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 co uld 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.
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. As of December 31, 2010, our general partner and its affiliates own approximately 17.1% 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 Louisiana and Texas as well as other states. 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 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 a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or your right to act with other unitholder s 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.
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 ob ligations 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.
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
Although we do not believe based upon our current operations that we are so treated, and despite the fact that we are a limited partnership under Delaware law, it is possible, in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
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. At the federal level, legislation has been proposed in a prior session of Congress that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to us as proposed, it could be reintroduced and amended prior to enactment in a manner that does apply to us. We are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread st ate budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.
Our 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 may be adjusted to reflect the impact of that law on us.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of inc ome, gain, loss and deduction among unitholders.
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, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the 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 resulting from that income.
Tax gain or loss on the 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. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, 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 due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, 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 non-U.S. 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 (“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 U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. 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.
To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our unitholders’ tax returns. 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.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements t o prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
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 technically 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders may receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 for the tax years in the technical termination occurs.
You may be subject to state and local taxes and return filing requirements in jurisdictions where you do not live as a result of investing in our common units.
In addition to federal income taxes, you may be subject to return filing requirements and other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct 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 return filing requirements. We own assets and conduct business in the States of Texas and Louisiana as well as other states. Currently, Texas does not impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or conduct business in states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.
None.
A description of our properties is contained in “Item 1. Business” 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.
On December 8, 2005, WTG filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa and two other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase SAOU from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. In October 2007, the District Court granted defendants’ motions f or summary judgment on all of WTG’s claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. On January 14, 2011, the Texas Supreme Court denied WTG’s petition for review of the lower courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the court reconsider its denial to review WTG’s appeal. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.
Except as provided above, neither we nor Targa are a party to any other legal proceedings 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. See “Item 1. Business — Regulation of Operations” and “Item 1. Business — Environmental, Health and Safety Matters.”
Our common units have been listed on the New York Stock Exchange (“NYSE”) since January 25, 2010 under the symbol “NGLS.” Previously, our common units were listed on The NASDAQ Stock Market LLC (“NASDAQ”) under the same symbol. The following table sets forth the high and low sales prices of the common units, as reported by the NYSE/NASDAQ, as well as the amount of cash distributions declared for the period January 1, 2008 through December 31, 2010.
As of February 22, 2011, there were approximately 64 unitholders of record of our 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. There is no established trading market for the 1,729,715 general partner units held only by our general partner.
As part of our acquisition of Targa’s Downstream Business, Targa agreed to provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at the distribution level of $0.5175 per limited partner unit, subject to maximum support of $8 million in any quarter. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support has been required through the fourth quarter of 2010.
The historical distributions paid by us are shown in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Distributions to our Unitholders.”
None.
None.
The following table presents selected historical consolidated financial and operating data of Targa Resources Partners LP. See “Basis of Presentation” included under Note 2 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for information regarding the retrospective adjustment of our financial information for the years 2006 through 2010 in conjunction with our acquisitions of entities under common control. The information contained herein should be read in conjunction with our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Consolidated Financial Statements” contained in this Annual Report.
The following table summarizes selected financial and operating data for the periods and as of the dates indicated:
The following discussion analyzes our financial condition and results of operations. You should read the following discussion in conjunction with our historical financial statements and notes included in Part IV of this Annual Report.
Targa Resources Partners LP is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
Targa Resources GP LLC is a Delaware limited liability company, formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.
We acquired Targa’s ownership interests in the following assets, liabilities and operations on the dates indicated (collectively, the “dropdown transactions”):
For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions as our “predecessors.”
Our business operations consist of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling natural gas liquids (“NGLs”) and NGL products.
We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities are reported in Other.
Prior to the second quarter of 2010, we reported our results under four reportable segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increase in our Coastal Gathering and Processing businesses as a result of our acquisition of the Permian Business and Straddle Assets, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing reportable segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant ope rational interrelationships among the Marketing and Distribution activities apparent in our current business model.
The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico and the Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.
The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the activities necessary to convert raw natural gas liquids into NGL products, market the finished products and provide certain value added services.
The Logistics Assets segment transports and stores mixed NGLs and fractionates, stores, and transports finished NGLs. These assets are generally connected to and supplied, in part, by our Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Western Louisiana.
The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.
Our results of operations are substantially impacted by the volumes that move through both of our gathering and processing and our logistics assets, our contract terms and changes in commodity prices.
We generally prefer to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements. However, negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, 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.
The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. During periods of low relative demand for available fractionation capacity, rates are low and take-or-pay contracts are not readily available. Currently, demand for fractionation services is relatively high, rates have increased, contract terms or lengths have increased and reservation fees are required. These fractionation contracts in the logistics assets segment are primarily fee-based arrangements while the marketing and distribution segment includes both fee based and percent of proceeds contracts.
The employees supporting our operations are employees of Targa. We reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to our assets, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
Under a 2009 amendment to the Omnibus Agreement, Targa will provide distribution support to us in the form of reduced general and administrative expense billings, up to $8.0 million per quarter, if necessary, for a 1.0 times distribution coverage ratio. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support has been required through the fourth quarter of 2010.
We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). 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 expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.
The following table shows the distributions we paid in 2010 and 2009.
We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our services, significant relationships, commodity prices, volatile capital markets and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Commodity Prices. Current forward commodity prices for the January 2011 through December 2011 period show natural gas and crude oil prices strengthening while NGL prices weaken on an absolute price basis and as a percentage of crude oil. Various industry commodity price forecasts based on fundamental analysis may differ significantly from forward market prices. Both are subject to change due to multiple factors. There has been and we believe there will continue to be significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems.
Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and market demand for natural gas, NGLs and condensate, which are beyond our control and have been volatile. Recent weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which caused a reduction in profitability of our processing operations. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigate our exposure to commodity price movements by entering into hedging arrang ements. For additional information regarding our hedging activities, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Volatile Capital Markets. We are dependent on our ability to access the equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are expected to continue to be, volatile and disrupted and weak economic conditions may cause a significant decline in commodity prices. As a result, we may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.
Increased Regulation. Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers may cause reductions in supplies of natural gas and of NGLs from producers. Please read “Risk Factors – Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells which could adversely impact our revenues by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.” Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less pre dictability in our results of operations. Please read “Risk Factors—The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to hedge risks associated with its business.”
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 and mixed NGLs that we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the volumes of natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also a ffected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services and changes in our customer mix.
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses and (3) the following non-GAAP measures — gross margin, operating margin, adjusted EBITDA and distributable cash flow.
Throughput Volumes, Facility Efficiencies and Fuel Consumption. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production as well as by capturing natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream fractionation facilities. We fractionate NGLs generated by our gathering and processing plants as well as by contracting for mixed NGL supply from third-party gathe ring or fractionation facilities.
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. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for our logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Labor, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses generally remain relatively stable and independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.
Gross Margin. Gross margin is defined as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and hedging program. We define Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGL plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.
Operating Margin. Operating margin is an important performance measure of the core profitability of our operations. We define operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.
Gross Margin and Operating Margin are non-GAAP measures. The generally accepted accounting principle (“GAAP”) measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income, and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Targa senior management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross Margin and Operating Margin provide useful information to investors because they are used as supplemental financial measure by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:
| · | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
| · | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
| · | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
Management compensates for the limitations of gross margin and operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Reconciliation of gross margin and operating | | (In millions) | |
| margin to net income (loss): | | | | | | | | | |
| Gross margin | | $ | 772.2 | | | $ | 710.9 | | | $ | 812.9 | |
| Operating expenses | | | (259.5 | ) | | | (234.4 | ) | | | (274.3 | ) |
| Operating margin | | | 512.7 | | | | 476.5 | | | | 538.6 | |
| Depreciation and amortization expenses | | | (176.2 | ) | | | (166.7 | ) | | | (156.8 | ) |
| General and administrative expenses | | | (115.8 | ) | | | (111.3 | ) | | | (124.1 | ) |
| Other operating income (loss) | | | (3.3 | ) | | | (3.7 | ) | | | 19.3 | |
| Interest expense, net | | | (110.8 | ) | | | (159.8 | ) | | | (156.1 | ) |
| Income tax expense | | | (4.0 | ) | | | (1.2 | ) | | | (2.9 | ) |
| Gain (loss) on sale of assets | | | - | | | | 0.1 | | | | (5.9 | ) |
| Gain (loss) on debt repurchases | | | - | | | | (1.5 | ) | | | 13.1 | |
| Risk management activities | | | 26.0 | | | | (30.9 | ) | | | 76.4 | |
| Equity in earnings of unconsolidated investments | | | 5.4 | | | | 5.0 | | | | 14.0 | |
| Gain (loss) on insurance claims | | | - | | | | - | | | | 18.5 | |
| Other, net | | | - | | | | 0.7 | | | | 1.1 | |
| Net income | | $ | 134.0 | | | $ | 7.2 | | | $ | 235.2 | |
Adjusted EBITDA. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others.
The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions) | |
| Reconciliation of net cash provided by | | | | | | | | | |
| operating activities to Adjusted EBITDA: | | | | | | | | | |
| Net cash provided by operating activities | | $ | 371.2 | | | $ | 422.9 | | | $ | 550.2 | |
| Net income attributable to noncontrolling interest | | | (24.9 | ) | | | (19.3 | ) | | | (33.1 | ) |
| Interest expense, net (1) | | | 74.8 | | | | 44.8 | | | | 34.7 | |
| Gain (loss) on debt repurchases | | | - | | | | (1.5 | ) | | | 13.1 | |
| Termination of commodity derivatives | | | - | | | | - | | | | 87.4 | |
| Current income tax expense | | | 2.8 | | | | 0.3 | | | | 0.8 | |
| Other (2) | | | (14.7 | ) | | | (10.6 | ) | | | 3.4 | |
| Changes in operating assets and liabilities which used (provided) cash: | | | | | | | | | | | | |
| Accounts receivable and other assets | | | 71.2 | | | | 57.0 | | | | (890.8 | ) |
| Accounts payable and other liabilities | | | (84.3 | ) | | | (93.0 | ) | | | 655.3 | |
| Adjusted EBITDA | | $ | 396.1 | | | $ | 400.6 | | | $ | 421.0 | |
__________
| (1) | Net of amortization of debt issuance costs of $6.6 million, $3.9 million and $2.1 million and amortization of discount and premium included in interest expense of less than $0.1 million, $3.4 million and $2.1 million for 2010, 2009 and 2008. Excludes affiliate and allocated interest expense. |
| (2) | Includes non-controlling interest percentage of our consolidated investment’s depreciation, interest expense and maintenance capital expenditures, equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets. |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions) | |
| Reconciliation of net income (loss) attributable to | | | | | | | | | |
| Targa Resources Partners LP to Adjusted EBITDA: | | | | | | | | | |
| Net income attributable to Targa Resources Partners LP | | $ | 109.1 | | | $ | (12.1 | ) | | $ | 202.1 | |
| Add: | | | | | | | | | | | | |
| Interest expense, net (1) | | | 110.8 | | | | 159.8 | | | | 156.1 | |
| Income tax expense | | | 4.0 | | | | 1.2 | | | | 2.9 | |
| Depreciation and amortization expenses | | | 176.2 | | | | 166.7 | | | | 156.8 | |
| Risk management activities | | | 6.4 | | | | 95.5 | | | | (85.4 | ) |
| Noncontrolling interest adjustment | | | (10.4 | ) | | | (10.5 | ) | | | (11.5 | ) |
| Adjusted EBITDA | | $ | 396.1 | | | $ | 400.6 | | | $ | 421.0 | |
__________
| (1) | Includes affiliate and allocated interest expense. |
Distributable Cash Flow. We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in our measure. 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 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 attributable to Targa Resources Partners LP. 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.
Management compensates 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 insights into its decision making processes.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions) | |
| Reconciliation of net income (loss) attributable to Targa | | | | | | | | | |
| Resources Partners LP to distributable cash flow: | | | | | | | | | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 109.1 | | | $ | (12.1 | ) | | $ | 202.1 | |
| Affiliate and allocated interest expense | | | 29.4 | | | | 107.7 | | | | 117.2 | |
| Depreciation and amortization expenses | | | 176.2 | | | | 166.7 | | | | 156.8 | |
| Deferred income tax expense | | | 1.2 | | | | 0.9 | | | | 2.1 | |
| Amortization in interest expense | | | 6.6 | | | | 3.9 | | | | 2.1 | |
| Loss (gain) on debt repurchases | | | - | | | | 1.5 | | | | (13.1 | ) |
| Risk management activities | | | 6.4 | | | | 95.5 | | | | (86.4 | ) |
| Maintenance capital expenditures | | | (50.5 | ) | | | (44.5 | ) | | | (68.4 | ) |
| Other (1) | | | (2.4 | ) | | | (7.4 | ) | | | (4.1 | ) |
| Distributable cash flow | | $ | 276.0 | | | $ | 312.2 | | | $ | 308.3 | |
__________
| (1) | Other includes reimbursements of certain environmental maintenance capital expenditures by Targa and the noncontrolling interest percentage of our consolidated investment’s depreciation, interest expense and maintenance capital expenditures. |
Results of Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include gross margin, operating margin, operating expenses, plant inlet, gross NGL production, adjusted EBITDA and distributable cash flow, among others. For a discussion of these measures, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations”.
The following table summarizes the key components of our results of operations for the periods indicated (In millions, except operating and price amounts):
| | | Year Ended December 31, | | | | 2010 vs. 2009 | | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | | $ Change | | | % Change | | | | $ Change | | | % Change | |
| Revenues (1) | | $ | 5,460.2 | | | $ | 4,503.8 | | | $ | 8,030.1 | | | | $ | 956.4 | | | | 21% | | | | $ | (3,526.3 | ) | | | (44% | ) |
| Product purchases | | | 4,688.0 | | | | 3,792.9 | | | | 7,217.2 | | | | | 895.1 | | | | 24% | | | | | (3,424.3 | ) | | | (47% | ) |
| Gross margin | | | 772.2 | | | | 710.9 | | | | 812.9 | | | | | 61.3 | | | | 9% | | | | | (102.0 | ) | | | (13% | ) |
| Operating expenses | | | 259.5 | | | | 234.4 | | | | 274.3 | | | | | 25.1 | | | | 11% | | | | | (39.9 | ) | | | (15% | ) |
| Operating margin | | | 512.7 | | | | 476.5 | | | | 538.6 | | | | | 36.2 | | | | 8% | | | | | (62.1 | ) | | | (12% | ) |
Depreciation and amortization expense | | | 176.2 | | | | 166.7 | | | | 156.8 | | | | | 9.5 | | | | 6% | | | | | 9.9 | | | | 6% | |
General and administrative expense | | | 122.4 | | | | 118.5 | | | | 97.3 | | | | | 3.9 | | | | 3% | | | | | 21.2 | | | | 22% | |
| Other | | | (3.3 | ) | | | (3.6 | ) | | | 13.4 | | | | | (0.3 | ) | | | (8% | ) | | | | (17.0 | ) | | | (127% | ) |
| Income from operations | | | 217.4 | | | | 194.9 | | | | 271.1 | | | | | 22.5 | | | | 12% | | | | | (76.2 | ) | | | (28% | ) |
| Interest expense, net | | | (110.8 | ) | | | (159.8 | ) | | | (156.1 | ) | | | | 49.0 | | | | 31% | | | | | (3.7 | ) | | | (2% | ) |
Equity in earnings of unconsolidated investment | | | 5.4 | | | | 5.0 | | | | 14.0 | | | | | 0.4 | | | | 8% | | | | | (9.0 | ) | | | (64% | ) |
| Gain (loss) on debt repurchases | | | - | | | | (1.5 | ) | | | 13.1 | | | | | 1.5 | | | | 100% | | | | | (14.6 | ) | | | (111% | ) |
Gain (loss) on mark-to-market derivative instruments | | | 26.0 | | | | (30.9 | ) | | | 76.4 | | | | | 56.9 | | | | 184% | | | | | (107.3 | ) | | | (140% | ) |
| Other | | | - | | | | 0.7 | | | | 19.6 | | | | | (0.7 | ) | | | (100% | ) | | | | (18.9 | ) | | | (96% | ) |
| Income tax expense | | | (4.0 | ) | | | (1.2 | ) | | | (2.9 | ) | | | | (2.8 | ) | | | (233% | ) | | | | 1.7 | | | | 59% | |
| Net income (loss) | | | 134.0 | | | | 7.2 | | | | 235.2 | | | | | 126.8 | | | | 1761% | | | | | (228.0 | ) | | | (97% | ) |
Less: Net income attributable to noncontrolling interest | | | 24.9 | | | | 19.3 | | | | 33.1 | | | | | 5.6 | | | | 29% | | | | | (13.8 | ) | | | (42% | ) |
Net income (loss) attributable to Targa Resources Partners LP | | $ | 109.1 | | | $ | (12.1 | ) | | $ | 202.1 | | | | $ | 121.2 | | | | 1002% | | | | $ | (214.2 | ) | | | (106% | ) |
| Financial and operating data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Adjusted EBITDA (2) | | $ | 396.1 | | | $ | 400.6 | | | $ | 421.0 | | | | $ | (4.5 | ) | | | (1% | ) | | | $ | (20.4 | ) | | | (5% | ) |
| Distributable cash flow (3) | | | 276.0 | | | | 312.2 | | | | 308.3 | | | | | (36.2 | ) | | | (12% | ) | | | | 3.9 | | | | 1% | |
| Operating data: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant natural gas inlet, MMCf/d (4)(5) | | | 2,268.0 | | | | 2,139.8 | | | | 1,846.4 | | | | | 128.2 | | | | 6% | | | | | 293.4 | | | | 16% | |
| Gross NGL production, MBbl/d | | | 121.2 | | | | 118.3 | | | | 101.9 | | | | | 2.9 | | | | 2% | | | | | 16.4 | | | | 16% | |
| Natural gas sales, Bbtu/d (5) | | | 685.1 | | | | 598.4 | | | | 532.1 | | | | | 86.7 | | | | 14% | | | | | 66.3 | | | | 12% | |
| NGL sales, MMbl/d | | | 251.5 | | | | 279.7 | | | | 286.9 | | | | | (28.2 | ) | | | (10% | ) | | | | (7.2 | ) | | | (3% | ) |
| Condensate sales, MBbl/d | | | 3.5 | | | | 4.7 | | | | 3.8 | | | | | (1.2 | ) | | | (26% | ) | | | | 0.9 | | | | 24% | |
| Average realized prices (6): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 4.39 | | | | 3.83 | | | | 8.19 | | | | | 0.56 | | | | 14% | | | | | (4.36 | ) | | | (53% | ) |
| NGL, $/gal | | | 1.06 | | | | 0.79 | | | | 1.38 | | | | | 0.27 | | | | 35% | | | | | (0.59 | ) | | | (43% | ) |
| Condensate, $/Bbl | | | 73.94 | | | | 56.25 | | | | 91.31 | | | | | 17.69 | | | | 31% | | | | | (35.06 | ) | | | (38% | ) |
__________
| (1) | Includes business interruption insurance proceeds of $13.3 million and $32.9 million for 2009 and 2008 recognized in periods prior to the conveyances of asset to us from Targa. These conveyances were accounted for under common control accounting. There were no business interruption proceeds received by us in 2010, as these amounts were retained by Targa under the terms of the purchase and sale agreements. |
| (2) | Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. |
| (3) | Distributable cash flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures. |
| (4) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. |
| (5) | Plant natural gas inlet volumes include producer take-in-kind, while natural gas sales exclude producer take-in-kind volumes. |
| (6) | Average realized prices include the impact of hedging activities. |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Revenues increased $956.4 million due to higher realized commodity prices ($1,221.9 million), and higher natural gas sales volumes ($117.4 million), partially offset by lower NGL and condensate sales volumes ($364.1 million), lower fee-based and other revenues ($5.5 million), and lower business interruption insurance proceeds ($13.3 million).
The increase in gross margin reflects higher revenue of $956.4 million partially offset by an increase in product purchase costs ($895.1 million). For information regarding period to period changes in our gross margins, see “Results of Operations—By Segment”.
The increase in operating expenses of $25.1 million was primarily due to increased compensation and benefits expenses, increased maintenance costs and environmental spending, partially offset by lower contract services and professional fees. See “Results of Operations—By Segment” for additional discussion regarding changes in operating expenses.
The increase in depreciation and amortization expenses of $9.5 million was primarily attributable to assets acquired in 2009 that had a full year period of depreciation in 2010, and incremental depreciation associated with $143.6 million of capital expenditures in 2010.
General and administrative expenses increased $3.9 million reflecting outside services expenses.
The $49.0 million decrease in interest expense was primarily due to an overall reduction in long-term debt of $379.6 million and lower interest rates on existing debt. We eliminated affiliate and allocated debt, which was partially offset by an increase in third-party debt.
See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.
During 2010, there was no gain or loss on debt repurchase. During 2009 there was a loss on debt repurchase of $1.5 million in 2009.
Our gain on mark-to-market derivative instruments for 2010 compared to a loss for 2009 was primarily due to the treatment of commodity hedges related to the Permian Business and Versado that were allocated to us through common control accounting. These allocated hedges did not qualify for hedge accounting prior to our acquisition of the underlying assets and therefore the change in fair value of these instruments was recorded in earnings using the mark-to-market method. The use of mark-to-market accounting caused non-cash earnings volatility due to changes in the underlying commodity price indices. During 2010, we recorded mark-to-market gain, compared to 2009, when we recorded mark-to-market loss due to these changes in commodity price indices.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Revenues decreased $3,526.3 million due to lower realized prices ($3,570.9 million), lower NGL sales volumes ($170.3 million), partially offset by higher natural gas and condensate sales volumes ($221.9 million) and higher fee-based and other revenues ($7.0 million).
The decrease in gross margin reflects lower revenue of $3,526.3 million partially offset by a reduction in product purchase costs of $3,424.3 million. For information regarding period to period changes in our gross margins, see “Results of Operations—By Segment”.
The decrease in operating expenses was primarily due to lower fuel, utilities and catalyst expenses ($20.6 million), lower maintenance and supplies expenses ($20.6 million), and lower contract labor costs ($7.8 million), partially offset by a lower level of cost recovery billings to others ($6.5 million). Year over year comparisons of operating expenses are affected by our consolidation of VESCO starting August 1, 2008, following our acquisition of majority ownership of this operation. Had VESCO been consolidated for all of 2008, operating expenses would have been $17.1 million higher for 2008. See “Results of Operations—By Segment” for additional discussion regarding changes in operating expenses.
The increase in depreciation and amortization expenses is primarily attributable to assets acquired in 2008 that had a full year period of depreciation in 2009, as well as incremental depreciation associated with capital expenditures in 2009 of $95.9 million.
The increase in general and administrative expense was primarily due to higher compensation-related expenses ($17.0 million) and increased insurance expenses ($6.0 million), reflecting higher property casualty premiums following significant 2008 Gulf Coast hurricane activity.
Other operating items were an overall gain of $3.6 million during 2009 versus an overall loss of $13.4 million during 2008, when we recorded a $19.3 million loss provision for property damage from Hurricanes Gustav and Ike net of expected insurance recoveries. During 2009 the loss provision was reduced by $3.6 million. A $5.9 million gain from a like-kind exchange of pipeline assets was also realized during 2008.
The $3.7 million increase in interest expense was primarily due to increased interest on debt allocated from Targa related to predecessor operations during 2009. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.
Equity in earnings of unconsolidated investments decreased $9.0 million in 2009 due primarily to the consolidation of VESCO following our acquisition of Chevron’s 53.9% interest on August 1, 2008.
Loss on debt repurchases of $1.5 million in 2009 relates to open market repurchases of our 11¼% Senior Notes due 2017 as compared to a gain of $13.1 million in 2008.
Results of Operations—By Reportable Segment
Our operating margin by reportable segment is:
| | Field | | Coastal | | | | | | | | | | | | |
| | Gathering | | Gathering | | | | | Marketing | | | | | | | |
| | and | | and | | Logistics | | and | | | | | | | |
| | Processing | | Processing | | Assets | | Distribution | | Other | | Total | |
| | (In millions) | |
| Year Ended December 31, 2010 | | $ | 236.6 | | | $ | 107.8 | | | $ | 83.8 | | | $ | 80.5 | | | $ | 4.0 | | | $ | 512.7 | |
| Year Ended December 31, 2009 | | | 183.2 | | | | 89.7 | | | | 74.3 | | | | 83.0 | | | | 46.3 | | | | 476.5 | |
| Year Ended December 31, 2008 | | | 385.4 | | | | 105.4 | | | | 40.1 | | | | 41.3 | | | | (33.6 | ) | | | 538.6 | |
Natural Gas Gathering and Processing Division
Field Gathering and Processing
| | | Year Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | $ Change | | | % Change | | | $ Change | | | % Change | |
| | | ($ in millions) | | | | | | | | | | | | | |
| Gross margin | | $ | 338.8 | | | $ | 268.3 | | | $ | 489.5 | | | $ | 70.5 | | | | 26% | | | $ | (221.2 | ) | | | (45% | ) |
| Operating expenses | | | 102.2 | | | | 85.1 | | | | 104.1 | | | | 17.1 | | | | 20% | | | | (19.0 | ) | | | (18% | ) |
| Operating margin | | $ | 236.6 | | | $ | 183.2 | | | $ | 385.4 | | | $ | 53.4 | | | | 29% | | | $ | (202.2 | ) | | | (52% | ) |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant natural gas inlet, MMcf/d | | | 587.7 | | | | 581.9 | | | | 584.1 | | | | 5.8 | | | | 1% | | | | (2.2 | ) | | (% | ) |
| Gross NGL production, MBbl/d | | | 71.2 | | | | 69.8 | | | | 68.0 | | | | 1.4 | | | | 2% | | | | 1.8 | | | | 3% | |
| Natural gas sales, BBtu/d (1) | | | 258.6 | | | | 219.6 | | | | 296.2 | | | | 39.0 | | | | 18% | | | | (76.6 | ) | | | (26% | ) |
| NGL sales, MBbl/d (1) | | | 56.6 | | | | 56.2 | | | | 54.1 | | | | 0.4 | | | | 1% | | | | 2.1 | | | | 4% | |
| Condensate sales, MBbl/d (1) | | | 2.9 | | | | 3.2 | | | | 3.5 | | | | (0.3 | ) | | | (9% | ) | | | (0.3 | ) | | | (9% | ) |
| Average realized prices: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 4.11 | | | | 3.69 | | | | 7.55 | | | | 0.42 | | | | 11% | | | | (3.86 | ) | | | (51% | ) |
| NGL, $/gal | | | 0.93 | | | | 0.69 | | | | 1.21 | | | | 0.24 | | | | 35% | | | | (0.52 | ) | | | (43% | ) |
| Condensate, $/Bbl | | | 75.48 | | | | 55.84 | | | | 86.51 | | | | 19.64 | | | | 35% | | | | (30.67 | ) | | | (35% | ) |
________
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year. |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $70.5 million increase in gross margin for 2010 was primarily due to higher commodity sales price ($303.9 million) and higher natural gas and NGL sales volumes ($22.6 million) offset by lower condensate sales volumes ($6.8 million), higher fee based and other revenue ($4.5 million) and higher product purchases ($253.6 million). The increased natural gas and NGL sales volumes were due primarily to higher natural gas and NGL production.
The increase in operating expenses was primarily due to higher system maintenance expenses ($8.2 million), higher compensation and benefit costs ($4.7 million) and higher contract and professional service expenses ($2.0 million).
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $221.2 million decrease in gross margin for 2009 was due to lower commodity sales prices ($853.9 million) and lower natural gas and condensate sales volumes ($157.2 million) offset by higher NGL sales volumes ($36.1 million), higher fee based and other revenue ($0.1 million) and lower product purchases ($753.8 million). The increased NGL sales volumes were due primarily to higher NGL production.
The decrease in operating expenses was primarily due to lower maintenance and supplies expenses ($8.4 million), lower contract services and professional fees ($4.4 million), and lower fuel, utilities and catalysts expenses ($3.2 million).
Coastal Gathering and Processing
| | | Year Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | $ Change | | | % Change | | | $ Change | | | % Change | |
| | | ($ in millions) | | | | | | | | | | | | | |
| Gross margin | | $ | 151.2 | | | $ | 132.7 | | | $ | 136.5 | | | $ | 18.5 | | | | 14% | | | $ | (3.8 | ) | | | (3% | ) |
| Operating expenses | | | 43.4 | | | | 43.0 | | | | 31.1 | | | | 0.4 | | | | 1% | | | | 11.9 | | | | 38% | |
| Operating margin | | $ | 107.8 | | | $ | 89.7 | | | $ | 105.4 | | | $ | 18.1 | | | | 20% | | | $ | (15.7 | ) | | | (15% | ) |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant natural gas inlet, MMcf/d (2) | | | 1,680.3 | | | | 1,557.8 | | | | 1,262.4 | | | | 122.5 | | | | 8% | | | | 295.4 | | | | 23% | |
| Gross NGL production, MBbl/d | | | 50.1 | | | | 48.5 | | | | 33.9 | | | | 1.6 | | | | 3% | | | | 14.6 | | | | 43% | |
| Natural gas sales, Bbtu/d (1) | | | 293.6 | | | | 258.4 | | | | 239.4 | | | | 35.2 | | | | 14% | | | | 19.0 | | | | 8% | |
| NGL sales, MBbl/d (1) | | | 43.7 | | | | 40.6 | | | | 31.7 | | | | 3.1 | | | | 8% | | | | 8.9 | | | | 28% | |
| Condensate sales, MBbl/d (1) | | | 0.5 | | | | 1.6 | | | | 1.5 | | | | (1.1 | ) | | | (69% | ) | | | 0.1 | | | | 7% | |
| Average realized prices: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 4.48 | | | | 4.00 | | | | 9.00 | | | | 0.48 | | | | 12% | | | | (5.00 | ) | | | (56% | ) |
| NGL, $/gal | | | 1.03 | | | | 0.77 | | | | 1.34 | | | | 0.26 | | | | 34% | | | | (0.57 | ) | | | (43% | ) |
| Condensate, $/Bbl | | | 78.82 | | | | 53.31 | | | | 90.10 | | | | 25.51 | | | | 48% | | | | (36.79 | ) | | | (41% | ) |
__________
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year. |
| (2) | The majority of our Coastal Straddle plant volumes are gathered on third party offshore pipeline systems and delivered to the plant inlets. |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $18.5 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($230.3 million) and an increase in natural gas and NGL sales volumes ($88.3 million) offset by decrease in condensate sales volumes ($21.8 million) and fee-based and other revenues ($11.3 million) and an increase in commodity purchases ($266.8 million). Natural gas sales volumes increased due to increased sales to other segments for resale partially offset by a small decrease in demand from our industrial customers. NGL, natural gas and inlet sales volumes increased primarily because the straddle plants were recovering operations in the first two quarters of 2009 after Hurricanes Gustuv and Ike disrupted operations in 2008.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $3.9 million decrease in gross margin for 2009 is primarily due to lower realized commodity prices ($847.7 million) and lower business interruption proceeds ($3.4 million) offset by higher commodity sales volumes ($246.0 million) as a result of the recovery of operations after Hurricanes Gustav and Ike, reduced product purchase costs ($596.7 million) and higher fee-based and other income ($4.6 million). VESCO has been consolidated in our financials since we purchased Chevron’s 53% interest in August 2008, giving us a controlling interest from that date forward. Had VESCO been consolidated for the entire period, gross margin for 2008 would have been $43.6 million.
The increase in operating expenses was primarily due to a full year of operating expenses from VESCO in 2009, as compared with five months of operating expenses from VESCO in 2008 due to our acquisition of majority ownership in and consolidation of VESCO on August 1, 2008. Had VESCO been consolidated for the entire period, operating expenses for 2008 would have been $17.8 million higher and our Coastal Gathering and Processing segment would have reported reductions in aggregate operating expense levels during 2009 as was the case with our other segments.
NGL Logistics and Marketing Division
Logistics Assets
| | | Year Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | $ Change | | | % Change | | | $ Change | | | % Change | |
| | | ($ in millions) | | | | | | | | | | | | | |
| Gross margin | | $ | 172.3 | | | $ | 156.2 | | | $ | 172.5 | | | $ | 16.1 | | | | 10% | | | $ | (16.3 | ) | | | (9% | ) |
| Operating expenses | | | 88.5 | | | | 81.9 | | | | 132.4 | | | | 6.6 | | | | 8% | | | | (50.5 | ) | | | (38% | ) |
| Operating margin | | $ | 83.8 | | | $ | 74.3 | | | $ | 40.1 | | | $ | 9.5 | | | | 13% | | | $ | 34.2 | | | | 85% | |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fractionation volumes, MBbl/d | | | 230.8 | | | | 217.2 | | | | 212.2 | | | | 13.6 | | | | 6% | | | | 5.0 | | | | 2% | |
| LSNG Treating volumes, MBbl/d | | | 18.0 | | | | 21.9 | | | | 20.7 | | | | (3.9 | ) | | | (18% | ) | | | 1.2 | | | | 6% | |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $16.1 million increase in gross margin reflects higher fractionation and treating fees ($20.4 million) higher terminalling and storage revenue ($2.6 million), offset by lower fee-based and other revenues ($6.9 million). The increase in fractionation volumes is as result of our capacity in our fractionating facilities being at or near capacity. We are expanding our fractionating capacity at the Cedar Bayou and Gulf Coast Fractionation plants to meet increased market demand.
The $6.6 million increase in operating expenses was primarily due to higher compensation costs ($5.0 million) and higher general maintenance supplies ($3.0 million).
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $16.3 million decrease in gross margin for 2009 was due to lower fractionation and treating revenue ($20.9 million) due to lower fees offset by higher other fee-based and other revenue ($4.6 million).
The decrease in operating expenses was primarily due to lower fuel and utilities expenses ($43.2 million), lower maintenance and supplies expenses ($4.7 million) and lower outside services ($9.4 million), partially offset by higher compensation expense ($1.1 million) and system product losses ($2.5 million).
Marketing and Distribution
| | | Year Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | $ Change | | | % Change | | | $ Change | | | % Change | |
| | | ($ in millions) | | | | | | | | | | | | | |
| Gross margin | | $ | 125.4 | | | $ | 128.9 | | | $ | 98.8 | | | $ | (3.5 | ) | | | (3% | ) | | $ | 30.1 | | | | 30% | |
| Operating expenses | | | 44.9 | | | | 45.9 | | | | 57.5 | | | | (1.0 | ) | | | (2% | ) | | | (11.6 | ) | | | (20% | ) |
| Operating margin | | $ | 80.5 | | | $ | 83.0 | | | $ | 41.3 | | | $ | (2.5 | ) | | | (3% | ) | | $ | 41.7 | | | | 101% | |
| Operating statistics: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas sales, BBtu/d | | | 634.9 | | | | 510.3 | | | | 417.4 | | | | 124.6 | | | | 24% | | | | 92.9 | | | | 22% | |
| NGL sales, MBbl/d | | | 246.7 | | | | 276.1 | | | | 284.0 | | | | (29.4 | ) | | | (11% | ) | | | (7.9 | ) | | | (3% | ) |
| Average realized prices: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 4.31 | | | | 3.65 | | | | 7.81 | | | | 0.66 | | | | 18% | | | | (4.16 | ) | | | (53% | ) |
| NGL realized price, $/gal | | | 1.10 | | | | 0.80 | | | | 1.40 | | | | 0.30 | | | | 38% | | | | (0.60 | ) | | | (43% | ) |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $3.5 million decrease in gross margin was due to increased commodity prices ($1,287.9 million) and higher natural gas volumes ($166.2 million) offset by lower NGL volumes ($359.8 million), lower fee-based and other revenues ($20.4 million), and increased product purchases ($1,077.2 million). Lower 2010 margins were primarily due to the 2009 impact of higher margins on forward sales agreements that were fixed at relatively high 2008 prices, along with spot fractionation volumes and associated fees. These items were partially offset by higher marketing fees on contract purchase volumes due to overall higher 2010 market prices. Margin on transportation activity decreased due to expiration of a barge contract partially offset by increased truck activity.
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower due to a change in contract terms with a petrochemical supplier that had a minimal impact to gross margin.
Operating expenses were essentially flat.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $30.1 million increase in gross margin for 2009 was due to higher natural gas sales volumes ($261.8 million), lower product purchase costs ($3,312.4 million) and a $33.0 million decrease in lower of cost or market adjustment, offset by lower realized commodity prices ($3,334.9 million), and lower NGL sales volumes ($188.2 million), lower fee-based and other revenues ($37.6 million) and lower business interruption proceeds ($16.3 million).
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower due to a change in contract terms with a petrochemical supplier in the third quarter of 2009 that had a minimal impact to gross margin.
The $11.7 million decrease in operating expenses was primarily due to a decrease in fuel and utilities expense ($5.8 million), a decrease in maintenance and supplies expenses ($4.2 million) and a decrease in outside services ($1.0 million). Factors contributing to the decrease included the expiration of a barge contract, partially offset by increased truck utilization.
Other
| | | Years Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | Change | | | % Change | | | Change | | | % Change | |
| | | ($ in millions) | | | | |
| Gross margin | | $ | 4.0 | | | $ | 46.3 | | | $ | (33.6 | ) | | $ | (42.3 | ) | | | (91% | ) | | $ | 79.9 | | | | 238% | |
| Operating margin | | $ | 4.0 | | | $ | 46.3 | | | $ | (33.6 | ) | | $ | (42.3 | ) | | | (91% | ) | | $ | 79.9 | | | | 238% | |
Other contains the financial effects of the cash flow hedging program on profitability. The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. We have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes by entering into derivative financial instruments. Our hedging strategy is in effect to forward sell our equity gas and NGL volumes generated by our gas plants. As such, these hedge positions will enhance our margins in periods of falling prices and decrease our margins in periods of rising prices.
On April 1, 2010 and August 1, 2010 (“the dropdown dates”), commodity derivative contracts were re-assigned to us as part of the conveyance of assets from Targa. As a result, we recast our financial statements as if these derivative contracts had always been assigned to us in accordance with common control accounting. On the dropdown dates, we designated the respective derivative contracts as hedges, and, as such, they receive hedge accounting treatment from their respective dropdown dates forward. Prior to the dropdown dates, under common control accounting, the respective commodity derivatives were not designated as hedges, and therefore receive mark-to-market accounting, which is recorded as a component of other income (loss).
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Our cash flow hedging program decreased gross margin by $42.3 million during 2010 versus 2009, due to higher commodity prices which resulted in lower revenues from settlements on derivative contracts, as well as the impact of lower volumes hedged.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Our cash flow hedges increased gross margin by $79.9 million during 2009 versus 2008, as lower commodity prices yielded higher settlement revenues on derivative contracts.
Insurance Update
Hurricanes Katrina and Rita affected certain of our Gulf Coast facilities in 2005. The final purchase price allocation for our acquisition from Dynegy in October 2005 included an $81.1 million receivable for insurance claims related to property damage caused by Hurricanes Katrina and Rita. During 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $18.5 million. During 2009, expenditures related to these hurricanes included $0.3 million capitalized as improvements. The insurance claim process is now complete with respect to Hurricanes Katrina and Rita for property damage and business interruption insurance.
Certain of our Louisiana and Texas facilities sustained damage and had disruptions to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2009 and 2010, the estimate was reduced by $3.7 million and $3.3 million. During 2009, expenditures related to the hurricanes included $33.2 million for previously accrued repair costs and $7.4 million capitalized as improvements. These are our common control numbers only and do not include amounts retained by Targa.
The following table provides income recognized from business interruption insurance, which includes amounts received for hurricane-related impacts by segment for the periods indicated. We did not have income from business interruption insurance during 2010.
| | Year Ended December 31, | |
| | 2009 | | 2008 | |
| | (In millions) | |
| Coastal Gathering and Processing | | $ | 10.9 | | | $ | 14.2 | |
| Logistics Assets | | | 1.9 | | | | 1.8 | |
| Marketing and Distribution | | | 0.5 | | | | 16.9 | |
| | | $ | 13.3 | | | $ | 32.9 | |
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our credit facility, the issuance of additional units by the Partnership and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.
We continue to evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations.
As of December 31, 2010 our liquidity of $309.7 million consisted of $76.3 million of available cash, and $233.4 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. On July 19, 2010, we entered into an amended and restated credit agreement that replaced our existing variable rate senior secured credit facility with a new variable rate senior secured credit facility due July 2015. The new senior secured credit facility increased available commitments to $1.1 billion, and allows us to request increases in commitments up to an additional $300 million. The amended and restated credit agreement increased our availability by $141.5 million .
Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facility should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distribution for at least the next twelve months.
A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status, as determined by Moody’s Investors Service, Inc. and Standard and Poor’s Rating Service, and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At December 31, 2010, our total outstanding letter of credit postings were $101.3 million.
We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of December 31, 2010, such annual minimum amounts payable to non-Targa unitholders approximate $86.3 million. 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 expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 10 and Note 11 of the notes to Consolidated Financial Statements included in this Annual Report.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital beca use we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.
As of December 31, 2010, we had a positive working capital balance of $11.0 million.
Subsequent Events. On January 24, 2011, we completed a public offering of 8,000,000 common units representing limited partner interests in us under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 we sold an additional 1,200,000 common units, providing net proceeds of approximately $38.9 million. In addition, our general partner contributed $6.3 million for 187,755 general partner units to maintain its 2% interest in us. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.
On February 2, 2011, we closed on a private placement of $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of $319.3 million.
On February 4, 2011 we exchanged $158.6 million under an exchange offer to holders of our 11¼% Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange we paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7 million of face value 11¼% Notes due 2017 were removed as we received sufficient consents in connection with the exchange offer to amend the indenture.
Net cash from the completion of the unit offerings and the note offering less cash paid in connection with the exchange offer was used to reduce outstanding borrowings under our senior secured credit facility by $595.2 million. Taking into account these payments, as of December 31, 2010, available borrowings under our senior secured credit facility would have been $828.6 million.
Cash Flow
The following table summarizes our consolidated cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated:
| | | Year Ended December 31, | | | 2010 vs. 2009 | | | 2009 vs. 2008 | |
| | | 2010 | | | 2009 | | | 2008 | | | $ Change | | | % Change | | | $ Change | | | % Change | |
| | (In millions) | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 371.2 | | | $ | 422.9 | | | $ | 550.2 | | | $ | (51.7 | ) | | | (12% | ) | | $ | (127.3 | ) | | | (23% | ) |
| Investing activities | | | (134.9 | ) | | | (94.6 | ) | | | (247.1 | ) | | | (40.3 | ) | | | (43% | ) | | | 152.5 | | | | 62% | |
| Financing activities | | | (250.9 | ) | | | (380.6 | ) | | | (249.5 | ) | | | 129.7 | | | | 34% | | | | (131.1 | ) | | | (53% | ) |
Operating Activities
The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the Consolidated Statements of Cash Flows included in our historical consolidated financial statements and related notes thereto beginning on page F-1 of this Annual Report and changes in working capital as discussed above under “—Liquidity and Capital Resources—Working Capital.”
The $51.7 million decrease in net cash provided by operating activities in 2010 compared to 2009 was primarily due to the following:
| · | Increased average realized prices and hedge volumes on commodity hedge transactions caused our hedge management process to be less effective during 2010. |
| · | Offset by a net decrease in working capital. |
| · | Please see “—Results of Operations—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009” for a discussion of material items that impacted our net income. |
The $127.3 million decrease in net cash provided by operating activities in 2009 compared to 2008 was primarily due to the following:
| · | Net cash flow from consolidated operations (excluding cash payments for interest and distributions received from unconsolidated affiliates) decreased $125.4 million period-to-period. The change in net cash provided by operating activities reflects: |
| · | Decrease in net income of $228.0 million; and |
| · | the changes in and timing and settlement of transactions as reflected in the changes in working capital of $(190.8) million and risk management activities of $269.4 million. |
Please see “—Results of Operations—Year Ended December 31, 2009 Compared to Year Ended December 31, 2008” for a discussion of material items that impacted our operating cash flow.
Investing Activities
Net cash used in investing activities increased by $40.3 million for 2010 compared to 2009. The increase is attributable to higher capital expenditures in 2010 compared to 2009.
Net cash used in investing activities decreased by $152.5 million for 2009 compared to 2008. The decrease is attributable to lower capital expenditures in 2009 and the VESCO acquisition in 2008.
The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and equipment additions and the difference, which is primarily settled accruals and non-cash additions:
| | Year Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| | (In millions) | |
| Gross additions to property, plant and equipment | | $ | 143.6 | | | $ | 99.2 | | | $ | 137.2 | |
| Non-cash additions to property, plant and equipment | | | (0.4 | ) | | | (9.8 | ) | | | (4.3 | ) |
| Change in accruals | | | (6.2 | ) | | | 6.5 | | | | (10.1 | ) |
| Cash expenditures | | $ | 137.0 | | | $ | 95.9 | | | $ | 122.8 | |
Financing Activities
Net cash used in financing activities decreased $129.7 million for 2010 compared to 2009. The decrease was primarily due to:
| · | The purchase from Targa of the Permian Business and Straddle Assets and Targa’s interests in the Versado and VESCO. These purchases included the repayment to Targa of $737.7 million in affiliate and allocated indebtedness, including interest. |
| · | Net borrowings under our senior secured credit facility increasing by $294.6 million in 2010 compared to 2009. |
| · | Proceeds from additional equity offerings increasing by $214.7 million during 2010 compared to 2009. |
| · | Offset by cash distributions to unitholders, including our general partner and incentive distribution rights, increased $49.7 million in 2010. |
Net cash used in financing activities increased $131.1 million for 2009 compared to 2008. The increase was primarily due to net repayments of indebtedness and distributions, partially offset by equity issuances.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and to enhance the value of our natural gas logistics and marketing assets.
We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues.
| | | | | | | | | | |
| | Year Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| Capital expenditures: | (In millions) | |
| Expansion | | $ | 93.1 | | | $ | 54.7 | | | $ | 68.8 | |
| Maintenance | | | 50.5 | | | | 44.5 | | | | 68.4 | |
| | | $ | 143.6 | | | $ | 99.2 | | | $ | 137.2 | |
We estimate that our capital expenditures for 2011 will be approximately $230 million, of which approximately 25% will be spent on maintenance capital.
Credit Facilities and Long-Term Debt
As of December 31, 2010, we had outstanding our Senior Notes of $680.1 million and borrowings under senior secured revolving credit facility of $765.3 million, with approximately $233.4 million of availability under our senior secured revolving credit facility. See “Debt Obligations” included under Note 10 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a discussion of our credit agreements.
As of December 31, 2010, we are in compliance with the covenants contained in our various debt agreements.
Senior Secured Revolving Credit Facility due 2015
On July 19, 2010, we entered into a new five-year $1.1 billion amended and restated senior secured credit facility, which allows us to request increases in commitments up to additional $300 million. The new senior secured credit facility amended and restated our former $977.5 million senior secured revolving credit facility due February 2012.
For the year ended December 31, 2010, we had gross borrowings under our senior secured revolving credit facilities of $1,343.1 million, and repayments totaling $1,057.0 million, for a net increase for the year ended December 31, 2010 of $286.1 million.
The amended and restated credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% (or base rate at the borrower’s option) dependent on our consolidated funded indebtedness to consolidated adjusted EBITDA ratio. Our senior secured credit facility is secured by a majority of our assets.
Our senior secured credit facility restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in our senior secured credit agreement) has occurred and is continuing. The senior secured credit facility requires us to maintain a consolidated funded indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The senior secured credit facility also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, as defined in the senior secured credit agreement) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrenc e of additional permitted indebtedness.
Outstanding Senior Notes
On June 18, 2008, we placed $250 million in aggregate principal amount at par value of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, we placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. On August 13, 2010, we placed $250 million in aggregate principal amount at par value of 7⅞% senior notes due 2018 (the “7⅞% Notes”). These notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any of our future subordinated indebtedness.
Our senior unsecured notes and associated indenture agreements (other than the indenture for the 11¼ Notes) restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the note s are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.
Subsequent Events. On February 2, 2011, we placed $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of $319.3 million.
On February 4, 2011 we exchanged $158.6 million under an exchange offer to holders of our 11¼% Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange we paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7 million of face value 11¼% Notes due 2017 were removed as we received sufficient consents in connection with the exchange offer to amend the indenture.
Cash from the completion of the unit offerings, the note offering and the exchange offer was used to reduce outstanding borrowings under our senior secured credit facility by $595.2 million. Taking into account these payments, as of December 31, 2010, available borrowings under our senior secured credit facility would have been $828.6 million.
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements as defined by the Securities and Exchange Commission. See “Contractual Obligations” below and “Commitments and Contingencies” included under Note 16 to our “Consolidated Financial Statements” beginning on page F-1 in this Annual Report for a discussion of our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.
Contractual Obligations
Following is a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2010:
| | | Payments Due By Period | |
| | | | | | Less Than | | | | | | | | | More Than | |
| Contractual Obligations | | Total | | | 1 Year | | | 1-3 Years | | | 4-5 Years | | | 5 Years | |
| | | (In millions) | |
| Debt obligations (1) | | $ | 1,445.4 | | | $ | - | | | $ | - | | | $ | 765.3 | | | $ | 680.1 | |
| Interest on debt obligations (2) | | | 422.3 | | | | 63.0 | | | | 188.9 | | | | 118.8 | | | | 51.6 | |
| Operating lease and service contract obligations (3) | | | 36.7 | | | | 10.6 | | | | 12.2 | | | | 5.3 | | | | 8.6 | |
| Capacity and terminalling payments (4) | | | 12.9 | | | | 6.6 | | | | 6.3 | | | | - | | | | - | |
| Land site lease and right-of-way (5) | | | 20.4 | | | | 1.3 | | | | 2.4 | | | | 2.1 | | | | 14.6 | |
| Asset retirement obligation | | | 37.5 | | | | - | | | | - | | | | - | | | | 37.5 | |
| Commodities (6) | | | 98.1 | | | | 98.1 | | | | - | | | | - | | | | - | |
| Purchase order commitments (7) | | | 63.5 | | | | 63.0 | | | | 0.5 | | | | - | | | | - | |
| | | $ | 2,136.8 | | | $ | 242.6 | | | $ | 210.3 | | | $ | 891.5 | | | $ | 792.4 | |
| Commodity Purchase Commitments | | | | | | | | | | | | | | | | | | | | |
| Natural Gas (million MMBtu) | | | 9.3 | | | | 9.3 | | | | - | | | | - | | | | - | |
| NGL (millions of gallons) | | | 56.3 | | | | 56.3 | | | | - | | | | - | | | | - | |
__________
| (1) | Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See “Debt Obligations” included under Note 10 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for information regarding our debt obligations. |
| (2) | Represents interest expense on our debt obligations based on interest rates as of December 31, 2010 and the scheduled future maturities of those debt obligations. |
| (3) | Includes minimum payments on lease obligations, service contracts, right-of-way agreement, with site leases and railcar leases. |
| (4) | Consists of capacity payments for firm transportation contracts. |
| (5) | Lease site and right-of-way expenses provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us; these agreements expire at various dates through 2099. |
| (6) | Includes natural gas and NGL purchase commitments. |
| (7) | Consists of open purchase orders and Versado remediation projects. |
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and est imates.
Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:
| · | changes in energy prices; |
| · | changes in competition; |
| · | changes in laws and regulations that limit the estimated economic life of an asset; |
| · | changes in technology that render an asset obsolete; |
| · | changes in expected salvage values; and |
| · | changes in the forecast life of applicable resources basins, if any. |
As of December 31, 2010, the net book value of our property, plant and equipment was $2.5 billion and we recorded $176.2 million in depreciation expense for 2010. The weighted average life of our long-lived assets is approximately 20 years. 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. For example, if the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense would increase by $19.6 million per year, which would result in a corresponding reduction in our operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long- lived assets, our operating income would decrease by $25.0 million in the year of impairment. There have been no material changes impacting estimated useful lives of the assets.
Revenue Recognition. As of December 31, 2010, our balance sheet reflects total accounts receivable from third parties of $466.1 million. We have recorded an allowance for doubtful accounts as of December 31, 2010 of $7.7 million.
Our exposure to uncollectible accounts receivable relates to the financial health of its counterparties. We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectibility resulted in a 1% reduction of our third-party accounts receivable, our operating income would decrease by $4.7 million in the year of assessment.
Price Risk Management (Hedging). Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into (i) derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on our variable debt. We are exposed to the credit risk of our counterparties in these derivative financial instruments. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure.
Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.
One of the primary factors that can affect our operating results each period is the price assumptions we use to value our derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction wi ll not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.
The estimated fair value of our derivative financial instruments was a net liability of $22.9 million as of December 31, 2010, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to less than $0.1 million as of December 31, 2010. We and our indirect parent, Targa, have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring our adjustment for credit risk, if a bankruptcy by financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments, we estimate that our operating income would decrease by $4.4 million in the year of bankruptcy.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Significant Accounting Policies” included under Note 4 to our “Consolidated Financial Statements” beginning on page F-1 in this Annual Report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, changes in interest rates, as well as nonperformance by our customers. We do not use risk sensitive instruments for trading purposes.
Commodity Price Risk. A majority of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2010, we have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes that result from our percent of proceeds processing arrangements for our Field Gathering and Processing, Operations through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGL and we pay th e hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric 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 as market conditions permit.
We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of its physical equity volumes. Our NGL hedges cover specific NGL products based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our NGL hedges fair values are based on published index prices for delivery at Mont Belvieu through 2013, except for the price of isobutane in 2012, which is based on the ending 2011 pricing. Our natural gas hedges fair values are based on published index prices for delivery at WAHA, Permian Basin and Mid-Continent, which closely approximate the actual NGL and natural gas delivery points. We hedge a portion of our condensat e sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
These commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to sec ure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.
For all periods presented we entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). During 2010, 2009 and 2008, our operating revenues were increased (decreased) by net hedge adjustments of $5.3 million, $45.6 million and $(33.7) million.
As of December 31, 2010, our commodity derivative arrangements were as follows:
| Natural Gas | |
| Instrument | | | Price | | | MMBtu per day | | | | |
| Type | Index | | $/MMBtu | | | 2011 | | | 2012 | | | 2013 | | | Fair Value | |
| | | | | | | | | | | | | | | | (In millions) | |
| Swap | IF-WAHA | | | 6.29 | | | | 23,750 | | | | - | | | | - | | | $ | 16.9 | |
| Swap | IF-WAHA | | | 6.61 | | | | - | | | | 14,850 | | | | - | | | | 9.6 | |
| Swap | IF-WAHA | | | 5.59 | | | | - | | | | - | | | | 4,000 | | | | 0.8 | |
| Total Swaps | | | | | | | | 23,750 | | | | 14,850 | | | | 4,000 | | | | | |
| Swap | IF-PB | | | 5.42 | | | | 2,000 | | | | - | | | | - | | | | 0.8 | |
| Swap | IF-PB | | | 5.54 | | | | - | | | | 4,000 | | | | - | | | | 1.1 | |
| Swap | IF-PB | | | 5.54 | | | | - | | | | - | | | | 4,000 | | | | 0.8 | |
| Total Swaps | | | | | | | | 2,000 | | | | 4,000 | | | | 4,000 | | | | | |
| Swap | IF-NGPL MC | | | 6.87 | | | | 4,350 | | | | - | | | | - | | | | 4.1 | |
| Swap | IF-NGPL MC | | | 6.82 | | | | - | | | | 4,250 | | | | - | | | | 3.1 | |
| Total Swaps | | | | | | | | 4,350 | | | | 4,250 | | | | - | | | | | |
| | | | | | | | | 30,100 | | | | 23,100 | | | | 8,000 | | | | | |
| Natural Gas Basis Swaps | | | | | | | | | | | | | |
| Basis Swaps | Various Indexes, Maturities January 2011-May 2011 | | | | (0.4 | ) |
| | | | | | | | | | | | | | | | | | | | $ | 36.8 | |
| NGL | |
| Instrument | | | Price | | | Barrels per day | | | | |
| Type | Index | | $/Gal | | | 2011 | | | 2012 | | | 2013 | | | Fair Value | |
| | | | | | | | | | | | | | | | (In millions) | |
| Swap | OPIS_MB | | | 0.85 | | | | 8,550 | | | | - | | | | - | | | $ | (18.0 | ) |
| Swap | OPIS_MB | | | 0.85 | | | | - | | | | 6,700 | | | | - | | | | (6.6 | ) |
| Swap | OPIS_MB | | | 0.92 | | | | - | | | | - | | | | 3,400 | | | | (4.0 | ) |
| Total Swaps | | | | | | | | 8,550 | | | | 6,700 | | | | 3,400 | | | | | |
| Floor | OPIS_MB | | | 1.44 | | | | 253 | | | | - | | | | - | | | | 0.8 | |
| Floor | OPIS_MB | | | 1.43 | | | | - | | | | 294 | | | | - | | | | 1.3 | |
| Total Floors | | | | | | | | 253 | | | | 294 | | | | - | | | | | |
| Total Sales | | | | | | | | 8,803 | | | | 6,994 | | | | 3,400 | | | | | |
| | | | | | | | | | | | | | | | | | | | $ | (26.5 | ) |
| Condensate | |
| Instrument | | | Price | | | Barrels per day | | | | |
| Type | Index | | $/Bbl | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | Fair Value | |
| | | | | | | | | | | | | | | | | | (In millions) | |
| Swap | NY-WTI | | | 80.37 | | | | 1,100 | | | | - | | | | - | | | | - | | | $ | (5.4 | ) |
| Swap | NY-WTI | | | 82.25 | | | | - | | | | 950 | | | | - | | | | - | | | | (4.0 | ) |
| Swap | NY-WTI | | | 81.82 | | | | - | | | | - | | | | 800 | | | | - | | | | (3.1 | ) |
| Swap | NY-WTI | | | 90.03 | | | | - | | | | - | | | | - | | | | 700 | | | | (0.6 | ) |
| Total Sales | | | | | | | | 1,100 | | | | 950 | | | | 800 | | | | 700 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | $ | (13.1 | ) |
These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore required an entity to develop its own assumptions. We determine the value of our NGL derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. Prior to 2009, all of our NGL contracts were classified as Level 3 within the hierarchy. In 2009, we were able to obtain inputs from quoted prices related to certain of these commodity derivatives for similar assets and liabilities in active markets. These inputs are observable for the asset or liability, either directly or indirectly, for the full term of the commodity swaps and options. For the NGL contracts that have inputs from quoted prices, we have changed our classification of these instruments from Level 3 to Level 2 within the fair value hierarchy. For those NGL contracts where we were unable to obtain quoted prices for the full term of the commodity swap and options the NGL valuations are still classified as Level 3 within the fair value hierarchy.
Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of December 31, 2010, we had variable rate borrowings of $765.3 million outstanding. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting pe riod. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense on the related debt is recognized in earnings.
As of December 31, 2010, we had the following open interest rate swaps:
| | | | | Notional | | Fair | |
| Period | | Fixed Rate | | Amount | | Value | |
| | | | | ($ in millions) | |
| 2011 | | | 3.52% | | | $ | 300 | | | $ | (7.8 | ) |
| 2012 | | | 3.40% | | | | 300 | | | | (7.5 | ) |
| 2013 | | | 3.39% | | | | 300 | | | | (4.0 | ) |
| 2014 | | | 3.39% | | | | 300 | | | | (0.8 | ) |
| | | | | | | | | | | $ | (20.1 | ) |
We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are deferred in OCI until the interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account our interest rate swaps, would increase our annual interest expense by $4.7 million.
Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
As of December 31, 2010, affiliates of Barclays, Credit Suisse and British Petroleum (“BP”) accounted for 62%, 13% and 12% of our counterparty credit exposure related to commodity derivative instruments. Barclays, and Credit Suisse are major financial institutions and BP is a major oil and gas company. These entities possess investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.
Item 8. Financial Statements and Supplementary Data
Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of this Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Disclosure Controls and Procedures
Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(3) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this annual report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered in this annual report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted und er the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a) Management’s Report on Internal Control Over Financial Reporting
The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). The general partner’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the general partner’s management concluded that our internal control over financial reporting was effective as of December 31, 2010 as stated in its report included in our consolidated financial statements on page F-2 of this Annual Report, which is incorporated herein by reference.
The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included in our Consolidated Financial Statements on page F-3 of this Annual Report, which is incorporated herein by reference.
(b) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2010, there were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.
None
Part III
Item 10. Directors, Executive Officers and Corporate Governance
We are a limited partnership and, therefore, have no officers or directors. Unless otherwise indicated, references to officers and directors of the Partnership in Items 10-14 of this Annual Report refer to the officers and directors of our general partner.
Management of Targa Resources Partners LP
Targa Resources GP LLC, our general partner, manages our operations and activities. Our general partner is not currently elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes fiduciary duties to our unitholders, but our partnership agreement contains various provisions modifying and restricting its fiduciary duties. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
The directors of our general partner oversee our operations. Our general partner currently has seven directors. TRI Resources, Inc. (“TRI”) elects all members to the board of directors of our general partner (the “Board”) and our general partner has three directors that are independent as defined under the independence standards established by the New York Stock Exchange (the “NYSE”). The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating/corporate governance committee.
The Board has a standing audit committee (the “Audit Committee”) that consists of three directors. Messrs. Robert B. Evans, Barry R. Pearl and William D. Sullivan serve as the members of the Audit Committee. The Board has affirmatively determined that Messrs. Evans, Pearl and Sullivan are independent as described in the rules of the NYSE and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The Board has also determined that, based upon relevant experience, Audit Committee member Barry R. Pearl is an “audit committee financial expert” as defined in Item 407 of Regulation S-K of the Exchange Act. Mr. Pearl serves as the Chairman of the Audit Committee. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and ou r compliance with legal and regulatory requirements and partnership policies and controls. The Audit Committee has sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the Audit Committee.
The compensation of our general partner’s executive officers is set by Targa, the indirect parent of our general partner, with the Board playing no role in the process. Compensation decisions relating to oversight of the long-term incentive plan described below, however, are made by the Board. While the Board may establish a compensation committee in the future, it has no current plans to do so.
The Board has a standing conflicts committee (the “Conflicts Committee”) to review specific matters that the Board believes may involve conflicts of interest. Messrs. Evans, Pearl and Sullivan serve as the members of the Conflicts Committee. Mr. Pearl serves as the Chairman of the Conflicts Committee. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors and certain other requirements. Any matters approved by the Conflicts Committee in good faith will be conc lusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
All of our executive management personnel are employees of Targa Resources LLC (“Targa Resources”), a wholly-owned subsidiary of Targa, and devote their time as needed to conduct our and Targa’s business and affairs. These officers of Targa Resources manage the day-to-day affairs of our business. Because Targa’s only cash generating assets are direct and indirect partnership interests in us, we expect that our executive officers will devote a substantially majority of their time to our business, as was the case in 2010. We expect the amount of time that the executive management personnel of our general partner devote to our business in future periods to be driven by the needs and demands of our ongoing business and business development efforts, which are likely to increase as our asset base and operations increa se in size. However, depending on how our business develops and the nature of the business development efforts by executive management, the amount of time that the executive management team of our general partner devotes to our business may increase or decrease in future periods. We also utilize a significant number of employees of Targa Resources to operate our business and provide us with general and administrative services. We reimburse Targa for allocated expenses of operational personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses. See “Reimbursement of Expenses of Our General Partner” included in this Item 10.
Directors, Executive Officers and Other Officers
Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are not family relationships among any of our general partner’s directors of executive officers. The following table shows information regarding the current directors, executive officers and certain significant employees of Targa Resources GP LLC as of February 25, 2011:
| Name | | Age | | Position With Targa Resources GP LLC |
| Rene R. Joyce | | 63 | | Chief Executive Officer and Director |
| Joe Bob Perkins | | 50 | | President |
| James W. Whalen | | 69 | | Executive Chairman of the Board |
| Roy E. Johnson | | 66 | | Executive Vice President |
| Michael A. Heim | | 62 | | Executive Vice President and Chief Operating Officer |
| Jeffrey J. McParland | | 56 | | President - Finance and Administration |
| Paul W. Chung | | 50 | | Executive Vice President, General Counsel and Secretary |
| Matthew J. Meloy | | 33 | | Senior Vice President, Chief Financial Officer and Treasurer |
| John R. Sparger | | 57 | | Senior Vice President and Chief Accounting Officer |
| Peter R. Kagan | | 42 | | Director |
| In Seon Hwang | | 34 | | Director |
| Robert B. Evans | | 62 | | Director |
| Barry R. Pearl | | 61 | | Director |
| William D. Sullivan | | 54 | | Director |
Rene R. Joyce has served as a director and Chief Executive Officer of our general partner since October 2006, of Targa since its formation in October 2005 and of TRI since its formation in February 2004 and was a consultant for the TRI predecessor company during 2003. He is also a member of the supervisory directors of Core Laboratories N.V. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell Oil Company (“Shell”) from 1998 through 1999 and President of energy services of Coral Energy Holding, L.P. (“Coral”) a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Teja s Gas Corporation (“Tejas”) during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas was acquired by Shell. As the founding Chief Executive Officer of Targa, Mr. Joyce brings deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as relationships with chief executives and other senior management at peer companies, customers and other oil and natural gas companies throughout the world. His experience and industry knowledge, complemented by an engineering and legal educational background, enable Mr. Joyce to provide the board with executive counsel on the full range of business, technical, and professional matters.
Joe Bob Perkins has served as President of our general partner since October 2006, of Targa since its formation in October 2005 and of TRI since February 2004 and was a consultant for the TRI predecessor company during 2003. Mr. Perkins also served as a consultant in the energy industry from 2002 through 2003 and was an active partner in RTM Media (an outdoor advertising firm) during such time period. Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group and Power Generation Group of Reliant Resources, Inc. and its parent/predecessor companies, from 1998 to 2002 and Vice President, Corporate Planning and Development of Houston Industries from 1996 to 1998. He served as Vice President, Business Development, of Coral fro m 1995 to 1996 and as Director, Business Development, of Tejas from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm of McKinsey & Company and with an exploration and production company.
James W. Whalen has served as Executive Chairman of the Board of our general partner since December 15, 2010 and of Targa and TRI since October 2010. Mr. Whalen has served as a director of our general partner since February 2007, of Targa since its formation in October 2005 and of TRI since May 2004. Mr. Whalen served as President – Finance and Administration of our general partner between October 2006 and December 2010 and of Targa and TRI between January 2006 and October 2010. Also, since November 2005, Mr. Whalen has served as President—Finance and Administration for various TRI subsidiaries. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of Parker Drilling Company. Between January 2002 a nd October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. He served as Chief Commercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen brings a breadth and depth of experience as an executive, board member, and audit committee member across several different companies and in energy and other industry areas. His valuable management and financial expertise includes an understanding of the accounting and financial matters that we and our industry address on a regular basis.
Roy E. Johnson has served as Executive Vice President of our general partner since October 2006, of Targa since October 2005 and of TRI since April 2004 and was a consultant for the TRI predecessor company during 2003. Mr. Johnson also served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. He served as Vice President, Business Development and President of the International Group of Tejas from 1995 to 2000. In these positions, he was responsible for acquisitions, pipeline expansion and development projects in North and South America. Mr. Johnson served as President of Louisiana Resources Company, a company engaged in intrastate natural gas t ransmission, from 1992 to 1995. Prior to 1992, Mr. Johnson held various positions with a number of different companies in the upstream and downstream energy industry.
Michael A. Heim has served as Executive Vice President and Chief Operating Officer of our general partner since October 2006, of Targa since October 2005 and of TRI since April 2004 and was a consultant for the TRI predecessor company during 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal Field Services, a subsidiary of The Coastal Corp. (“Coastal”), a diversified energy company, from 1997 to 2001 and President of Coastal States Gas Transmission Company from 1997 to 2001. In these positions, he was responsible for Coasta l’s midstream gathering, processing and marketing businesses. Prior to 1997, he served as an officer of several other Coastal exploration and production, marketing and midstream subsidiaries.
Jeffrey J. McParland has served as President – Finance and Administration of our general partner since December 15, 2010 and of Targa and TRI since October 2010. Mr. McParland has also served as director of TRI since December 16, 2010. He was an Executive Vice President and Chief Financial Officer of our general partner from October 2006 to December 15, 2010, of Targa from October 2005 to October 2010 and of TRI from April 2004 to October 2010 and was a consultant for the TRI predecessor company during 2003. He served as a director of our general partner from October 2006 to February 2007. Mr. McParland served as Treasurer of our general partner from October 2006 until May 2007, of Targa from October 2005 to May 2007 and of TRI from April 2004 until May 2007. Mr. McParland served as Secretary of TRI between February 2004 and May 2004, at which time he was elected as Assistant Secretary. Mr. McParland served as Senior Vice President, Finance, of Dynegy Inc., a company engaged in power generation, the midstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operations activities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generation and engineering and construction industries.
Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of our general partner since October 2006, of Targa since October 2005 and of TRI since May 2004. Mr. Chung served as Executive Vice President and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell, from 2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies, including the law firm of Vinson & Elkins L.L.P.
Matthew J. Meloy has served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since December 15, 2010 and of Targa since October 2010. Mr. Meloy served as Vice President – Finance and Treasurer of our general partner between March 2008 and December 2010, of Targa between March 2008 and October 2010 and of TRI between April 2008 and October 2010. He also served as Director, Corporate Development, of Targa and TRI between March 2006 and March 2008 and of our general partner between October 2006 and March 2008. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most recently serving as Assistant Vice President.
John R. Sparger has served as Senior Vice President and Chief Accounting Officer of our general partner since October 2006 and of Targa and TRI since January 2006. Mr. Sparger served as Vice President, Internal Audit of our general partner and Targa between October 2005 and January 2006 and of TRI between November 2004 and January 2006. Mr. Sparger served as a consultant in the energy industry from 2002 through September 2004, including TRI between February 2004 and September 2004, providing advice to various energy companies and entities regarding processes, systems, accounting and internal controls. Prior to 2002, he worked in various accounting and administrative positions with companies in the energy industry, audit and consulting positions in public accounting and consulting positions with a large international consulting firm.
Peter R. Kagan has served as a director of our general partner since February 2007 of Targa since October 2005 and of TRI between February 2004 and December 16, 2010. Mr. Kagan is a Managing Director of Warburg Pincus LLC and a general partner of Warburg Pincus & Co., where he has been employed since 1997 and became a partner of Warburg Pincus & Co. in 2002. He is also a member of Warburg Pincus’ Executive Management Group. He is also a director of Antero Resources Corporation, Broad Oak Energy, Inc. (“Broad Oak”), Canbriam Energy, Fairfield Energy Limited, Laredo Petroleum and MEG Energy Corp. Mr. Kagan serves as a director because certain investment funds managed by Warburg Pincus LLC, for whom Mr. Kagan is a managing director and member, initially con trolled us through their ownership of securities in Targa. Mr. Kagan has significant experience with energy companies and investments and broad familiarity with the industry and related transactions and capital markets activity, which enhance his contributions to the board.
In Seon Hwang has served as a director of the Company since May 2006 and of Targa between May 2006 and December 16, 2010. Mr. Hwang is a Member and Managing Director of Warburg Pincus LLC and a general partner of Warburg Pincus & Co., where he has been employed since 2004, and became a partner of Warburg Pincus & Co. in 2009. Prior to joining Warburg Pincus, Mr. Hwang worked at GSC Partners, a distressed investment firm, from 2002 until 2004, the M&A group at Goldman Sachs from 1998 to 2000, and the Boston Consulting Group from 1997 to 1998. He is also a director of Competitive Power Ventures and serves on the investment committee of Sheridan Production Partners LLC. Mr. Hwang serves as a director because certain investment funds managed by Warburg Pincus LLC, for who m Mr. Hwang is a managing director and member, control us through their ownership of securities in Targa Resources Corp. Mr. Hwang has significant experience with energy companies and investments and broad familiarity with the industry and related transactions and capital markets activity, which enhance his contributions to the board of directors.
Robert B. Evans has served as a director of our general partner since February 2007. Mr. Evans is also a director of New Jersey Resources Corporation. Mr. Evans was the President and Chief Executive Officer of Duke Energy Americas, a business unit of Duke Energy Corp., from January 2004 until his retirement in March 2006. Mr. Evans served as the transition executive for Energy Services, a business unit of Duke Energy, during 2003. Mr. Evans also served as President of Duke Energy Gas Transmission beginning in 1998 and was named President and Chief Executive Officer in 2002. Prior to his employment at Duke Energy, Mr. Evans served as Vice President of marketing and regulatory affairs for Texas Eastern Transmission and Algonquin Gas Transmission from 1996 to 1998. Mr. Evans’ extensive experience in the gas transmission and energy services sectors enhances the knowledge of the board in these areas of the oil and gas industry. As a former President and CEO of various operating companies, his breadth of executive experiences is applicable to many of the matters routinely facing us.
Barry R. Pearl has served as a director of our general partner since February 2007. Mr. Pearl is Executive Vice President of Kealine LLC (and its WesPac Energy LLC affiliate), a private developer and operator of petroleum infrastructure facilities and is a director of Kayne Anderson Energy Development Company, Kayne Anderson Midstream/Energy Fund and Magellan Midstream Holdings, L.P., the general partner of Magellan Midstream Partners, L.P. Mr. Pearl served as President and Chief Executive Officer of TEPPCO Partners from May 2002 until December 2005 and as President and Chief Operating Officer from February 2001 through April 2002. Mr. Pearl served as Vice President of Finance and Chief Financial Officer of Maverick Tube Corporation from June 1998 until December 2000. From 1984 t o 1998, Mr. Pearl was Vice President of Operations, Senior Vice President of business development and planning and Senior Vice President and Chief Financial Officer of Santa Fe Pacific Pipeline Partners, L.P. Mr. Pearl’s board and executive experience across energy related companies including other MLPs enable him to make broad contributions to the issues and opportunities that we face. His industry, financial and executive experiences enable him to make valuable contributions to our audit and conflicts committees.
William D. Sullivan has served as a director of our general partner since February 2007. Mr. Sullivan is a director of SM Energy Company, where he serves as a non-executive Chairman of the Board. Mr. Sullivan is also a director of Legacy Reserves GP, LLC and Tetra Technologies, Inc. Mr. Sullivan served as President and Chief Executive Officer of Leor Energy LP from June 15, 2005 to August 5, 2005. Between 1981 and August 2003, Mr. Sullivan was employed in various capacities by Anadarko Petroleum Corporation, including serving as Executive Vice President, Exploration and Production between August 2001 and August 2003. Since Mr. Sullivan’s departure from Anadarko Petroleum Corporation in August 2003, he has served on various private energy company boards. Mr. Sullivan’s extensive experience in the exploration and production sector enhances the knowledge of the board in this particular area of the oil and gas industry. As a former exploration and production operating officer with responsibilities over significant gas gathering, compression and processing operations, his experience is valuable to the board’s understanding of one of our most important customer types and contributes to other matters routinely facing us.
Reimbursement of Expenses of Our General Partner
Under the terms of the Second Amended and Restated Omnibus Agreement (the “Omnibus Agreement”), we reimburse Targa for the payment of certain operating and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. Pursuant to these arrangements, Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits. Our general partner determines the amount of general and administrative expenses to be allocated to us in accordance with our partnership agreement. Since October 1, 2010, after the final conveyance of assets to us by Targa, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, other than Targa’s direct costs of being a separate reporting company.
During the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011, Targa will provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at a distribution level of $0.5175 per limited partner unit, subject to maximum support of $8.0 million in any quarter.
Corporate Governance
Codes of Business Conduct and Ethics
Our general partner has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all other senior financial and accounting officers of our general partner, and Targa’s Code of Conduct (the “Code of Conduct”), which applies to officers, directors and employees of Targa and its subsidiaries, including our general partner. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to or waiver from, any provision of the Code of Ethics or Code of Conduct under Item 5.05 of a current report on Form 8-K.
Available Information
We make available, free of charge within the “Corporate Governance” section of our website at www.targaresources.com and in print to any unitholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct and the Audit Committee Charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Partners LP, 1000 Louisiana, Suite 4300, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to, our internet website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Executive Sessions of Non-Management Directors
Our non-management directors meet in executive session without management participation at regularly scheduled executive sessions. These meetings are chaired by Mr. Peter Kagan.
Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Partners LP, 1000 Louisiana, Suite 4300, Houston, Texas 77002.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% unitholders to file with the SEC reports of ownership and changes in ownership of our equity securities. Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certifications from our directors and executive officers, we believe that during 2010, all of our directors, executive officers and beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements applicable to them.
Executive Compensation
Compensation Discussion and Analysis
The following discussion and analysis contains statements regarding our and our executive officers’ future performance targets and goals. These targets and goals are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.
Overview
Neither we nor our general partner directly employ any of the persons responsible for managing our business. Any compensation decisions that are required to be made by our general partner will be made by the Board, which does not have a compensation committee. All of our general partner’s executive officers are employees of Targa Resources LLC. We reimburse Targa and its affiliates for the compensation of our general partner’s executive officers pursuant to the terms of, and subject to the limitations contained in, the Omnibus Agreement.
Targa has ultimate decision making authority with respect to the compensation of our general partner’s executive officers identified in the Summary Compensation Table (“named executive officers”). Prior to Targa’s initial public offering (the “IPO”) in December 2010, under the terms of its Amended and Restated Stockholders’ Agreement, as amended (the “Stockholders’ Agreement”), that was in effect until the closing of the IPO, compensatory arrangements with Targa’s named executive officers, who are also our general partner’s named executive officers, were required to be submitted to a vote of Targa’s stockholders unless such arrangements were approved by the compensation committee (the “Compensation Committee”) of Targa’s board of directors. As such, the Compensation Committee was responsible for overseeing the development of an executive compensation philosophy, strategy, framework and individual compensation elements for our general partner’s named executive officers that were based on Targa’s business priorities. The Stockholders’ Agreement terminated upon completion of the IPO. Compensatory arrangements with our general partner’s named executive officers remain the responsibility of the Compensation Committee.
The following Compensation Discussion and Analysis describes the material elements of compensation for our general partner’s named executive officers as determined by the Compensation Committee and is presented from the perspective of our general partner’s named executive officers in their roles as officers of Targa. These elements and the Compensation Committee’s decisions with respect to determinations on payments are not subject to approval by the Board or the board of directors of Targa (the “Targa Board”). Certain members of the Board are members of the Targa Board, including the Compensation Committee. Messrs. Pearl, Evans and Sullivan, each a director of our general partner, were observers at Compensation Committee meetings in 2010. As used in this Compensation Discussion and Analysis (other th an in this overview), references to “our,” “we,” “us,” the “Company” and similar terms refer to Targa.
Compensation Philosophy
The Compensation Committee believes that total compensation of executives should be competitive with the market in which we compete for executive talent which encompasses not only midstream natural gas companies, but also other energy industry companies as described in “The Role of Peer Groups and Benchmarking” below. The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:
| | • | provide a competitive total compensation program that enables us to attract and retain key executives; |
| | • | ensure an alignment between our strategic and financial performance and the total compensation received by our named executive officers; |
| | • | provide compensation for performance that reflects individual and company performance both in absolute terms and relative to our peer group; |
| | • | ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable, compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders; and |
| | • | ensure that our total compensation program supports our business objectives and priorities. |
Consistent with this philosophy and compensation objectives, we do not pay for perquisites for any of our named executive officers, other than parking subsidies.
The Role of Peer Groups and Benchmarking
Our Chief Executive Officer (the “CEO”), President and President — Finance and Administration (collectively, “Senior Management”) review compensation practices at peer companies, as well as broader industry compensation practices, at a general level and by individual position to ensure that our total compensation is reasonably comparable to industry practice and meets our compensation objectives. In addition, when evaluating compensation levels for each named executive officer, the Compensation Committee reviews publicly available compensation data for executives in our peer group, compensation surveys and compensation levels for each named executive officer with respect to their roles and levels of responsibility, accountability and decision-making authority. Although Senior Management and the Compensation Committee consider compensation data from other companies, they do not attempt to set compensation components to meet specific benchmarks, such as salaries “above the median” or total compensation “at the 50th percentile.” The peer company data that is reviewed by Senior Management and the Compensation Committee is simply one factor out of many that is used in connection with the establishment of the compensation for our officers. The other factors considered by Senior Management and the Compensation Committee include, but are not limited to, (i) available compensation data about rankings and comparisons, (ii) effort and accomplishment on a group basis, (iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team and (vi) the perception of both the Targa Board and the Compensation Committee of performance relative to expectations, actual market/business conditions and peer company performance. All of these factors, including peer company data, are utilized in a subjective assessment of each year’s decisions relating to annual cash incentives, long-term incentives and base compensation changes with a view towards total compensation and pay-for-performance.
As part of the annual review process conducted in 2009 for 2010 compensation, Senior Management identified peer companies in the midstream energy industry and reviewed compensation information filed by the peer companies with the SEC. The peer group reviewed by Senior Management and the Compensation Committee for 2010 consisted of the following companies: Atlas Pipeline Partners, L.P., Copano Energy L.L.C., Crosstex Energy, L.P., DCP Midstream Partners LP, Enbridge Energy Partners LP, Energy Transfer Partners, LP, Magellan Midstream Partners LP, MarkWest Energy Partners, LP, Martin Midstream Partners, NuStar Energy, ONEOK Partners, LP, Plains All American Pipeline Partners, LP, Regency Energy Partners LP, TEPPCO Partners and Williams Partners LP. During the second quarter of 2010, following its initial review rela ting to 2010 compensation, the Compensation Committee engaged BDO USA, LLP (“BDO”), a compensation consultant, to conduct a new review of executive and key employee compensation to help it assure that compensation goals were being met and that the most recent trends in compensation were appropriately considered. In this additional review process, the peer companies were reassessed to determine whether the peer groups for long-term cash incentive awards (performance units) and for compensation comparison and analysis remained appropriate and adequately reflected the market for executive talent. As a result, the peer group used for long-term cash incentive awards and for compensation comparison was expanded and weighted to include energy companies other than midstream master limited partnerships (“MLPs”) to better reflect the market for executive talent in the energy industry. Because many companies in the expanded peer group are larger than the Company as measured by market capitalization and total assets, with the assistance of BDO, compensation data for the peer companies was analyzed using multiple regression analysis to develop a prediction of the total compensation that peer companies of comparable size to the Company would offer similarly-situated executives. This regressed data was then weighted as follows to develop a reference point for judging the adequacy of executive pay at the Company: MLPs (given a 70% weighting), exploration and production companies (“E&Ps”) (given a 15% weighting) and utility companies (given a 15% weighting). The peer group companies in each of the three categories are:
| | • | MLP peer companies: Atlas Pipeline Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, LP, DCP Midstream Partners, LP, Enbridge Energy Partners LP, Energy Transfer Partners, LP, Enterprise Products Partners LP, Magellan Midstream Partners, LP, MarkWest Energy Partners, LP, NuStar Energy LP, ONEOK Partners, LP, Regency Energy Partners LP and Williams Partners LP |
| | • | E&P peer companies: Cabot Oil & Gas Corp., Cimarex Energy Co., Denbury Resources Inc., EOG Resources Inc., Murphy Oil Corp., Newfield Exploration Co., Noble Energy Inc., Penn Virginia Corp., Petrohawk Energy Corp., Pioneer Natural Resources Co., Southwestern Energy Co. and Ultra Petroleum Corp. |
| | • | Utility peer companies: Centerpoint Energy Inc., El Paso Corp., Enbridge Inc., EQT Corp., National Fuel Gas Co., NiSource Inc., ONEOK Inc., Questar Corp., Sempra Energy, Spectra Energy Co., Southern Union Co. and Williams Companies Inc. |
Senior Management and the Compensation Committee review our compensation practices and performance against peer companies on at least an annual basis.
Role of Senior Management in Establishing Compensation for Named Executive Officers
Typically, Senior Management consults with BDO, the compensation consultant engaged by the Compensation Committee, and reviews market data to determine relevant compensation levels and compensation program elements. Based on these consultations and a review of publicly available information for the peer group, Senior Management submits emerging conclusions and later a proposal to the chairman of the Compensation Committee. The proposal includes a recommendation of base salary, annual bonus and any new long-term compensation to be paid or awarded to executive officers and employees. The chairman of the Compensation Committee reviews and discusses the proposal with Senior Management and the consultant and may discuss it with the other members of the Compensation Committee, other board members, or the full boards of the Company and the Ge neral Partner and may request that Senior Management provide him with additional information or reconsider their proposal. The resulting recommendation is then submitted to the Compensation Committee for consideration, which also meets separately with the compensation consultant. The final compensation decisions are reported to the Targa Board.
Our Senior Management has no other role in determining compensation for our named executive officers, but our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.
Elements of Compensation for Named Executive Officers
Our compensation philosophy for executive officers emphasizes our executives having a significant long-term equity stake. For this reason, in connection with TRI Resources Inc.’s formation in 2004 and with our acquisition of Dynegy Midstream Services, Limited Partnership from Dynegy, Inc. in 2005, the named executive officers were granted restricted stock and options to purchase restricted stock to attract, motivate and retain our executive team. In connection with the IPO, the named executive officers were granted additional shares of bonus stock as an additional recognition for past performance and positioning to this point in time and restricted stock as one-time retention and incentive awards in connection with our transition from a private to a public company. Both of these equity awards align our executive office rs interests with those of stockholders. Our executive officers have also invested a significant portion of their personal investable assets in our equity and have made significant investments in the equity of the Partnership. With these equity interests as context, elements of compensation for our named executive officers are the following: (i) annual base salary; (ii) discretionary annual cash awards; (iii) performance awards under our long-term incentive plan, (iv) awards under our new stock incentive plan; (v) contributions under our 401(k) and profit sharing plan; and (vi) participation in our health and welfare plans on the same basis as all of our other employees.
Base Salary. The base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. The salaries are intended to provide fixed compensation based on historical salaries paid to our named executive officers for services rendered to us, market data on compensation paid to similarly situated executives and responsibilities and performance of our named executive officers.
Annual Cash Incentives. The discretionary annual cash awards available to our named executive officers provide an opportunity to supplement the annual base salary of our named executive officers so that, on a combined basis, the annual cash compensation opportunity for our named executive officers yields competitive cash compensation levels and drives performance in support of our business strategies. It is our general policy to pay these awards prior to the end of the first quarter of the fiscal year following the fiscal year to which they related. The payment of individual cash bonuses to executive management, including our named executive officers, is subject to the sole discretion of the Compensation Committee.
The discretionary annual cash awards are designed to reward our employees for contributions towards our achievement of financial and operational business priorities (including business priorities of the Partnership) approved by the Compensation Committee and to aid us in retaining and motivating employees. These priorities are not objective in nature—they are subjective and performance in regard to these priorities is ultimately evaluated by the Compensation Committee in its sole discretion. The approach taken by the Compensation Committee in reviewing performance against the priorities is along the lines of grading a multi-faceted essay rather than a simple true/false exam. As such, success does not depend on achieving a particular target; rather, success is determined based on past norms, expectations and unanticipated obstacle s or opportunities that arise. For example, hurricanes and deteriorating market conditions may alter the priorities initially established by the Compensation Committee such that certain performance that would otherwise be deemed a negative may, in context, be a positive result. This subjectivity allows the Compensation Committee to account for the full industry and economic context of our actual performance or that of our personnel. The Compensation Committee considers all strategic priorities and reviews performance against the priorities but does not assign specific weightings to the strategic priorities in advance.
Under plans to pay a discretionary annual cash award that have been adopted and may be adopted in subsequent years, funding of a discretionary cash bonus pool is expected to be recommended by our Senior Management and approved by the Compensation Committee annually based on our achievement of certain strategic, financial and operational objectives. Such plans are and will be approved by the Compensation Committee, which considers certain recommendations by our Senior Management. Near or following the end of each year, Senior Management recommends to the Compensation Committee the total amount of cash to be allocated to the bonus pool based upon our overall performance relative to these objectives. Upon receipt of our Senior Management’s recommendation, the Compensation Committee, in its sole discretion, determines the total amoun t of cash to be allocated to the bonus pool. Additionally, the Compensation Committee, in its sole discretion, determines the amount of the cash bonus award to each of our executive officers, including the CEO. The executive officers determine the amount of the cash bonus pool to be allocated to our departments, groups and employees (other than our executive officers) based on performance and on the recommendation of their supervisors, managers and line officers.
Stock Option Grants. Under our 2005 Stock Incentive Plan, as amended (the “2005 Incentive Plan”), incentive stock options and non-incentive stock options to purchase, in the aggregate, up to 2,536,969 shares of our restricted stock may be granted to our employees, directors and consultants. No option awards have been granted to the named executive officers since 2005 under the 2005 Incentive Plan and option awards that were previously granted to our named executive officers under the 2005 Incentive Plan and that were outstanding upon the closing of the IPO were surrendered and cancelled. We will no longer make grants under the 2005 Incentive Plan.
Restricted Stock Grants. Under the 2005 Incentive Plan, up to 3,586,263 shares of our restricted stock may be granted to our employees, directors and consultants. No restricted stock awards have been granted to the named executive officers under the 2005 Stock Incentive Plan since 2005. We will no longer make grants under the 2005 Incentive Plan.
New Incentive Plan. In connection with the IPO, we adopted the 2010 Stock Incentive Plan (the “2010 Incentive Plan”) under which we may grant to the named executive officers, other key employees, consultants and directors certain awards, including restricted stock and performance awards. The 2010 Incentive Plan provides for discretionary grants of the following types of awards: (a) incentive stock options qualified as such under U.S. federal income tax laws, (b) stock options that do not qualify as incentive stock options, (c) phantom stock awards, (d) restricted stock awards, (e) performance awards, (f) bonus stock awards, or (g) any combination of such awards. The maximum aggregate number of shares of our common stock that may be granted in connection with awards under the 2010 Incentive Plan is 5 million, of which approximately 1.9 million shares were awarded in connection with our IPO. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, restrictions on transferability, and any other restrictions imposed by the Compensation Committee in its discretion. Except as otherwise provided under the terms of the 2010 Incentive Plan or an award agreement, the holder of a restricted stock award may have rights as a stockholder, including the right to vote or to receive dividends (subject to any mandatory reinvestment or other requirements imposed by the Compensation Committee). A restricted stock award that is subject to forfeiture restrictions may be forfeited and reacquired by us upon termination of employment or services. Common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, may be subject to the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was made. Bonus stock awards under the 2010 Incentive Plan are awards of our common stock. These awards are granted on such terms and conditions and at such purchase price (if any) determined by the Compensation Committee and need not be subject to performance criteria, objectives, or forfeiture. Additional details relating to shares of restricted stock and bonus stock granted under the 2010 Incentive Plan are included below under “—Application of Compensation Elements—Equity Ownership” and “—Executive Compensation Tables—Outstanding Equity Awards at 2010 Fiscal Year-End.”
LTIP Awards. We may grant to the named executive officers and other key employees performance unit awards linked to the performance of the Partnership’s common units, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. These awards, which may be settled in cash or equity, are designed to further align the interests of the named executive officers and other key employees with those of the Partnership’s equity holders. Additional details relating to our peer group applicable to LTIP awards payouts are included below under “—Application of Compensation Elements—Long-Term Cash Incentives.”
Retirement Benefits. We offer eligible employees a Section 401(k) tax-qualified, defined contribution plan (the “401(k) Plan”) to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our 401(k) Plan and may elect to defer up to 30% of their annual compensation on a pre-tax basis and have it contributed to the plan, subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “Code”). In addition, we make the following contributions to the 40 1(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employee’s eligible compensation; and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation. We may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance.
Health and Welfare Benefits. All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, health, life insurance and dental coverage and disability insurance.
Perquisites. We believe that the elements of executive compensation should be tied directly or indirectly to the actual performance of the Company. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than parking subsidies.
Relation of Compensation Elements to Compensation Philosophy
Our named executive officers, other senior managers and directors, through a combination of personal investment and equity grants, own approximately 6.2% of our fully diluted equity. Based on our named executive officers’ ownership interests in us and their direct ownership of the Partnership’s common units, they own, directly and indirectly, approximately 0.9% of the Partnership’s limited partner interests. The Compensation Committee believes that the elements of its compensation program fit the established overall compensation objectives in the context of management’s substantial ownership of our equity, which allows us to provide competitive compensation opportunities to align and drive the performance of the named executive officers in support of our and the Partnership’s business strategies and to att ract, motivate and retain high quality talent with the skills and competencies required by us and the Partnership.
Application of Compensation Elements
Equity Ownership. Historically, we have used both stock options and restricted stock to compensate our employees, including our named executive officers. Based on recommendations by our compensation consultant after completing the second quarter compensation review, we currently expect the Compensation Committee’s awards under the 2010 Incentive Plan to consist primarily of restricted stock and performance awards rather than stock options. In addition, we expect the Compensation Committee’s awards under our long term incentive plan to consist of performance based restricted stock and cash-settled performance units. In connection with the IPO, our employees, including the named exe cutive officers, were granted an aggregate of approximately 1.9 million shares of restricted stock and bonus stock under the 2010 Incentive Plan. Of these initial awards, our named executive officers were granted shares of restricted stock and bonus stock as follows: (i) with respect to restricted stock: Mr. Joyce—121,125 shares; Mr. Perkins—67,980 shares; Mr. Whalen—67,980 shares; Mr. Heim—60,885 shares; Mr. McParland—56,100 shares; and Mr. Meloy —22,425 shares and (ii) with respect to bonus stock: Mr. Joyce—122,439 shares; Mr. Perkins—106,200 shares; Mr. Whalen—106,200 shares; Mr. Heim—61,825 shares; and Mr. McParland—87,642 shares. The restricted stock awards have vesting restrictions. The restricted stock awards ((i) above) to executive officers and other key employees were made based upon the recommendation of BDO using market-based precedent and market-based amounts to provide a one-time retention and incentive award in connection with our transition from a private to a public company. The awards to the executive officers were established using a market-based multiple of 3X annual target long-term incentive compensation for each individual. BDO concluded that at the proposed 3X annual target long-term incentive level, the awards for executive management were of lesser value than grants awarded to senior executives in connection with other recent industry transactions over the last three years and that the value of the overall program available to executive officers would fall in a range between the 50th and 75th percentile of the expanded peer group over the next three years. The comparable transactions included the merger of Markwest Hydrocarbons with Markwest Energy Partners, L.P., the acquisition of the controlling interest of Buckeye GP Holding by BGHGP Holdings, LLC, the merger of Inergy L.P. and Inergy LP Holdings, the acquisition of Genesis Energy’s general partner from Denbury Resources by Quintana Energy Investor Group and transactions involving Precision Drilling, Apache, RRI Energy, Approach Resources, Concho Resources, Encore Energy Partners, and Vanguard Natural Resources. The bonus stock awards ((ii) above) were fully vested on the date of grant. Both of these awards are intended to align the interests of key employees (including our named executive officers) with those of our stockholders. Therefore, participants (including our named executive officers) did not pay any consideration for the common stock they received with respect to these awards, and we did not receive any cash remuneration for the common stock delivered with respect to these awards. Partially as a result of the overall award structure, our named executive officers, as well as all other holders, of outstanding out-of-the-money options that were granted under the 2005 Incentive Plan cancelled thos e options.
The Compensation Committee also made cash bonus awards to our executive officers, including our named executive officers, in connection with the IPO in the aggregate amount of $3 million. After the internal reallocation described below, the cash awards to our named executive officers were as follows: Mr. Heim—$732,000.
The bonus stock awards and the cash bonus awards were granted to the seven-person executive management team to provide (i) a higher “carry” of their equity interests and (ii) additional discretionary compensation, in each case in recognition of our executive management team’s efforts in bringing us to this point in our successful history. The initial allocation among the seven persons of the 1.9 million shares of discretionary bonus and restricted stock awards and $3 million cash bonus awarded to the executive team was initially based on the relative current base compensation of each individual. The Targa Board and the Compensation Committee allowed a voluntary reallocation of equity for cash among the members of the executive management group to accommodate individual preferences. The n amed executive officers, other than Mr. Heim, elected to exchange their portion of the cash bonus for additional equity and Mr. Heim and our two other executive officers elected to exchange some of their equity for larger shares of the cash bonus. The final allocation for the named executive officers is shown above. The amounts of restricted stock, bonus stock and cash bonus awards were determined pursuant to our compensation philosophy and the compensation review discussed above.
Base Salary. In 2010, base salaries for our named executive officers were established based on historical levels for these officers, taking into consideration officer salaries in our peer group and the value of the total compensation opportunities available to our executive officers including, in particular, the long-term equity component of our compensation program. As described above, the second quarter compensation review indicated that the compensation for our named executive officers was not consistent with compensation paid at MLP peer companies or with our expanded peer group generally when the data is adjusted for company size. In order to begin closing this gap in compensation, the Compensation Committee authorized the following increased base salaries for our named executive officers effective July 1, 2010.
| Rene R. Joyce | | $ | 475,000 | |
| Jeffrey J. McParland | | | 340,000 | |
| Joe Bob Perkins | | | 412,000 | |
| James W. Whalen | | | 412,000 | |
| Michael A. Heim | | | 369,000 | |
| Matthew J. Meloy | | | 207,500 | |
Annual Cash Incentives. The Compensation Committee approved our 2010 Annual Incentive Plan (the “Bonus Plan”) in February 2010 with the following nine key business priorities to be considered when making awards under the Bonus Plan: (i) continue to control all operating, capital and general and administrative costs, (ii) invest in our businesses primarily within existing cash flow, (iii) continue priority emphasis and strong performance relative to a safe workplace, (iv) reinforce business philosophy and mindset that promotes environmental and regulatory compliance, (v) continue to tightly manage the Downstream Business’ inventory exposure, (vi) execute on major capital and development projects, such as finalizing negotia tions, completing projects on time and on budget, and optimizing economics and capital funding, (vii) pursue selected opportunities, including new shale play gathering and processing build-outs, other fee-based capex projects and potential purchases of strategic assets, (viii) pursue commercial and financial approaches to achieve maximum value and manage risks, and (ix) execute on all business dimensions, including the financial business plan. The Compensation Committee also established the following overall threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100% for the target level and 200% for the maximum level. The CEO and the Compensation Committee relied on compensation consultants and market data from peer company and broader industry compensation practices to establish the threshold, target and maximum percentage levels, which are generally consistent with peer company and broader energy compensation p ractices. The cash bonus pool target amount is determined by summing, on an employee by employee basis, the product of base salaries and market-based target bonus percentages. The CEO and the Compensation Committee arrive at the total amount of cash to be allocated to the cash bonus pool by multiplying percentage of target awarded by the Compensation Committee by the total target cash bonus pool. The funding of the cash bonus pool and the payment of individual cash bonuses to executive management, including our named executive officers, are subject to the sole discretion of the Compensation Committee.
In February 2011, the Compensation Committee approved a cash bonus pool equal to 180% of the target level for the employee group, including our named executive officers, under the Bonus Plan for performance during 2010 in recognition of outstanding efforts and organizational performance. The Compensation Committee determined to pay these above target level bonuses because it considered overall performance, including organizational performance, to have substantially exceeded expectations in 2010 based on the nine key business priorities it established for 2010. The Compensation Committee considered or subjectively evaluated (rather than measured) organizational performance by reviewing the apparent overall performance of our personnel with respect to the initial and subsequent business priorities relative to both the overall and managem ent-specific performance expectations of the Compensation Committee, each on an absolute level and relative to the Compensation Committee’s sense of peer performance. This subjective assessment that performance substantially exceeded expectations was based on a qualitative evaluation rather than a mechanical, quantitative determination of results across each of the key business priorities. Aspects of performance important to this qualitative determination included (i) continued focus on cost control, including the completion of capital projects typically below budget, (ii) strong success investing in our businesses, (iii) proactive efforts to enhance safety and compliance with environmental and regulatory requirements, (iv) disciplined management of NGL inventory levels and related commodity price exposure, (v) success on transactions including project economics and project management, (vi) pursuing multiple opportunities to expand our downstream position and to add fee-based business, (vii) innovation in new gathering and processing commercial transactions and in securing significant volume guarantees in downstream contracting, (viii) exceeding the financial business plan, (ix) resolution of certain significant disputes and (x) completion of the dropdown of our businesses to the Partnership and clarification of strategic direction for our investors. This subjective evaluation that performance had substantially exceeded expectations occurred with the background and ongoing context of detailed board and committee refinements of the 2010 business priorities both before the beginning of and during the year, continued board and committee discussion and active dialogue with management about priorities in subsequent board and committee meetings, and further board and committee discussion of performance relative to expectations following the end of 2010. The extensive business and board experience of the Compensation Committee and of the T arga Board provide the perspective to make this subjective assessment in a qualitative manner to evaluate management performance overall and the performance of the executive officers. The named executive officers received the following bonus awards, which are equivalent to the same average percentage of target as the Company bonus pool:
| Rene R. Joyce | | $ | 855,000 | |
| Jeffrey J. McParland | | | 489,600 | |
| Joe Bob Perkins | | | 593,280 | |
| James W. Whalen | | | 593,280 | |
| Michael A. Heim | | | 531,360 | |
| Matthew J. Meloy | | | 224,100 | |
In addition to the cash bonus awards approved under the Bonus Plan, in February 2011, the Compensation Committee approved an aggregate cash bonus pool of $1.5 million for our executive officers and two other employees in recognition of their role in extraordinary execution of the business priorities, completion of drop downs to the Partnership and clarification of our strategic direction in 2010.
Long-term Cash Incentives. In January 2008 and 2009, we granted our executive officers cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in June of 2011 and 2012, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. The peer group companies for 2008 and 2009 were Energy Transfer Partners, ONEOK Partners, Copano, DCP Midstream, Regency Energy Partners, Plains All American Pipeline, MarkWest Energy Partners, Williams Energy Partners, Magellan Midstream, Martin Midstream, Enbridge Energy Partners, Crosstex and Targa Resources Partners LP. The Compensation Comm ittee has the ability to modify the peer-group in the event a peer company is no longer determined to be one of the Partnership’s peers. The cash settlement value of these performance unit awards will be the sum of the value of an equivalent Partnership common unit at the time of vesting plus associated distributions over the three year period multiplied by a performance vesting percentage which may be zero or range from 50% to 100%. This cash settlement value may be higher or lower than the Partnership common unit price at the time of the grant. If the Partnership’s performance equals or exceeds the performance for the median of the group, 100% of the award will vest. If the Partnership ranks tenth in the group, 50% of the award will vest, between tenth and seventh, 50% to 100% will vest based on an interpolated basis, and for a performance ranking lower than tenth, no amounts will vest. In January 2008, our named executive officers, who are also executive officers of the General Partner, receiv ed awards of performance units as follows: 4,000 performance units to Mr. Joyce, 2,700 performance units to Mr. McParland, 3,500 performance units to Mr. Perkins, 3,500 performance units to Mr. Whalen and 3,500 performance units to Mr. Heim. In August 2008, Mr. Meloy received an award of 1,500 performance units. In January 2009, the named executive officers received awards of performance units as follows: 34,000 performance units to Mr. Joyce, 15,500 performance units to Mr. McParland, 20,800 performance units to Mr. Perkins and 20,800 performance units to Mr. Heim. In August 2009, Mr. Meloy received an award of 7,500 performance units.
In addition to the January 2009 grants, in December 2009, our executive officers were awarded performance units under our long-term incentive plan for the 2010 compensation cycle that will vest in June 2013 as follows: 18,025 performance units to Mr. Joyce, 13,464 performance units to Mr. Whalen, 9,350 performance units to Mr. McParland, 13,860 performance units to Mr. Perkins and 9,894 performance units to Mr. Heim. In August 2010, Mr. Meloy received an award of 4,000 performance units. The cash settlement value of these performance unit awards will be the sum of the value of an equivalent Partnership common unit at the time of vesting plus associated distributions over the three year period multiplied by a performance vesting percentage which may be zero or range from 25% to 150%. This cash settlement value m ay be higher or lower than the Partnership common unit price at the time of the grant. If the Partnership’s performance equals or exceeds the performance for the 25th percentile of the group but is less than or equal to the 50th percentile of the group, then 25% to 100% of the award will vest. If the Partnership’s performance equals or exceeds the performance for the 50th percentile of the group but is less than or equal to the 75th percentile of the group, then 100% to 150% of the award will vest. The vesting between the 25th percentile and the 50th percentile will be done on an interpolated basis between 25% and 100% and the vesting between the 50th percentile and 75th percentile will be done on an interpolated basis between 100% and 150%. If the Partnership’s performance is above the performance of the 75th percentile of the group, the performance percentage will be 150% and all amounts will vest. If the Partnership’s performance is below the performance of the 25th& #160;percentile of the group, the performance percentage will be zero and no amounts will vest. The performance period for these performance unit awards began on June 30, 2010 and ends on the third anniversary of such date.
Set forth below is the “performance for the median” of the peer group for each of the 2008, 2009 and 2010 grants and a comparison of the Partnership’s performance to the peer group as of December 31, 2010:
| | | Performance (1) | | |
| | | Peer Group | | | | Partnership |
| Grant | | Median | | Partnership | | Position (2) |
| 2008 | | 43.5% | | 74.6% | | 1 of 13 |
| 2009 (January grants) | | 59.4% | | 100.6% | | 1 of 13 |
| 2009 (December grants) | | 16.8% | | 34.3% | | 100th percentile |
| 2010 | | 16.8% | | 34.3% | | 100th percentile |
__________
| (1) | Total return measured by (i) subtracting the average closing price per share/unit for the first ten trading days of the performance period (the “Beginning Price”) from the sum of (a) the average closing price per share/unit for the last ten trading days ending on the date that is 15 days prior to the end of the performance period plus (b) the aggregate amount of dividends/distributions paid with respect to a share/unit during such period (the result being referred to as the “Value Increase”) and (ii) dividing the Value Increase by the Beginning Price. The performance period for the 2008 and January 2009 awards begins on June 30, 2008 and June 30, 2009 while the December 2009 and 2010 awards begins on June 30, 2010, and all awards end on the third anniversary of such dates. |
| (2) | The Partnership’s position for the December 2009 and the 2010 grants is measured by the Partnership’s placement in a particular quartile rather than its specific rank against the peer group. |
Health and Welfare Benefits. For 2010, our named executive officers participated in our health and welfare benefit programs, including medical, health, life insurance, dental coverage and disability insurance, on the same basis as all of our other employees.
Perquisites. Consistent with our compensation philosophy, we did not pay for perquisites for any of our named executive officers during 2010, other than parking subsidies.
Changes for 2011
Base Salary. The 2010 increase in base pay for the key employees closed only approximately one-half of the gap in executive compensation highlighted by the review referred to above under “—The Role of Peer Groups and Benchmarking.” In order to begin closing this remaining gap in compensation, the Compensation Committee authorized and executive management will implement, the following increased base salaries for our named executive officers effective April 1, 2011:
| Rene R. Joyce | | $ | 547,000 | |
| Jeffrey J. McParland | | | 389,000 | |
| Joe Bob Perkins | | | 468,000 | |
| James W. Whalen | | | 468,000 | |
| Michael A. Heim | | | 415,000 | |
| Matthew J. Meloy | | | 235,000 | |
With this move in base salaries, the gap will be reduced by approximately one-half.
Annual Cash Incentives. In light of recent economic and financial events, Senior Management developed and proposed a set of strategic priorities to the Compensation Committee. In February 2011, the Compensation Committee approved our 2011 Annual Incentive Compensation Plan (the “2011 Bonus Plan”), the cash bonus plan for performance during 2011, and established the following eight key business priorities: (i) continue to control all operating, capital and general and administrative costs, (ii) invest in our businesses, (iii) continue priority emphasis and strong performance relative to a safe workplace, (iv) reinforce business philosophy and mindset that promotes compliance with all aspects of our business including environmental and reg ulatory compliance, (v) continue to manage tightly credit, inventory, interest rate and commodity price exposures, (vi) execute on major capital and development projects, such as finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding, (vii) pursue selected growth opportunities, including new gathering and processing build-outs leveraging our NGL logistics platform for development projects, other fee-based capex projects and potential purchases of strategic assets and (viii) execute on all business dimensions to maximize value and manage risks. The Compensation Committee also established the following overall threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100% for the target level and 200% for the maximum level. As with the Bonus Plan, funding of the cash bonus pool and the payment of individual cash bonuses to executive management, including ou r named executive officers, are subject to the sole discretion of the Compensation Committee. The market-based base salary bonus percentages for the named executive officers used in determining the annual cash incentives were increased in connection with the increases in base salary in 2010.
Long-term Incentives. On February 14, 2011, our named executive officers were awarded restricted common stock of the Company under our stock incentive plan for the 2011 compensation cycle that will vest in three years from the grant date as follows: 7,690 shares to Mr. Joyce, 4,250 shares to Mr. Perkins, 4,250 shares to Mr. Whalen, 3,770 shares to Mr. Heim, 3,540 shares to Mr. McParland, and 1,260 shares to Mr. Meloy.
On February 17, 2011, our named executive officers were awarded equity-settled performance units under the Partnership’s long-term incentive plan for the 2011 compensation cycle that will vest in June 2014 as follows: 21,110 performance units to Mr. Joyce, 11,690 performance units to Mr. Perkins, 11,690 performance units to Mr. Whalen, 10,360 performance units to Mr. Heim, 9,710 performance units to Mr. McParland, and 3,470 performance units to Mr. Meloy. The settlement value of these performance unit awards will be determined using the formula adopted for the performance unit awards granted in December 2009.
Compensation Committee Interlocks and Insider Participation
The Partnership’s general partner does not maintain a compensation committee. The following officers of the Partnership’s general partner participated in deliberations of Targa’s Compensation Committee concerning executive officer compensation during 2010: Messrs. Joyce and Perkins. See “Item 13. Certain Relationships and Related Transactions, and Director Independence” for a description of certain relationships and related-party transactions.
Compensation Committee Report
In fulfilling its oversight responsibilities, the Board has reviewed and discussed with management the compensation discussion and analysis contained in this Annual Report. Based on these reviews and discussions, the Board recommended that the compensation discussion and analysis be included in the Annual Report for the year ended December 31, 2010 for filing with the SEC.
The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that the company specifically incorporates it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.
Rene R. Joyce
James W. Whalen
Peter R. Kagan
In Seon Hwang
Robert B. Evans
Barry R. Pearl
William D. Sullivan
Executive Compensation Tables
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2010, 2009 and 2008. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
| | Summary Compensation Table for 2010 | |
| | | | | | | | | | Non-Equity | | | | | | | |
| | | | | | | Stock | | | Incentive Plan | | | All Other | | | | |
| | | | | | | Awards | | | Compensation | | | Compensation | | | Total | |
| Name | Year | | Salary | | | ($) (2) (3) | | | | (4) | | | | (5) | | | Compensation | |
| Rene R. Joyce | 2010 | | $ | 410,000 | | | $ | 2,664,750 | | | $ | 855,000 | | | $ | 22,410 | | | $ | 3,952,160 | |
| Chief Executive Officer | 2009 | | | 337,500 | | | | 1,398,946 | | | | 510,000 | | | | 20,187 | | | | 2,266,633 | |
| | 2008 | | | 322,500 | | | | 148,400 | | | | 247,500 | | | | 19,205 | | | | 737,605 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Jeffrey J. McParland (1) | 2010 | | | 305,500 | | | | 1,234,200 | | | | 489,600 | | | | 20,655 | | | | 2,049,955 | |
| President - Finance & | 2009 | | | 265,000 | | | | 683,450 | | | | 400,500 | | | | 20,061 | | | | 1,369,011 | |
| Administration | 2008 | | | 253,000 | | | | 110,170 | | | | 194,250 | | | | 19,031 | | | | 576,451 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Joe Bob Perkins | 2010 | | | 361,250 | | | | 1,495,560 | | | | 593,280 | | | | 20,448 | | | | 2,470,538 | |
| President | 2009 | | | 303,750 | | | | 970,109 | | | | 459,000 | | | | 20,129 | | | | 1,752,988 | |
| | 2008 | | | 290,250 | | | | 129,850 | | | | 222,750 | | | | 19,124 | | | | 661,974 | |
| | | | | | | | | | | | | | | | | | | | | | |
| James W. Whalen (1) | 2010 | | | 356,750 | | | | 1,495,560 | | | | 593,280 | | | | 22,328 | | | | 2,467,918 | |
| Executive Chairman of the | 2009 | | | 297,000 | | | | 543,150 | | | | 445,500 | | | | 19,936 | | | | 1,305,586 | |
| Board | 2008 | | | 290,250 | | | | 129,850 | | | | 222,750 | | | | 18,871 | | | | 661,721 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Michael A. Heim | | | | | | | | | | | | | | | | | | | | | |
| Executive Vice President and | 2010 | | | 328,000 | | | | 1,339,470 | | | | 531,360 | | | | 21,776 | | | | 2,220,606 | |
| Chief Operating Officer | 2009 | | | 281,000 | | | | 810,117 | | | | 424,500 | | | | 20,089 | | | | 1,535,706 | |
| | 2008 | | | 268,750 | | | | 129,850 | | | | 206,250 | | | | 19,071 | | | | 623,921 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Matthew J. Meloy (1) | 2010 | | | 195,625 | | | | 493,350 | | | | 224,100 | | | | 19,740 | | | | 932,815 | |
| Senior Vice President, Chief | | | | | | | | | | | | | | | | | | | | | |
| Financial Officer and Treasurer | | | | | | | | | | | | | | | | | | | | | |
____________
| (1) | Mr. McParland became President, Finance and Administration in December 2010 and previously served as Executive Vice President and Chief Financial Officer. Mr. Whalen became Executive Chairman of the Board of Directors in December 2010 and previously served as President, Finance and Administration. Mr. Meloy was promoted to Senior Vice President and Chief Financial Officer in December 2010. Prior to his promotion, Mr. Meloy served as Vice President—Finance and Treasurer. |
| (2) | The Summary Compensation Table for 2010 does not reflect the following awards granted to the named executive officers by Targa Resources Corp. in connection with its initial public offering: (i) the grant date fair value of bonus stock approved on December 6, 2010 and granted on December 10, 2010 as follows: Mr. Joyce—$2,693,658; Mr. McParland—$1,928,124; Mr. Perkins—$2,336,400; Mr. Whalen—$2,336,400; and Mr. Heim—$1,360,150; (ii) a $732,000 cash bonus awarded on December [10], 2010 by Targa Resources Corp. to Mr. Heim in lieu of additional equity and (iii) the following cash bonuses: Mr. Joyce—$265,067; Mr. McParland—$189,732; Mr. Perkins—$229,911; and Mr. Heim—$205,915. The cost of these awards has not been, and will not be, allocated to the Partnership. Please see “Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Bonus Stock Awards” and “Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Annual Cash Incentives.” |
| (3) | The restricted stock awards in 2010 to executive officers were made based upon the recommendation of the compensation consultant using market-based precedent and market-based amounts to provide a one-time retention and incentive award in connection with our transition from a private to a public company. Please see “Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements.” Amounts represent the aggregate grant date fair value of awards computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note [12] to our Consolidated Financial Statements beginning on page F-1. Detailed information about the amount recognized for specific awards is reported in the table under “—Grants of Plan-Based Awards” below. The grant date fair value of a comm on stock award approved on December 6, 2010 and granted on December 10, 2010, assuming vesting will occur, is $22.00. |
| (4) | Amounts represent awards granted pursuant to our Bonus Plan. See the narrative to the section titled “—Grants of Plan-Based Awards” below for further information regarding these awards. |
| (5) | For 2010 “All Other Compensation” includes the (i) aggregate value of matching and non-matching contributions to our 401(k) plan and (ii) the dollar value of life insurance coverage provided by the Company. |
| | | 401(k) and Profit | | | Dollar Value of | | | | |
| Name | | Sharing Plan | | | Life Insurance | | | Total | |
| Rene R. Joyce | | $ | 19,600 | | | $ | 2,810 | | | $ | 22,410 | |
| Jeffrey J. McParland | | | 19,600 | | | | 1,304 | | | | 20,904 | |
| Joe Bob Perkins | | | 19,600 | | | | 848 | | | | 20,448 | |
| James W. Whalen | | | 19,600 | | | | 2,738 | | | | 22,338 | |
| Michael A. Heim | | | 19,600 | | | | 2,176 | | | | 21,776 | |
| Matthew J. Meloy | | | 19,600 | | | | 140 | | | | 19,740 | |
Grants of Plan Based Awards
The following table and the footnotes thereto provide information regarding grants of plan-based equity and non-equity awards made to the named executive officers during 2010:
| | | Grants of Plan Based Awards for 2010 | |
| | | | | | | Estimated Possible Payouts Under | | | All Other Stock | | | Grant Date Fair | |
| | | | | | | Non-Equity Incentive Plan Awards (1) | | | Awards: Number of | | | Value of | |
| | | Grant | | Approval | | | | | | | | | | | Shares of Stocks | | | Stock and | |
| Name | | Date | | Date | | Threshold | | | Target | | | 2X Target | | | or Units (2)(3) | | | Option Awards (3) | |
| Mr. Joyce | | | N/A | | | | $ | 237,500 | | | $ | 475,000 | | | $ | 950,000 | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 121,125 | | | $ | 2,644,750 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mr. McParland | | | N/A | | | | | 136,000 | | | | 272,000 | | | | 544,000 | | | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 56,100 | | | | 1,234,200 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mr. Perkins | | | N/A | | | | | 164,800 | | | | 329,000 | | | | 659,200 | | | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 67,980 | | | | 1,495,560 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mr. Whalen | | | N/A | | | | | 164,800 | | | | 329,600 | | | | 659,200 | | | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 67,980 | | | | 1,495,560 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mr. Heim | | | N/A | | | | | 147,600 | | | | 295,200 | | | | 590,400 | | | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 60,885 | | | | 1,339,470 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mr. Meloy | | | N/A | | | | | 41,500 | | | | 83,000 | | | | 166,000 | | | | | | | | | |
| | | 12/10/10 | | 12/06/10 | | | | | | | | | | | | | | | 22,425 | | | | 493,350 | |
| (1) | These awards were granted under the Bonus Plan. At the time the Bonus Plan was adopted, the estimated future payouts in the above table under the heading “Estimated Possible Payouts Under Non-Equity Incentive Plan Awards” represented the portion of the cash bonus pool available for awards to the named executive officers under the Bonus Plan based on the three performance levels. In February 2011, the Compensation Committee approved a bonus award for the named executive officers equal to 1.8x of the target. See “—Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Annual Cash Incentives.” |
| (2) | Represents restricted common stock awards that were granted under our 2010 Incentive Plan. The stock awards to executive officers were made based upon the recommendation of the compensation consultant using market-based precedent and market-based amounts to provide a one-time retention and incentive award in connection with our transition from a private to a public company. |
| (3) | The Grants of Plan Based Awards for 2010 table does not reflect the following awards granted to the named executive officers by Targa Resources Corp. in connection with its initial public offering: (i) bonus stock awards approved on December 6, 2010 and granted on December 10, 2010 as follows: Mr. Joyce—122,439 shares; Mr. McParland—87,642 shares; Mr. Perkins—106,200 shares; Mr. Whalen—106,200 shares; and Mr. Heim—61,825 shares; and (ii) the grant date fair value of such bonus stock as follows: Mr. Joyce—$2,693,658; Mr. McParland—$1,928,124; Mr. Perkins—$2,336,400; Mr. Whalen—$2,336,400; and Mr. Heim—$1,360,150. The cost of these awards has not been, and will not be, allocated to the Partnership. Please see “Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Bonus Stock Awards.” |
| (4) | The dollar amounts shown for the restricted common stock awards approved on December 6, 2010 and granted on December 10, 2010 are determined by multiplying the shares reported in the table by $22.00 (the grant date fair value of awards computed in accordance with FASB ASC Topic 718). |
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2010 salaries, bonuses, incentive plans and awards is included in “—Executive Compensation—Compensation Discussion and Analysis.”
2010 Stock Incentive Plan
Restricted Stock Awards. Subject to the terms of the applicable restricted stock agreement, restricted stock granted under the 2010 Incentive Plan during 2010 has a vesting period of two years from the date of grant (with respect to 60% of the shares awarded) and three years from the date of grant (with respect to 40% of the shares awarded). The named executive officers have all of the rights of a stockholder of the Company with respect to the restricted stock granted in 2010 including, without limitation, voting rights. The named executive officers do not have the right to receive any dividends or other distributions, including any special or extraordinary dividends or distributions, with respect to the restricted stock granted in 2010 unless and until the restricted stock vests. Dividends on unvested restricted stock are credited to an unfunded account maintained by the Company. These credited dividends are paid to the employee when the shares of restricted stock vest. In the event all or any portion of the restricted stock granted in 2010 fails to vest, such restricted stock and dividends will be forfeited to us.
Bonus Stock Awards. Bonus stock awarded in 2010 is not subject to any vesting or forfeiture provisions.
Please see “—Executive Compensation—Compensation Discussion and Analysis—Elements of Compensation for Named Executive Officers—New Incentive Plan” and “—Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Equity Ownership” for a detailed discussion of the grants of restricted stock and bonus stock.
Outstanding Equity Awards at 2010 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding each stock option and other equity-based awards outstanding as of December 31, 2010 for each of our named executive officers.
| | | Outstanding Equity Awards at 2010 Fiscal Year-End | |
| | | Stock Awards | |
| | | | | | | | | Equity Incentive Plan | | | Equity Incentive Plan | |
| | | Number of | | | Market Value | | | Awards: Number of | | | Awards: Market or | |
| | | Shares of | | | of Shares of | | | Unearned | | | Payout Value of | |
| | | Stock That | | | Stock That | | | Performance Units | | | Unearned Performance | |
| | | Have not | | | Have not | | | That have not | | | Units That have not | |
| Name | | Vested (1) | | | Vested (2) | | | Vested (3) | | | Vested (4) | |
| Rene R. Joyce | | | 121,125 | | | $ | 3,247,361 | | | | 56,025 | | | $ | 2,263,953 | |
| Jeffrey J. McParland | | | 56,100 | | | | 1,504,041 | | | | 27,550 | | | | 1,113,254 | |
| Joe Bob Perkins | | | 67,980 | | | | 1,822,544 | | | | 38,160 | | | | 1,542,127 | |
| James W. Whalen | | | 67,980 | | | | 1,822,544 | | | | 16,964 | | | | 686,185 | |
| Michael A. Heim | | | 60,885 | | | | 1,632,327 | | | | 34,194 | | | | 1,381,504 | |
| Matthew J. Meloy | | | 22,425 | | | | 601,214 | | | | 13,000 | | | | 525,233 | |
| (1) | Represents shares of our restricted common stock awarded on December 10, 2010. These shares vest as follows: 60% on December 10, 2012 and 40% on December 10, 2013. |
| (2) | The dollar amounts shown are determined by multiplying the number of shares of common stock reported in the table by the sum of the closing price of a share of common stock on December 31, 2010 ($26.81). |
| (3) | Represents the number of performance units awarded on January 17, 2008, January 22, 2009 and December 3, 2009 under our long-term incentive plan. With respect to Mr. Meloy, the performance units were granted on October 1, 2008, August 4, 2009 and August 2, 2010. These awards vest in June 2011, June 2012, and June 2013, based on the Partnership’s performance over the applicable period measured against a peer group of companies. These awards are discussed in more detail under the heading “—Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Long-Term Cash Incentives.” |
| (4) | The dollar amounts shown are determined by multiplying the number of performance units reported in the table by the sum of the closing price of a common unit of the Partnership on December 31, 2010 ($33.96) and the related distribution equivalent rights for each award and assume full payout under the awards at the time of vesting. |
Option Exercises and Stock Vested in 2010
The following table provides the amount realized during 2010 by each named executive officer upon the exercise of options and upon the vesting of our restricted common stock and performance units.
| | | Option Exercises and Stock Vested for 2010 | |
| | | Option Awards | | | Stock Awards | |
| | | Number of Shares | | | | | | Number of Shares | | | | |
| | | Acquired on | | | Value Realized | | | Acquired on | | | Value Realized | |
| Name | | Exercise (1) | | | on Exercise | | | Vesting (2) | | | on Vesting (3) | |
| Rene R. Joyce | | | 155,447 | | | $ | 459,957 | | | | 15,000 | | | $ | 499,406 | |
| Jeffrey J. McParland | | | 108,556 | | | | 324,555 | | | | 8,200 | | | | 273,009 | |
| Joe Bob Perkins | | | 117,241 | | | | 350,520 | | | | 10,800 | | | | 359,573 | |
| James W. Whalen | | | 45,158 | | | | 135,012 | | | | 10,800 | | | | 359,573 | |
| Michael A. Heim | | | 127,946 | | | | 377,735 | | | | 10,000 | | | | 332,938 | |
| Matthew J. Meloy | | | 15,942 | | | | 43,162 | | | | 3,000 | | | | 99,881 | |
____________
| (1) | At the time of exercise of the stock options, the common stock acquired upon exercise had a value of $3.46 per share. This value was determined by an independent consultant pursuant to a valuation of our common stock dated June 2, 2010. |
| (2) | Represents performance units granted in February 2007 that vested in August 2010 and were settled by cash payment. |
| (3) | Computed by multiplying the number of performance units by the value of an equivalent Partnership common unit at the time of vesting and adding associated distributions over the vesting period. |
Change in Control and Termination Benefits
2010 Incentive Plan. If a Change in Control (as defined below) occurs and the named executive officer has remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs, then the restricted stock granted to him under our form of restricted stock agreement (the “Stock Agreement”) and related dividends then credited to him will fully vest on the date upon which such Change in Control occurs.
Restricted stock granted to a named executive officer under the Stock Agreement and related dividends then credited to him will fully vest if his employment is terminated by reason of death or a Disability (as defined below). If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then his unvested restricted stock is forfeited to us for no consideration.
The following terms have the specified meanings for purposes of the 2010 Incentive Plan and Stock Agreement:
| · | Affiliate means any corporation, partnership (including the Partnership), limited liability company or partnership, association, trust, or other organization which, directly or indirectly, controls, is controlled by, or is under common control with, the Company. For purposes of the preceding sentence, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any entity or organization, shall mean the possession, directly or indirectly, of the power (i) to vote more than 50% of the securities having ordinary voting power for the election of directors of the controlled entity or organization or (ii) to direct or cause the direction of the management and policies of th e controlled entity or organization, whether through the ownership of voting securities or by contract or otherwise. |
| · | Change in Control means the occurrence of one of the following events: (i) any Person, including a “group” as contemplated by section 13(d)(3) of the Exchange Act (other than Warburg Pincus LLC or any other Affiliate), acquires or gains ownership or control (including, without limitation, the power to vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the outstanding shares of the Company’s voting stock (based upon voting power) or more than 50% of the combined voting power of the equity interests in the Partnership or the general partner of the Partnership; (ii) the completion of a liquidation or dissolution of the Company or the approval by the limited partners of the Partnership, in one or a series of transactions, of a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by the Company of all or substantially all of its assets in or more transactions to any Person other than Warburg Pincus LLC or any other Affiliate; (iv) the sale or disposition by either the Partnership or the general partner of the Partnership of all or substantially all of its assets in one or more transactions to any Person other than to Warburg Pincus LLC, Targa Resources GP LLC, or any other Affiliate; (v) a transaction resulting in a Person other than Targa Resources GP LLC or an Affiliate being the general partner of the Partnership; or (vi) as a result of or in connection with a contested election of directors, the persons who were directors of the Company before such election shall cease to constitute a majority of the Company’s board of directors. Notwithstanding the foregoing, with respect to an award under the 2010 Incentive Plan that is subject to section 409A of the Internal Revenue Code of 1986, a s amended (the “Code”), and with respect to which a Change in Control will accelerate payment, “Change in Control” shall mean a “change of control event” as defined in the regulations and guidance issued under section 409A of the Code. |
| · | Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan. |
| · | Person means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof, or other entity. |
The following table reflects payments that would have been made to each of the named executive officers under the 2010 Incentive Plan and related agreements in the event there was a Change in Control or their employment was terminated, each as of December 31, 2010.
| | | | | | Termination for | |
| Name | | Change of Control (1) | | | Death or Disability (1) | |
| Rene R. Joyce | | $ | 3,247,361 | | | $ | 3,247,361 | |
| Jeffrey J. McParland | | | 1,504,041 | | | | 1,504,041 | |
| Joe Bob Perkins | | | 1,822,544 | | | | 1,822,544 | |
| James W. Whalen | | | 1,822,544 | | | | 1,822,544 | |
| Michael A. Heim | | | 1,632,327 | | | | 1,632,327 | |
| Matthew J. Meloy | | | 601,214 | | | | 601,214 | |
| (1) | Amounts relate to the unvested shares of restricted stock of the Company granted on December 10, 2010. |
Long-Term Incentive Plan. If a Change of Control (as defined below) occurs during the performance period established for the performance units and related distribution equivalent rights granted to a named executive officer under our form of Performance Unit Grant Agreement (a “Performance Unit Agreement”), the performance units and related distribution equivalent rights then credited to a named executive officer will be cancelled and the named executive officer will be paid an amount of cash equal to the sum of (i) the product of (a) the Fair Market Value (as defined below) of a common unit of the Partnership multiplied by (b) the number of performance units granted t o the named executive officer, plus (ii) the amount of distribution equivalent rights then credited to the named executive officer, if any.
Performance units and the related distribution equivalent rights granted to a named executive officer under a Performance Unit Agreement will be automatically forfeited without payment upon the termination of his employment with us and our affiliates, except that: if his employment is terminated by reason of his death, a disability that entitles him to disability benefits under our long-term disability plan or by us other than for Cause (as defined below), he will be vested in his performance units that he is otherwise qualified to receive payment for based on achievement of the performance goal at the end of the Performance Period.
The following terms have the specified meanings for purposes of our long-term incentive plan:
| | • | Change of Control means (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than an affiliate of us, becoming the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership or its general partner, (ii) the limited partners of the Partnership approving, in one or a series of transactions, a plan of complete liquidation of the Partnership, (iii) the sale or other disposition by either the Partnership or the General Partner of all or substantially all of its assets in one or more transactions to any person other than the General Partner or one of the General Partner’s affiliates or (iv) a transaction result ing in a person other than the Partnership’s general partner or one of such general partner’s affiliates being the general partner of the Partnership. With respect to an award subject to Section 409A of the Code, Change of Control will mean a “change of control event” as defined in the regulations and guidance issued under Section 409A of the Code. |
| | • | Fair Market Value means the closing sales price of a common unit of the Partnership on the principal national securities exchange or other market in which trading in such common units occurs on the applicable date (or if there is not trading in the common units on such date, on the next preceding date on which there was trading) as reported in The Wall Street Journal (or other reporting service approved by the Compensation Committee). In the event the common units are not traded on a national securities exchange or other market at the time a determination of fair market value is required to be made, the determination of fair market value shall be made in good faith by the Compensation Committee. |
| | • | Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily of otherwise) to us or our affiliates, (iii) breach of any corporate policy or code of conduct established by us or our affiliates or breach of any agreement between the named executive officer and us or our affiliates or (iv) conviction of a misdemeanor involving moral turpitude or a felony. If the named executive officer is a party to an agreement with us or our affiliates in which this term is defined, then that definition will apply for purposes of our long-term incentive plan and the Performance Unit Agreement. |
The following table reflects payments that would have been made to each of the named executive officers under our long-term incentive plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2010.
| | | | | | | Termination for | |
| Name | | Change of Control | | | Death or Disability | |
| Rene R. Joyce | | $ | 2,049,196 | (1) | | | $ | 2,049,196 | (1) | |
| Jeffrey J. McParland | | | 1,008,188 | (2) | | | | 1,008,188 | (2) | |
| Joe Bob Perkins | | | 1,394,083 | (3) | | | | 1,394,083 | (3) | |
| James W. Whalen | | | 608,637 | (4) | | | | 608,637 | (4) | |
| Michael A. Heim | | | 1,255,173 | (5) | | | | 1,255,173 | (5) | |
| Matthew J. Meloy | | | 477,053 | (6) | | | | 477,053 | (6) | |
| (1) | Of this amount, $135,840 and $20,800 relate to the performance units and related distribution equivalent rights granted on January 17, 2008; $1,154,640 and $106,590 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $612,129 and $19,197 relate to the performance units and related distribution equivalent rights granted on December 3, 2009. |
| (2) | Of this amount, $91,692 and $14,040 relate to the performance units and related distribution equivalent rights granted on January 17, 2008; $526,380 and $48,593 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $317,526 and $9,958 relate to the performance units and related distribution equivalent rights granted on December 3, 2009. |
| (3) | Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17, 2008; $706,368 and $65,208 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $470,686 and $14,761 relate to the performance units and related distribution equivalent rights granted on December 3, 2009. |
| (4) | Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17, 2008; $0 and $0 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $457,237 and $14,339 relate to the performance units and related distribution equivalent rights granted on December 3, 2009. |
| (5) | Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17, 2008; $706,368 and $65,208 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $336,000 and $10,537 relate to the performance units and related distribution equivalent rights granted on December 3, 2009. |
| (6) | Of this amount, $50,940and $7,800 relate to the performance units and related distribution equivalent rights granted on October 1, 2008; $254,700 and $23,513 relate to the performance units and related distribution equivalent rights granted on August 4, 2009; and $135,840 and $4,260 relate to the performance units and related distribution equivalent rights granted on August 1, 2010. |
2005 Incentive Plan. No payments would have been made to each of the named executive officers under the 2005 Incentive Plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2010.
The following table reflects the aggregate payments that would have been made to each of the named executive officers under the 2010 Incentive Plan, the Long-Term Incentive Plan and related agreements in the event there was a Change in Control/Change of Control or their employment was terminated, each as of December 31, 2010.
| | | | | | Termination for | |
| Name | | Change of Control | | | Death or Disability | |
| Rene R. Joyce | | $ | 5,296,557 | | | $ | 5,296,557 | |
| Jeffrey J. McParland | | | 2,512,229 | | | | 2,512,229 | |
| Joe Bob Perkins | | | 3,216,627 | | | | 3,216,627 | |
| James W. Whalen | | | 2,431,181 | | | | 2,431,181 | |
| Michael A. Heim | | | 2,887,500 | | | | 2,887,500 | |
| Matthew J. Meloy | | | 1,078,267 | | | | 1,078,267 | |
Director Compensation
The following table sets forth the compensation earned by the General Partner’s non-employee directors for 2010:
| | Director Compensation for 2010 | |
| | Fees Earned | | Stock | | | | |
| | of Paid | | | Awards | | Total | |
| Name | in Cash | | ($) (3) | | Compensation | |
| Robert B. Evans (1)(2) | | $ | 148,500 | | | $ | 53,213 | | | $ | 201,713 | |
| Chansoo Joung (1)(2) | | | 56,500 | | | | 53,213 | | | | 109,713 | |
| Peter R. Kagan (1)(2) | | | 55,000 | | | | 53,213 | | | | 108,213 | |
| Barry R. Pearl (1)(2) | | | 180,000 | | | | 53,213 | | | | 233,213 | |
| William D. Sullivan (1)(2) | | | 148,500 | | | | 53,213 | | | | 201,713 | |
____________
| (1) | On January 22, 2010, Messrs. Evans, Joung, Kagan, Pearl and Sullivan each received 2,250 common units of the Partnership in connection with their service on the Board of Directors of the Partnership’s general partner (the “Board”). The grant date fair value of each common unit granted to each of these named individuals computed in accordance with FAS 123R was $23.65, based on the closing price of the common units on the day prior to the grant date. |
| (2) | As of December 31, 2010, Mr. Evans held 26,150 common units, Messrs. Joung and Kagan each held 10,250 common units, Mr. Pearl held 12,550 common units and Mr. Sullivan held 14,950 common units of the Partnership. |
| (3) | Amounts represent the aggregate grant date fair value of awards computed in accordance with FASB ASC Topic 718. For a discussion of the assumptions and methodologies used to value the awards reported in this column, see the discussion of common unit awards contained in the Notes to Consolidated Financial Statements at Note 13 included in this annual report. |
Narrative to Director Compensation Table
For 2010, each of the General Partner’s independent directors received an annual cash retainer of $40,000 and the chairman of the General Partner’s Audit Committee received an additional annual retainer of $20,000. All of the General Partner’s independent directors receive $1,500 for each of the General Partner’s Board, Audit Committee and Conflicts Committee meetings attended. Payment of independent director fees is generally made twice annually, at the second regularly scheduled meeting of the General Partner’s Board and the final regularly scheduled meeting of the General Partner’s Board for the fiscal year. All independent directors are reimbursed for out-of-pocket expenses incurred in attending the General Partner’s Board and committee meetings.
A director who is also an employee receives no additional compensation for services as a director. Accordingly, the Summary Compensation Table reflects total compensation received by Messrs. Joyce and Whalen for services performed for the General Partner and its affiliates.
Director Long-term Equity Incentives. The Partnership made equity-based awards in January 2010 to the General Partner’s non-management and independent directors under the Partnership’s long-term incentive plan. These awards were determined by us and approved by the General Partner’s Board. Each of these directors received an award of 2,250 restricted units, which will settle with the delivery of Partnership common units. The Partnership made similar grants under its long-term incentive plan to Targa’s independent directors. All of these awards are subject to three-year vesting, without a performance condition and vest ratably on each anniversary of the grant. The awards are intended to align the long-term interests of the General Partner’s directors with those of the Partnership’s unitholders. The independent and non-management directors of the General Partner and Targa’s independent directors currently participate in the Partnership’s plan.
Changes for 2011
Director Compensation. In February 2011, the Board approved changes to director compensation for the 2011 fiscal year. For 2011, each independent director of the General Partner will receive an annual cash retainer of $50,000.
Director Long-term Equity Incentives. In February 2011, each of the General Partner’s non-management and independent directors received an award of 2,120 common units under the Partnership’s long-term incentive plan.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of our units and of Targa common stock, as applicable, as of February 25, 2011 held by:
| · | 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 executive officers of Targa Resources GP LLC as a group. |
Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the unitholders identified in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them. Percentage ownership calculations for any unitholder listed in the table below are based on 42,349,738 shares of Targa’s common stock and 84,756,009 of our common units outstanding on February 25, 2011.
| | | | Targa Resources Partners LP | | Targa Resources Corp. |
| | | | | | Percentage | | | | Percentage |
| | | | Common | | of Common | | Common | | of Common |
| | | | Units | | Units | | Stock | | Stock |
| | | | Beneficially | | Beneficially | | Beneficially | | Beneficially |
| Name of Beneficial Owner (1) | | Owned (2) | | Owned | | Owned | | Owned |
| Targa Resources Corp. (3) | | 11,645,659 | | 13.7% | | - | | - |
| Tortoise Capital Advisors, LLC (4) | | 7,033,000 | | 8.3% | | | | |
| Rene R. Joyce | | 81,000 | | * | | 1,122,596 | | 2.7% |
| Joe Bob Perkins | | 32,100 | | * | | 914,058 | | 2.2% |
| Michael A. Heim | | 8,000 | | * | | 815,552 | | 1.9% |
| Jeffrey J. McParland | | 16,500 | | * | | 757,316 | | 1.8% |
| James W. Whalen | | 111,152 | | * | | 637,679 | | 1.5% |
| Matthew J Meloy | | 6,000 | | * | | 79,599 | | * |
| In Seon Hwang (3) | | 2,120 | | * | | 13,891,741 | | 32.8% |
| Peter R. Kagan (3) | | 12,370 | | * | | 13,891,741 | | 32.8% |
| Robert B. Evans | | 28,270 | | * | | - | | - |
| Barry R. Pearl | | 14,670 | | * | | - | | - |
| William D. Sullivan | | 17,070 | | * | | - | | - |
| | | | | | | | | | |
| All directors and executive officers | | | | | | | | |
| | as a group (14 persons) | | 370,252 | | * | | 19,582,931 | | 46.2% |
* Less than 1%
| (1) | Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002 and the nature of the beneficial ownership for all the equity securities is sole voting and investment power. |
| (2) | The common units presented as being beneficially owned by our directors and executive officers do not include the common units held indirectly by Targa Resources Corp. that may be attributable to such directors and officers based on their ownership of equity interests in Targa Resources Corp. |
| (3) | The units attributed to Targa Resources Corp. are held by three indirect wholly-owned subsidiaries, Targa GP Inc., Targa LP Inc., and Targa Versado Holdings LP. Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership and two affiliated partnerships, Warburg Pincus Netherlands Private Equity VII C.V.I., a company organized under the laws of the Netherlands, and WP-WP VIII Investors, LP, a Delaware limited partnership, (together “WP VIII”), and Warburg Pincus Private Equity IX, L.P., a Delaware limited partnership (“WP IX”), in the aggregate own, on a fully diluted basis, approximately 33% of the equity interests of Targa Resources Corp. The general partner of WP VIII is Warburg Pincus Partners, LLC, a New York limited liability company (“WP Partners LLC”), and the general partner of WP IX is Warburg Pincus IX, LLC, a New York limited liability company, of which WP Partners LLC is the sole member. Warburg Pincus & Co., a New York general partnership (“WP”), is the managing member of WP Partners LLC. WP VIII and WP IX are managed by Warburg Pincus LLC, a New York limited liability company (“WP LLC”). The address of the Warburg Pincus entities is 450 Lexington Avenue, New York, New York 10017. Messrs. Hwang and Kagan are Partners of WP and Managing Directors and Members of WP LLC. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Hwang, Kagan, Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities. |
| (4) | The business address for Tortoise Capital Advisors, L.L.C. (“TCA”) is 11550 Ash Street, Suite 300, Leawood, Kansas 66211. TCA acts as an investment advisor to certain closed-end investment companies registered or regulated under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owners under Rule 13d-3 of the Act of the securities they own of record because they have the right to acquire investment and voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with in dividual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. Of the 7,033,000 common units reported as beneficially held by TCA, TCA has reported that it has shared voting power with respect to 7,033,000 of these common units and shared dispositive power with respect to all of the common units. None of the securities listed are owned of record by TCA, and TCA disclaims any beneficial interest in such securities. |
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth certain information as of December 31, 2010 regarding our long-term incentive plan under which our common units are authorized for issuance to employees, consultants and directors of us, our general partner and its affiliates. Our sole equity compensation plan is our long-term incentive plan, which was approved by our partners prior to our initial public offering.
| | | | | | | Number of securities |
| | Number of | | | | | remaining available |
| | securities to be | | | | | for future issuance |
| | issued upon | | Weighted average | | under equity |
| | exercise of | | exercise price of | | compensation plans |
| | outstanding | | outstanding | | (excluding securities |
| | options, warrants | | options, warrants | | reflected in column |
| Plan category | and rights | | and rights | | (a)) |
| | (a) | | | (b) | | (c) |
| Equity compensation plans approved by security holders | | | | | | 1,600,250 |
| Equity compensation plans not approved by security holders | | | | | | |
| Total | | | $ | | | 1,600,250 |
Generally, awards of restricted units under our long-term incentive plan to our officers and employees are subject to vesting over time as determined by the board of our general partner and, prior to vesting, are subject to forfeiture. Long-term incentive plan awards may vest in other circumstances, as approved by the board of our general partner and reflected in an award agreement. Restricted common units are issued, subject to vesting, on the date of grant. The board of our general partner may provide that distributions on restricted units are subject to vesting and forfeiture provisions, in which cash such distributions would be held, without interest, until they vest or are forfeited.
Item 13. Certain Relationships and Related Transactions, and Director Independence
As of February 25, 2011, our general partner and Targa and affiliates owned 12,015,911 common units representing an aggregate 14.2% limited partner interest in us. In addition, our general partner owns a 2% general partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and its Affiliates
The following table summarizes the distributions and payments made and to be made by us to our general partner and its affiliates in connection with our ongoing operation and any liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
| Operational Stage | |
| | |
| Distributions of available cash to our general partner | We will generally make cash distributions 98% to our |
| and its affiliates | limited partner unitholders pro rata, including our |
| | general partner and its affiliates as the holders of |
| | 12,015,911 common 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 $2.3 million on their |
| | general partner units and $15.7 million on their |
| | common units. |
| 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. |
| | 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. |
| 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. |
Purchase and Sale Agreements
On April 27, 2010, we closed on our previously announced acquisition of (i) 100% of the limited partner interests in Targa Midstream Services Limited Partnership (“TMS”), (ii) 100% of the limited liability company interests in Targa Gas Marketing LLC (“TGM”), (iii) 100% of the limited partner interests in Targa Permian LP (“Permian”), (iv) 100% of the limited partner interests in Targa Straddle LP (“Targa Straddle”) and (v) 100% of the limited liability company interests in Targa Straddle GP LLC (“Targa Straddle GP”) for aggregate consideration of $420 million, subject to certain adjustments. Pursuant to the Permian/Straddle Purchase Agreement, Targa has indemnified us, our affiliates and our respective officers, directors, employees, counsel, accountants, financial advisers a nd consultants from and against (i) all losses that we incur arising from any breach of their representations, warranties or covenants in the Permian/Straddle Purchase Agreement and (ii) certain environmental, operational and litigation matters. We have indemnified Targa, their affiliates and their respective officers, directors, employees, counsel, accountants, financial advisers and consultants from and against all losses that they incur arising from or out of (i) the business or operations of the Permian/Straddle Business (whether relating to periods prior to or after the closing of the acquisition of the Permian/Straddle Business) to the extent such losses are not matters for which they have indemnified us or (ii) any breach of our representations, warranties or covenants in the Permian/Straddle Purchase Agreement. Certain of Targa’s indemnification obligations are subject to an aggregate deductible of $6.3 million and a cap equal to $46.2 million. In addition, these part ies’ reciprocal indemnification obligations for certain tax liability and losses are not subject to the deductible and cap. Targa’s environmental indemnification was limited to matters for which they receive notice and a claim for indemnification prior to the second anniversary of the closing. Indemnification claims for breaches of representations and warranties (other than for certain fundamental representations and warranties) must be delivered to Targa prior to the first anniversary of the closing. We have given no claims for indemnification under the Permian/Straddle Purchase Agreement.
On August 25, 2010, we closed on our previously announced acquisition of Targa’s interests in Versado (“Versado”). We acquired (i) all of the member interests in Targa Versado GP LLC (“Targa Versado GP”) and (ii) all of the limited partner interests in Targa Versado LP (“Targa Versado LP”), for aggregate consideration of $247.2 million, subject to certain adjustments, including the issuance to Targa of 89,813 common units and the issuance to our general partner of 1,833 general partner units, enabling our general partner to maintain its 2% general partner interest in us. Targa Versado GP and Targa Versado LP, collectively, own the interests in Versado. Pursuant to the Versado Purchase Agreement, Targa indemnified us, our affiliates and our respective officers, directors, employees, c ounsel, accountants, financial advisers and consultants from and against (i) all losses that they incur arising from any breach of our representations, warranties or covenants in the Versado Purchase Agreement and (ii) certain environmental matters. We have indemnified Targa, their affiliates and their respective officers, directors, employees, counsel, accountants, financial advisers and consultants from and against all losses that they incur arising from or out of (i) the business or operations of Targa Versado GP and Targa Versado LP (whether relating to periods prior to or after the closing of the acquisition of the interests in Versado) to the extent such losses are not matters for which Targa has indemnified us or (ii) any breach our representations, warranties or covenants in the Versado Purchase Agreement. Certain of Targa’s indemnification obligations are subject to an aggregate deductible of $3.4 million and a cap equal to $25.3 million. In addition, the parties’ reciprocal indemnificat ion obligations for certain tax liability and losses are not subject to the deductible and cap. Pursuant to the Versado Purchase Agreement, Targa also agreed to reimburse us for maintenance capital expenditure amounts incurred by us or our subsidiaries in respect of certain New Mexico Environmental Department capital projects.
On September 28, 2010, we closed on our previously announced acquisition of Targa’s interests in its Venice Operations (“VESCO”). We acquired all of the member interests in Targa Capital LLC (“Targa Capital”), for aggregate consideration of $175.6 million, subject to certain adjustments. Targa capital owns a 76.8% ownership interest in VESCO. Pursuant to the VESCO Purchase Agreement, Targa indemnified us, our affiliates and our respective officers, directors, employees, counsel, accountants, financial advisers and consultants from and against (i) all losses that they incur arising from any breach of our representations, warranties or covenants in the VESCO Purchase Agreement and (ii) certain environmental and litigation matters. We have indemnified Targa, its affiliates and their respective offi cers, directors, employees, counsel, accountants, financial advisers and consultants from and against all losses that we incur arising from or out of (i) the business or operations of Targa Capital (whether relating to periods prior to or after the closing of the acquisition of Targa Capital) to the extent such losses are not matters for which they have indemnified us or (ii) any breach of our representations, warranties or covenants in the VESCO Purchase Agreement. Certain of Targa’s indemnification obligations are subject to an aggregate deductible of $2.5 million and a cap equal to $18.425 million. In addition, the parties’ reciprocal indemnification obligations for certain tax liability and losses are not subject to the deductible and cap.
Omnibus Agreement
Our Omnibus Agreement with Targa, our general partner and others addresses the reimbursement of our general partner for costs incurred on our behalf, competition and indemnification matters. Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, are terminable by Targa at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of us or our general partner.
Reimbursement of Operating and General and Administrative Expense
Under the terms of the Omnibus Agreement, we reimburse Targa for the payment of certain operating and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. Pursuant to these arrangements, Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health i nsurance benefits. Since October 1, 2010, after the final conveyance of assts to us from Targa, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, other than Targa’s direct costs of being a separate public reporting company.
During the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011, Targa will provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at the distribution level at the time of the dropdown of $0.5175 per limited partner unit, subject to maximum support of $8.0 million in any quarter. No distribution support has been necessary through the fourth quarter of 2010.
Competition
Targa is not restricted, under either our partnership agreement or the Omnibus Agreement, from competing with us. Targa may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification
Under the Omnibus Agreement, we have agreed to indemnify Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.
Additionally, Targa has agreed to indemnify us for losses relating to income tax liabilities attributable to pre-IPO operations that are not reserved on the books of the Predecessor Business of the North Texas System as of February 14, 2007. Targa does not have any obligation under this indemnification until our aggregate losses exceed $250,000. Targa’s obligation under this indemnification will terminate upon the expiration of any applicable statute of limitations. We will indemnify Targa for all losses attributable to the post-IPO operations of the North Texas System.
In February 2007, our general partner and we entered into Indemnification Agreements (each, an “Indemnification Agreement”) with each independent director of Targa Resources GP LLC (each, an “Indemnitee”). Each Indemnification agreement provides that each of us and Targa Resources GP LLC will indemnify and hold harmless each Indemnitee against Expenses (as defined in the Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. If such indemnification is unavailable as a result of a court decision and if we or Targa Resources GP LLC is jointly liable in the p roceeding with the Indemnitee, we and Targa Resources GP LLC will contribute funds to the Indemnitee for his Expenses (as defined in the Indemnification Agreement) in proportion to relative benefit and fault of us or Targa Resources GP LLC on the one hand and Indemnitee on the other in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that we and Targa Resources GP LLC will indemnify and hold harmless the Indemnitee against Expenses incurred for actions taken as a director or officer of us or Targa Resources GP LLC or for serving at the request of us or Targa Resources GP LLC as a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has been entered by a court determining that, in respect of the matter for which the Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal proceeding, the Indemnitee acted with knowledge that the Indemnitee’s conduct was unlawful. The Indemnification Agreement also provides that we and Targa Resources GP L LC must advance payment of certain Expenses to the Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Indemnitee to return such advance if it is it is ultimately determined that the Indemnitee is not entitled to indemnification.
In February 2007, Targa Resources Corp., the indirect holder of all of Targa’s common units, entered into Indemnification Agreements (each, a “Parent Indemnification Agreement”) with each director and officer of Targa (each, a “Parent Indemnitee”), including Messrs. Joyce, Whalen and Kagan and Joung who serve or served as directors and/or officers of our general partner. Each Parent Indemnification Agreement provides that Targa Resources Corp. will indemnify and hold harmless each Parent Indemnitee for Expenses (as defined in the Parent Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the Parent Indemnitee. If such indemnificat ion is unavailable as a result of a court decision and if Targa Resources Corp. and the Indemnitee are jointly liable in the proceeding, Targa Resources Corp. will contribute funds to the Parent Indemnitee for his expenses in proportion to relative benefit and fault of Targa Resources Corp. and Parent Indemnitee in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that Targa Resources Investments Inc. will indemnify the Parent Indemnitee for monetary damages for actions taken as a director or officer of Targa Resources Corp. or for serving at Targa’s request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the Parent Indemnitee acted in good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in the best interests of Targa Resources Corp. and, in all other cases, not opposed to the best interests of Targa Resources Investments Inc. and (ii) in the case of a criminal proceeding, the Parent Indemnitee must have had no reasonable cause to believe that his conduct was unlawful. The Parent Indemnification Agreement also prov ides that Targa Resources Corp. must advance payment of certain Expenses to the Parent Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Parent Indemnitee to return such advance if it is it is ultimately determined that the Parent Indemnitee is not entitled to indemnification. In December 2010, we entered into a parent indemnification agreement with Mr. Meloy.
Relationships with Warburg Pincus LLC
Chansoo Joung and Peter Kagan, two of the directors of our general partner and Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We purchased $41.5 million of product from Broad Oak during 2010. Peter Kagan is also a director of Antero Resources Corporation (“Antero”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Antero. We purchased $0.1 million of product from Antero during 2010. These transactions were at market prices consistent with similar transactions with nonaffiliated entities
Relationships with Bank of America Corporation (“BofA”)
Equity. Until December 10, 2010, BofA was classified as a beneficial security holder of more than 5% of Targa, our parent company’s common stock as defined by Item 403(a) of Regulation S-K. After this date, BofA’s beneficial ownership of Targa’s outstanding common stock dropped below 5%.
Financial Services. An affiliate of BofA is a lender and an agent under our and our subsidiaries’ senior credit facilities with commitments of $72.0 million. BofA and its affiliates have engaged, and may in the future engage, in other commercial and investment banking transactions with subsidiaries of the Company in the ordinary course of their business. They have received, and expect to receive, customary compensation and expense reimbursement for these commercial and investment banking transactions.
Hedging Relationships. We had previously entered into various commodity derivative transactions with BofA. As of December 31, 2010, we had no open positions with BofA. During 2010 we received from (paid to) BofA $1.9 million in commodity derivative settlements.
Commercial Relationships. Our product sales included in revenues to affiliates of BofA during 2010 were $26.0 million. Our product purchases from affiliates of BofA during 2010 were $3.7 million.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand. The directors and officers of Targa Resources GP LLC have fiduciary duties to manage Targa and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its affiliates, on the one hand and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:
| · | 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. |
Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conf licts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “Conflicts of Interest.”
Pursuant to Targa’s Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interest between them and Targa or any of its subsidiaries, unless the conflict is pre-approved by the Board of Directors.
Director Independence
The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. Our general partner has a standing Audit Committee that consists of three directors: Messrs. Evans, Pearl and Sullivan. The board of directors of our general partner has affirmatively determined that Messrs. Evans, Pearl and Sullivan are independent as described in the rules of the NYSE and the Exchange Act for purposes of serving on the board of directors and the Audit Committee.
The board of directors of our general partner examined the relationship between Targa and its subsidiaries and each of Maritech, Legacy and SM Energy. William D. Sullivan, one of our general partner’s directors, is a director of each of Maritech Legacy Reserves GP, LLC, Legacy’s general partner, and SM Energy. The Board determined that the relationship was not material since (i) the amounts involved were a small percentage of the total revenues of Targa, us and each of Maritech Legacy and SM Energy and (ii) the payments to Targa and us were for gas gathering and processing arrangements in the ordinary course of business. The relationship is consistent with Mr. Sullivan’s status as an independent director.
To be independent under the NYSE rules, a company’s board of directors must affirmatively determine that the director has no material relationship with the company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the company). The board of directors of our general partner has made no such determination with respect to Messrs. Joyce, Kagan, Joung and Whalen because the NYSE rules do not require us to have a majority of independent directors. As such, Messrs. Joyce, Kagan, Joung and Whalen are not independent under NYSE rules applicable to service on compensation and nominating/governance committees.
Item 14. Principal Accountant Fees and Service
We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in Targa’s general and administrative expense allocation to us) for independent auditing, tax and related services for each of the last two fiscal years:
| | Year Ended December 31, | |
| | 2010 | | 2009 | |
| | (In millions) | |
| Audit fees (1) | | $ | 3.5 | | | $ | 4.5 | |
| Audit related fees (2) | | | - | | | | - | |
| Tax fees (3) | | | - | | | | 0.2 | |
| All other fees (4) | | | - | | | | - | |
| | | $ | 3.5 | | | $ | 4.7 | |
| (1) | Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control 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. |
| (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 of our financial statements and are not reported under audit fees. |
| (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 and partnership tax planning |
| (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 LLP during the last two years. |
All services provided by our independent principal accountant are subject to pre-approval by the audit committee of our general partner. The audit committee of our general partner is informed of each engagement of the independent principal accountant to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant.
PART IV
Item 15. Exhibits and Financial Statement Schedules
| | (a)(1) Financial Statements |
Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Exhibit
Number Description 60;
| 2.1** | Purchase and Sale Agreement, dated September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)). |
| 2.2 | Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)). |
| 2.3 | Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)). |
| 2.4 | Purchase and Sale Agreement, dated March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010(File No. 001-33303)). |
| 2.5 | Purchase and Sale Agreement, dated August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)). |
| 2.6 | Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)). |
| 3.1 | Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)). |
| 3.2 | Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). |
| 3.3 | Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). |
| 3.4 | First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)). |
| 3.5 | Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)). |
| 3.6 | Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). |
| 4.1 | Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). |
| 4.2 | Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008 (File No. 001-33303)). |
| 4.3 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.4 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.5 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.6 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.7 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.8 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.9 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.15 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.10 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.17 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.11 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.12 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.21 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.13 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.23 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.14 | Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.15 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.16 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.17 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.18 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.19 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.20 | Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.21 | Supplemental Indenture dated August 10, 2010 to Indenture dated June 18, 2008, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.46 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). |
| 4.22 | Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association LP (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.23 | Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.24 | Indenture dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)). |
| 4.25 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.26 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.27 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.28 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.29 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.30 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.31 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.32 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.18 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.33 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.34 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.22 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.35 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.24 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.36 | Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)). |
| 4.37 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.38 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.39 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.40 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.41 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.42 | Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)). |
| 4.43 | Supplemental Indenture dated August 10, 2010 to Indenture dated July 6, 2009, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.66 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). |
| 4.44 | Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.45 | Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.46 | First Supplemental Indenture dated February 2, 2011 to Indenture dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)). |
| 4.47 | Registration Rights Agreement dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)). |
| 4.48 | Indenture dated August 13, 2010 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)). |
| 4.49 | Registration Rights Agreement dated August 13, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)). |
| 4.50 | Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.51 | Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)). |
| 4.52 | Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)). |
| 4.53 | Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)). |
| 10.1 | Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-33303)). |
| 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 Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)). |
| 10.3 | Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)). |
| 10.4 | Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)). |
| 10.5 | Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)). |
| 10.6 | Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (File No. 001-33303)). |
| 10.7 | Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP��s Current Report on Form 8-K filed October 4, 2010 (File No. 001-33303)). |
| 10.8 | Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)). |
| 10.9 | First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)). |
| 10.10 | Purchase Agreement, dated June 30, 2009 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)). |
| 10.11 | Purchase Agreement dated August 10, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)). |
| 10.12 | Purchase Agreement dated January 19, 2011 by and among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several Initial Purchasers (incorporated by reference to Exhibit 1.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 24, 2011 (File No. 001-33303)). |
| 10.13+ | Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)). |
| 10.14+ | Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No. 333-171082)). |
| 10.15+ | Targa Resources Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)). |
| 10.16+ | Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008 (incorporated by reference to Exhibit 10.10 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)). |
| 10.17+ | Form of Restricted Unit Grant Agreement - 2007 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 13, 2007 (File No. 001-33303)). |
| 10.18+ | Form of Restricted Unit Grant Agreement – 2010 (incorporated by reference to Exhibit 10.15 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)). |
| 10.19+ | Form of Performance Unit Grant Agreement – 2007 (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on February 13, 2007 (File No. 001-33303)). |
| 10.20+ | Form of Performance Unit Grant Agreement – 2008 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2008 (File No. 001-33303)). |
| 10.21+ | Form of Performance Unit Grant Agreement – 2009 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 28, 2009 (File No. 001-33303)). |
| 10.22+ | Form of Performance Unit Grant Agreement – 2010 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 7, 2009 (File No. 001-33303)). |
| 10.23+ | Form of Performance Unit Grant Agreement – 2011 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 18, 2011) (File No. 001-33303)). |
| 10.24+ | Targa Resources Investments Inc. 2008 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)). |
| 10.25+ | Targa Resources Investments Inc. 2009 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)). |
| 10.26+ | Targa Resources Investments Inc. 2010 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.22 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)). |
| 10.27+* | Targa Resources Corp. 2011 Annual Incentive Compensation Plan |
| 10.28 | 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 and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 8, 2007 (File No. 333-138747)). [Bob/Brad - Is this contract still ongoing and material?] |
| 10.29 | Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)). |
| 10.30+ | Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). |
| 10.31+ | Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). |
| 10.32+ | Targa Resources Partners LP Indemnification Agreement for Williams D. Sullivan dated February 14, 2007 (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). |
| 21.1* | Subsidiaries of Targa Resources Partners LP. |
| 23.1* | Consent of Independent Registered Public Accounting Firm. |
| 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
| | ** Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SEC upon request |
+ Management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | TARGA RESOURCES PARTNERS LP |
| | |
| | By: Targa Resources GP LLC, |
| | its general partner |
| Dated: February 25, 2011 | By: | /s/ Matthew J. Meloy | |
| | | Matthew J. Meloy |
| | | Senior Vice President, Chief Financial Officer and Treasurer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 25, 2011.
| Signature | | Title (Position with Targa Resources GP LLC) | |
| | | Chief Executive Officer and Director | |
| /s/ Rene R. Joyce | | (Principal Executive Officer) | |
| Rene R. Joyce | | | |
| | | Senior Vice President, Chief Financial Officer and Treasurer | |
| /s/ Matthew J. Meloy | | (Principal Financial Officer) | |
| Mathew J. Meloy | | | |
| | | Senior Vice President and Chief Accounting Officer | |
| /s/ John R. Sparger | | (Principal Accounting Officer) | |
| John R. Sparger | | | |
| | | | |
| /s/ James W. Whalen | | Executive Chairman of the Board | |
| James W. Whalen | | | |
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| /s/ Peter R. Kagan | | Director | |
| Peter R. Kagan | | | |
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| /s/ In Seon Hwang | | Director | |
| In Seon Hwang | | | |
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| /s/ Barry R. Pearl | | Director | |
| Barry R. Pearl | | | |
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| /s/ Robert B. Evans | | Director | |
| Robert B. Evans | | | |
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| /s/ William D. Sullivan | | Director | |
| Wlliam D. Sullivan | | | |
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| TARGA RESOURCES PARTNERS LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS | |
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The management of Targa Resources GP LLC, the general partner of Targa Resources Partners LP, is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
The management of Targa Resources GP LLC has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of our internal control over financial reporting. Based on that evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2010.
The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-3.
/s/ Rene R. Joyce
Rene R. Joyce
Chief Executive Officer of Targa Resources GP LLC,
the general partner of Targa Resources Partners LP
(Principal Executive Officer)
/s/ Mathew J. Meloy
Matthew J. Meloy
Senior Vice President and Chief Financial Officer
of Targa Resources GP LLC, the general partner of
Targa Resources Partners LP
(Principal Financial Officer)
Report of Independent Registered Public Accounting Firm
To the Partners of Targa Resources Partners LP:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners' equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Partners LP and its subsidiaries (the "Partnership") at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material missta tement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 15 to the consolidated financial statements, the Partnership has engaged in significant transactions with its parent company, Targa Resources Corp. and its subsidiaries, related parties.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with autho rizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2011
| TARGA RESOURCES PARTNERS LP | |
| CONSOLIDATED BALANCE SHEETS | |
| | December 31, | |
| | 2010 | | | 2009 | |
| | (In millions) | |
| ASSETS | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 76.3 | | | $ | 90.9 | |
| Trade receivables, net of allowances of $7.7 million and $7.9 million | | | 466.1 | | | | 405.5 | |
| Inventory | | | 50.3 | | | | 39.3 | |
| Assets from risk management activities | | | 25.2 | | | | 32.9 | |
| Other current assets | | | 2.9 | | | | 1.9 | |
| Total current assets | | | 620.8 | | | | 570.5 | |
| Property, plant and equipment, at cost | | | 3,299.5 | | | | 3,155.5 | |
| Accumulated depreciation | | | (804.3 | ) | | | (628.9 | ) |
| Property, plant and equipment, net | | | 2,495.2 | | | | 2,526.6 | |
| Long-term assets from risk management activities | | | 18.9 | | | | 13.8 | |
| Investment in unconsolidated affiliate | | | 15.2 | | | | 18.5 | |
| Other long-term assets | | | 36.3 | | | | 23.3 | |
| Total assets | | $ | 3,186.4 | | | $ | 3,152.7 | |
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| LIABILITIES AND OWNERS' EQUITY | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable to third parties | | $ | 250.5 | | | $ | 193.1 | |
| Accounts payable to Targa Resources Corp. | | | 51.4 | | | | 20.2 | |
| Accrued liabilities | | | 273.7 | | | | 261.5 | |
| Liabilities from risk management activities | | | 34.2 | | | | 29.2 | |
| Total current liabilities | | | 609.8 | | | | 504.0 | |
| Long-term debt payable to third parties | | | 1,445.4 | | | | 908.4 | |
| Long-term debt allocated from Targa Resources Corp. | | | - | | | | 151.8 | |
| Long-term debt payable to Targa Resources Corp. | | | - | | | | 764.8 | |
| Long-term liabilities from risk management activities | | | 32.8 | | | | 43.8 | |
| Deferred income taxes | | | 8.7 | | | | 5.8 | |
| Other long-term liabilities | | | 40.6 | | | | 45.8 | |
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| Commitments and contingencies (see Note 16) | | | | | | | | |
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| Owners' equity: | | | | | | | | |
| Common unitholders (75,545,409 and 61,639,846 units issued and | | | | | | | | |
| outstanding as of December 31, 2010 and 2009) | | | 935.3 | | | | 850.5 | |
| General partner (1,541,744 and 1,257,957 units issued and | | | | | | | | |
| outstanding as of December 31, 2010 and 2009) | | | 15.1 | | | | 10.1 | |
| Net parent investment | | | - | | | | (218.0 | ) |
| Accumulated other comprehensive income (loss) | | | (30.6 | ) | | | (37.8 | ) |
| | | | 919.8 | | | | 604.8 | |
| Noncontrolling interests in subsidiaries | | | 129.3 | | | | 123.5 | |
| Total owners' equity | | | 1,049.1 | | | | 728.3 | |
| Total liabilities and owners' equity | | $ | 3,186.4 | | | $ | 3,152.7 | |
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| See notes to consolidated financial statements | | | | | |
| TARGA RESOURCES PARTNERS LP | |
| CONSOLIDATED STATEMENTS OF OPERATIONS | |
| | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions, except per unit amounts) | |
| Revenues | | $ | 5,460.2 | | | $ | 4,503.8 | | | $ | 8,030.1 | |
| Costs and expenses: | | | | | | | | | | | | |
| Product purchases | | | 4,688.0 | | | | 3,792.9 | | | | 7,217.2 | |
| Operating expenses | | | 259.5 | | | | 234.4 | | | | 274.3 | |
| Depreciation and amortization expenses | | | 176.2 | | | | 166.7 | | | | 156.8 | |
| General and administrative expenses | | | 122.4 | | | | 118.5 | | | | 97.3 | |
| Other operating (income) expense (see Note 21) | | | (3.3 | ) | | | (3.6 | ) | | | 13.4 | |
| Income from operations | | | 217.4 | | | | 194.9 | | | | 271.1 | |
| Other income (expense): | | | | | | | | | | | | |
| Interest expense from affiliate | | | (23.8 | ) | | | (97.7 | ) | | | (112.6 | ) |
| Interest expense allocated from Parent | | | (5.6 | ) | | | (10.0 | ) | | | (4.6 | ) |
| Other interest expense, net | | | (81.4 | ) | | | (52.1 | ) | | | (38.9 | ) |
| Equity in earnings of unconsolidated investments | | | 5.4 | | | | 5.0 | | | | 14.0 | |
| Gain (loss) on debt repurchases | | | - | | | | (1.5 | ) | | | 13.1 | |
| Gain (loss) on mark-to-market derivative instruments | | | 26.0 | | | | (30.9 | ) | | | 76.4 | |
| Gain on insurance claims | | | - | | | | - | | | | 18.5 | |
| Other | | | - | | | | 0.7 | | | | 1.1 | |
| Income before income taxes | | | 138.0 | | | | 8.4 | | | | 238.1 | |
| Income tax expense: | | | | | | | | | | | | |
| Current | | | (2.8 | ) | | | (0.3 | ) | | | (0.8 | ) |
| Deferred | | | (1.2 | ) | | | (0.9 | ) | | | (2.1 | ) |
| | | | (4.0 | ) | | | (1.2 | ) | | | (2.9 | ) |
| Net income | | | 134.0 | | | | 7.2 | | | | 235.2 | |
| Less: Net income attributable to noncontrolling interests | | | 24.9 | | | | 19.3 | | | | 33.1 | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 109.1 | | | $ | (12.1 | ) | | $ | 202.1 | |
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| Net income (loss) attributable to predecessor operations | | $ | 25.8 | | | $ | (66.7 | ) | | $ | 110.7 | |
| Net income attributable to general partner | | | 18.1 | | | | 10.4 | | | | 7.0 | |
| Net income allocable to limited partners | | | 65.2 | | | | 44.2 | | | | 84.4 | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 109.1 | | | $ | (12.1 | ) | | $ | 202.1 | |
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| Net income per limited partner unit - basic and diluted | | $ | 0.92 | | | $ | 0.86 | | | $ | 1.83 | |
| Weighted average limited partner units outstanding - | | | | | | | | | | | | |
| basic and diluted | | | 70.8 | | | | 51.2 | | | | 46.2 | |
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| See notes to consolidated financial statements | |
| | | | | | | | | | | | | |
| TARGA RESOURCES PARTNERS LP | |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |
| | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions) | |
| Net income | | $ | 134.0 | | | $ | 7.2 | | | $ | 235.2 | |
| Other comprehensive income (loss): | | | | | | | | | | | | |
| Commodity hedging contracts: | | | | | | | | | | | | |
| Change in fair value | | | 23.4 | | | | (72.7 | ) | | | 129.9 | |
| Settlement reclassified to revenues | | | (5.3 | ) | | | (45.6 | ) | | | 33.7 | |
| Interest rate hedges: | | | | | | | | | | | | |
| Change in fair value | | | (20.1 | ) | | | (2.1 | ) | | | (19.0 | ) |
| Settlements reclassified to interest | | | 9.2 | | | | 10.4 | | | | 2.7 | |
| Foreign currency translation adjustment | | | - | | | | - | | | | (1.8 | ) |
| Other comprehensive income (loss) | | | 7.2 | | | | (110.0 | ) | | | 145.5 | |
| Comprehensive income (loss) | | | 141.2 | | | | (102.8 | ) | | | 380.7 | |
| Less: Comprehensive income attributable to | | | | | | | | | | | | |
| noncontrolling interests | | | 24.9 | | | | 19.3 | | | | 33.1 | |
| Comprehensive income (loss) attributable to | | | | | | | | | | | | |
| Targa Resources Partners LP | | $ | 116.3 | | | $ | (122.1 | ) | | $ | 347.6 | |
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| See notes to consolidated financial statements | |
| TARGA RESOURCES PARTNERS LP | |
| CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY | |
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| | | | | | | | | | | | Accumulated | | | | | | | | | | |
| | | | | | | | | | | | Other | | | Net | | | | | | | |
| | | Limited Partners | | | General | | | Comprehensive | | | Parent | | | Noncontrolling | | | | |
| | | Common | | | Subordinated | | | Partner | | | Income (Loss) | | | Investment | | | Interests | | | Total | |
| | | (In millions) | |
| Balance, December 31, 2007 | | $ | 770.2 | | | $ | (85.0 | ) | | $ | 4.3 | | | $ | (73.3 | ) | | $ | (64.2 | ) | | $ | 100.8 | | | $ | 652.8 | |
| VESCO acquisition | | | - | | | | - | | | | - | | | | - | | | | - | | | | 41.8 | | | | 41.8 | |
| Distribution of property | | | - | | | | - | | | | - | | | | - | | | | - | | | | (14.8 | ) | | | (14.8 | ) |
| Amortization of equity awards | | | 0.3 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0.3 | |
| Distributions to unitholders | | | (64.0 | ) | | | (21.3 | ) | | | (5.7 | ) | | | - | | | | - | | | | - | | | | (91.0 | ) |
| Other distributions, net | | | - | | | | - | | | | - | | | | - | | | | (341.2 | ) | | | (34.6 | ) | | | (375.8 | ) |
| Contribution from noncontrolling interest | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0.4 | | | | 0.4 | |
| Net income | | | 63.3 | | | | 21.1 | | | | 7.0 | | | | - | | | | 110.7 | | | | 33.1 | | | | 235.2 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | 145.5 | | | | - | | | | - | | | | 145.5 | |
| Balance, December 31, 2008 | | | 769.8 | | | | (85.2 | ) | | | 5.6 | | | | 72.2 | | | | (294.7 | ) | | | 126.7 | | | | 594.4 | |
| Issuance of common units: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity offering | | | 103.1 | | | | - | | | | 2.2 | | | | - | | | | - | | | | - | | | | 105.3 | |
| Acquisition related | | | 129.8 | | | | - | | | | 2.7 | | | | - | | | | - | | | | - | | | | 132.5 | |
| Contribution under common control | | | (7.8 | ) | | | - | | | | (0.2 | ) | | | - | | | | 7.2 | | | | - | | | | (0.8 | ) |
| Other distributions, net | | | - | | | | - | | | | - | | | | - | | | | (151.1 | ) | | | (22.5 | ) | | | (173.6 | ) |
| Settlement of affiliated indebtedness | | | - | | | | - | | | | - | | | | - | | | | 287.3 | | | | - | | | | 287.3 | |
| Amortization of equity awards | | | 0.3 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0.3 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | (110.0 | ) | | | - | | | | - | | | | (110.0 | ) |
| Conversion of subordinated units | | | (97.6 | ) | | | 97.6 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Net income (loss) | | | 44.7 | | | | (0.5 | ) | | | 10.4 | | | | - | | | | (66.7 | ) | | | 19.3 | | | | 7.2 | |
| Distributions to unitholders | | | (91.8 | ) | | | (11.9 | ) | | | (10.6 | ) | | | - | | | | - | | | | - | | | | (114.3 | ) |
| Balance, December 31, 2009 | | | 850.5 | | | | - | | | | 10.1 | | | | (37.8 | ) | | | (218.0 | ) | | | 123.5 | | | | 728.3 | |
| Proceeds from equity offerings | | | 317.8 | | | | - | | | | 6.8 | | | | - | | | | - | | | | - | | | | 324.6 | |
| Distribution to Parent | | | - | | | | - | | | | - | | | | - | | | | (102.5 | ) | | | - | | | | (102.5 | ) |
| Settlement of affiliated indebtedness | | | - | | | | - | | | | - | | | | - | | | | 205.9 | | | | - | | | | 205.9 | |
| Distributions under common control | | | (151.7 | ) | | | - | | | | (2.8 | ) | | | - | | | | 88.8 | | | | - | | | | (65.7 | ) |
| Distributions to noncontrolling interest | | | - | | | | - | | | | - | | | | - | | | | - | | | | (19.1 | ) | | | (19.1 | ) |
| Amortization of equity awards | | | 0.4 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 0.4 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | 7.2 | | | | - | | | | - | | | | 7.2 | |
| Net income | | | 65.2 | | | | - | | | | 18.1 | | | | - | | | | 25.8 | | | | 24.9 | | | | 134.0 | |
| Distributions to unitholders | | | (146.9 | ) | | | - | | | | (17.1 | ) | | | - | | | | - | | | | - | | | | (164.0 | ) |
| Balance, December 31, 2010 | | $ | 935.3 | | | $ | - | | | $ | 15.1 | | | $ | (30.6 | ) | | $ | - | | | $ | 129.3 | | | $ | 1,049.1 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| See notes to consolidated financial statements | |
| TARGA RESOURCES PARTNERS LP | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (In millions) | |
| Cash flows from operating activities | | | | | | | | | |
| Net income | | $ | 134.0 | | | $ | 7.2 | | | $ | 235.2 | |
| Adjustments to reconcile net income to net cash | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Amortization in interest expense | | | 6.6 | | | | 3.9 | | | | 2.1 | |
| Amortization in general and administrative expense | | | 0.4 | | | | 0.3 | | | | 0.4 | |
| Interest expense on affiliate and allocated indebtedness | | | 29.4 | | | | 107.7 | | | | 118.2 | |
| Depreciation and other amortization expense | | | 171.3 | | | | 165.2 | | | | 156.8 | |
| Asset impairment charges | | | 4.9 | | | | 1.5 | | | | - | |
| Accretion of asset retirement obligations | | | 3.2 | | | | 3.0 | | | | 1.9 | |
| Deferred income tax expense | | | 1.2 | | | | 0.9 | | | | 2.1 | |
| Equity in earnings of unconsolidated investment, net | | | | | | | | | | | | |
| of distributions | | | 3.3 | | | | - | | | | (9.4 | ) |
| Risk management activities | | | 3.8 | | | | 95.6 | | | | (173.8 | ) |
| Loss (gain) on debt repurchases | | | - | | | | 1.5 | | | | (13.1 | ) |
| Loss (gain) on sale of assets | | | - | | | | 0.1 | | | | (5.9 | ) |
| Changes in operating assets and liabilities: | | | | | | | | | | | | |
| Receivables and other assets | | | (59.8 | ) | | | (80.3 | ) | | | 812.6 | |
| Inventory | | | (11.4 | ) | | | 23.3 | | | | 78.2 | |
| Accounts payable and other liabilities | | | 84.3 | | | | 93.0 | | | | (655.1 | ) |
| Net cash provided by operating activities | | | 371.2 | | | | 422.9 | | | | 550.2 | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Outlays for property, plant and equipment | | | (137.0 | ) | | | (95.9 | ) | | | (122.8 | ) |
| Acquisition of controlling interest of VESCO, net of cash acquired | | | - | | | | - | | | | (124.9 | ) |
| Other, net | | | 2.1 | | | | 1.3 | | | | 0.6 | |
| Net cash used in investing activities | | | (134.9 | ) | | | (94.6 | ) | | | (247.1 | ) |
| Cash flows from financing activities | | | | | | | | | | | | |
| Proceeds from borrowings under credit facility | | | 1,343.1 | | | | 569.2 | | | | 185.3 | |
| Repayments of credit facility | | | (1,057.0 | ) | | | (577.7 | ) | | | (323.8 | ) |
| Proceeds from issuance of senior notes | | | 250.0 | | | | 237.4 | | | | 250.0 | |
| Repurchases of senior notes | | | - | | | | (18.9 | ) | | | (26.8 | ) |
| Increase in affiliated indebtedness | | | - | | | | - | | | | 3.4 | |
| Repayment of affiliated and allocated indebtedness | | | (737.7 | ) | | | (397.5 | ) | | | - | |
| Proceeds from equity offerings | | | 317.8 | | | | 103.1 | | | | - | |
| Distributions to unitholders | | | (164.0 | ) | | | (114.3 | ) | | | (91.0 | ) |
| General partner contributions | | | 6.8 | | | | 2.2 | | | | - | |
| Costs incurred in connection with financing arrangements | | | (20.2 | ) | | | (9.6 | ) | | | (7.2 | ) |
| Allocation of debt from Targa | | | - | | | | - | | | | 137.1 | |
| Parent distributions | | | (102.5 | ) | | | (151.9 | ) | | | (342.2 | ) |
| Distributions under common control | | | (68.1 | ) | | | - | | | | - | |
| Distribution to noncontrolling interests | | | (19.1 | ) | | | (22.6 | ) | | | (34.3 | ) |
| Net cash used in financing activities | | | (250.9 | ) | | | (380.6 | ) | | | (249.5 | ) |
| Net change in cash and cash equivalents | | | (14.6 | ) | | | (52.3 | ) | | | 53.6 | |
| Cash and cash equivalents, beginning of period | | | 90.9 | | | | 143.2 | | | | 89.6 | |
| Cash and cash equivalents, end of period | | $ | 76.3 | | | $ | 90.9 | | | $ | 143.2 | |
| | | | | | | | | | | | | |
| See notes to consolidated financial statements | |
| | | | | | | | | | | | | |
TARGA RESOURCES PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Targa Resources Partners LP is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). We report our results of operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. See Note 20.
Our gathering and processing assets are located in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in Southeastern New Mexico and West Texas and the onshore and offshore coastal regions of Louisiana.
Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the U.S.
Targa Resources GP LLC is a Delaware single-member limited liability company, formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of December 31, 2010, Targa and its subsidiaries own a 17.1% interest in us in the form of 1,541,744 general partner units and 11,645,659 common units.
Targa sold or conveyed its ownership interests in the following assets, liabilities and operations to us on the dates indicated:
| · | February, 2007 – North Texas System; |
| · | October 2007 – San Angelo (“SAOU”) and Louisiana (“LOU”); |
| · | September 2009 – Downstream Business (See Note 5); |
| · | April 2010 – Permian Business and Straddle Assets (See Note 5); |
| · | August 2010 – Versado (See Note 5); and |
| · | September 2010 – Venice Operations (See Note 5). |
For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these conveyances collectively as our “predecessors.”
We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial results of our predecessors may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities.
We are required by GAAP to record the conveyances described in Note 1 based on Targa historical amounts, assuming that the acquisitions occurred at the date they qualified as entities under common control (October 31, 2005) following the acquisition of the SAOU and LOU. We recognize the difference between our acquisition cost and the Targa basis in the net assets as an adjustment to owners’ equity. We have retrospectively adjusted the financial statements, footnotes and other financial information presented for any period affected by common control accounting to reflect the results of the combined entities.
In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2010, up until the issuance of the financial statements. See Note 10 and Note 11.
During 2009, we recorded adjustments related to prior periods which decreased our income before income taxes for 2009 by $1.8 million. The adjustment related to natural gas sales transactions which occurred during 2006. After evaluating the quantitative and qualitative aspects of the error, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing this adjustment in the 2009 financial statements was not material to the 2009 results of operations, financial position, or cash flows.
Consolidation Policy. Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.
Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and are subject to an insignificant risk of changes in value.
Allowance for Doubtful Accounts. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
Inventory. Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.
Product Exchanges. Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchanging parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances. Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices as of the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments. We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain Downstream liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP are not accounted for as derivatives.
If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
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. The ultimate gain or loss on the derivative transaction upon settlement is also recognized as a component of other income and expense.
Targa has allocated to us a portion of our predecessor’s cash flows under its corporate wide hedging program. All of these derivatives are recorded on the balance sheets at fair value. As we were not a direct party to those hedge transactions, we do not apply hedge accounting. Therefore, changes in the unrealized fair value of these allocated hedges are recognized currently on a mark-to-market basis in earnings as a component of other income and expense. Upon the conveyance of the predecessor’s business, we legally incorporated these cash flow hedges into our hedge accounting program either by executing a new hedge in our name or obtaining a hedge contract novation from the counterparty to the Targa hedge.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the 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 assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
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. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis.
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.
Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component.
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.
We 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.
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. Asset recoverability is measured 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. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determina tion 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. See Note 7.
Asset Retirement Obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, we revise the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.
Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. We record these changes as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of estimated future asset retirement costs increase or decrease the carrying amounts of the ARO asset and liability. Upon settlement, we will recognize a gain or loss to the extent that the settlement cost differs from the recorded ARO amount. See Note 8.
Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases and debt extinguishments include any associated unamortized debt issue costs.
Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. See Note 16.
Income Taxes. We generally are not subject to federal income taxes. For federal income tax purposes our earnings or losses are included in the tax returns of our individual partners, however, some minor barge, terminalling and cogeneration activities are organized as corporations for federal income tax purposes. We are also subject to a Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.
Noncontrolling interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with any third party investor’s interest shown as noncontrolling interest within the equity section of the balance sheet. In the statements of operations, noncontrolling interest reflects the allocation of earnings to third party investors.
Revenue Recognition. Our primary types of sales and service activities reported as operating revenues include:
| · | sales of natural gas, NGLs and condensate; |
| · | natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas; and |
| · | NGL fractionation, terminalling and storage, transportation and treating. |
We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. 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. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids bas is or a fee basis, depending on market conditions. 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.
We generally report revenues gross in our consolidated statements of operations. Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.
Unit-Based Employee Compensation. We award share-based compensation to non-management directors in the form of restricted common units, which are deemed to be equity awards. Compensation expense on restricted common units is measured by the fair value of the award at the date of grant. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. We are also allocated compensation expense related to Targa’s share-based compensation plans. See Note 13.
Comprehensive Income. Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges, and currency translation adjustments.
Net Income per Limited Partner Unit. Net income attributable to Targa Resources Partners LP is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.
Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distribu ting all of the earnings for a particular period.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.
Use of Estimates. When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of finan cial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Accounting Pronouncements Recently Adopted
In January 2010, FASB issued guidance that requires additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and increased disclosure of different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Our adoption did not have a material impact on our consolidated financial statements.
On September 24, 2009, we acquired Targa’s interests in the Downstream Business for $530.0 million, effective September 1, 2009. The consideration consisted of $397.5 million in cash and $132.5 million in partnership interests represented by 174,033 general partner units and 8,527,615 common units. This consideration was used to repay $530.0 million of affiliated indebtedness, with the remaining $287.3 million of affiliated indebtedness treated as a capital contribution.
On April 27, 2010, we acquired Targa’s interests in its Permian Business and Straddle Assets for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million of consideration reported as a parent distribution.
On August 25, 2010, we acquired Targa’s 63% equity interest in Versado, effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. This consideration was used to repay $247.2 million of affiliated indebtedness. Targa contributed the remaining $205.8 million of affiliate indebtedness as a capital contribution. Under the terms of the Versado acquisition Purchase and Sale Agreement, Targa will reimburse us for future maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently estimated at $19 million, to be incurred through 2011.
On September 28, 2010, we acquired Targa’s Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), for aggregate consideration of $175.6 million, effective September 1, 2010. This consideration was used to repay $160.2 million of affiliate indebtedness, with the remaining $15.4 million of consideration reported as a parent distribution.
These acquisitions have been accounted for as acquisitions under common control, resulting in the retrospective adjustment of our prior results.
Due to fluctuating commodity prices for natural gas liquids (“NGL”), we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases in the period they are recognized, with the related cash impact in the subsequent period of sale. For 2010 and 2009, we did not recognize an adjustment to the carrying value of our NGL inventory. At December 31, 2008, we recognized $6.0 million to reduce the carrying value of NGL inventory to its net realizable value.
| | | December 31, | | | Estimated useful lives | |
| | | 2010 | | | 2009 | | | (In years) | |
| Natural gas gathering systems | | $ | 1,630.9 | | | $ | 1,578.0 | | | 5 to 20 | |
| Processing and fractionation facilities | | | 961.9 | | | | 949.8 | | | 5 to 25 | |
| Terminalling and natural gas liquids storage facilities | | | 244.7 | | | | 238.6 | | | 5 to 25 | |
| Transportation assets | | | 275.6 | | | | 271.6 | | | 10 to 25 | |
| Other property, plant and equipment | | | 46.8 | | | | 45.3 | | | 3 to 25 | |
| Land | | | 51.2 | | | | 50.9 | | | | - | |
| Construction in progress | | | 88.4 | | | | 21.3 | | | | - | |
| | | $ | 3,299.5 | | | $ | 3,155.5 | | | | | |
Our asset retirement obligations primarily relate to certain gas-gathering pipelines and processing facilities, and are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Beginning of period | | $ | 34.1 | | | $ | 34.0 | | | $ | 12.6 | |
| Liabilities settled | | | - | | | | - | | | | (0.2 | ) |
| Change in cash flow estimate | | | 0.2 | | | | (2.8 | ) | | | 2.8 | |
| Acquisition of controlling interest in VESCO | | | - | | | | - | | | | 16.9 | |
| Accretion expense | | | 3.2 | | | | 2.9 | | | | 1.9 | |
| End of period | | $ | 37.5 | | | $ | 34.1 | | | $ | 34.0 | |
As of December 31, 2010, our unconsolidated investment consists of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF).
Prior to July 31, 2008, our unconsolidated investments also included a 22.9% ownership interest in VESCO. On July 31, 2008, we acquired an additional 53.9% interest, giving us effective control under the terms of the operating agreement; therefore, we have consolidated the operations of VESCO in our financial results effective August 1, 2008.
The following table shows the activity related to our unconsolidated investments for the years indicated:
| | | December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Equity in earnings of | | | | | | | | | |
| VESCO (1)(2) | | $ | - | | | $ | - | | | $ | 10.1 | |
| GCF | | | 5.4 | | | | 5.0 | | | | 3.9 | |
| | | | 5.4 | | | | 5.0 | | | | 14.0 | |
| Cash Distributions: | | | | | | | | | | | | |
| GCF | | $ | 8.7 | | | $ | 5.0 | | | $ | 4.6 | |
__________
| (1) | Includes our equity earnings through July 31, 2008. |
| (2) | Includes business interruption insurance claims of $4.1 million for 2008. |
Our allocated cost basis of GCF at our acquisition date was less than our partnership equity balance by approximately $5.2 million. This basis difference is being amortized over the estimated useful life of the underlying fractionating assets (25 years) on a straight-line basis and is included as a component of our equity in earnings of unconsolidated investments.
| | | December 31, | |
| | | 2010 | | | 2009 | |
| Targa Resources Partners LP: | | | | | | |
| Senior secured revolving credit facility, variable rate, due July 2015 | | $ | 765.3 | | | $ | - | |
| Senior secured revolving credit facility, variable rate, due February 2012 | | | - | | | | 479.2 | |
| Senior unsecured notes, 8¼% fixed rate, due July 2016 | | | 209.1 | | | | 209.1 | |
| Senior unsecured notes, 11¼% fixed rate, due July 2017 | | | 231.3 | | | | 231.3 | |
| Unamortized discounts, net of premiums | | | (10.3 | ) | | | (11.2 | ) |
| Senior unsecured notes, 7 7/8% fixed rate, due October 2018 | | | 250.0 | | | | - | |
| Targa Permian LP: | | | | | | | | |
| Note payable to Parent, 10% fixed rate, due December 2011 (including | | | | | | | | |
| accrued interest of $0 and $36.2 million) | | | - | | | | 170.2 | |
| Targa Straddle LP: | | | | | | | | |
| Note payable to Parent, 10% fixed rate, due December 2011 (including | | | | | | | | |
| accrued interest of $0 million and $33.4 million) | | | - | | | | 156.8 | |
| Targa Versado LP: | | | | | | | | |
| Note payable to Parent, 10% fixed rate, due December 2011 (including | | | | | | | | |
| accrued interest of $0 million and $126.1 million) | | | - | | | | 435.0 | |
| Targa Venice Operations: | | | | | | | | |
| Allocated debt from Parent, variable rate (including accrued interest | | | | | | | | |
| of $0 million and $14.7 million) | | | - | | | | 151.8 | |
| Note payable to Parent, 10% fixed rate, due December 2011 (including | | | | | | | | |
| accrued interest of $0 million and $0.8 million) | | | - | | | | 2.8 | |
| | | $ | 1,445.4 | | | $ | 1,825.0 | |
| | | | | | | | | |
| Letters of credit issued | | $ | 101.3 | | | $ | 108.4 | |
The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during the year ended December 31, 2010:
| | Range of Interest Rates Paid | | Weighted Average Interest Rate Paid |
| Senior Secured Revolving Credit Facility | 1.2% to 5.0% | | 2.3% |
Compliance with Debt Covenants
As of December 31, 2010, we are in compliance with the covenants contained in our various debt agreements.
Senior Secured Credit Facility
On July 19, 2010, we entered into an Amended and Restated Credit Agreement that replaced our existing variable rate Senior Secured Credit Facility with a new variable rate Senior Secured Credit Facility due July 2015. The new Senior Secured Credit Facility increases available commitments to $1.1 billion from $958.5 million, and allows us to request increases in commitments up to an additional $300 million. We incurred a charge of $0.8 million attributable to a partial write-off of debt issue costs associated with this amended and restated credit facility related to a change in syndicate members. The remaining balance in debt issue costs of $4.7 million is being amortized over the life of the amended and restated credit facility.
The new credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% dependent on our consolidated funded indebtedness to consolidated adjusted EBITDA ratio. Our new credit facility is secured by a majority of our assets.
As of December 31, 2010, availability under our senior secured revolving credit facility was $233.4 million, after giving effect to $101.3 million in outstanding letters of credit.
Our senior secured credit facility restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in our senior secured credit agreement) has occurred and is continuing. The senior secured credit facility requires us to maintain a consolidated funded indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The senior secured credit facility also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, as defined in the senior secured credit agreement) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrenc e of additional permitted indebtedness.
Senior Unsecured Notes
We have three issues of unsecured senior notes. On June 18, 2008, we privately placed $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, we privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. On August 13, 2010 we privately placed $250 million in aggregate principal amount of 7⅞% senior notes due 2018 (the “7⅞% Notes”).
These notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us. These notes are effectively subordinated to all secured indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.
Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1. Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15. Interest on the 7⅞% Notes accrues at the rate of 7⅞% per annum and is payable semi-annually in arrears on April 15 and October 15, commencing on April 15, 2011.
We may redeem up to 35% of the aggregate principal amount of our series of notes at any time prior to July 1, 2011 for the 8¼% Notes (July 15, 2012 for the 11¼% Notes, and October 15, 2013 for the 7⅞% Notes), with the net cash proceeds of one or more equity offerings. We must pay a redemption price of 108.25% of the principal amount of the 8¼% Notes (111.25% for the 11¼% Notes, and 107.875% for the 7⅞ Notes), plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:
| (1) | at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and |
| (2) | the redemption occurs within 90 days of the date of the closing of such equity offering. |
We may also redeem all or a part of the each of our series of notes, on or after July 1, 2012 for the 8¼% Notes (July 15, 2013 for the 11¼% Notes, October 15, 2014 for the 7⅞ Notes) at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on July 1 for the 8¼% Notes (July 15 for the 11¼% Notes, October 15 for the 7⅞% Notes)&# 160;of each year indicated below:
| 8¼% Notes | | 11¼% Notes | | 7⅞% Notes |
| Year | | Redemption % | | Year | | Redemption % | | Year | | Redemption % |
| 2012 | | 104.125% | | 2013 | | 105.625% | | 2014 | | 103.938% |
| 2013 | | 102.063% | | 2014 | | 102.813% | | 2015 | | 101.969% |
| 2014 and thereafter | | 100.000% | | 2015 and thereafter | | 100.000% | | 2016 and thereafter | | 100.000% |
During 2008, we repurchased $40.9 million face value of our outstanding 8¼% Notes in open market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest. We recognized a gain on the debt repurchases of $13.1 million associated with the purchased notes. The repurchased 8¼% Notes were retired and are not eligible for re-issue at a later date.
During 2009, we repurchased $18.7 million face value ($17.8 million carrying value) of our outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus accrued interest of $0.3 million. We recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes. The repurchased 11¼% Notes were retired and are not eligible for re-issue at a later date.
Subsequent Events. On February 2, 2011, we privately placed $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of approximately $319.3 million.
On February 4, 2011 we exchanged $158.6 million under an exchange offer to holders of our 11¼% Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange we paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7 million of face value 11¼% Notes due 2017 were removed as we received sufficient consents in connection with the exchange offer to amend the indenture.
Affiliated Indebtedness
The contributions of the North Texas System, the Downstream Business, the Permian Business and Straddle Assets, the Versado and Targa’s Venice Operations have been treated as transfers between entities under common control and periods prior to the transfer have been adjusted to present comparative information. On January 1, 2007, Targa contributed to us affiliated indebtedness applicable to each of these predecessor businesses. In addition, Targa allocated indebtedness in August 2008 in connection with its acquisition of a controlling interest in VESCO. We include the financial effects of this affiliated indebtedness in our consolidated financial statements prepared on common control accounting basis. The following table summarizes the financial effects of this affiliated indebtedness:
| | | | | | | | | | | | | | | | |
| | | North Texas | | | Downstream | | | Permian and | | | | | | Venice | |
| | | System | | | Business | | | Straddle | | | Versado | | | Operations | |
| Original principal December 1, 2005 | | $ | 816.2 | | | $ | 568.7 | | | $ | 232.2 | | | $ | 308.9 | | | $ | 2.0 | |
| Interest accrued during 2005 and 2006 | | | 88.3 | | | | 61.8 | | | | 25.1 | | | | 33.4 | | | | 0.2 | |
| Borrowings during 2006 | | | | | | | 9.2 | | | | - | | | | - | | | | - | |
| Parent debt contributed January 1, 2007 | | | 904.5 | | | | 639.7 | | | | 257.3 | | | | 342.3 | | | | 2.2 | |
| Additional borrowings: | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2007 | | | - | | | | 13.0 | | | | - | | | | - | | | | - | |
| For the year ended December 31, 2008 | | | - | | | | 3.4 | | | | - | | | | - | | | | 137.1 | |
| Interest accrued prior to Targa conveyance: | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2007 (4) | | | 9.8 | | | | 58.5 | | | | 23.2 | | | | 30.9 | | | | 0.2 | |
| For the year ended December 31, 2008 | | | - | | | | 59.3 | | | | 23.2 | | | | 30.9 | | | | 4.8 | |
| For the year ended December 31, 2009 | | | - | | | | 43.4 | | | | 23.3 | | | | 30.9 | | | | 10.2 | |
| For the year ended December 31, 2010 | | | - | | | | - | | | | 5.8 | | | | 18.0 | | | | 5.7 | |
| | | | 9.8 | | | | 161.2 | | | | 75.5 | | | | 110.7 | | | | 20.9 | |
| Outstanding affiliate debt at conveyance date | | | | | | | | | | | | | | | | | | | | |
| or December 31, 2009 (1) | | | 914.3 | | | | 817.3 | | | | 332.8 | | | | 453.0 | | | | 160.2 | |
| | | | | | | | | | | | | | | | | | | | | |
| Payment (cash and units) (1)(2)(3) | | | (665.7 | ) | | | (530.0 | ) | | | (332.8 | ) | | | (247.2 | ) | | | (160.2 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Affiliate debt contributed at conveyance date | | $ | 248.6 | | | $ | 287.3 | | | $ | - | | | $ | 205.8 | | | $ | - | |
__________
| (1) | The Permian Business and the Straddle Assets were conveyed to us in April 2010, at which time the entire affiliate debt balance of $332.8 million was paid as part of the transaction. See Note 5. |
| (2) | Versado was conveyed to us in August 2010, at which time $247.2 million of affiliate debt balance was paid and the remaining $205.8 million of consideration was reported as a capital contribution. See Note 5. |
| (3) | VESCO was conveyed to us in September 2010, at which time $160.2 million was paid and the remaining $15.4 million of consideration was reported as a parent distribution. See Note 5. |
| (4) | In 2007, Targa also allocated $9.6 million of interest related to the conveyance of the SAOU and LOU. |
The stated 10% interest rate in the formal debt arrangement was not indicative of prevailing external rates of interest including that incurred under our credit facility. Using the weighted average rates incurred under Targa’s outstanding borrowings, unaudited pro forma affiliated interest expense would have been reduced by $23.0 million, $49.9 million and $30.4 million for the years ended December 31, 2010, 2009 and 2008. The unaudited pro forma affiliate and allocated interest expense for the Downstream Business, the Permian Business, the Straddle Assets, the Versado and Targa’s Venice Operations has been calculated by applying the weighted average rates of 1.4%, 4.9%, and 7.3% that Targa incurred under its outstanding borrowings for the periods indicated. The unaudited pro forma interest adjustment for the North Texas Sy stem has been calculated by applying the weighted average rate of 6.9% that Targa incurred under its credit facility for the period from January 1, 2007 to February 13, 2007.
General. In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter.
Conversion of Subordinated Units. Under the terms of our amended and restated Partnership Agreement, all 11,528,231 subordinated units converted to common units on a one-for-one basis on May 19, 2009. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.
Public Offering of Common Units. On August 12, 2009, we completed a unit offering under our shelf registration statement of 6,900,000 common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds of the offering were $105.3 million, after deducting underwriting discounts, commissions and offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. We used a portion of the proceeds to repay $103.5 million of outstanding borrowings under our senior secured revolving credit facility.
On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in us under an existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of approximately $121.8 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units, providing net proceeds of approximately $18.2 million. In addition, our general partner contributed $3.0 million for 129,082 general partner units to maintain a 2% interest in us. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.
On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa. We did not receive any of the proceeds from this offering and the number our outstanding common units remained unchanged.
On August 13, 2010, the we completed an offering of 6,500,000 of our common units under the Registration Statement at a price of $24.80 per common unit ($23.82 per common unit, net of underwriting discounts) providing net proceeds to the Partnership of approximately $154.7 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 975,000 common units, providing net proceeds of approximately $23.1 million. In addition, our general partner contributed $3.8 million for 152,551 general partner units to maintain its 2% general partner interest. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility.
Distributions. Distributions will generally be made 98% to the common unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages.
Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.5063 per unit. Our general partner interest received no incentive distributions prior to the fourth quarter of 2007.
In connection with our Downstream business acquisition, Targa agreed to provide limited distribution support through 2011. See Note 15.
The following table shows the amount of cash distributions we have paid to date:
| | | | Distributions Paid | | | Distributions | |
| | For the Three | | Limited Partners | | | General Partner | | | | | | per limited | |
| Date Paid | Months Ended | | Common | | | Subordinated | | | Incentive | | | | 2% | | | Total | | | partner unit | |
| | | | (In millions, except per unit amounts) | | | | |
| 2010 | | | | | | | | | | | | | | | | | | | | |
| November 12, 2010 | September 30, 2010 | | $ | 40.6 | | | $ | - | | | $ | 4.6 | | | $ | 0.9 | | | $ | 46.1 | | | $ | 0.5375 | |
| August 13, 2010 | June 30, 2010 | | | 35.9 | | | | - | | | | 3.5 | | | | 0.8 | | | | 40.2 | | | | 0.5275 | |
| May 14, 2010 | March 31, 2010 | | | 35.2 | | | | - | | | | 2.8 | | | | 0.8 | | | | 38.8 | | | | 0.5175 | |
| February 12, 2010 | December 31, 2009 | | | 35.2 | | | | - | | | | 2.8 | | | | 0.8 | | | | 38.8 | | | | 0.5175 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2009 | | | | | | | | | | | | | | | | | | | | | | | | | |
| November 14, 2009 | September 30, 2009 | | $ | 31.9 | | | $ | - | | | $ | 2.6 | | | $ | 0.7 | | | $ | 35.2 | | | $ | 0.5175 | |
| August 14, 2009 | June 30, 2009 | | | 23.9 | | | | - | | | | 2.0 | | | | 0.5 | | | | 26.4 | | | | 0.5175 | |
| May 15, 2009 | March 31, 2009 | | | 18.0 | | | | 5.9 | | | | 1.9 | | | | 0.5 | | | | 26.3 | | | | 0.5175 | |
| February 13, 2009 | December 31, 2008 | | | 18.0 | | | | 6.0 | | | | 1.9 | | | | 0.5 | | | | 26.4 | | | | 0.5175 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | | | | | | | | | | | | | | |
| November 14, 2008 | September 30, 2008 | | $ | 17.9 | | | $ | 6.0 | | | $ | 1.9 | | | $ | 0.5 | | | $ | 26.3 | | | $ | 0.5175 | |
| August 14, 2008 | June 30, 2008 | | | 17.8 | | | | 5.9 | | | | 1.7 | | | | 0.5 | | | | 25.9 | | | | 0.5125 | |
| May 15, 2008 | March 31, 2008 | | | 14.5 | | | | 4.8 | | | | 0.2 | | | | 0.4 | | | | 19.9 | | | | 0.4175 | |
| February 13, 2007 | December 31, 2007 | | | 13.8 | | | | 4.6 | | | | 0.1 | | | | 0.4 | | | | 18.9 | | | | 0.3975 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2007 | | | | | | | | | | | | | | | | | | | | | | | | | |
| November 14, 2007 | September 30, 2007 | | $ | 11.1 | | | $ | 3.9 | | | $ | - | | | $ | 0.3 | | | $ | 15.3 | | | $ | 0.3375 | |
| August 14, 2007 | June 30, 2007 | | | 6.5 | | | | 3.9 | | | | - | | | | 0.2 | | | | 10.6 | | | | 0.3375 | |
| May 15, 2007 | March 31, 2007 | | | 3.3 | | | | 1.9 | | | | - | | | | 0.1 | | | | 5.3 | | | | 0.1688 | |
__________
| (1) | Subordinated note converted to common units on May 19, 2009. |
Subsequent Events. On January 24, 2011, we completed a public offering of 8,000,000 common units representing limited partner interests in us under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option on February 3, 2011, we sold an additional 1,200,000 common units, providing net proceeds of $38.9 million. In addition, our general partner contributed $6.3 million for 187,755 general partner units to maintain a 2% interest in us. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility and for general partnership purposes, incl uding working capital.
On February 14, 2011, we paid a cash distribution of $0.5475 per unit on our outstanding common units to unitholders of record on February 3, 2011, for the three months ended December 31, 2010. The total distribution paid was $53.5 million, with $40.0 million paid to our non-affiliated common unitholders and $6.4 million, $1.1 million, and $6.0 million paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.
We recognize income from business interruption insurance in our consolidated statements of operations as a component of revenues from third parties in the period that a proof of loss is executed and submitted to the insurers for payment. For 2010, we did not have income from business interruption insurance. For 2009 and 2008, we recognized $13.3 million and $32.9 million in income from business interruption insurance.
Hurricanes Katrina and Rita
In 2005, Hurricanes Katrina and Rita, which occurred prior to the close of Targa’s acquisition of Dynegy’s midstream business, damaged certain of our acquired Gulf Coast facilities. The final purchase allocation for these acquisitions included an $81.1 million receivable for insurance claims related to our share of the property damage caused by Katrina and Rita. During 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $18.5 million, which is shown in the Consolidated Statement of Operations as other income. The insurance claim process is now complete with respect to Katrina and Rita for property damage and business interruption insurance.
Hurricanes Gustav and Ike
Certain Louisiana and Texas facilities sustained damage and had disruptions to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2010 and 2009, we reduced the estimate by $3.3 million, and $3.7 million to give effect to higher insurance recoveries and lower out of pocket costs. During 2009, we incurred expenditures related to the hurricanes amounting to $33.2 million for previously accrued repair costs and $7.4 million capitalized for improvements to the facilities. During 2010, total expenditures related to the hurricanes were $0.3 million.
Under common control accounting, we must include the effects of insurance claims on predecessor operations in our retrospectively adjusted financial statements. However, as part of the Downstream, Straddle and VESCO acquisition agreements, Targa retained the right to receive any future insurance proceeds associated with claims arising before the acquisition closing dates.
2005 Incentive Compensation Plan
Stock Option Plans
Under Targa’s 2005 Incentive Compensation Plan (“the Plan”), options to purchase a fixed number of shares of its stock may be granted to our employees, directors and consultants. Generally, options granted under the Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.
The fair value of each option granted was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions for 2010, 2009 and 2008, including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 3.9% for 2010 and 3.6% for 2009 and 2008, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on Targa’s common stock of 39.4% for 2010 and 25.5% for 2009 and 2008. Our selection of the risk-free interest rate was based on published yields for United States government securities with comparable terms. Because Targa was a non-public company until December 10, 2010, its expected stock price volatility was estimated based upon the historical price volatility of the Dow Jones U.S. Pipelines Index over a period equal to the expected average t erm of the options granted. The calculated fair value of options granted during the year ended December 31, 2010, and 2008 was $4.09, and $3.01 per share. There were no options granted in 2009.
We recognized compensation expense associated with Targa’s stock options of $0.2 million, $0.1 million and $0.2 million during 2010, 2009 and 2008.
The following table shows Targa’s stock option activity for the periods indicated:
| | | Number of | | | Weighted Average | |
| | | Options (1) | | | Exercise Price (2) | |
| Outstanding at December 31, 2009 | | | 2,215,442 | | | $ | 17.04 | |
| Granted | | | 46,018 | | | | 7.22 | |
| Exercised | | | (1,189,863 | ) | | | 0.67 | |
| Rescinded | | | (987,629 | ) | | | 24.87 | |
| Cashed out | | | (59,002 | ) | | | 1.90 | |
| Forfeited | | | (24,966 | ) | | | 25.51 | |
| Outstanding at December 31, 2010 | | | - | | | | | |
_______
| (1) | The number of options was adjusted to reflect Targa’s IPO reverse stock split in December 2010 with a conversion rate of 2.03. |
| (2) | The weighted average prices were adjusted to reflect Targa’s IPO reverse stock split in December 2010 with a conversion rate of 2.03. |
The aggregated intrinsic value of Targa’s stock options exercised in 2010, 2009 and 2008 was $3.4 million, $0.2 million, and $0.5 million.
Concurrent with Targa’s IPO in December 2010, unexercised in-the-money stock options were cashed out, resulting in $1.2 million of additional compensation expense in 2010. Unexercised out-of-the-money stock options were rescinded. As such, Targa has no outstanding stock options at December 31, 2010.
In connection with Targa’s extraordinary special distribution of dividends to its common and common equivalent shareholders (Note 10), in April 2010, Targa reduced the strike price on all of its outstanding options by $5.63. All unvested options were deemed to have immediately vested in May 2010. The weighted average exercise prices in the table above were adjusted to reflect Targa’s IPO reverse stock split with the conversion rate of 2.03, and the reduced strike prices for options exercised, rescinded, and cashed out after the strike price was reduced in May 2010. There were no options granted or forfeited after May 2010. This reduction is considered an award modification for accounting purposes; therefore, Targa re-determined the fair value of the options immediately following the reduction. The modification did not resul t in any additional compensation expense.
Non-vested (Restricted) Common Stock
Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted common shares (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the non-vested shares generally lapse four years from the date of grant.
Conversion of Vested Restricted Common Stock
Concurrent with Targa’s IPO in December 2010, all vested restricted common shares converted to unrestricted common stock in the Company. The following table provides a summary of Targa’s non-vested restricted common stock awards for the periods indicated:
| | | Year Ended | | | Weighted Average | |
| | | December 31, 2010 (1) | | | Grant-Date Fair Value (2) | |
| Outstanding at beginning of period | | | 25,091 | | | $ | 3.40 | |
| Granted | | | 30,198 | | | | 7.22 | |
| Vested | | | (55,289 | ) | | | 5.49 | |
| Outstanding at end of period | | | - | | | | | |
_______
| (1) | The number of restricted stock was adjusted to reflect Targa’s IPO reverse stock split with the conversion rate of 2.03. |
| (2) | The weighted average prices were adjusted to reflect Targa’s IPO reverse stock split with the conversion rate of 2.03. |
The following table presents weighted average fair value of shares granted and total fair value of shares vested during the periods indicated.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Weighted average fair value of shares granted (per share) (1) | | $ | 7.22 | | | $ | - | | | $ | 7.02 | |
| Total fair value of shares vested (in millions) | | | 0.3 | | | | 2.4 | | | | 16.6 | |
_______
| (1) | The weighted average prices were adjusted to reflect Targa’s IPO reverse stock split with the conversion rate of 2.03. |
During 2010, 2009 and 2008, we recognized $0.2 million, $0.3 million and $1.0 million of compensation expense associated with the vesting of Targa’s restricted stock.
2010 TRC Stock Incentive Plan
In connection with Targa’s IPO in December 2010, Targa adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance awards, or (viii) any combina tion of such awards (collectively referred to a “Awards”).
On December 6, 2010, Targa awarded 556,514 bonus stock awards to its executive management team which vested upon the closing of Targa’s IPO on December 10, 2010. Total compensation expense associated with these awards in 2010 was $12.2 million. The compensation expense was calculated based on the fair value of the stock of $22 per share at grant date.
On December 6, 2010, Targa granted to executive management and certain employees 1,350,000 Restricted Stock Awards. These awards vest over a three year period at 60% in 24 months and the remaining 40% in 36 months. There are no restrictions on the shares once the vesting requirement is met. Total compensation expense associated with these awards in 2010 was $1.1 million. We expect to incur an additional $28.6 million of expense related to the restricted awards over the next three years. The compensation expense was calculated based on the fair value of the stock of $22 per share at grant date.
Subsequent Event. In February 2011, Targa’s Compensation Committee (the “Committee”) made awards to executive management for the 2011 compensation cycle of 33,140 restricted common shares under the TRC Plan that will vest three years from the grant date and 68,030 equity-settled performance units under the Partnership’s LTIP that will vest in June 2014. The settlement value of these performance unit awards will be determined using the formula adopted for the performance unit awards granted in December 2009.
Non-Employee Director Grants and Incentive Plan related to the Partnership’s Common Units
In connection with the Partnership’s IPO in February 2007, Targa adopted a long-term incentive plan (“LTIP”) for employees, consultants and directors of the Partnership or its affiliates who perform services for us or our affiliates. The LTIP provides for the grant of cash-settled performance units which are linked to the performance of the Partnership’s common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of Targa’s board of directors. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.
Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership common unit, including DERs. The amount vesting under such awards is based on the total return per common unit of the Partnership through the end of the performance period multiplied by the vesting percentage determined from the Partnership’s ranking in a defined peer group.
The following table summarizes the LTIP units for the year ended 2010:
| | | Program Year | | | | |
| | | 2007 Plan | | | 2008 Plan | | | 2009 Plan | | | 2010 Plan | | | Total | |
| Unit outstanding January 1, 2010 | | | 275,400 | | | | 135,800 | | | | 534,900 | | | | 90,403 | | | | 1,036,503 | |
| Granted | | | - | | | | - | | | | - | | | | 219,597 | | | | 219,597 | |
| Vested and paid | | | (275,400 | ) | | | - | | | | - | | | | - | | | | (275,400 | ) |
| Forfeited | | | - | | | | (2,000 | ) | | | (7,400 | ) | | | (3,000 | ) | | | (12,400 | ) |
| Units outstanding December 31, 2010 | | | - | | | | 133,800 | | | | 527,500 | | | | 307,000 | | | | 968,300 | |
| | | | | | | | | | | | | | | | | | | | | |
| Calculated fair market value as of December 31, 2010 | | | | | | $ | 5,176,263 | | | $ | 20,113,575 | | | $ | 13,621,590 | | | $ | 38,911,428 | |
| Liabilities recognized as of December 31, 2010 | | | | | | | | | | | | | | | | | | | | |
| Current | | | | | | $ | 4,276,430 | | | $ | - | | | $ | - | | | $ | 4,276,430 | |
| Long-term | | | | | | | - | | | | 10,145,414 | | | | 3,434,471 | | | | 13,579,885 | |
| | | | | | | | | | | | | | | | | | | | | |
| To be recognized in future periods | | | | | | | 899,833 | | | | 9,968,161 | | | | 10,187,119 | | | | 21,055,113 | |
| | | | | | | | | | | | | | | | | | | | | |
| Vesting date | | | | | | June 2011 | | | June 2012 | | | June 2013 | | | | | |
Because the performance units require cash settlement, they have been accounted for as liabilities in our financial statements. During 2010, we paid $9.1 million for vested LTIP units.
During 2010, Targa changed the fair value measurement model from a Black-Scholes option pricing model to Monte Carlo simulation model. Targa considered the Monte Carlo simulation model to be more appropriate for LTIP valuation purposes than the previous method because it directly incorporates the peer group ranking market conditions.
Prior to the change, the fair value of a performance unit was the sum of: (i) the closing price of one of our common units on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with a grant date equal to the reporting date and an expiration date equal to the last day of the performance period; and (iii) estimated DERs. The fair value of the call options was estimated using a Black-Scholes option pricing model. The market condition was indirectly incorporated into the valuation based on our point-in-time ranking versus peers at the measurement date.
With the Monte Carlo simulation model, the fair value of a performance unit is the sum of: (i) the simulated share price of multiple correlated assets incorporated with peer ranking; and (ii) the estimated value of expected DERs. The simulated stock price was estimated using the Monte Carlo simulation with discount rate of 7.17% and expected volatility of 33.8%.
The remaining weighted average recognition period for the unrecognized compensation cost is approximately two years. During 2010, 2009 and 2008 we recognized compensation expense of $13.9 million, $10.5 million and $0.1 million related to the performance units.
Director Grants
During 2010 and 2009, Targa Resources GP LLC, the Partnership’s general partner, also made equity-based awards of 15,750 and 32,000 of the Partnership’s restricted common units (2,250 and 4,000 of its restricted common units to each of the Partnership’s and our non-management directors) under its Incentive Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. During 2010, 2009 and 2008, the Partnership recognized compensation expense of $0.4 million, $0.3 million and $0.3 million related to these awards with an offset to common equity. The Partnership estimates that the remaining fair value of $0.2 million will be recognized in expense over approximately one year . As of December 31, 2010 there were 39,074 unvested restricted common units outstanding under this plan.
The following table summarizes the Partnership’s unit-based awards for each of the periods indicated (in units and dollars):
| | | Year Ended | | | Weighted-average | |
| | | December 31, 2010 | | | Grant-Date Fair Value | |
| Outstanding at beginning of year | | $ | 41,993 | | | $ | 12.88 | |
| Granted | | | 15,750 | | | | 23.51 | |
| Vested | | | (18,669 | ) | | | 15.06 | |
| Outstanding at end of year | | | 39,074 | | | | 16.12 | |
The weighted average grant-date fair value of the unit-based awards for the years ended 2010, 2009 and 2008 were $16.12, $12.88 and $22.12.
Subsequent event. On February 14, 2011, the Partnership’s general partner made equity based awards of 10,600 of the Partnership’s restricted common units (2,120 restricted common units under to each of the Partnership’s non-management directors) under its Incentive Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.
Other Compensation Plans
Targa have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). Targa also contributed an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $7.2 million, $6.6 million, and $8.4 million during 2010, 2009, and 2008.
Commodity Hedges
In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (floors).
The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. This strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, the NGL hedges are based on published index prices for delivery at Mont Belvieu and the natural gas hedges are based on published index prices for delivery at Permian Basin, Mid-Continent and WAHA, which closely approximate our actual NGL and natural gas delivery points.
We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with our underlying West Texas condensate equity volumes.
Hedge ineffectiveness has been immaterial for all periods.
At December 31, 2010, the notional volumes of our commodity hedges were:
| Commodity | | Instrument | | Unit | | 2011 | | 2012 | | 2013 | | 2014 | |
| Natural Gas | | Swaps | | MMBtu/d | | 30,100 | | 23,100 | | 8,000 | | - | |
| NGL | | Swaps | | Bbl/d | | 8,550 | | 6,700 | | 3,400 | | - | |
| NGL | | Floors | | Bbl/d | | 253 | | 294 | | - | | - | |
| Condensate | | Swaps | | Bbl/d | | 1,100 | | 950 | | 800 | | 700 | |
Interest Rate Swaps
As of December 31, 2010, we had $765.3 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:
| | | | | | | | | | |
| | | | | | Notional | | | Fair | |
| Period | | Fixed Rate | | | Amount | | | Value | |
| 2011 | | | 3.52 | % | | $ | 300 | | | $ | (7.8 | ) |
| 2012 | | | 3.40 | % | | | 300 | | | | (7.5 | ) |
| 2013 | | | 3.39 | % | | | 300 | | | | (4.0 | ) |
| 2014 | | | 3.39 | % | | | 300 | | | | (0.8 | ) |
| | | | | | | | | | | $ | (20.1 | ) |
All interest rate swaps have been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility.
The following schedules reflect the fair values of derivative instruments in our financial statements:
| | Asset Derivatives | | Liability Derivatives | |
| Balance | Fair Value as of | | Balance | | Fair Value as of | |
| Sheet | December 31, | | Sheet | | December 31, | |
| Location | | 2010 | | | 2009 | | Location | | 2010 | | | 2009 | |
| Derivatives designated as hedging instruments | | | | | | | | | | | | | | |
| Commodity contracts | Current assets | | $ | 24.8 | | | $ | 31.6 | | Current liabilities | | $ | 25.5 | | | $ | 20.7 | |
| Long-term assets | | | 18.9 | | | | 11.7 | | Long-term liabilities | | | 20.5 | | | | 39.1 | |
| | | | | | | | | | | | | | | | | | | |
| Interest rate contracts | Current assets | | | - | | | | 0.2 | | Current liabilities | | | 7.8 | | | | 8.0 | |
| Long-term assets | | | - | | | | 1.9 | | Long-term liabilities | | | 12.3 | | | | 4.7 | |
| Total derivatives designated as hedging instruments | | | $ | 43.7 | | | $ | 45.4 | | | | $ | 66.1 | | | $ | 72.5 | |
| | | | | | | | | | | | | | | | | | | |
| Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | | | |
| Commodity contracts | Current assets | | $ | 0.4 | | | $ | 1.1 | | Current liabilities | | $ | 0.9 | | | $ | 0.5 | |
| Long-term assets | | | - | | | | 0.2 | | Long-term liabilities | | | - | | | | - | |
| Total derivatives not designated as hedging instruments | | | $ | 0.4 | | | $ | 1.3 | | | | $ | 0.9 | | | $ | 0.5 | |
| Total derivatives | | | $ | 44.1 | | | $ | 46.7 | | | | $ | 67.0 | | | $ | 73.0 | |
| | | | | | | | | | | | | | | | | | | |
The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.
The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense:
| | | Gain (Loss) Recognized in OCI on Derivatives | |
| Derivatives in | | (Effective Portion) | |
| Cash Flow Hedging | | Year Ended December 31, | |
| Relationships | | 2010 | | | 2009 | | | 2008 | |
| Interest rate contracts | | $ | (20.1 | ) | | $ | (2.1 | ) | | $ | (19.0 | ) |
| Commodity contracts | | | 23.4 | | | | (72.7 | ) | | | 129.9 | |
| | | $ | 3.3 | | | $ | (74.8 | ) | | $ | 110.9 | |
| | | | | | | | | | | | | |
| | | | |
| | | Amount of Gain (Loss) Reclassified from OCI into Income | |
| | | (Effective Portion) | |
| | | Year Ended December 31, | |
| Location of Gain (Loss) | | 2010 | | | 2009 | | | | 2008 | |
| Interest expense, net | | $ | (9.2 | ) | | $ | (10.4 | ) | | $ | (2.7 | ) |
| Revenues | | | 5.3 | | | | 45.6 | | | | (33.7 | ) |
| | | $ | (3.9 | ) | | $ | 35.2 | | | $ | (36.4 | ) |
Our earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. During 2010, 2009 and 2008, we recorded the following mark-to-market gains (losses):
| | | | Amount of Gain (Loss) Recognized | |
| Derivatives Not | Location of Gain (Loss) | | in Income on Derivatives | |
| Designated as Hedging | Recognized in Income | Year Ended December 31, | |
| Instruments | on Derivatives | 2010 | | | 2009 | | | 2008 | |
| Commodity contracts | Other income (expense) | | $ | 26.0 | | | $ | (30.9 | ) | | $ | 76.4 | |
The following table shows the unrealized gains (losses) included in OCI:
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Unrealized net gains (losses) on commodity hedges | | $ | (10.5 | ) | | $ | (28.7 | ) | | $ | 89.6 | |
| Unrealized net gain (losses) on interest rate hedges | | $ | (20.1 | ) | | $ | (9.3 | ) | | $ | (17.5 | ) |
As of December 31, 2010, deferred net losses of $0.8 million on commodity hedges and $7.4 million on interest rate hedges recorded in OCI are expected to be reclassified to income and interest expense during the next twelve months.
In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. We also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps. Prior to the terminations, these swaps were designated as hedges. Deferred losses of $0.3 million will be reclassified from OCI as a non-cash reduction of revenue during 2011 when the hedged forecasted sales transactions occur. During 2010, 2009 and 2008, deferred losses of $27.4 million, $37.8 million and $21.7 million related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue.
In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts in July 2008. Deferred losses of $0.1 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives of $1.0 million to adjust the fair value of the Lehman derivative contracts to zero. In October 2008, we terminated the Lehman derivative contracts.
See Note 4, Note 15, Note 18 and Note 22 for additional disclosures related to derivative instruments and hedging activities.
Targa Resources Corp.
On February 14, 2007, as part of the North Texas conveyance, we entered into an Omnibus Agreement with Targa, our general partner and others that addressed the reimbursement of our general partner for costs incurred on our behalf and indemnification matters. In conjunction with subsequent Targa asset conveyances, the parties amended the Omnibus Agreement to run through April 2013 and to have Targa provide general and administrative and other services to us associated with (1) our existing assets and any future Targa conveyances and (2) subject to mutual agreement, our future acquisitions from third parties. Targa, at its option, may terminate any or all of the provisions of this agreement, other than the indemnification provisions described in Note 16, if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will terminate in the event of a change of control of us or our general partner.
Reimbursement of Operating and General and Administrative Expense
The employees supporting our operations are employees of Targa. We reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to our assets, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Since October 1, 2010, after the final conveyance of assets to us by Targa, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, other than Targa’s direct costs of being a separate public reporting company.
Pursuant to the Omnibus Agreement with respect to the North Texas System, Targa capped the North Texas System’s general and administrative expenses at $5.0 million annually through February 14, 2010. There is not a cap of expenses related to any of the other Targa conveyances. However, Targa will provide distribution support to us in the form of reduced general and administrative expense billings, up to $8.0 million per quarter, if necessary, for a 1.0 times distribution coverage ratio. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support was required through the fourth quarter of 2010. We filed the Omnibus Agreement, as amended, with the SEC.
Centralized Cash Management
Prior to the Targa conveyances of assets, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. Beginning with the contribution of these systems to us, our consolidated subsidiaries’ bank accounts have been maintained under our separate centralized cash management system.
Contracts with Affiliates
Sales to and purchases from affiliates. Since our inception, we have routinely conducted business with other subsidiaries of Targa that we did not own. The related party transactions resulted primarily from purchases and sales of natural gas and purchases of NGL products and were settled in cash. Subsequent to the dropdown of all of the operating assets into us by Targa, all intercompany sale and purchase transactions are now eliminated in consolidation.
The following table summarizes transactions with Targa and Targa affiliates. Management believes these transactions are executed on terms that are fair and reasonable.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Cash | | | | | | | | | |
| Parent allocation of payroll and related | | | | | | | | | |
| costs included in operating expense | | $ | 78.8 | | | $ | 65.2 | | | $ | 62.9 | |
| Parent allocation of general & administrative expense | | | 110.9 | | | | 110.7 | | | | 93.3 | |
| Cash distributions to Targa based on unit ownership | | | 39.5 | | | | 38.9 | | | | 27.0 | |
| Distributions to Targa, net | | | 102.5 | | | | 151.9 | | | | 342.2 | |
| Noncash | | | | | | | | | | | | |
| Unit distributions to Targa | | | 2.5 | | | | 132.5 | | | | - | |
| Settlement of affiliated indebtedness | | | 205.9 | | | | 287.3 | | | | - | |
| Parent contribution of interest expense | | | 23.8 | | | | 97.7 | | | | 112.6 | |
| Affiliate interest expense accrued | | | (23.8 | ) | | | (97.7 | ) | | | (112.6 | ) |
| Parent allocation of debt | | | - | | | | - | | | | 137.1 | |
| Parent allocation of interest expense | | | 5.6 | | | | 10.0 | | | | 4.6 | |
Transactions with GCF
For the years 2010, 2009 and 2008, transactions with GCF included in revenues were $0.3 million, $0.2 million and $0.5 million. For the same periods, transactions with GCF included in costs and expenses were $1.1 million, $1.4 million and $3.5 million. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Relationships with Warburg Pincus LLC
Chansoo Joung and Peter Kagan, two of the directors of our general partner and Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We purchased $41.5 million, $9.7 million and $4.8 million of product from Broad Oak during 2010, 2009 and 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities. We had no commercial transactions prior to 2008 with Broad Oak.
Peter Kagan is also a director of Antero Resources Corporation (“Antero”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Antero. We purchased $0.1 million, $0.5 million and $64.4 million of product from Antero during 2010, 2009 and 2008. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationships with Bank of America Corporation (“BofA”)
Equity. Prior to December 10, 2010, BofA was considered a beneficial owner of more than 5% of the common stock of Targa. Upon Targa’s initial public offering, BofA reduced its ownership below 5%.
Financial Services. An affiliate of Bank of American (“BofA”) is a lender and an agent under our senior credit facility with commitments of $72 million. BofA and its affiliates have engaged, and may in the future engage, in other commercial and investment banking transactions with us in the ordinary course of our business. They have received, and expect to receive, customary compensation and expense reimbursement for these commercial and investment banking transactions.
Commodity Hedges. We have previously entered into various commodity derivative transactions with BofA. As of December 31, 2010, we have no open positions with BofA. During 2010, 2009 and 2008, we received from (paid to) BofA $1.9 million, $24.2 million and ($30.5) million in commodity derivative settlements.
Commercial Relationships. Our product sales and product purchases with BofA were:
| | | Year Ended | |
| | | December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Included in revenues | | $ | 26.0 | | | $ | 36.7 | | | $ | 97.0 | |
| Included in costs and expenses | | | 3.7 | | | | 1.0 | | | | 5.1 | |
Future non-cancelable commitments related to certain contractual obligations are presented below:
| | | Payments Due by Period | |
| | | Total | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | |
| Operating leases and service contract (1) | | $ | 36.7 | | | $ | 10.6 | | | $ | 8.4 | | | $ | 3.8 | | | $ | 2.7 | | | $ | 2.6 | | | $ | 8.6 | |
| Capacity and terminalling payments (2) | | | 12.9 | | | | 6.6 | | | | 4.7 | | | | 1.6 | | | | - | | | | - | | | | - | |
| Land site lease and right-of-way (3) | | | 20.4 | | | | 1.3 | | | | 1.2 | | | | 1.2 | | | | 1.1 | | | | 1.0 | | | | 14.6 | |
| | | $ | 70.0 | | | $ | 18.5 | | | $ | 14.3 | | | $ | 6.6 | | | $ | 3.8 | | | $ | 3.6 | | | $ | 23.2 | |
__________
| (1) | Include minimum lease payment obligations associated with gas processing plant site leases and railcar leases. |
| (2) | Consist of capacity payments for firm transportation contracts. |
| (3) | Provide for surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us; agreements expire at various dates through 2099. |
Total expenses related to operating leases, capacity payments and land site lease and right-of-way agreements were:
| | Year Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| Operating leases | | $ | 13.5 | | | $ | 13.7 | | | $ | 14.7 | |
| Capacity payments | | | 8.6 | | | | 9.6 | | | | 6.7 | |
| Land site lease and right-of-way | | | 2.8 | | | | 2.3 | | | | 4.0 | |
Environmental
For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.
In May 2007, the New Mexico Environmental Department (“NMED”) alleged air emissions violations at Eunice, Monument and Saunders gas processing plants, which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.
In January 2010, we settled the alleged violations with NMED for a penalty of approximately $1.5 million, which is accrued for as of December 31, 2010. As part of the settlement, we agreed to install two acid gas injection wells, additional emission control equipment and monitoring equipment. We estimate the total cost to complete these projects to be approximately $33.4 million, of which $4.0 million has already been paid.
Under the terms of the Versado Purchase and Sale Agreement, Targa will reimburse us for future maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently estimated at $19 million, to be incurred through 2011.
Our environmental liability at December 31, 2010 and December 31, 2009 was $1.6 million and $3.2 million. Our December 31, 2010 liability consisted of $0.2 million for gathering system leaks, and $1.4 million for ground water assessment and remediation.
Legal Proceedings
On December 8, 2005, WTG Gas Processing, L.P. (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa and two other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase SAOU from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. In January 2011, the Texas Supreme Court denied WTG’s petition for review of the lower courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the court reconsider its denial to review WTG’s appeal. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.
Except as provided above, neither we nor Targa are a party to any other legal proceedings 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.
The estimated fair values of our assets and liabilities classified as financial instruments have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.
The carrying value of our senior secured credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:
| | As of December 31, | |
| | 2010 | | 2009 | |
| | Carrying | | Fair | | Carrying | | Fair | |
| | Amount | | Value | | Amount | | Value | |
| Senior unsecured notes, 8¼% fixed rate | | $ | 209.1 | | | $ | 219.4 | | | $ | 209.1 | | | $ | 206.5 | |
| Senior unsecured notes, 11¼% fixed rate | | | 231.3 | | | | 265.0 | | | | 231.3 | | | | 253.5 | |
| Senior unsecured notes, 7 7/8% fixed rate | | | 250.0 | | | | 259.7 | | | | - | | | | - | |
We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
| · | Level 1 – observable inputs such as quoted prices in active markets; |
| · | Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable; and |
| · | Level 3 – unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. |
Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain counterparties. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold.
The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.
| | | December 31, 2010 | |
| | | | | | | | | | | | | |
| | | Total | | | Level 1 | | | Level 2 | | | Level 3 | |
| | | | | | | | | | | | | |
| Assets from commodity derivative contracts | | $ | 44.1 | | | $ | - | | | $ | 43.9 | | | $ | 0.2 | |
| Assets from interest rate derivatives | | | - | | | | - | | | | - | | | | - | |
| Total assets | | $ | 44.1 | | | $ | - | | | $ | 43.9 | | | $ | 0.2 | |
| Liabilities from commodity derivative contracts | | $ | 46.9 | | | $ | - | | | $ | 35.1 | | | $ | 11.8 | |
| Liabilities from interest rate derivatives | | | 20.1 | | | | - | | | | 20.1 | | | | - | |
| Total liabilities | | $ | 67.0 | | | $ | - | | | $ | 55.2 | | | $ | 11.8 | |
| | | December 31, 2009 | |
| | | Total | | | Level 1 | | | Level 2 | | | Level 3 | |
| Assets from commodity derivative contracts | | $ | 44.6 | | | $ | - | | | $ | 44.6 | | | $ | - | |
| Assets from interest rate derivatives | | | 2.1 | | | | - | | | | 2.1 | | | | - | |
| Total assets | | $ | 46.7 | | | $ | - | | | $ | 46.7 | | | $ | - | |
| Liabilities from commodity derivative contracts | | $ | 60.3 | | | $ | - | | | $ | 46.6 | | | $ | 13.7 | |
| Liabilities from interest rate derivatives | | | 12.7 | | | | - | | | | 12.7 | | | | | |
| Total liabilities | | $ | 73.0 | | | $ | - | | | $ | 59.3 | | | $ | 13.7 | |
The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
| | | Commodity Derivative Contracts | |
| | | 2010 | | | 2009 | | | 2008 | |
| Balance at January 1 | | $ | (13.7 | ) | | $ | 148.2 | | | $ | (124.2 | ) |
| Unrealized gains included in OCI | | | 2.6 | | | | (57.1 | ) | | | 149.6 | |
| Purchases | | | - | | | | - | | | | 3.3 | |
| Terminations included in OCI | | | - | | | | - | | | | 77.8 | |
| Settlements included in Income | | | (0.5 | ) | | | (35.0 | ) | | | 41.7 | |
| Transfers out of Level 3 (1) | | | - | | | | (69.8 | ) | | | - | |
| Balance at December 31 | | $ | (11.6 | ) | | $ | (13.7 | ) | | $ | 148.2 | |
________
| (1) | During 2009, we reclassified certain of our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exist) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets. |
For all periods indicated in the above table, all Level 3 derivative instruments were designated as cash flow hedges, and, as such, all changes in their fair value are reflected in Other Comprehensive Income. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Cash: | | | | | | | | | |
| Interest paid | | $ | 69.8 | | | $ | 27.0 | | | $ | 29.3 | |
| Taxes Paid | | | 2.5 | | | | - | | | | - | |
| Non-cash: | | | | | | | | | | | | |
| Net settlement of allocated indebtedness and debt issue costs | | | 205.9 | | | | 287.3 | | | | - | |
| Like-kind exchange of property, plant and equipment | | | - | | | | - | | | | 5.8 | |
| Inventory line-fill transferred to property, plant and equipment | | | 0.4 | | | | 9.8 | | | | 4.3 | |
| Issuance of Common Units in Downstream Acquisition | | | - | | | | 129.8 | | | | - | |
| Issuance of Common Units in VESCO & Versado Acquisitions | | | 2.5 | | | | - | | | | - | |
| Issuance of General Partner Units in Downstream Acquisition | | | - | | | | 2.7 | | | | - | |
In connection with the April 2010 acquisition of Targa’s interest in the Permian Business and Straddle Assets and its impact on our structure used for internal management purposes, an updated evaluation of our reportable segments was performed during the second quarter of 2010. As a result, our operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. The financial results of our hedging activities are reported in Other. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.
Prior to the second quarter of 2010, we reported our results under four reportable segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increase in our Coastal Gathering and Processing businesses as a result of our acquisition of the Permian Business and Straddle Assets and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational int errelationships among the Marketing and Distribution activities apparent in our current business model.
The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment assets are located in North Texas and the Permian Basin of Texas and New Mexico and the Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.
The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the activities necessary to convert raw natural gas liquids into NGL products, market the finished products and provide certain value added services.
The Logistics Assets segment is involved in transporting and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our gathering and processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana.
The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.
Our reportable segment information is shown in the following tables:
| Year Ended December 31, 2010 | |
| | Field | | Coastal | | | | | | | | | | | |
| | Gathering | | Gathering | | | | Marketing | | | | | | | |
| | and | | and | | Logistics | | and | | | | | | | |
| | Processing | | Processing | | Assets | | Distribution | | Other | | Eliminations | | Total | |
| Revenues | $ | 211.6 | | $ | 446.6 | | $ | 84.5 | | $ | 4,713.5 | | $ | 4.0 | | $ | - | | $ | 5,460.2 | |
| Intersegment revenues | | 1,084.4 | | | 755.7 | | | 88.0 | | | 494.8 | | | - | | | (2,422.9 | ) | | - | |
| Revenues | $ | 1,296.0 | | $ | 1,202.3 | | $ | 172.5 | | $ | 5,208.3 | | $ | 4.0 | | $ | (2,422.9 | ) | $ | 5,460.2 | |
| Operating margin | $ | 236.6 | | $ | 107.8 | | $ | 83.8 | | $ | 80.5 | | $ | 4.0 | | $ | - | | $ | 512.7 | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 1,623.4 | | $ | 451.5 | | $ | 471.9 | | $ | 519.9 | | $ | 44.1 | | $ | 75.6 | | $ | 3,186.4 | |
| Capital expenditures | $ | 67.8 | | $ | 6.9 | | $ | 66.3 | | $ | 2.7 | | $ | - | | $ | - | | $ | 143.6 | |
| Year Ended December 31, 2009 | |
| | Field | | Coastal | | | | | | | | | | | |
| | Gathering | | Gathering | | | | Marketing | | | | | | | |
| | and | | and | | Logistics | | and | | | | | | | |
| | Processing | | Processing | | Assets | | Distribution | | Other | | Eliminations | | Total | |
| Revenues | $ | 191.7 | | $ | 392.0 | | $ | 76.7 | | $ | 3,797.1 | | $ | 46.3 | | $ | - | | $ | 4,503.8 | |
| Intersegment revenues | | 780.1 | | | 525.0 | | | 79.5 | | | 337.4 | | | - | | | (1,722.0 | ) | | - | |
| Revenues | $ | 971.8 | | $ | 917.0 | | $ | 156.2 | | $ | 4,134.5 | | $ | 46.3 | | $ | (1,722.0 | ) | $ | 4,503.8 | |
| Operating margin | $ | 183.2 | | $ | 89.7 | | $ | 74.3 | | $ | 83.0 | | $ | 46.3 | | $ | - | | $ | 476.5 | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 1,668.2 | | $ | 489.0 | | $ | 414.4 | | $ | 442.3 | | $ | 46.8 | | $ | 92.0 | | $ | 3,152.7 | |
| Capital expenditures | $ | 53.4 | | $ | 14.0 | | $ | 15.8 | | $ | 16.0 | | $ | - | | $ | - | | $ | 99.2 | |
| Year Ended December 31, 2008 | |
| | Field | | Coastal | | | | | | | | | | | |
| | Gathering | | Gathering | | | | Marketing | | | | | | | |
| | and | | and | | Logistics | | and | | | | | | | |
| | Processing | | Processing | | Assets | | Distribution | | Other | | Eliminations | | Total | |
| Revenues | $ | 415.9 | | $ | 781.2 | | $ | 69.1 | | $ | 6,797.5 | | $ | (33.6 | ) | $ | - | | $ | 8,030.1 | |
| Intersegment revenues | | 1,530.8 | | | 736.4 | | | 103.4 | | | 619.5 | | | - | | | (2,990.1 | ) | | - | |
| Revenues | $ | 1,946.7 | | $ | 1,517.6 | | $ | 172.5 | | $ | 7,417.0 | | $ | (33.6 | ) | $ | (2,990.1 | ) | $ | 8,030.1 | |
| Operating margin | $ | 385.4 | | $ | 105.4 | | $ | 40.1 | | $ | 41.3 | | $ | (33.6 | ) | $ | - | | $ | 538.6 | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 1,725.7 | | $ | 522.4 | | $ | 421.5 | | $ | 356.9 | | $ | 202.1 | | $ | 120.0 | | $ | 3,348.6 | |
| Capital expenditures | $ | 82.7 | | $ | 13.1 | | $ | 37.2 | | $ | 4.2 | | $ | - | | $ | - | | $ | 137.2 | |
The following table shows our revenues by product and services for each period presented:
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Natural gas sales | | $ | 1,076.5 | | | $ | 808.6 | | | $ | 1,590.3 | |
| NGL sales | | | 4,115.3 | | | | 3,366.6 | | | | 6,148.5 | |
| Condensate sales | | | 95.1 | | | | 95.5 | | | | 131.5 | |
| Fractionation & Treating fees | | | 55.8 | | | | 61.1 | | | | 66.8 | |
| Storage & Terminalling fees | | | 40.1 | | | | 41.0 | | | | 33.0 | |
| Transportation fees | | | 33.8 | | | | 43.4 | | | | 39.2 | |
| Gas processing fees | | | 32.1 | | | | 24.0 | | | | 22.0 | |
| Hedge settlements | | | 6.1 | | | | 45.7 | | | | (33.7 | ) |
| Business interruption insurance | | | - | | | | 13.3 | | | | 32.9 | |
| Other | | | 5.4 | | | | 4.6 | | | | (0.4 | ) |
| | | $ | 5,460.2 | | | $ | 4,503.8 | | | $ | 8,030.1 | |
The following table is a reconciliation of operating margin to net income for each period presented:
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Reconciliation of operating margin to net income: | | | | | | | | | |
| Operating margin | | $ | 512.7 | | | $ | 476.5 | | | $ | 538.6 | |
| Depreciation and amortization expenses | | | (176.2 | ) | | | (166.7 | ) | | | (156.8 | ) |
| General and administrative expenses | | | (122.4 | ) | | | (118.5 | ) | | | (97.3 | ) |
| Interest expense, net | | | (110.8 | ) | | | (159.8 | ) | | | (156.1 | ) |
| Income tax expense | | | (4.0 | ) | | | (1.2 | ) | | | (2.9 | ) |
| Other, net | | | 34.7 | | | | (23.1 | ) | | | 109.7 | |
| Net income | | $ | 134.0 | | | $ | 7.2 | | | $ | 235.2 | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Casualty loss (gain) adjustment, See Note 12 | | $ | (3.3 | ) | | $ | (3.7 | ) | | $ | 19.3 | |
| Loss (gain) on sale of assets | | | - | | | | 0.1 | | | | (5.9 | ) |
| | | $ | (3.3 | ) | | $ | (3.6 | ) | | $ | 13.4 | |
Nature of Operations in Midstream Energy Industry
We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.
A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates. The fair value of our commodity and interest rate derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs, or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
In an effort to reduce the variability of our cash flows we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2011 through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in adv ance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges. See Note 14.
Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement. See Note 14.
Counterparty Risk – Credit and Concentration
Derivative Counterparty Risk
Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
We have master netting agreements with most of our hedge counterparties. These netting agreements allow us to net settle asset and liability positions with the same counterparties. As of December 31, 2010, we had $25.8 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $38.4 million as of that date.
Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
As of December 31, 2010, affiliates of Barclays, Credit Suisse and British Petroleum (“BP”) accounted for 62%, 13% and 12%, of our counterparty credit exposure related to commodity derivative instruments. Barclays, Credit Suisse and BP are major financial institutions or corporations, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. The following table summarizes the activity affecting our allowance for bad debts:
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| Balance at beginning of year | | $ | 7.9 | | | $ | 9.2 | | | $ | 0.9 | |
| Additions | | | - | | | | - | | | | 8.3 | |
| Deductions | | | (0.2 | ) | | | (1.3 | ) | | | - | |
| Balance at end of year | | $ | 7.7 | | | $ | 7.9 | | | $ | 9.2 | |
Significant Commercial Relationships
We are exposed to concentration risk when a significant customer or supplier accounts for a significant portion of our business activity. The following table lists the percentage of our consolidated sales or purchases with customers and suppliers which accounted for more than 10% of our consolidated revenues and consolidated product purchases for the periods indicated:
| | | Year Ended December 31, | |
| | | 2010 | | 2009 | | 2008 | |
| % of consolidated revenues | | | | | | |
| | Chevron Phillips Chemical Company LLC | 10% | | 15% | | 19% | |
| %of product purchases | | | | | | |
| | Louis Dreyfus Energy Services L.P. | 10% | | 11% | | 9% | |
All transactions in the above table were associated with the Marketing and Distribution segment.
Casualty or Other Risks
Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. A portion of the insurance costs described above is allocated to us by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 15.
Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.
Under the Omnibus agreement described in Note 15, Targa has also indemnified us for pre-closing claims attributable to rights-of-way, certain consents or governmental permits, for a period of one to two years from our acquisitions (the North Texas System was three years). Targa has also indemnified us for certain pre-closing legal proceedings. Targa’s indemnification of any potential income tax issues attributable to pre-closing operations for each of our acquisitions terminate upon the expiration of the applicable statutes of limitations under the Omnibus Agreement, as amended.
| | | First | | | Second | | | Third | | | Fourth | | | | |
| | | Quarter | | | Quarter | | | Quarter | | | Quarter | | | Total | |
| | | (In millions, except per unit amounts) | |
| Year Ended December 31, 2010: | | | | | | | | | | | | | | | |
| Revenues | | $ | 1,483.8 | | | $ | 1,237.6 | | | $ | 1,216.9 | | | $ | 1,521.9 | | | $ | 5,460.2 | |
| Gross margin | | | 185.9 | | | | 179.8 | | | | 184.7 | | | | 221.8 | | | | 772.2 | |
| Operating income | | | 56.7 | | | | 46.5 | | | | 48.8 | | | | 65.4 | | | | 217.4 | |
| Net income | | | 49.9 | | | | 22.9 | | | | 18.4 | | | | 42.8 | | | | 134.0 | |
| Net income allocable to limited partners | | | 9.4 | | | | 15.9 | | | | 10.1 | | | | 29.8 | | | | 65.2 | |
| Net income per limited partner | | | | | | | | | | | | | | | | | | | | |
| unit - basic and diluted | | $ | 0.14 | | | $ | 0.23 | | | $ | 0.14 | | | $ | 0.39 | | | $ | 0.92 | |
| | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2009: | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 996.1 | | | $ | 1,006.5 | | | $ | 1,118.1 | | | $ | 1,383.1 | | | $ | 4,503.8 | |
| Gross margin | | | 146.5 | | | | 167.7 | | | | 181.9 | | | | 214.8 | | | | 710.9 | |
| Operating income | | | 16.3 | | | | 41.6 | | | | 53.0 | | | | 84.0 | | | | 194.9 | |
| Net income (loss) | | | (8.5 | ) | | | (18.4 | ) | | | 1.3 | | | | 32.8 | | | | 7.2 | |
| Net income (loss) allocable to limited partners | | | (4.0 | ) | | | 4.5 | | | | 11.4 | | | | 32.3 | | | | 44.2 | |
| Net income (loss) per limited partner | | | | | | | | | | | | | | | | | | | | |
| unit - basic and diluted | | $ | (0.09 | ) | | $ | 0.10 | | | $ | 0.17 | | | $ | 0.52 | | | $ | 0.86 | |
F - 40
