, we continually evaluate the market for attractive fee based and other arrangements which will further reduce the variability of our cash flows. | |
| Mitigating commodity price exposure through prudent hedging arrangements. The primary purpose of our commodity price risk management activities is to hedge our exposure to commodity price risk inherent in our contract mix and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. We have tailored our hedges to match our actual NGL product composition and to approximate our actual NGL and natural gas delivery points. We intend to continue to manage our exposure to commodity prices in the future by entering into hedge transactions, as market conditions permit. |
5
| Capitalizing on organic expansion opportunities. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that will allow us to leverage our existing market position and leverage our core competitiveness in the midstream energy industry. | |
| Focusing on producing regions with attractive characteristics. We seek to focus on regions (1) where treating or processing is required to access end-markets; (2) where permitting, drilling and workover activity is high; (3) with the potential for long-term acreage dedications; (4) with a strong base of current production and the potential for significant future development and (5) that can serve as a platform to expand into adjacent areas with existing or new production. | |
| Pursuing strategic and accretive acquisitions. We plan to pursue strategic and accretive acquisition opportunities within the midstream energy industry, both from Targa and from third parties. We seek acquisition opportunities in our existing areas of operation with the opportunity for operational efficiencies and the potential for higher capacity utilization and expansion of those assets, as well as acquisitions in other related lines of our midstream business and new geographic areas of operation. | |
| Leveraging our relationship with Targa. Our relationship with Targa provides us access to its extensive pool of operational, commercial and risk management expertise which enables all of the strategies. In addition, we intend to pursue acquisition opportunities as well as organic growth opportunities with Targa and with Targas assistance. We may also acquire assets or businesses directly from Targa, which will provide us access to a broader array of growth opportunities than those available to many of our competitors. |
| Affiliation with Targa. We expect that our relationship with Targa will provide us with significant business opportunities. We believe Targas relationships throughout the energy industry, including with producers of natural gas in the United States, will help facilitate implementation of our acquisition strategy and other strategies. | |
| Strategically located assets. The Barnett Shale region of the Fort Worth Basin is one of the most productive natural gas-producing regions in North America and has generally long-lived, predictable reserves. The other Fort Worth Basin formations are well-established, mature plays that exhibit lower decline rates than those of the Barnett Shale. Current high levels of natural gas exploration, development and production activities within both Barnett and non-Barnett areas of our operations present significant organic growth opportunities to generate additional throughput on our system. | |
| High quality and efficient assets. Our gathering and processing systems consist of high-quality assets that have been well maintained, resulting in low cost, efficient operations. We have implemented state of the art processing, measurement and operations and maintenance technologies. | |
| Low maintenance capital expenditures. Our maintenance capital expenditures have averaged approximately $12 million over the three years ended December 31, 2006. We believe that this level of maintenance capital expenditures is sufficient for us to continue operations in a safe, prudent and cost-effective manner. | |
| Prudent hedging arrangements. While our percent-of-proceeds gathering and processing contracts subject us to commodity price risk, we have entered into long-term hedges covering a majority of our expected natural gas, NGL and condensate equity volumes for the years 2007 through 2010. This strategy minimizes commodity price risk related to these arrangements. For additional information regarding our hedging activities, please see Item 7A Quantitative and Qualitative Disclosures about Market Risk. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions using swaps, collars, purchased puts (or floors) or other hedge instruments for existing and expected equity production as market conditions permit. |
6
| Strong producer customer base. We have a strong producer customer base consisting of both major oil and gas companies and independent producers and believe we have a reputation as a reliable operator. Targa also has relationships throughout the energy industry, including with producers of natural gas in the United States, and has established a positive reputation in the energy business which we believe will assist us in our primary business objectives. | |
| Comprehensive package of midstream services. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, compression, treating, processing and NGL fractionating. We believe our ability to provide all of these services provides us with an advantage in competing for new supplies of natural gas because we can provide substantially all of the services producers, marketers and others require to move natural gas and NGLs from wellhead to market on a cost-effective basis. | |
| Experienced management team. Targa has an experienced and knowledgeable executive management team with an average of 27 years of experience in the energy industry that owns a 10.2% indirect ownership interest in us. Targas executive management team has a proven track record of enhancing value through the acquisition, optimization and integration of midstream assets. In addition, Targas operations and commercial management team consists of individuals with an average of 23 years of midstream operating experience. Our relationship with Targa provides us with access to significant operational, commercial, technical, risk management and other expertise. |
7
8
| Percent-of-Proceeds, or Percent-of-Value or Percent-of-Liquids. In a percent-of-proceeds arrangement, the processor remits to the producers a percentage of the proceeds from the sales of residue gas and NGL products or a percentage of residue gas and NGL products at the tailgate. The percent-of-value and percent-of-liquids are variations on this arrangement. These types of arrangements expose the processor to some commodity price risk as the revenues from the contracts are directly correlated with the price of natural gas and NGLs. | |
| Keep-Whole. A keep-whole arrangement allows the processor to keep 100% of the NGLs produced and requires the return of the processed natural gas, or value of the gas, to the producer or owner. A wellhead purchase contract is a variation of this arrangement. Since some of the gas is used during processing, the processor must compensate the producer or owner for the gas shrink entailed in processing by supplying additional gas or by paying an agreed value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs. As a result, a processor with these types of contracts benefits when the value of the NGLs is high relative to the cost of the natural gas and is disadvantaged when the cost of the natural gas is high relative to the value of the NGLs. |
9
| Fee-Based. Under a fee-based contract, the processor receives a fee per gallon of NGLs produced or per Mcf of natural gas processed. Under this arrangement, a processor would have no commodity price risk exposure. |
| Ethane. Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. | |
| Propane. Propane is used as heating fuel, engine fuel and industrial fuel, for agricultural burning and drying and as petrochemical feedstock for production of ethylene and propylene. | |
| Normal Butane. Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used to derive isobutane. | |
| Isobutane. Isobutane is principally used by refiners to enhance the octane content of motor gasoline and in the production of MTBE, an additive in cleaner burning motor gasoline. | |
| Natural Gasoline. Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock. |
10
11
| Natural Gas Pipeline Company of America which is owned by Kinder Morgan, Inc. and serves the Midwest, specifically the Chicago market; | |
| ET Fuel System which is owned by Energy Transfer Partners, L.P. and has access to the Waha, Carthage and Katy hubs in Texas; |
12
| Atmos Pipeline Texas (Atmos-Texas) which is owned by Atmos Energy Corporation and has access to the Waha, Carthage and Katy hubs in Texas; and | |
| Enbridge Pipelines (North Texas) L.P. which is owned by Enbridge Energy Partners, L.P. and has access to several local residue gas markets. |
13
14
15
16
| requiring the installation of pollution control equipment or otherwise restricting the way we can handle or dispose of our wastes; | |
| limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species; | |
| requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and | |
| enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. |
17
18
19
Item 1A. | Risk Factors |
| the fees we charge and the margins we realize for our services; | |
| the prices of, levels of production of, and demand for, natural gas and NGLs | |
| the volume of natural gas we gather, treat, compress, process, transport and sell, and the volume of NGLs we process or fractionate and sell; | |
| the relationship between natural gas and NGL prices; | |
| cash settlements of hedging positions; | |
| the level of competition from other midstream energy companies; |
20
| the level of our operating and maintenance and general and administrative costs; and | |
| prevailing economic conditions. |
| the level of capital expenditures we make; | |
| our ability to make borrowings under our credit facility to pay distributions; | |
| the cost of acquisitions; | |
| our debt service requirements and other liabilities; | |
| fluctuations in our working capital needs; | |
| general and administrative expenses, including expenses we will incur as a result of being a public company; | |
| restrictions on distributions contained in our debt agreements; and | |
| the amount of cash reserves established by our general partner for the proper conduct of our business. |
| the impact of seasonality and weather; | |
| general economic conditions; | |
| the level of domestic crude oil and natural gas production and consumption; | |
| the availability of imported natural gas, liquified natural gas, NGLs and crude oil; | |
| actions taken by foreign oil and gas producing nations; | |
| the availability of local, intrastate and interstate transportation systems; | |
| the availability and marketing of competitive fuels; | |
| the impact of energy conservation efforts; and | |
| the extent of governmental regulation and taxation. |
21
22
| competition from other systems that may be able to meet producer needs or supply end-user markets on a more cost-effective basis; | |
| operational problems such as catastrophic events at the Chico processing plant or gathering lines, labor difficulties or environmental proceedings or other litigation that compel cessation of all or a portion of the operations on our Chico system; | |
| an inability to obtain sufficient quantities of natural gas for the Chico system at competitive terms; or | |
| reductions in exploration or production activity, or shut-ins by producers in the areas in which we operate. |
23
| damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism; | |
| inadvertent damage from third parties, including from construction, farm and utility equipment; | |
| leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and | |
| other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
24
| our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; | |
| we need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; | |
| our debt level makes us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and | |
| our debt level may limit our flexibility in responding to changing business and economic conditions. |
25
26
27
| perform ongoing assessments of pipeline integrity; | |
| identify and characterize applicable threats to pipeline segments that could impact a high consequence area; | |
| improve data collection, integration and analysis; | |
| repair and remediate the pipeline as necessary; and | |
| implement preventive and mitigating actions. |
28
| mistaken assumptions about volumes, revenues and costs, including synergies; | |
| an inability to integrate successfully the businesses we acquire; | |
| the assumption of unknown liabilities; | |
| limitations on rights to indemnity from the seller; | |
| mistaken assumptions about the overall costs of equity or debt; | |
| the diversion of managements and employees attention from other business concerns; | |
| unforeseen difficulties operating in new product areas or new geographic areas; and | |
| customer or key employee losses at the acquired businesses. |
29
| neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targas directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests; | |
| our general partner is allowed to take into account the interests of parties other than us, such as Targa, or its owners, including Warburg Pincus, in resolving conflicts of interest; and | |
| Targa is not limited in its ability to compete with us and is under no obligation to offer assets to us. |
30
| permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; | |
| provides that our general partner does not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership; | |
| generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be fair and reasonable to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is fair and reasonable, our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; | |
| provides that our general partner and its officers and directors are not liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and | |
| provides that in resolving conflicts of interest, it is presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. |
31
32
| our unitholders proportionate ownership interest in us will decrease; | |
| the amount of cash available for distribution on each unit may decrease; | |
| because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; | |
| the ratio of taxable income to distributions may increase; | |
| the relative voting strength of each previously outstanding unit may be diminished; and | |
| the market price of the common units may decline. |
33
34
| a court or government agency determined that we were conducting business in a state but had not complied with that particular states partnership statute; or | |
| your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute control of our business. |
35
36
Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
Item 3. | Legal Proceedings |
Item 4. | Submission of Matters to a Vote of Security Holders |
37
43
50
66
77
79
84
85
F-22
Item 5.
Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities
less the amount of cash reserves established by our general
partner to:
provide for the proper conduct of our business
comply with applicable law, any of our debt instruments or other
agreements; or
provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters;
plus; if our general partner so determines, all or a portion of
cash on hand on the date of determination of available cash for
the quarter.
38
Table of Contents
39
Table of Contents
Item 6.
Selected
Financial Data
Predecessor Business
Targa North Texas LP
Dynegy
Year
Two Months
Ten Months
Ended
Ended
Ended
December 31,
December 31,
October 31,
Years Ended December 31,
2006
2005
2005
2004
2003
2002
(Audited)
(Audited)
(Audited)
(Audited)
(Audited)
(Unaudited)
(in millions of dollars, except operating and price data)
$
384.8
$
75.1
$
293.3
$
258.6
$
196.8
$
112.5
269.3
54.9
210.8
182.6
147.3
82.7
24.1
3.5
18.0
17.7
15.1
14.9
56.0
9.2
11.3
12.2
12.0
11.8
6.9
1.1
7.3
7.2
7.7
7.7
72.9
11.5
2.5
0.3
0.6
(0.3
)
$
(46.9
)
$
(5.1
)
$
45.9
$
38.6
$
14.1
$
(4.3
)
$
91.4
$
16.7
$
64.5
$
58.3
$
34.4
$
14.9
$
84.5
$
15.6
$
57.2
$
50.8
$
26.1
$
7.5
168.3
168.8
161.2
152.0
134.3
106.6
161.8
161.9
156.2
145.4
128.6
104.0
18.9
19.8
18.5
17.2
15.9
12.5
74.9
72.3
68.9
59.2
42.0
38.2
15.2
15.4
14.3
13.2
15.3
12.3
0.5
0.5
0.5
0.7
0.6
0.6
$
6.09
$
8.61
$
6.79
$
5.43
$
4.97
$
2.84
0.88
0.90
0.78
0.64
0.47
0.35
65.31
57.54
53.42
40.56
29.86
23.24
$
1,064.1
$
1,097.0
$
196.4
$
191.2
$
180.4
$
178.2
1,115.8
1,122.8
198.5
193.5
182.9
179.7
864.0
868.9
215.7
219.5
158.5
168.8
164.8
167.3
$
16.2
$
(1.5
)
$
72.7
$
58.0
$
31.3
$
10.2
(23.1
)
(2.1
)
(16.4
)
(23.4
)
(14.6
)
(30.6
)
6.9
3.6
(56.3
)
(34.6
)
(16.7
)
20.4
40
Table of Contents
(1)
In May 2006, Texas adopted a margin tax consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods sold.
The amount presented represents our estimated liability for this
tax.
(2)
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures Operating Margin,
included in this Item 6.
(3)
EBITDA is net income before interest, income taxes, depreciation
and amortization. Please see Non-GAAP Financial
Measures EBITDA, included in this Item 6.
(4)
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points.
(5)
Plant natural gas inlet represents the volume of natural gas
passing through the meter located at the inlet of a natural gas
processing plant.
(6)
Average realized prices include the impact of hedging activities.
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
41
Table of Contents
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
42
Table of Contents
Predecessor Business
Targa North Texas LP
Dynegy
Year
Two Months
Ten Months
Years
Years
Years
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
December 31,
October 31,
December 31,
December 31,
December 31,
2006
2005
2005
2004
2003
2002
(in millions)
$
16.2
$
(1.5
)
$
72.7
$
58.0
$
31.3
$
10.2
67.8
10.7
(0.2
)
0.1
0.3
(0.7
)
0.7
0.3
(0.6
)
0.8
1.3
(2.7
)
(1.0
)
0.6
1.3
5.5
(17.1
)
(3.8
)
(4.9
)
(3.6
)
$
84.5
$
15.6
$
57.2
$
50.8
$
26.1
$
7.5
$
(46.9
)
$
(5.1
)
$
45.9
$
38.6
$
14.1
$
(4.3
)
72.9
11.5
2.5
56.0
9.2
11.3
12.2
12.0
11.8
$
84.5
$
15.6
$
57.2
$
50.8
$
26.1
$
7.5
$
(46.9
)
$
(5.1
)
$
45.9
$
38.6
$
14.1
$
(4.3
)
56.0
9.2
11.3
12.2
12.0
11.8
2.5
0.3
0.6
(0.3
)
72.9
11.5
6.9
1.1
7.3
7.2
7.7
7.7
$
91.4
$
16.7
$
64.5
$
58.3
$
34.4
$
14.9
(1)
Excludes non-cash amortization of debt issue costs of
$5.1 million for the year ended December 31, 2006 and
$0.8 million for the two months ended December 31, 2005
Item 7.
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
Table of Contents
44
Table of Contents
45
Table of Contents
46
Table of Contents
47
Table of Contents
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
48
Table of Contents
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
49
Table of Contents
Predecessor Business
Targa North Texas LP
Combined
Dynegy
Year
Two Months
Year
Ten Months
Years
Ended
Ended
Ended
Ended
Ended
December 31,
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2005
2004
(in millions)
$
16.2
$
(1.5
)
$
71.2
$
72.7
$
58.0
67.8
10.7
10.7
(0.2
)
0.1
0.4
0.3
(0.7
)
(0.6
)
0.8
2.1
1.3
(2.7
)
1.3
5.5
(11.6
)
(17.1
)
(3.8
)
$
84.5
$
15.6
$
72.8
$
57.2
$
50.8
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
72.9
11.5
11.5
2.5
56.0
9.2
20.5
11.3
12.2
$
84.5
$
15.6
$
72.8
$
57.2
$
50.8
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
56.0
9.2
20.5
11.3
12.2
2.5
0.3
72.9
11.5
11.5
6.9
1.1
8.4
7.3
7.2
$
91.4
$
16.7
$
81.2
$
64.5
$
58.3
(1)
Excludes non-cash amortization of debt issue costs of
$5.1 million for the year ended December 31, 2006 and
$0.8 million for the two months ended December 31,
2005.
Table of Contents
Predecessor Business
Targa North Texas LP
Combined
Dynegy
Year
Two Months
Year
Ten Months
Year
Ended
Ended
Ended
Ended
Ended
December 31,
December 31,
December 31,
December 31,
December 31,
2006
2005
2005
2005
2004
(in millions)
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
56.0
9.2
20.5
11.3
12.2
2.5
5.1
0.8
0.8
(11.7
)
(1.6
)
(12.9
)
(11.3
)
(10.2
)
$
5.0
$
3.3
$
49.2
$
45.9
$
40.6
(a)
Distributable cash flow for the year ended December 31,
2006 and the two months ended December 31, 2005, reflects
allocated interest from parent of $72.9 million and
$11.5 million, respectively.
51
Table of Contents
Percent of
96%
Decreases in natural gas
and/or
NGL
prices generate decreases in operating margins.
4%
Increases in natural gas prices
relative to NGL prices generate decreases in operating margins.
Decreases in NGL prices relative to natural gas prices generate
decreases in operating margins.
sales of natural gas, NGLs and condensate; and
natural gas processing, from which we generate revenue through
the compression, gathering, treating and processing of natural
gas.
52
Table of Contents
Service Life
(Years)
15 to 25
3 to 7
53
Table of Contents
54
Table of Contents
Predecessor Business
Targa North Texas LP
Combined
Dynegy
Year
Two Months
Year
Ten Months
Year
Ended
Ended
Ended
Ended
Ended
December 31,
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2005
2004
(in millions of dollars, except operating and price data)
$
384.8
$
75.1
$
368.4
$
293.3
$
258.6
269.3
54.9
265.7
210.8
182.6
24.1
3.5
21.5
18.0
17.7
56.0
9.2
20.5
11.3
12.2
6.9
1.1
8.4
7.3
7.2
0.3
28.5
6.4
52.3
45.9
38.6
(72.9
)
(11.5
)
(11.5
)
(2.5
)
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
$
91.4
$
16.7
$
81.2
$
64.5
$
58.3
$
84.5
$
15.6
$
72.8
$
57.2
$
50.8
168.3
168.8
162.5
161.2
152.0
161.8
161.9
157.2
156.2
145.4
18.9
19.8
18.7
18.5
17.2
74.9
72.3
69.5
68.9
59.2
15.2
15.4
14.5
14.3
13.2
0.5
0.5
0.5
0.5
0.7
$
6.09
$
8.61
$
7.11
$
6.79
$
5.43
0.88
0.90
0.80
0.78
0.64
65.31
57.54
54.03
53.42
40.56
(1)
In May 2006, Texas adopted a margin tax, consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods sold.
The amount presented represents our estimated liability for this
tax.
(2)
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures Operating Margin
included in this Item 7.
(3)
EBITDA is net income before interest, income taxes, depreciation
and amortization. Please see Non-GAAP Financial
Measures EBITDA, included in this Item 7.
(4)
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points.
(5)
Plant natural gas inlet represented the volume of natural gas
passing through the meter located at the inlet of a natural gas
processing plant.
(6)
Plant inlet volumes include producer take-in-kind, while natural
gas sales exclude producer take-in-kind volumes.
55
Table of Contents
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
56
Table of Contents
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
Predecessor Business
Targa North Texas LP
Combined
Dynegy
Two Months
Ten Months
Year Ended
Ended
Year Ended
Ended
Years Ended
December 31,
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2005
2004
(in millions of dollars)
$
16.2
$
(1.5
)
$
71.2
$
72.7
$
58.0
67.8
10.7
10.7
(0.2
)
0.1
0.4
0.3
(0.7
)
(0.6
)
0.8
2.1
1.3
(2.7
)
1.3
5.5
(11.6
)
(17.1
)
(3.8
)
$
84.5
$
15.6
$
72.8
$
57.2
$
50.8
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
72.9
11.5
11.5
2.5
56.0
9.2
20.5
11.3
12.2
$
84.5
$
15.6
$
72.8
$
57.2
$
50.8
$
(46.9
)
$
(5.1
)
$
40.8
$
45.9
$
38.6
56.0
9.2
20.5
11.3
12.2
2.5
0.3
72.9
11.5
11.5
6.9
1.1
8.4
7.3
7.2
$
91.4
$
16.7
$
81.2
$
64.5
$
58.3
(1)
Excludes non-cash amortization of debt issue costs of
$5.1 million for the year ended December 31, 2006 and
$0.8 million for the two months ended December 31,
2005.
57
Table of Contents
a net decrease attributable to commodity prices of
$6.2 million, consisting of increases in NGL and condensate
revenue of $19.4 million and $2.2 million,
respectively, offset by a decrease in natural gas revenue of
$27.8 million; and
a net increase attributable to volumes of $22.6 million,
consisting of increases in natural gas, NGL and condensate
revenue of $14.0 million, $8.5 million and
$0.1 million, respectively.
58
Table of Contents
an increase attributable to commodity prices of
$81.3 million, consisting of increases in natural gas, NGL
and condensate revenue of $42.6 million, $36.2 million
and $2.5 million, respectively;
a net increase attributable to volumes of $29.2 million,
consisting of increases in natural gas and NGL revenue of
$19.9 million and $11.8 million, respectively,
partially offset by a decrease in condensate revenue of
$2.5 million; and
partially offset by a decrease in fee and other revenues of
$0.7 million.
59
Table of Contents
cash generated from operations;
borrowings under our credit facility;
issuance of additional partnership units; and
debt offerings.
60
Table of Contents
61
Table of Contents
incur indebtedness;
62
Table of Contents
grant liens; and
engage in transactions with affiliates.
Payments Due by Period
Less Than
More Than
Total
1 Year
1-3 Years
4-5 Years
5 Years
(in millions of dollars)
$
864.0
$
281.1
$
9.8
$
9.8
$
563.3
284.2
63.0
89.8
87.8
43.6
0.3
0.1
0.2
8.3
2.6
4.9
0.8
1.7
1.7
$
1,158.5
$
346.8
$
104.7
$
98.4
$
608.6
(1)
Represents required future principal repayments of debt
obligations allocated from Targa.
(2)
The allocated debt from Targa of $864.0 million at
December 31, 2006 was partially repaid and the remainder of
the allocated debt was treated as contributed capital on
February 14, 2007 in conjunction with our IPO. The
following table shows the extinguishment of the allocated debt
from Targa:
(a)
Allocated debt presented above represents indebtedness incurred
by Targa in connection with the DMS Acquisition that has been
allocated to the North Texas System. 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, the guarantee
was terminated, the collateral interest was released and the
allocated indebtedness was retired.
(3)
Represents interest expense on allocated debt, based on interest
rates as of December 31, 2006. We used an average rate of
7% to estimate our interest on variable rate debt obligations.
(4)
Consists of capacity payments for natural gas pipelines.
SFAS 157,
Fair Value
Measurements,
and
SFAS 159,
Fair Value Option for Financial Assets
and Financial Liabilities Including an amendment of
FASB Statement No. 115.
63
Table of Contents
Item 7A.
Quantitative
and Qualitative Disclosures about Market Risk
64
Table of Contents
Avg. Price
MMBtu per Day
Index
$/MMBtu
2007
2008
2009
2010
Fair Value
(in thousands)
IF-NGPL MC
8.56
8,152
$
7,262
IF-NGPL MC
8.43
6,964
3,444
IF-NGPL MC
8.02
6,256
1,677
IF-NGPL MC
7.43
5,685
932
8,152
6,964
6,256
5,685
13,315
IF-Waha
8.73
5,460
4,606
IF-Waha
8.53
4,657
1,787
IF-Waha
7.96
4,196
809
IF-Waha
7.38
3,809
514
5,460
4,657
4,146
3,809
7,716
13,612
11,621
10,452
9,494
21,031
IF-NGPL MC
6.45
520
200
IF-NGPL MC
6.55
1,000
342
IF-NGPL MC
6.55
850
246
520
1,000
850
788
IF-Waha
6.70
350
137
IF-Waha
6.85
670
231
IF-Waha
6.55
565
154
350
670
565
522
870
1,670
1,415
1,310
$
22,341
65
Table of Contents
Avg. Price
Barrels per Day
Index
$/Bbl
2007
2008
2009
2010
Fair Value
(in thousands)
NY-WTI
$
72.82
439
$
1,225
NY-WTI
70.68
384
415
NY-WTI
69.00
322
183
NY-WTI
68.10
301
152
439
384
322
301
1,975
NY-WTI
$
58.60
25
19
NY-WTI
60.50
55
83
NY-WTI
60.00
50
84
25
55
50
186
464
439
372
301
$
2,161
Table of Contents
Item 8.
Financial
Statements and Supplementary Data
Item 9.
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
Item 9A.
Controls
and Procedures
Item 9B.
Other
Information
Item 10.
Directors,
Executive Officers and Corporate Governance
67
Table of Contents
59
Chief Executive Officer and
Director
46
President
65
President Finance and
Administration and Director
62
Executive Vice President
58
Executive Vice President and Chief
Operating Officer
52
Executive Vice President, Chief
Financial Officer and Treasurer
47
Executive Vice President, General
Counsel and Secretary
38
Director
46
Director
58
Director
57
Director
50
Director
(1)
As of March 30, 2007
68
Table of Contents
69
Table of Contents
70
Table of Contents
Item 11.
Executive
Compensation
71
Table of Contents
72
Table of Contents
annual base salary;
discretionary annual cash awards;
performance awards under Targas long-term incentive plan;
Targas contributions under its 401(k) and profit sharing
plan; and
Targas other benefit plans on the same basis as all other
Targa employees.
73
Table of Contents
74
Table of Contents
75
Table of Contents
James W. Whalen
Peter R. Kagan
Chansoo Joung
Robert B. Evans
Barry R. Pearl
William D. Sullivan
Item 12.
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
each person who then beneficially owns 5% or more of the then
outstanding units;
all of the directors of Targa Resources GP LLC;
each named executive officer of Targa Resources GP LLC; and
all directors and officers of Targa Resources GP LLC as a group.
76
Table of Contents
Percentage of
Percentage of Total
Percentage of
Subordinated
Common and
Common Units
Common Units
Subordinated
Units
Subordinated Units
Benefically
Benefically
Units Benefically
Benefically
Benefically
Owned
Owned
Owned(5)
Owned
Owned
11,528,231
100.00
%
37.37
%
20,000
*
222,495
1.93
%
*
7,100
*
187,910
1.63
%
*
2,500
*
174,076
1.51
%
*
1,500
*
152,173
1.32
%
*
163,701
1.42
%
*
35,700
*
138,339
1.20
%
*
138,339
1.20
%
*
2,000
*
*
2,000
*
*
3,900
*
*
4,300
*
*
6,700
*
*
85,700
*
1,177,033
10.21
%
4.09
%
*
Less than 1%.
(1)
Unless otherwise indicated, the address for all beneficial
owners in this table is 1000 Louisiana, Suite 4300,
Houston, Texas 77002. The nature of the beneficial ownership for
all the shares is sole voting and investment power.
(2)
The units attributed to Targa Resources Investments Inc. are
held by two indirect wholly-owned subsidiaries, Targa GP Inc.
and Targa LP Inc.
(3)
Warburg Pincus Private Equity VIII, L.P. (WP VIII)
and Warburg Pincus Private Equity IX, L.P. (WP IX)
in the aggregate beneficially own 73.6% of Targa Resources
Investments Inc. The general partner of WP VIII is Warburg
Pincus Partners, LLC (WP Partners LLC) and the
general partner of WP IX is Warburg Pincus IX, LLC, of which WP
Partners LLC is sole member. Warburg Pincus & Co.
(WP) is the managing member of WP Partners LLC. WP
VIII and WP IX are managed by Warburg Pincus LLC (WP
LLC). The address of the Warburg Pincus entities is 466
Lexington Avenue, New York, New York 10017. Peter R. Kagan, one
of our directors, is a general partner of WP and a Managing
Director and member of WP LLC. Charles R. Kaye and Joseph P.
Landy are Managing General Partners of WP and Managing Members
of WP LLC and may be deemed to control the Warburg Pincus
entities. Messrs. Kagan, Kaye and Landy disclaim beneficial
ownership of all shares held by the Warburg Pincus entities.
(4)
Warburg Pincus Private Equity VIII, L.P. (WP VIII)
and Warburg Pincus Private Equity IX, L.P. (WP IX)
in the aggregate beneficially own 73.6% of Targa Resources
Investments Inc. The general partner of WP VIII is Warburg
Pincus Partners, LLC (WP Partners LLC) and the
general partner of WP IX is Warburg Pincus IX, LLC, of which WP
Partners LLC is sole member. Warburg Pincus & Co.
(WP) is the managing member of WP Partners LLC. WP
VIII and WP IX are managed by Warburg Pincus LLC (WP
LLC). The address of the Warburg Pincus entities is 466
Lexington Avenue, New York, New York 10017. Chansoo Joung, one
of our directors, is a general partner of WP. Mr. Joung
disclaims beneficial ownership of all shares held by the Warburg
Pincus entities. Charles R. Kaye and Joseph P. Landy are
Managing General Partners of WP and Managing Members of WP LLC
and may be deemed to control the Warburg Pincus entities.
Messrs. Joung, Kaye and Landy disclaim beneficial ownership
of all shares held by the Warburg Pincus entities.
(5)
The subordinated units presented as being beneficially owned by
the directors and executive officers of Targa Resources GP LLC
represent the number of units held indirectly by Targa Resources
Investments
Table of Contents
Inc. that are attributable to such directors and officers based
on their ownership of equity interests in Targa Resources
Investments Inc.
The consideration received by
Targa and its subsidiaries for the contribution of the assets
and liabilities to us
Operational Stage
Distributions of available cash to
our general partner and its affiliates
We will generally make cash
distributions 98% to our limited partner unitholders pro rata,
including our general partner and its affiliates, as the holders
of 11,528,231 subordinated units, and 2% to our general partner.
In addition, if distributions exceed the minimum quarterly
distribution and other higher target distribution levels, our
general partner will be entitled to increasing percentages of
the distributions, up to 50% of the distributions above the
highest target distribution level.
Assuming we have sufficient
available cash to pay the full minimum quarterly distribution on
all of our outstanding units for four quarters, our general
partner and its affiliates would receive an annual distribution
of approximately $0.8 million on their general partner
units and $15.6 million on their subordinated units.
78
Table of Contents
Payments to our general partner
and its affiliates
We reimburse Targa for the payment
of certain operating expenses and for the provision of various
general and administrative services for our benefit. Please see
Omnibus Agreement Reimbursement of
Operating and General and Administrative Expense.
Withdrawal or removal of our
general partner
If our general partner withdraws
or is removed, its general partner interest and its incentive
distribution rights will either be sold to the new general
partner for cash or converted into common units, in each case
for an amount equal to the fair market value of those interests.
Please see The Partnership Agreement
Withdrawal or Removal of the General Partner.
Liquidation Stage
Liquidation
Upon our liquidation, the
partners, including our general partner, will be entitled to
receive liquidating distributions according to their respective
capital account balances.
general and administrative expenses, which are capped at
$5 million annually for three years, subject to increases
based on increases in the Consumer Price Index and subject to
further increases in connection with expansions of our
operations through the acquisition or construction of new assets
or businesses with the concurrence of our conflicts committee;
thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement; and
operations and certain direct expenses, which are not subject to
the $5 million cap for general and administrative expenses.
Table of Contents
80
Table of Contents
81
Table of Contents
approved by the conflicts committee, although our general
partner is not obligated to seek such approval;
approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
Item 14.
Principal
Accounting Fees and Services
For Year Ended December 31,
2006
2005
$
820.7
$
0
0
0
0
0
0
0
(1)
Audit fees represent amounts billed for each of the years
presented for professional services rendered in connection with
(i) the audit of our annual financial statements and
internal controls over financial reporting, (ii) the review
of our quarterly financial statements or (iii) those
services normally provided in connection with statutory and
regulatory filings or engagements including comfort letters,
consents and other services related to SEC matters. This
information is presented as of the latest practicable date for
this annual report on
Form 10-K.
(2)
Audit-related fees represent amounts we were billed in each of
the years presented for assurance and related services that are
reasonably related to the performance of the annual audit or
quarterly reviews. This category primarily includes services
relating to internal control assessments and accounting-related
consulting.
82
Table of Contents
(3)
Tax fees represent amounts we were billed in each of the years
presented for professional services rendered in connection with
tax compliance, tax advice, and tax planning. This category
primarily includes services relating to the preparation of
unitholder annual K-1 statements, partnership tax planning
and property tax assistance.
(4)
All other fees represent amounts we were billed in each of the
years presented for services not classifiable under the other
categories listed in the table above. No such services were
rendered by PricewaterhouseCoopers during the last two years.
Item 15.
Exhibits
and Financial Statement Schedules
83
Table of Contents
Exhibit
3
.1
Certificate of Limited Partnership
of the Partnership, incorporated by reference to
Exhibit 3.2 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
3
.2
Certificate of Formation of Targa
Resources GP LLC, incorporated by reference to Exhibit 3.3
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
3
.3
Agreement of Limited Partnership
of Targa Resources Partners LP.*
3
.4
First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP,
dated February 14, 2007, incorporated by reference to
Exhibit 3.1 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
3
.5
Limited Liability Company
Agreement of Targa Resources GP LLC, incorporated by reference
to Exhibit 3.4 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
4
.1
Specimen Unit Certificate
representing common units.*
10
.1
Credit Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, as Borrower, Bank of America, N.A., as Administrative Agent,
Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch
Capital, Royal Bank of Canada and The Royal Bank of Scotland
PLC, as Co-Documentation Agents, and the other lenders party
thereto, incorporated by reference to Exhibit 10.1 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.2
Contribution, Conveyance and
Assumption Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, Targa Resources Operating LP, Targa
Resources GP LLC, Targa Resources Operating GP LLC, Targa GP
Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North
Texas GP LLC and Targa North Texas LP, incorporated by reference
to Exhibit 10.2 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.3
Omnibus Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources, Inc., Targa Resources LLC and Targa
Resources GP LLC, incorporated by reference to Exhibit 10.3
to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.4
Targa Resources Partners Long-Term
Incentive Plan, incorporated by reference to Exhibit 10.2
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.5
Targa Resources Investments Inc.
Long-Term Incentive Plan, incorporated by reference to
Exhibit 10.9 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.6
Form of Restricted Unit Grant
Agreement, incorporated by reference to Exhibit 10.2 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
10
.7
Form of Performance Unit Grant
Agreement, incorporated by reference to Exhibit 10.3 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
10
.8
Gas Gathering and Purchase
Agreement by and between Burlington Resources Oil & Gas
Company LP, Burlington Resources Trading Inc. and Targa
Midstream Services Limited Partnership (portions of this exhibit
have been omitted pursuant to a request for confidential
treatment), incorporated by reference to Exhibit 10.5 to
the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.9
Natural Gas Purchase Agreement
with Targa Gas Marketing LLC, incorporated by reference to
Exhibit 10.6 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.10
NGL and Condensate Purchase
Agreement with Targa Liquids Marketing and Trade, incorporated
by reference to Exhibit 10.7 to the Partnerships
Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.11
Targa Resources Partners LP
Indemnification Agreement for Barry R. Pearl dated
February 14, 2007.*
10
.12
Targa Resources Partners LP
Indemnification Agreement for Robert B. Evans dated
February 14, 2007.*
Table of Contents
Exhibit
10
.13
Targa Resources Partners LP
Indemnification Agreement for William D. Sullivan dated
February 14, 2007.*
21
.1
Subsidiaries of the Partnership,
incorporated by reference to Exhibit 21.1 to the
Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
31
.1
Certification of the Chief
Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
31
.2
Certification of the Chief
Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
32
.1
Certification of the Chief
Executive Officer pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.*
32
.2
Certification of the Chief
Financial Officer pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.*
*
Filed herewith
Management contract or compensatory plan or arrangement
Table of Contents
(Registrant)
By:
Chief Executive Officer and
Director (Principal Executive Officer)
Executive Vice President, Chief
Financial Officer and Treasurer (Principal Financial Officer)
Senior Vice President and Chief
Accounting Officer (Principal Accounting Officer)
President Finance and
Administration and Director
Director
Director
Director
Director
Director
86
Table of Contents
F-2
F-4
F-5
F-6
F-7
F-8
F-26
F-27
F-28
F-29
F-30
F-31
F-1
Table of Contents
F-2
Table of Contents
F-3
Table of Contents
F-4
Table of Contents
TNT LP
TNT LP Predecessor
Year
Two Months
Ten Months
Year
Ended
Ended
Ended
Ended
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2004
(in thousands)
$
15,224
$
22,192
$
8,732
$
12,039
369,605
52,952
284,603
246,516
384,829
75,144
293,335
258,555
268,487
54,981
209,835
182,234
846
11
1,024
278
24,102
3,494
18,035
17,702
55,958
9,150
11,262
12,201
6,904
1,063
7,273
7,230
(32
)
329
356,297
68,699
247,397
219,974
28,532
6,445
45,938
38,581
(72,910
)
(11,542
)
(44,378
)
(5,097
)
45,938
38,581
(2,532
)
(46,910
)
(5,097
)
45,938
38,581
35,189
(4,610
)
(312
)
1,047
(99
)
(404
)
32
30,910
(67
)
$
(16,000
)
$
(5,164
)
$
45,938
$
38,581
F-5
Table of Contents
Targa North
Targa North Texas LP
Texas LP
General
Limited
Predecessor
Partner
Partner
Equity
Total
(in thousands)
$
$
$
164,802
$
164,802
(34,573
)
(34,573
)
38,581
38,581
168,810
168,810
(56,268
)
(56,268
)
45,938
45,938
158,480
158,480
109,939
109,940
219,879
2,415
2,415
4,830
(34
)
(33
)
(67
)
(2,548
)
(2,549
)
(5,097
)
109,772
109,773
219,545
6,036
6,035
12,071
15,455
15,455
30,910
(23,455
)
(23,455
)
(46,910
)
$
107,808
$
107,808
$
$
215,616
F-6
Table of Contents
TNT LP
TNT LP Predecessor
Year
Two Months
Ten Months
Year
Ended
Ended
Ended
Ended
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2004
(in thousands)
$
(46,910
)
$
(5,097
)
$
45,938
$
38,581
55,958
9,150
11,262
12,201
144
35
187
204
5,154
848
(32
)
329
2,532
(1,541
)
215
(60
)
(280
)
683
1,155
(1,155
)
423
87
630
10
51
(574
)
644
(845
)
(1,334
)
2,658
(1,763
)
(4,357
)
16,490
3,850
16,218
(1,471
)
72,705
58,019
(23,117
)
(2,134
)
(16,469
)
(23,664
)
32
8
32
218
(23,085
)
(2,126
)
(16,437
)
(23,446
)
6,867
3,597
(56,268
)
(34,573
)
6,867
3,597
(56,268
)
(34,573
)
$
$
$
$
$
$
907,634
$
$
272
23,342
4,932
870,125
F-7
Table of Contents
F-8
Table of Contents
F-9
Table of Contents
F-10
Table of Contents
Range of
Years
15 to 25
3 to 7
sales of natural gas, NGLs and condensate; and
natural gas processing, from which we generate revenue through
the compression, gathering, treating, and processing of natural
gas.
F-11
Table of Contents
F-12
Table of Contents
$
2,105
1,104,000
23,342
(37,937
)
(870,125
)
(1,506
)
$
219,879
Pro Forma
Year Ended December 31,
2005
(Unaudited)
(in thousands)
$
368,479
(265,851
)
(54,876
)
32
(29,865
)
17,919
(69,252
)
$
(51,333
)
F-13
Table of Contents
December 31,
2006
2005
(in thousands)
$
1,113,799
$
1,078,402
15,411
27,705
1,129,210
1,106,107
(65,102
)
(9,126
)
$
1,064,108
$
1,096,981
TNT LP
December 31,
December 31,
2006
2005
(in thousands)
$
863,960
$
868,892
(281,083
)
(4,932
)
$
582,877
$
863,960
December 31,
December 31,
2006
2005
(in thousands)
$
486,962
$
491,894
276,151
276,151
100,847
100,847
863,960
868,892
(281,083
)
(4,932
)
$
582,877
$
863,960
F-14
Table of Contents
Range of
Weighted Average
Interest Rates Paid
Interest Rate Paid
6.59% to 7.75%
7.03
%
6.83% to 7.62%
7.26
%
Allocated to
TNT LP
$
281,083
4,932
4,932
4,932
4,932
563,149
$
863,960
F-15
Table of Contents
a pledge of TNT LPs general partner and limited partner
interests; and
a security interest in, and mortgages on, TNT LPs tangible
and intangible assets.
TNT LP
TNT LP Predecessor
Two Months
Ten Months
Year Ended
Ended
Ended
Year Ended
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2004
(in thousands)
$
1,541
$
2,054
$
1,897
$
1,838
(1
)
(548
)
(30
)
(145
)
144
35
187
204
$
1,684
$
1,541
$
2,054
$
1,897
F-16
Table of Contents
2007
2008
2009
2010
2011+
$
2.6
$
2.5
$
2.4
$
0.8
$
0.1
0.1
0.1
1.7
$
2.7
$
2.6
$
2.5
$
0.8
$
1.7
F-17
Table of Contents
TNT LP
TNT LP Predecessor
Year
Two Months
Ten Months
Year
Ended
Ended
Ended
Ended
December 31,
December 31,
October 31,
December 31,
2006
2005
2005
2004
(in thousands)
$
(369,605
)
$
(52,952
)
$
(284,603
)
$
(246,516
)
846
11
1,024
278
300,967
44,781
220,038
204,435
67,756
10,694
6,903
1,063
7,273
7,230
6,867
3,597
(56,268
)
(34,573
)
219,879
272
4,932
1,233
5,204
221,112
$
12,071
$
224,709
$
(56,268
)
$
(34,573
)
F-18
Table of Contents
Commodity
Instrument Type
Daily Volumes
Natural gas
Swap
4,200 MMBtu
$
9
.14 per MMBtu
IF-Waha
Natural gas
Swap
3,847 MMBtu
8
.76 per MMBtu
IF-Waha
Natural gas
Swap
3,556 MMBtu
8
.07 per MMBtu
IF-Waha
Natural gas
Swap
3,289 MMBtu
7
.39 per MMBtu
IF-Waha
Condensate
Swap
319 barrels
75
.27 per barrel
NY-WTI
Condensate
Swap
264 barrels
72
.66 per barrel
NY-WTI
Condensate
Swap
202 barrels
70
.60 per barrel
NY-WTI
Condensate
Swap
181 barrels
69
.28 per barrel
NY-WTI
F-19
Table of Contents
F-20
Table of Contents
Avg. Price
Barrels per Day
Index
$/gal
2007
2008
2009
2010
Fair Value
(in thousands)
OPIS-MB
$
0.99
2,416
$
3,553
OPIS-MB
0.95
2,160
2,235
OPIS-MB
0.91
1,948
1,223
OPIS-MB
0.88
1,759
606
2,416
2,160
1,948
1,759
$
7,617
F-21
Table of Contents
Avg. Price
Barrels per day
Index
$/Bbl
2007
2008
2009
2010
Fair Value
(in thousands)
NY-WTI
$
72.82
439
$
1,225
NY-WTI
70.68
384
415
NY-WTI
69.00
322
183
NY-WTI
68.10
301
152
439
384
322
301
1,975
NY-WTI
$
58.60
25
19
NY-WTI
60.50
55
83
NY-WTI
60.00
50
84
25
55
50
186
464
439
372
301
$
2,161
December 31,
2006
2005
(in thousands)
$
17,250
$
34
15,541
24
(53
)
(96
)
(72
)
$
32,695
$
(67
)
Table of Contents
First
Second
Third
Fourth
Quarter
Quarter
Quarter
Quarter
Total
(Dollars in thousands, except per unit amounts)
$
96,251
$
92,673
$
101,966
$
93,939
$
384,829
7,132
6,805
6,996
7,599
28,532
(10,229
)
(12,951
)
(12,244
)
(11,486
)
(46,910
)
$
$
$
$
75,144
(b)
$
75,144
6,445
(b)
6,445
(5,097
)(b)
(5,097
)
$
71,414
$
80,280
$
98,045
$
43,596(c
)
$
293,335
10,485
12,152
15,445
7,856(c
)
45,938
10,485
12,152
15,445
7,856(c
)
45,938
(a)
Total basic net income per limited partner unit was not
calculated as Partner Units were not outstanding as of
December 31, 2006.
(b)
Reflects two months of results.
(c)
Reflects one month of results.
F-23
Table of Contents
TRP LP issued to Targa 11,528,231 subordinated units,
representing a 36.6% limited partner interest;
TRP LP issued to the general partner, Targa Resources GP LLC,
629,555 general partner units representing an 2% general partner
interest in TRP LP, and all of TRP LPs incentive
distribution rights, which incentive distribution rights entitle
our general partner to increasing percentages of the cash that
is distributed in excess of $0.3881 per unit per quarter;
TRP LP issued 19,320,000 common units to the public in
connection with its IPO of 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 a 61.4% limited partner interest, and used
the proceeds to pay expenses associated with the offering, the
formation transactions, and fees associated with our credit
facility and paid $371.2 million to Targa to retire a
portion of our allocated indebtedness;
TRP LP borrowed approximately $294.5 million under its
$500 million credit facility, the net proceeds of which
were paid to Targa to retire an additional portion of our
allocated indebtedness; and
our remaining allocated indebtedness was retired and treated as
a capital contribution by Targa.
$
864.0
$
405.7
(30.3
)
(4.2
)
$
371.2
(371.2
)
(294.5
)
(198.3
)
$
F-24
Table of Contents
Partnership Pro Forma
Year Ended
December 31,
2006
(unaudited)
(in millions)
$
384.8
269.3
24.0
56.0
6.9
356.2
28.6
20.6
2.5
$
5.5
$
0.1
$
5.4
F-25
Table of Contents
F-26
Table of Contents
$
1,000
$
1,000
$
980
20
$
1,000
F-27
Table of Contents
1.
Nature of
Operations
2.
Subsequent
Event
F-28
Table of Contents
F-29
Table of Contents
$
980
20
$
1,000
$
1,000
$
1,000
F-30
Table of Contents
1.
Nature of
Operations
2.
Subsequent
Event
F-31
Table of Contents
Exhibit
3
.1
Certificate of Limited Partnership
of the Partnership, incorporated by reference to
Exhibit 3.2 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
3
.2
Certificate of Formation of Targa
Resources GP LLC, incorporated by reference to Exhibit 3.3
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
3
.3
Agreement of Limited Partnership
of Targa Resources Partners LP.*
3
.4
First Amended and Restated
Agreement of Limited Partnership of Targa Resources Partners LP,
dated February 14, 2007, incorporated by reference to
Exhibit 3.1 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
3
.5
Limited Liability Company
Agreement of Targa Resources GP LLC, incorporated by reference
to Exhibit 3.4 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
4
.1
Specimen Unit Certificate
representing common units.*
10
.1
Credit Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, as Borrower, Bank of America, N.A., as Administrative Agent,
Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch
Capital, Royal Bank of Canada and The Royal Bank of Scotland
PLC, as Co-Documentation Agents, and the other lenders party
thereto, incorporated by reference to Exhibit 10.1 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.2
Contribution, Conveyance and
Assumption Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, Targa Resources Operating LP, Targa
Resources GP LLC, Targa Resources Operating GP LLC, Targa GP
Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North
Texas GP LLC and Targa North Texas LP, incorporated by reference
to Exhibit 10.2 to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.3
Omnibus Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources, Inc., Targa Resources LLC and Targa
Resources GP LLC, incorporated by reference to Exhibit 10.3
to the Partnerships Current Report on
Form 8-K
filed with the SEC on February 16, 2007.
10
.4
Targa Resources Partners Long-Term
Incentive Plan, incorporated by reference to Exhibit 10.2
to the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.5
Targa Resources Investments Inc.
Long-Term Incentive Plan, incorporated by reference to
Exhibit 10.9 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.6
Form of Restricted Unit Grant
Agreement, incorporated by reference to Exhibit 10.2 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
10
.7
Form of Performance Unit Grant
Agreement, incorporated by reference to Exhibit 10.3 to the
Partnerships Current Report on
Form 8-K
filed with the SEC on February 13, 2007.
10
.8
Gas Gathering and Purchase
Agreement by and between Burlington Resources Oil & Gas
Company LP, Burlington Resources Trading Inc. and Targa
Midstream Services Limited Partnership (portions of this exhibit
have been omitted pursuant to a request for confidential
treatment), incorporated by reference to Exhibit 10.5 to
the Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.9
Natural Gas Purchase Agreement
with Targa Gas Marketing LLC, incorporated by reference to
Exhibit 10.6 to the Partnerships Registration
Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.10
NGL and Condensate Purchase
Agreement with Targa Liquids Marketing and Trade, incorporated
by reference to Exhibit 10.7 to the Partnerships
Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
10
.11
Targa Resources Partners LP
Indemnification Agreement for Barry R. Pearl dated
February 14, 2007.*
10
.12
Targa Resources Partners LP
Indemnification Agreement for Robert B. Evans dated
February 14, 2007.*
Table of Contents
Exhibit
10
.13
Targa Resources Partners LP
Indemnification Agreement for William D. Sullivan dated
February 14, 2007.*
21
.1
Subsidiaries of the Partnership,
incorporated by reference to Exhibit 21.1 to the
Partnerships Registration Statement (File
No. 333-138747)
on
Form S-1,
as amended.
31
.1
Certification of the Chief
Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
31
.2
Certification of the Chief
Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
32
.1
Certification of the Chief
Executive Officer pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.*
32
.2
Certification of the Chief
Financial Officer pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.*
*
Filed herewith
Management contract or compensatory plan or arrangement
- 2 -
- 3 -
GENERAL PARTNER: | ||||||||
|
||||||||
TARGA RESOURCES GP LLC | ||||||||
|
||||||||
By: | /s/ Rene R. Joyce | |||||||
|
Name: | Rene R. Joyce | ||||||
|
Title: | Chief Executive Officer | ||||||
|
||||||||
LIMITED PARTNERS : | ||||||||
|
||||||||
TARGA GP INC. | ||||||||
|
||||||||
By: | /s/ Rene R. Joyce | |||||||
|
Name: | Rene R. Joyce | ||||||
|
Title: | Chief Executive Officer | ||||||
|
||||||||
TARGA LP INC. | ||||||||
|
||||||||
By: | /s/ Rene R. Joyce | |||||||
|
Name: | Rene R. Joyce | ||||||
|
Title: | Chief Executive Officer |
Partner/Address | Capital Contribution | Sharing Ratio | ||||||
Targa Resources GP LLC
1000 Louisiana, Suite 4300 Houston, Texas 77002 |
$ | 20 | (1) | 2.00 | % | |||
Targa GP Inc.
1000 Louisiana, Suite 4300 Houston, Texas 77002 |
$ | 490 | (2) | 49.00 | % | |||
Targa LP Inc.
1000 Louisiana, Suite 4300 Houston, Texas 77002 |
$ | 490 | (3) | 49.00 | % |
(1) | Targa Resources GP LLC has made or will make an initial capital contribution of $20 to the Partnership for its 2.00% general partner interest in the Partnership. | |
(2) | Targa GP Inc. has made or will make an initial capital contribution of $490 to the Partnership for its 49.00% limited partner interest in the Partnership. | |
(3) | Targa LP Inc. has made or will make an initial capital contribution of $490 to the Partnership for its 49.00% limited partner interest in the Partnership. |
2
3
4
5
6
7
8
TARGA RESOURCES PARTNERS LP | ||||||
|
||||||
By Targa Resources GP LLC, | ||||||
its general partner | ||||||
|
||||||
|
By:
Name: |
/s/
Rene R. Joyce
|
||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300
Houston, Texas 77002 |
||||||
|
||||||
TARGA RESOURCES GP LLC | ||||||
|
||||||
|
By:
Name: |
/s/
Rene R. Joyce
|
||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300
Houston, Texas 77002 |
||||||
|
||||||
INDEMNITEE: | ||||||
|
||||||
/s/ Robert B Evans | ||||||
Robert B. Evans | ||||||
|
2
3
4
5
6
7
8
TARGA RESOURCES PARTNERS LP | ||||||
|
||||||
By Targa Resources GP LLC, | ||||||
its general partner | ||||||
|
||||||
|
By: | / s / Rene R. Joyce | ||||
|
||||||
|
Name: | Rene R. Joyce | ||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300 | ||||||
|
Houston, Texas 77002 | |||||
|
||||||
TARGA RESOURCES GP LLC | ||||||
|
||||||
|
By: | / s / Rene R. Joyce | ||||
|
||||||
|
Name: | Rene R. Joyce | ||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300 | ||||||
|
Houston, Texas 77002 | |||||
|
||||||
INDEMNITEE: | ||||||
|
||||||
/ s / Barry R. Pearl | ||||||
Barry R. Pearl |
2
3
4
5
6
7
8
TARGA RESOURCES PARTNERS LP | ||||||
|
||||||
By Targa Resources GP LLC, | ||||||
its general partner | ||||||
|
||||||
|
By: | / s / Rene R. Joyce | ||||
|
||||||
|
Name: | Rene R. Joyce | ||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300 | ||||||
|
Houston, Texas 77002 | |||||
|
||||||
TARGA RESOURCES GP LLC | ||||||
|
||||||
|
By: | / s / Rene R. Joyce | ||||
|
||||||
|
Name: | Rene R. Joyce | ||||
|
Title: | Chief Executive Officer | ||||
|
||||||
Address: 1000 Louisiana, Suite 4300 | ||||||
|
Houston, Texas 77002 | |||||
|
||||||
INDEMNITEE: | ||||||
|
||||||
/ s / William D. Sullivan | ||||||
William D. Sullivan |
By: |
/s/
Rene
R. Joyce
|
Title: |
Chief Executive Officer of Targa Resources
GP LLC, the general partner of Targa Resources Partners LP (Principal Executive Officer) |
By: |
/s/
Jeffrey
J. McParland
|
Title: |
Executive Vice President, Chief Financial Officer and Treasurer
of Targa Resources GP LLC, the
general partner of Targa Resources Partners LP (Principal Financial Officer) |
By: |
/s/
Rene
R. Joyce
|
Title: |
Chief Executive Officer of Targa Resources GP
LLC, the general partner of the Partnership |
By: |
/s/
Jeffrey
J. McParland
|
Title: | Executive Vice President, Chief Financial Officer and Treasurer of Targa Resources GP LLC, the general partner of the Partnership |