Exhibit 99.2
The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical financial statements and notes included in Exhibit 99.3.
Overview
We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products.
We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly owned subsidiary of Targa. Our limited partner common units are publicly traded on the NASDAQ Stock Market LLC under the symbol “NGLS.”
We conduct our business operations through two divisions and report our results of operations under four segments: Our Natural Gas Gathering and Processing division, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing, and Wholesale Marketing.
Our natural gas gathering and processing assets are located primarily in the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. 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.
Recent Events
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 will have no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.
On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $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. Proceeds from the 11¼% Notes were used to repay borrowings under our credit facility. During the third quarter of 2009, we repurchased $18.7 million face value of the 11¼% Notes for $18.9 million plus accrued interest of $0.3 million.
On July 29, 2009, we executed a Commitment Increase Supplement to our existing senior secured credit facility, which increased the commitments under our credit facility by $127.5 million, bringing the total commitments to $977.5 million. We may request additional commitments under our credit facility of up to $22.5 million, which would increase the total commitments under our credit facility to $1 billion.
On August 12, 2009, we completed a unit offering under our shelf registration statement of 6.9 million common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds generated by the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. The proceeds were used to reduce borrowings under our credit facility by $103.5 million.
On September 24, 2009, we completed the acquisition of the Downstream Assets of Targa Resources, Inc. (the “Downstream Business”) for $530 million. See “Basis of Financial Statement Presentation” included under Note 2 of the Notes to “Supplemental Consolidated Financial Statements” in Exhibit 99.3 for information regarding the
retrospective adjustment of our financial information for the years 2006 through 2008 as entities under common control in connection with our acquisition of the Downstream Business.
Factors That Significantly Affect Our Results
Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather through our pipeline systems, which we refer to as throughput volume. Throughput volumes generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs (which maybe impacted by economic, political and regulatory development factors beyond our control).
Contract Mix. Our natural gas gathering and processing contract arrangements can have a significant impact on our profitability. Because of the significant volatility of natural gas and NGL prices, the contract mix of our natural gas gathering and processing segment can have a significant impact on our profitability. Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive environment at the time the contract is executed and customer preferences. Contract mix and, accordingly, exposure to natural gas and NGL prices may change over time as a result of changes in these underlying factors.
Set forth below is a table summarizing the contract mix of our natural gas gathering and processing division for 2008 and the potential impacts of commodity prices on operating margins:
| Contract Type | | Percent of Throughput | | Impact of Commodity Prices |
| Percent-of-Proceeds | | | 77% | | Decreases in natural gas and/or NGL prices generate decreases in operating margin. |
| Wellhead Purchases/Keep Whole | | | 20% | | Increases in natural gas prices relative to NGL prices generate decreases in operating margin. Decreases in NLG prices relative to natural gas prices generate decreases in operating margin. |
| Hybrid | | | 1% | | In periods of favorable processing economics, similar to percent-of-liquids (or wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor). In periods of unfavorable processing economics, similar to fee-based. |
| Fee-Based | | | 2% | | No direct impact from commodity price movements. |
Actual 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. We prefer to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements.
We attempt to mitigate the impact of commodity prices on our results of operations through hedging activities which can materially impact our results of operations. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Impact of Our Hedging Activities. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGLs and condensate equity volumes for the years 2009 through 2012 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. For additional information regarding our hedging activities, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
General and Administrative Expenses. Prior to the contribution of the assets of the North Texas System to us and the acquisition of the assets from the SAOU and LOU Systems and Downstream Business by us from Targa, general and administrative expenses were allocated from Targa to the North Texas, SAOU and LOU Systems and Downstream Business in accordance with the general and administrative expenses allocation policies of Targa. On February 14, 2007, we entered into an omnibus agreement with Targa, pursuant to which our allocated general and administrative expenses related to the North Texas System were capped at $5.0 million per year for three years, subject to adjustment.
On October 24, 2007, we amended and restated our omnibus agreement with Targa (the “Omnibus Agreement”). The Omnibus Agreement governs certain relationships between Targa and us, including:
| | • | Targa’s obligation to provide certain general and administrative services to us; |
| | • | our obligation to reimburse Targa and its affiliates for the provision of general and administrative services (a) subject to a cap of $5 million (relating solely to the North Texas System) in the first year, with increases in the subsequent two years based on a formula specified in the Omnibus Agreement and (b) fully allocated as to the SAOU and LOU Systems according to Targa’s previously established allocation practices; |
| | • | our obligation to reimburse Targa and its affiliates for direct expenses incurred on our behalf; and |
| | • | Targa’s obligation to indemnify us for certain liabilities and our obligation to indemnify Targa for certain liabilities. |
On September 24, 2009 we completed the acquisition of Targa’s Downstream Business. As part of the transaction, 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 for a 1.0 times distribution coverage ratio, at the current $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.
Allocated general and administrative expenses were $61.7 million, $60.4 million and $56.5 million for 2008, 2007 and 2006.
In addition to these allocated general and administrative expenses, we incur incremental general and administrative expenses as a result of operating as a separate publicly held limited partnership. These direct, incremental general and administrative expenses, which were approximately $4.2 million and $3.3 million during 2008 and 2007, including one-time expenses associated with our equity offerings, financing arrangements and acquisitions were not subject to the cap contained in the Omnibus Agreement. These costs include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, registrar and transfer agent fees and independent director compensation. These incremental general and administrative expenditures are not reflected in the historical financial statements of the North Texas, SAOU and LOU Systems, and Downstream Business.
The historical supplemental financial statements of the SAOU and LOU Systems, the North Texas System and the Downstream Business include certain items that will not impact our future results of operations and liquidity including the items described below:
Affiliate Indebtedness and Borrowings. Affiliate indebtedness prior to our acquisition of the SAOU and LOU Systems, the contribution of the North Texas System and the acquisition of the Downstream Business, consisted of borrowings incurred by Targa and allocated to us for financial reporting purposes.
Prior to Targa’s acquisition of Dynegy’s interest in Dynegy Midstream Services, Limited Partnership (the
“DMS Acquisition”), which included the North Texas System, the Predecessor Business was financed through borrowings by Targa and reflected allocated indebtedness on its balance sheet and allocated interest expense on its income statement. A substantial portion of the DMS Acquisition was also financed through borrowings by Targa. Following the October 31, 2005 DMS Acquisition, a significant portion of Targa’s acquisition borrowings were allocated to the North Texas System, resulting in approximately $870.1 million of allocated indebtedness and corresponding levels of interest expense. This indebtedness was incurred by Targa in connection with the DMS Acquisition, and the entity holding the North Texas System provided a guarantee of this indebtedness. This indebtedness was also secured by a collateral interest in both the equity of the entity holding the North Texas System as well as its assets. In connection with our IPO, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.
On February 14, 2007, we borrowed approximately $294.5 million under our credit facility. The proceeds from this borrowing, together with approximately $371.2 million of net proceeds from our IPO (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units), were used to repay approximately $665.7 million of affiliate indebtedness and the remaining balance of this indebtedness was retired and treated as a capital contribution to us.
On October 24, 2007, we completed our acquisition of the SAOU and LOU Systems concurrently with the sale of 13,500,000 common units representing limited partnership interests in us for gross proceeds of $362.7 million (approximately $349.2 million after underwriting discount and structuring fees). The net proceeds from the sale of the 13,500,000 units were used to pay approximately $2.5 million in expenses associated with the sale of the common units and $24.2 million to Targa for certain hedge transactions associated with the SAOU and LOU Systems. We used the net proceeds after offering expenses and the hedge transactions of $322.5 million along with net borrowings of $375.5 million to pay approximately $698.0 million of the acquisition costs of the SAOU and LOU Systems. The allocated indebtedness from Targa related to the SAOU and LOU Systems was $124.0 million. Targa debt was guaranteed by the entities that own the SAOU and LOU Systems and was secured by a collateral interest in both the equity interests of those entities as well as their underlying assets. In conjunction with our acquisition of the SAOU and LOU Systems, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.
On January 1, 2007, Targa contributed to us affiliated indebtedness related to the assets of Targa Downstream LP and Targa LSNG LP of approximately $639.7 million (including accrued interest of $61.8 million). During the years ended December 31, 2008 and 2007, additional affiliated indebtedness of $3.4 million and $13.0 million was incurred by Targa LSNG LP to fund the construction of its Mont Belvieu, Texas isomerization unit. During 2008 and 2007, we recorded $59.3 million and $58.5 million in interest expense associated with this affiliated debt.
Working Capital Adjustments. Prior to the contribution of the North Texas System in February 2007, the acquisition of the SAOU and LOU Systems in October 2007 and the acquisition of the Downstream Business in September 2009, all intercompany transactions, including commodity sales and expense reimbursements, were not cash settled with the Predecessor Business’ respective parent, but were recorded as an adjustment to parent equity on the balance sheet. The primary intercompany transactions between the respective parent and the Predecessor Business are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. Accordingly, the working capital of the Predecessor Business does not reflect any affiliate accounts receivable for intercompany commodity sales or affiliate accounts payable for the personnel and services provided or paid for by the applicable parent on behalf of the Predecessor Business.
Distributions to our Unitholders
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. Historically, we have relied on internally generated cash flows for these purposes. Due to the timing of our IPO, a pro-rated distribution for the first quarter of 2007 of $0.16875 per common and subordinated unit was paid.
The following table shows the distributions we paid for the period February 14, 2007 through February 13, 2009.
| | | | Distributions Paid | | | Distributions | |
| | For the Three | | Common | | | Subordinated | | | General Partner | | | | | | per limited | |
| Date Paid | Months Ended | | Units | | | Units | | | Incentive | | | | 2% | | | Total | | | partner unit | |
| | | | (In thousands, except per unit amounts) | |
| February 13, 2009 | December 31, 2008 | | $ | 17,949 | | | $ | 5,966 | | | $ | 1,933 | | | $ | 528 | | | $ | 26,376 | | | $ | 0.51750 | |
| November 14, 2008 | September 30, 2008 | | | 17,934 | | | | 5,966 | | | | 1,931 | | | | 527 | | | | 26,358 | | | | 0.51750 | |
| August 14, 2008 | June 30, 2008 | | | 17,759 | | | | 5,908 | | | | 1,711 | | | | 518 | | | | 25,896 | | | | 0.51250 | |
| May 15, 2008 | March 31, 2008 | | | 14,467 | | | | 4,813 | | | | 208 | | | | 398 | | | | 19,886 | | | | 0.41750 | |
| February 14, 2008 | December 31, 2007 | | | 13,768 | | | | 4,582 | | | | 66 | | | | 376 | | | | 18,792 | | | | 0.39750 | |
| November 14, 2007 | September 30, 2007 | | | 11,082 | | | | 3,891 | | | | - | | | | 305 | | | | 15,278 | | | | 0.33750 | |
| August 14, 2007 | June 30, 2007 | | | 6,526 | | | | 3,890 | | | | - | | | | 212 | | | | 10,628 | | | | 0.33750 | |
| May 15, 2007 | March 31, 2007 | | | 3,263 | | | | 1,945 | | | | - | | | | 107 | | | | 5,315 | | | | 0.16875 | |
General Trends and Outlook
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply and Outlook. Fluctuations in energy prices can affect production rates and investments by third parties in the development of new natural gas reserves. Generally, drilling and production activity will increase as natural gas prices increase and decrease as natural gas prices decrease.
Significant Relationships. Our largest suppliers of natural gas are Crosstex Energy, a gas gatherer that sells to us on a spot basis, and ConocoPhillips Company, representing 12% and 11% of the natural gas supplied to our system for 2008; and 11% and 12% of the natural gas supplied to our system for 2007.
During 2008 and 2007, approximately 22% and 24% of our consolidated revenues, and approximately 8% and 11% of our consolidated product purchases, were derived from transactions with Chevron and CPC. No other third party customer accounted for more than 10% of our consolidated revenues during these periods.
Commodity Prices. 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. The current weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which has caused a reduction in profitability of our processing operations. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigate our exposure to commodity price movements by entering into hedging arrangements. For additional information regarding our hedging activities, See “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, extremely volatile and disrupted and the current weak economic conditions have recently caused 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.
How We Evaluate Our Operations
Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas that we purchase as well as operating and general and administrative costs. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the natural gas and NGL throughput on our system are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, demand for our products and changes in our customer mix.
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) throughput volumes, (2) facility efficiencies and fuel consumption, (3) operating margin, (4) operating expenses, (5) Adjusted EBITDA and (6) distributable cash flow.
Throughput Volumes, Facility Efficiencies and Fuel Consumption. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our systems. This is achieved by connecting new wells, adding new volumes in existing areas of production as well as by capturing supplies currently gathered by third parties.
In addition, we seek to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. This information is tracked through our processing plants to determine customer settlements and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plants to monitor the fuel consumption and recoveries of the facilities. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.
Operating Margin. We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases, and operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail below. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis.
The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
We compensate for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into our decision-making processes.
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Reconciliation of net income (loss) attributable to Targa | | (In millions) | |
| Resources Partners LP to operating margin: | | | | | | | | | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 49.4 | | | $ | 35.1 | | | $ | (23.0 | ) |
| Add: | | | | | | | | | | | | |
| Depreciation and amortization expense | | | 97.8 | | | | 93.5 | | | | 90.7 | |
| General and administrative and other expense | | | 67.7 | | | | 63.7 | | | | 57.3 | |
| Interest expense, net | | | 97.1 | | | | 99.4 | | | | 127.1 | |
| Income tax expense | | | 2.4 | | | | 2.5 | | | | 3.4 | |
| Gain on debt repurchases | | | (13.1 | ) | | | - | | | | - | |
| (Gain) loss related to derivatives | | | 1.0 | | | | 30.2 | | | | (16.8 | ) |
| Other, net | | | (5.0 | ) | | | (2.3 | ) | | | (3.2 | ) |
| Operating margin (1) | | $ | 297.3 | | | $ | 322.1 | | | $ | 235.5 | |
________
| | (1) | Includes non-cash charges related to commodity hedges of $1.0 million, $30.2 million and ($16.8) million for 2008, 2007 and 2006 and affiliated interest expense of $59.2 million and $58.5 million for 2008 and 2007. |
Our operating margin by segment and in total is as follows for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Natural Gas Gathering and Processing | | $ | 215.8 | | | $ | 203.8 | | | $ | 171.7 | |
| Logistics Assets | | | 49.9 | | | | 40.0 | | | | 42.6 | |
| NGL Distribution and Marketing Services | | | 18.5 | | | | 55.5 | | | | 10.6 | |
| Wholesale Marketing | | | 13.1 | | | | 22.8 | | | | 10.6 | |
| | | $ | 297.3 | | | $ | 322.1 | | | $ | 235.5 | |
We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:
| | · | 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. |
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repair and maintenance, utilities and contract services compose the most significant portion of our operating expenses. These expenses generally remain relatively stable independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.
Adjusted EBITDA. Adjusted EBITDA is another non-GAAP financial measure that is used by us. 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, 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. |
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. Our non-GAAP financial measure of 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.
We compensate 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 our decision-making processes.
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Reconciliation of net cash provided by | | (In millions) | |
| operating activities to Adjusted EBITDA: | | | | | | | | | |
| Net cash provided by operating activities | | $ | 293.0 | | | $ | 268.3 | | | $ | 169.9 | |
| Net income attributable to noncontrolling interest | | | (0.3 | ) | | | (0.1 | ) | | | 0.6 | |
| Interest expense, net (1) | | | 35.8 | | | | 39.1 | | | | 118.0 | |
| Gain on debt repurchases | | | 13.1 | | | | - | | | | - | |
| Termination of commodity derivatives | | | 87.4 | | | | - | | | | - | |
| Current income tax expense | | | 0.6 | | | | 0.6 | | | | - | |
| Other | | | 3.7 | | | | (1.5 | ) | | | (0.6 | ) |
| Changes in operating assets and liabilities which | | | | | | | | | | | | |
| used (provided) cash: | | | | | | | | | | | | |
| Accounts receivable and other assets | | | (658.2 | ) | | | 145.7 | | | | (71.1 | ) |
| Accounts payable and other liabilities | | | 494.3 | | | | (191.6 | ) | | | (37.6 | ) |
| Adjusted EBITDA | | $ | 269.4 | | | $ | 260.5 | | | $ | 179.2 | |
________
| | (1) | Net of amortization of debt issuance costs of $2.1 million, $1.8 million and $9.1 million for 2008, 2007 and 2006. |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Reconciliation of net income (loss) attributable to Targa | | (In millions) | |
| Resources Partners LP to Adjusted EBITDA: | | | | | | | | | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 49.4 | | | $ | 35.1 | | | $ | (23.0 | ) |
| Add: | | | | | | | | | | | | |
| Interest expense, net | | | 97.1 | | | | 99.4 | | | | 127.1 | |
| Income tax expense | | | 2.4 | | | | 2.5 | | | | 3.4 | |
| Depreciation and amortization expense | | | 97.8 | | | | 93.5 | | | | 90.7 | |
| Non-cash (gain) loss related to derivatives | | | 23.4 | | | | 30.8 | | | | (18.3 | ) |
| Noncontrolling interest adjustment | | | (0.7 | ) | | | (0.8 | ) | | | (0.7 | ) |
| Adjusted EBITDA | | $ | 269.4 | | | $ | 260.5 | | | $ | 179.2 | |
Distributable Cash Flow. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).
The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors.
The GAAP measure most directly comparable to distributable cash flow is net income. Our non-GAAP measure of distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility.
We compensate for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision making processes.
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Reconciliation of net income (loss) attributable to Targa | | (In millions) | |
| Resources Partners LP distributable cash flow: | | | | | | | | | |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 49.4 | | | $ | 35.1 | | | $ | (23.0 | ) |
| Depreciation and amortization expense | | | 97.8 | | | | 93.5 | | | | 90.7 | |
| Deferred income tax expense | | | 1.8 | | | | 1.9 | | | | 3.4 | |
| Amortization in interest expense | | | 2.1 | | | | 1.8 | | | | 9.1 | |
| Gain on debt repurchases | | | (13.1 | ) | | | - | | | | - | |
| Non-cash (gain) loss related to derivatives | | | 23.4 | | | | 30.8 | | | | (18.3 | ) |
| Maintenance capital expenditures | | | (40.3 | ) | | | (30.4 | ) | | | (25.1 | ) |
| Other | | | (0.4 | ) | | | (0.5 | ) | | | (0.5 | ) |
| Distributable cash flow | | $ | 120.7 | | | $ | 132.2 | | | $ | 36.3 | |
Results of Operations
The following table summarizes the key components of our results of operations for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Revenues (1) | | $ | 7,473.4 | | | $ | 6,816.1 | | | $ | 5,907.5 | |
| Product purchases | | | 6,922.1 | | | | 6,274.4 | | | | 5,478.9 | |
| Operating expenses | | | 254.0 | | | | 219.6 | | | | 193.1 | |
| Depreciation and amortization expense | | | 97.8 | | | | 93.5 | | | | 90.7 | |
| General and administrative expense | | | 68.6 | | | | 64.0 | | | | 57.3 | |
| Other | | | (0.9 | ) | | | (0.3 | ) | | | - | |
| Income from operations | | | 131.8 | | | | 164.9 | | | | 87.5 | |
| Interest expense, net | | | (97.1 | ) | | | (99.4 | ) | | | (127.1 | ) |
| Equity in earnings of unconsolidated investment | | | 3.9 | | | | 3.5 | | | | 2.8 | |
| Gain on debt repurchases | | | 13.1 | | | | - | | | | - | |
| Gain (loss) on mark-to-market derivative instruments | | | (1.0 | ) | | | (30.2 | ) | | | 16.8 | |
| Other | | | 1.4 | | | | (1.1 | ) | | | (0.2 | ) |
| Income tax expense | | | (2.4 | ) | | | (2.5 | ) | | | (3.4 | ) |
| Net income (loss) | | | 49.7 | | | | 35.2 | | | | (23.6 | ) |
| Less: Net income (loss) attributable to noncontrolling interest | | | 0.3 | | | | 0.1 | | | | (0.6 | ) |
| Net income (loss) attributable to Targa Resources Partners LP | | $ | 49.4 | | | $ | 35.1 | | | $ | (23.0 | ) |
| Financial and operating data: | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | |
| Operating margin (2) | | $ | 297.3 | | | $ | 322.1 | | | $ | 235.5 | |
| Adjusted EBITDA (3) | | | 269.4 | | | | 260.5 | | | | 179.2 | |
| Distributable cash flow (4) | | | 120.7 | | | | 132.2 | | | | 36.3 | |
| Operating data: | | | | | | | | | | | | |
| Gathering throughput, MMcf/d (5) | | | 445.8 | | | | 452.0 | | | | 433.8 | |
| Plant natural gas inlet, MMcf/d (6) (7) | | | 421.2 | | | | 429.2 | | | | 419.6 | |
| Gross NGL production, MBbl/d | | | 42.0 | | | | 42.6 | | | | 42.4 | |
| Natural gas sales, BBtu/d (7) | | | 415.6 | | | | 410.2 | | | | 489.4 | |
| NGL sales, MBbl/d | | | 278.1 | | | | 310.1 | | | | 290.1 | |
| Condensate sales, MBbl/d | | | 3.6 | | | | 3.6 | | | | 3.3 | |
| Average realized prices: | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 8.45 | | | | 6.60 | | | | 6.62 | |
| NGL, $/gal | | | 1.39 | | | | 1.19 | | | | 1.02 | |
| Condensate, $/Bbl | | | 82.52 | | | | 65.63 | | | | 59.87 | |
________
| | (1) | Includes business interruption insurance revenues of $18.6 million, $4.6 million and $7.0 million for the years ended 2008, 2007 and 2006. |
| | (2) | Operating margin is revenues less product purchases and operating expense. See “How We Evaluate Our Operations.” |
| | (3) | Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. See “How We Evaluate Our Operations.” |
| | (4) | Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts, less maintenance capital expenditures. See “How We Evaluate Our Operations.” |
| | (5) | Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points. |
| | (6) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. |
| | (7) | Plant inlet volumes include producer take-in-kind, while natural gas sales exclude producer take-in-kind volumes. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased by $657.3 million, or 10%, to $7,473.4 million for 2008 compared to $6,816.1 million for 2007. Revenues from the sale of natural gas increased by $291.7 million, consisting of increases of $275.9 million due to higher realized prices and $15.8 million due to higher sales volumes. Revenues from the sale of NGL increased by $306.5 million, consisting of an increase of $875.6 million due to higher realized prices, partially offset by a decrease of $569.1 million due to lower sales volumes. Revenues from the sale of condensate increased by $23.2 million, consisting of increases of $22.2 million due to higher realized prices and $1.0 million due to higher sales volumes. Non-commodity revenues, which principally include revenues derived from fee-based services and business interruption insurance, increased by $35.9 million.
Our average realized prices for natural gas increased by $1.85 per MMBtu, or 28%, to $8.45 per MMBtu for 2008 compared to $6.60 per MMBtu for 2007. Our average realized prices for NGL increased by $0.20 per gallon, or 17%, to $1.39 per gallon for 2008 compared to $1.19 per gallon for 2007. Our average realized price for condensate increased by $16.89, or 26%, to $82.52 per barrel for 2008 compared to $65.63 per barrel for 2007.
Natural gas sales volumes increased by 5.4 BBtu per day, or 1%, to 415.6 BBtu per day for 2008 compared to 410.2 BBtu per day for 2007. NGL sales volumes decreased by 32.0 MBbl per day, or 10%, to 278.1 MBbl per day for 2008 compared to 310.1 MBbl per day for 2007. Condensate sales volumes remained unchanged for 2008 compared to 2007. For information regarding the period to period changes in our commodity sales volumes, see “Results of Operations—By Segment.”
Product purchases increased by $647.7 million, or 10%, to $6,922.1 million for 2008 compared to $6,274.4 million for 2007. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.
Operating expenses increased by $34.4 million, or 16%, to $254.0 million for 2008 compared to $219.6 million for 2007. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.
Depreciation and amortization expense increased by $4.3 million, or 5%, to $97.8 million for 2008 compared to $93.5 million for 2007. The increase is primarily attributable to a 22% increase in purchases of property, plant and equipment for 2008 compared to 2007.
General and administrative expense increased by $4.6 million, or 7%, to $68.6 million for 2008 compared to $64.0 million for 2007. The increase included increases in compensation related expenses, professional services, allocated corporate level expenses and insurance expenses.
Interest expense decreased by $2.3 million, or 2%, to $97.1 million for 2008 compared to $99.4 million for 2007. The decrease is primarily from lower average outstanding debt during 2008. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.
Gain on debt repurchases of $13.1 million for 2008 relates to open market repurchases of our 8¼% Senior Notes due 2016.
Our loss on mark-to-market derivative instruments was $1.0 million for 2008 compared to $30.2 million for 2007. During 2008 we adjusted the fair value of certain contracts with Lehman Brothers Commodity Services Inc. to zero as a result of the Lehman Brothers bankruptcy filing. The 2007 loss resulted from derivative financial instruments that did not qualify for hedge accounting.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues increased by $908.6 million, or 15%, to $6,816.1 million for 2007 compared to $5,907.5 million for 2006. Revenues from the sale of natural gas decreased by $189.7 million, consisting of a decrease of $191.4 million due to lower sales volume partially offset by an increase of $1.7 million due to higher realized prices. Revenues from the sale of NGLs increased by $1,081.3 million, consisting of increases of $766.1 million due to higher realized prices and $315.2 million due to higher sales volumes. Revenues from the sale of condensate increased by $12.2 million, consisting of an increase of $4.8 million due to higher sales volumes and $7.4 million due to higher realized prices. Non-commodity revenues, which principally include revenues derived from fee-based services and business interruption insurance, increased by $4.8 million.
Our average realized prices for natural gas decreased by $0.02 per MMBtu, or less than 1%, to $6.60 per MMBtu for 2007 compared to $6.62 per MMBtu for 2006. Our average realized prices for NGL increased by $0.17 per gallon, or 17%, to $1.19 per gallon for 2007 compared to $1.02 per gallon for 2006. Our average realized price for condensate increased by $5.76 per barrel, or 10%, to $65.63 per barrel for 2007 compared to $59.87 per barrel for 2006.
Natural gas sales volumes decreased by 79.2 BBtu per day, or 16%, to 410.2 BBtu per day for 2007 compared to 489.4 BBtu per day for 2006. NGL sales volumes increased by 20.0 MBbl per day, or 7%, to 310.1 MBbl per day for 2007 compared to 290.1 MBbl per day for 2006. Condensate sales volumes increased by 0.3 MBbl per day, or 9%, to 3.6 MBbl per day for 2007 compared to 3.3 MBbl per day for 2006. For information regarding the period to period changes in our commodity sales volumes, see “Results of Operations—By Segment.”
Product purchases increased by $795.5 million, or 15%, to $6,274.4 million for 2007 compared to $5,478.9 million for 2006. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.
Operating expenses increased by $26.5 million, or 14%, to $219.6 million for 2007 compared to $193.1 million for 2006. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.
Depreciation and amortization expense for 2007 was $93.5 million compared to $90.7 million for 2006, an increase of $2.8 million or 3%. The increase is due to the higher carrying value of property, plant and equipment as a result of plant and gathering system expansions.
General and administrative expense increased by $6.7 million, or 12%, to $64.0 million for 2007 compared to $57.3 million for 2006. The increased included increases in insurance expenses, professional services, compensation related expenses and other general and administrative expenses, partially offset by a decrease in allocated corporate level expenses.
Interest expense decreased by $27.7 million, or 22%, to $99.4 million for 2007 compared to $127.1 million for 2006. The decrease is primarily the result of lower average debt during 2007, partially offset by the effect of higher interest rates during 2007. See “Liquidity and Capital Resources” in this Item 7 for information regarding our outstanding debt obligations.
Results of Operations—By Segment
Natural Gas Gathering and Processing Segment
The following table provides summary financial data regarding results of operations in our Natural Gas Gathering and Processing segment for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Revenues | | $ | 2,074.1 | | | $ | 1,661.5 | | | $ | 1,738.5 | |
| Product purchases | | | (1,803.0 | ) | | | (1,406.8 | ) | | | (1,517.7 | ) |
| Operating expenses | | | (55.3 | ) | | | (50.9 | ) | | | (49.1 | ) |
| Operating margin (1) | | $ | 215.8 | | | $ | 203.8 | | | $ | 171.7 | |
| Operating statistics: (2) | | | | | | | | | | | | |
| Gathering throughput, MMcf/d | | | 445.8 | | | | 452.0 | | | | 433.8 | |
| Plant natural gas inlet, MMcf/d | | | 421.2 | | | | 429.2 | | | | 419.6 | |
| Gross NGL production, MBbl/d | | | 42.0 | | | | 42.6 | | | | 42.4 | |
| Natural gas sales, BBtu/d | | | 415.6 | | | | 410.2 | | | | 489.4 | |
| NGL sales, MBbl/d | | | 37.3 | | | | 36.4 | | | | 36.0 | |
| Condensate sales, MBbl/d | | | 3.6 | | | | 3.6 | | | | 3.3 | |
| Average realized prices: | | | | | | | | | | | | |
| Natural gas, $/MMBtu | | | 8.45 | | | | 6.60 | | | | 6.62 | |
| NGL, $/gal | | | 1.17 | | | | 1.03 | | | | 0.85 | |
| Condensate, $/Bbl | | | 82.52 | | | | 65.63 | | | | 59.87 | |
________
| (1) | See “How We Evaluate Our Operations.” |
| (2) | 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, 2008 Compared to Year Ended December 31, 2007
Revenues. Revenues increased $412.6 million, or 25%, to $2,074.1 million for 2008 compared to $1,661.5 million for 2007. The increase was primarily due to the following factors:
| | · | an increase attributable to prices of $383.5 million, consisting of increases in natural gas, NGL, and condensate revenues of $280.5million, $80.8 million, and $22.2 million; |
| | · | an increase attributable to volumes of $32.2 million, consisting of increases in natural gas, NGL and condensate revenues of $15.7 million, $15.5 million, and $1.0 million; and |
| | · | an increase in fee and other revenues of $3.1 million. |
Average realized prices for our sales of:
| | · | natural gas increased by $1.85 per MMBtu, or 28%, to $8.45 per MMBtu during 2008 compared to $6.60 per MMBtu for 2007. |
| | · | NGLs increase by $0.14 per gallon, or 14%, to $1.17 per gallon for 2008 compared to $1.03 per gallon for 2007. |
| | · | condensate increased by $16.89 per Bbl, or 26%, to $82.52 per Bbl for 2008 compared to $65.63 per Bbl for 2007. |
Natural gas sales volume increased by 5.4 BBtu/d or 1%, to 415.6 BBtu/d during 2008 compared to 410.2 BBtu/d for 2007 due to a lower proportion of take-in-kind volumes, increased marketing activity and the effects of unfavorable processing economics. Net NGL sales increased by 0.9 MBbl/d or 2%, to 37.3 MBbl/d for 2008 compared to 36.4 MBbl/d for 2007. Condensate sales remained flat at 3.6 MBbl/d.
Product Purchases. Product purchases during 2008 were $1,803.0 million, which increased by $396.2 million or 28%, compared to $1,406.8 million during 2007. The increase in product purchases corresponds with the increase in commodity revenue for 2008.
Operating Expenses. Operating expenses during 2008 were $55.3 million, which increased by $4.4 million or 9%, compared to $50.9 million during 2007. The increase in operating expenses was primarily the result of increases in general maintenance and supplies, lube oil, environmental and automotive expenses, compensation related expenses and ad valorem taxes.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues. Revenues decreased by $77.0 million or 4%, to $1,661.5 million for 2007 compared to $1,738.5 million for 2006. This decrease was primarily due to the following:
| | · | a net increase attributable to prices of $102.5 million, consisting of a decrease in natural gas revenues of $3.9 million and increases in NGL and condensate revenues of $99.0 million and $7.4 million; |
| | · | a net decrease attributable to volumes of $181.2 million, consisting of a decrease in natural gas revenues of $191.6 million and increases of NGL and condensate revenues of $5.7 million and $4.8 million; and |
| | · | a decrease in fee and other revenues of $1.6 million. |
Average realized prices for our sales of:
| | · | natural gas decreased by $0.02 per MMBtu or less than 1%, to $6.60 per MMBtu during 2007 compared to $6.62 per MMBtu for 2006. |
| | · | NGLs increased by $0.18 per gallon or 21%, to $1.03 per gallon for 2007 compared to $0.85 per gallon for 2006. |
| | · | condensate increased by $5.76 per Bbl or 10%, to $65.63 per Bbl for 2007 compared to $59.87 per Bbl for 2006. |
Natural gas sales volume decreased by 79.2 BBtu/d or 16%, to 410.2 BBtu/d during 2007 compared to 489.4 BBtu/d for 2006. The decrease in sales of natural gas volumes was attributable to a net decrease in natural gas purchased from affiliates and increased take-in-kind volumes by producers for whom we process natural gas, offset by net increases in other non-wellhead supply sources and wellhead supplies attributable to additional well connections which were partially offset by the natural decline of field production. Net NGL sales increased by 0.4 MBbl/d or 1%, to 36.4 MBbl/d for 2007 compared to 36.0 MBbl/d for 2006. The volume increase was primarily attributable to additional well connections partially offset by the natural decline in field production. Condensate production increased by 0.3 MBbl/d or 9%, to 3.6 MBbl/d for 2007 compared to 3.3 MBbl/d for 2006.
Product Purchases. Product purchases during 2007 were $1,406.8 million, a decrease of $110.9 million or 7%, compared to $1,517.7 million during 2006.
Operating Expenses. Operating expenses during 2007 were $50.9 million, an increase of $1.8 million or 4%, compared to $49.1 million during 2006. The increase was partially attributable to increased operating costs due to our processing plant and gathering system expansions, as well as increased prices for labor, supplies and equipment.
Logistics Assets Segment
The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Revenues from services | | $ | 235.5 | | | $ | 195.1 | | | $ | 177.7 | |
| Other revenues (1) | | | 2.5 | | | | - | | | | 0.4 | |
| | | | 238.0 | | | | 195.1 | | | | 178.1 | |
| Operating expenses | | | (188.1 | ) | | | (155.1 | ) | | | (135.5 | ) |
| Operating margin (2) | | $ | 49.9 | | | $ | 40.0 | | | $ | 42.6 | |
| Equity in earnings of GCF | | $ | 3.9 | | | $ | 3.5 | | | $ | 2.8 | |
| Operating statistics: | | | | | | | | | | | | |
| Fractionation volumes, MBbl/d | | | 212.2 | | | | 209.2 | | | | 181.9 | |
| Treating volumes, MBbl/d (3) | | | 20.7 | | | | 9.1 | | | | - | |
________
| (1) | Includes business interruption insurance revenues of $2.5 million and $0.4 million for 2008 and 2006. |
| (2) | See “How We Evaluate Our Operations.” |
| (3) | Consists of the volumes treated in our low sulfur natural gasoline (“LSNG”) unit, which began commercial operations in June 2007. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues from fractionation, terminalling and storage, transport, and treating increased $40.4 million, or 21%, to $235.5 million for 2008 compared to $195.1 million for 2007. The increase was due to higher service rates, a full year of commercial operations at our LSNG unit in 2008 compared to six months of operations in 2007, increased treating and related service revenues, additional transport fees from spot barge activity and additional terminalling revenue from a new common carrier connection.
Operating expenses increased $33.0 million, or 21%, to $188.1 million for 2008 compared to $155.1 million for 2007. The increase was primarily the result of higher fuel and utilities expense, increased LSNG unit and other facility maintenance costs, plant turnaround costs and third-party fractionation expense, additional barge activity, inventory adjustments and pipeline integrity costs.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues from fractionation, terminalling and storage, transport, and treating increased $17.4 million, or 10%, to $195.1 million for 2007 compared to $177.7 million for 2006. The increase was primarily the result of higher service rates for 2007 compared to 2006, the commencement of commercial operations at our LSNG unit in June 2007 and higher fractionation volumes. These increases were partially offset by the effect of lower terminalling and storage and transport volumes.
Higher service rates for 2007 compared to 2006 were derived primarily from commercial transportation activities. These include new barge transportation contracts for mixed butanes and propane/propylene mix, new railcar lease revenue earned from the NGL Distribution and Marketing and Wholesale Marketing segment and increased truck transportation fees as a result of an increased fuel surcharge.
The overall volume increase was due to higher fractionation and LSNG related service volumes in 2007 compared to 2006, partially offset by lower terminalling and storage volumes primarily due to lower imports. Our fractionation facilities operated at 75% and 66% of design capacity for 2007 and 2006.
Operating expenses increased $19.6 million, or 14%, to $155.1 million for 2007 compared to $135.5 million for 2006. This increase is primarily due to:
| | · | increased railcar lease expense as a result of new railcar leases following the termination of a railcar sharing agreement. Under the railcar sharing agreement, rail transportation costs were included in product purchases in our NGL Distribution and Marketing and Wholesale Marketing segments; |
| | · | the June 2007 commencement of commercial operations at our new LSNG unit, which added to operating expenses; |
| | · | increased fractionation-related expenses due to higher fractionation volumes and increased fuel costs; |
| | · | higher barge transportation costs, caused by an increase in tug rates; and |
| | · | increased terminalling and storage costs due to the timing of well workovers at Mont Belvieu. |
NGL Distribution and Marketing Services Segment
The following table provides summary financial data regarding results of operations of our NGL Distribution and Marketing Services segment for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| NGL sales revenues | | $ | 5,172.2 | | | $ | 4,889.3 | | | $ | 3,728.4 | |
| Other revenues (1) | | | 12.5 | | | | 6.5 | | | | 10.4 | |
| | | | 5,184.7 | | | | 4,895.8 | | | | 3,738.8 | |
| Product purchases | | | (5,164.5 | ) | | | (4,838.8 | ) | | | (3,726.2 | ) |
| Operating expenses | | | (1.7 | ) | | | (1.5 | ) | | | (2.0 | ) |
| Operating margin (2) | | $ | 18.5 | | | $ | 55.5 | | | $ | 10.6 | |
| Operating statistics: | | | | | | | | | | | | |
| NGL sales, MBbl/d | | | 244.6 | | | | 275.6 | | | | 246.3 | |
| NGL realized price, $/gal | | | 1.38 | | | | 1.16 | | | | 0.99 | |
________
| (1) | Includes business interruption insurance revenues of $9.6 million, $3.8 million and $5.5 million for 2008, 2007 and 2006. |
| (2) | See “How We Evaluate Our Operations.” |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased $288.9 million, or 6%, to $5,184.7 million for 2008 compared to $4,895.8 million for 2007. Higher market prices increased revenue $820.6 million partially offset by lower sales volume, which decreased revenue by $537.8 million. The increase in other revenues was primarily from increased business interruption insurance revenues during 2008.
NGL sales decreased 31.0 MBbl/d, or 11%, to 244.6 MBbl/d for 2008 compared to 275.6 MBbl/d for 2007. The decrease was primarily the result of disruptions due to hurricanes Gustav and Ike as well as reduced petrochemical operating rates for 2008 as compared to 2007.
Product purchases increased $325.7 million, or 7%, to $5,164.5 million for 2008 compared to $4,838.8 million for 2007. Higher market prices increased product purchases by $857.9 million partially offset by lower volumes, which decreased product purchases by $532.2 million.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues increased $1,157.0 million, or 31%, to $4,895.8 million for 2007 compared to $3,738.8 million for 2006. The net increase comprised a $443.6 million increase as a result of higher sales volumes, a $717.3 million
increase due to higher commodity prices, a $2.2 million decrease in non-commodity revenues, which are principally derived from fee-based services, and a $1.7 million decrease in business interruption insurance revenues.
NGL sales increased 29.3 MBbl/d, or 12%, to 275.6 MBbl/d for 2007 compared to 246.3 MBbl/d for 2006. The increase was primarily the result of a new source of raw product supply; sales of production from Gillis, Mertzon, and Sterling plants which prior to April 2006 were marketed by our Natural Gas Gathering and Processing segment; increased sales of production from our Yscloskey facility which was not in operation during a portion of 2006 as a result of damage from hurricanes Katrina and Rita during 2005.
Our average realized price for NGLs increased $0.17 per gallon, or 17%, to $1.16 per gallon for 2007 compared to $0.99 per gallon for 2006.
Product purchases increased $1,112.6 million, or 30%, to $4,838.8 million for 2007 compared to $3,726.2 million for 2006. Higher average market prices increased product purchases by $669.3 million and higher volumes increased product purchases by $443.1 million.
Wholesale Marketing Segment
The following table provides summary financial data regarding results of operations of our Wholesale Marketing segment for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| NGL sales revenues | | $ | 1,453.3 | | | $ | 1,294.7 | | | $ | 1,302.5 | |
| Other revenues (1) | | | 6.8 | | | | 1.2 | | | | 7.9 | |
| | | | 1,460.1 | | | | 1,295.9 | | | | 1,310.4 | |
| Product purchases | | | (1,446.9 | ) | | | (1,273.1 | ) | | | (1,299.8 | ) |
| Operating expenses | | | (0.1 | ) | | | - | | | | - | |
| Operating margin (2) | | $ | 13.1 | | | $ | 22.8 | | | $ | 10.6 | |
| Operating statistics: | | | | | | | | | | | | |
| NGL sales, MBbl/d | | | 62.5 | | | | 63.6 | | | | 73.2 | |
| NGL realized price, $/gal | | | 1.51 | | | | 1.33 | | | | 1.16 | |
________
| (1) | Includes business interruption insurance revenues of $6.5 million, $0.8 million and $1.1 million for 2008, 2007 and 2006. |
| (2) | See “How We Evaluate Our Operations.” |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased $164.2 million, or 13%, to $1,460.1 million for 2008 compared to $1,295.9 million for 2007. Higher NGL market prices increased revenue $177.4 million partially offset by lower sales volume, which decreased revenue by $18.9 million. The increase in other revenues consists of a $5.7 million increase in business interruption insurance revenues.
Our average realized price for NGL increased $0.18 per gallon, or 14%, to $1.51 per gallon for 2008 compared to $1.33 per gallon for 2007. The increase was primarily due to higher overall market prices for all components. However, market prices dropped significantly in the fourth quarter of 2008 quarter due to overall market conditions. NGL sales decreased 1.1 MBbl/d, or 2%, to 62.5 MBbl/d for 2008 compared to 63.6 MBbl/d for 2007. The decrease in volumes is due primarily to the expiration of refinery supply agreements and an operating disruption at a customer facility.
Product purchases increased $173.8 million, or 14%, to $1,446.9 million for 2008 compared to $1,273.1 million for 2007. Higher NGL market prices and lower of cost or market adjustments increased product purchases by
$186.4 million and $6.0 million partially offset by lower volumes, which decreased product purchases by $18.6 million.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues decreased $14.5 million, or 1%, to $1,295.9 million for 2007 compared to $1,310.4 million for 2006. Lower NGL sales volumes decreased revenues by $170.2 million and higher commodity prices increased revenues by $162.4 million. The decrease in other revenues consists primarily of a $6.7 million decrease in fee-based service revenue due to the termination of certain refinery service contracts.
NGL sales decreased 9.6 MBbl/d, or 13%, to 63.6 MBbl/d for 2007 compared to 73.2 MBbl/d for 2006. The decrease is primarily due to direct and indirect impacts of terminated feedstock contracts with Chevron that ended in September 2006.
Product purchases decreased $26.7 million, or 2%, to $1,273.1 million for 2007 compared to $1,299.8 million for 2006. Lower NGL volumes decreased product purchases by $169.9 million partially offset by higher market prices, which increased product purchases by $140.2 million. We incurred a smaller lower of cost or market adjustment in 2007 versus 2006 by $3.0 million.
Insurance Claims
We recognize income from business interruption insurance in our combined 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 2008, income from business interruption insurance resulting from the effects of Hurricanes Katrina and Rita was $18.1 million. In addition, we received $0.6 million during 2008 as a result of fire damage claims at certain plants in our Wholesale Marketing segment.
Hurricanes Gustav and Ike
In September 2008, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from Hurricanes Gustav and Ike.
We currently estimate the cost associated with our interest for repairs to the impacted facilities to be approximately $17.4 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $3.3 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance.
During 2008 we recorded a loss provision of $4.8 million for our estimated out-of-pocket cleanup and repair costs related to these two hurricanes, after estimated insurance proceeds. As of December 31, 2008, expenditures related to the hurricanes totaled $5.5 million.
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, to meet our collateral requirements, or to pay our distributions 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 credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis 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. In order to increase our cash position in the face of the credit and capital market disruptions, on October 16, 2008, we requested a $100 million funding under our credit facility. Lehman Bank, a lender under our credit facility, defaulted on its portion of this borrowing request, resulting in actual funding of $97.8 million. As a result, we believe the availability under our credit facility has been effectively reduced by $10.0 million.
Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell a significant portion of 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 and have recently declined significantly. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2012. 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. In the event of a global recession, commodity prices may stay depressed or fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.
As of December 31, 2008, we had liquidity of $433.8 million, including $91.3 million of available cash and $342.5 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the other twenty three lenders in our credit facility. To date, other than the Lehman Bank default, we have experienced no disruptions in our ability to access funds committed under our credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment.
Historically, our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures, with remaining amounts being distributed to Targa during its period of ownership and to our unitholders since our IPO. 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 facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, hurricane-related repair expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.
We intend to make cash distributions to our unitholders and our general partner in an amount at least equal to 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. Historically, we have relied on internally generated cash flows for these purposes. See “—Factors That Significantly
Affect Our Results—Distributions to our Unitholders” for a table that shows the distributions we declared subsequent to the fourth quarter of 2008 and distributions declared and paid in 2008 and 2007.
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 because 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.
Prior to the contribution of the North Texas System in February 2007, the acquisition of the SAOU and LOU Systems in October 2007 and the acquisition of the Downstream Business in September 2009, all intercompany transactions, including commodity sales and expense reimbursements, were not cash settled with Targa, but were recorded as an adjustment to parent equity on the balance sheet. The primary transactions between Targa and us are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. As a result of this accounting treatment, our working capital did not reflect any affiliate accounts receivable for intercompany commodity sales or any affiliate accounts payable for the personnel and services provided by or paid for by our parent prior to the acquisition of the North Texas System and the subsequent acquisition of the SAOU and LOU Systems.
As of December 31, 2008, we had a positive working capital balance of $224.5 million.
The Partnership is obligated to make minimum quarterly cash distributions to unitholders from available cash, as defined in the partnership agreement. As of December 31, 2008, such minimum amounts payable to non-Targa unitholders total approximately $46.8 million annually.
Cash Flow
The following table summarizes cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Net cash provided by (used in): | | | | | | | | | |
| Operating activities | | $ | 293.0 | | | $ | 268.3 | | | $ | 169.9 | |
| Investing activities | | | (86.1 | ) | | | (76.8 | ) | | | (54.6 | ) |
| Financing activities | | | (175.9 | ) | | | (139.7 | ) | | | (110.7 | ) |
Operating Activities
Net cash provided by operating activities was $293.0 million for 2008 compared to $268.3 million for 2007. The $24.7 million increase was primarily due to changes in operating assets and liabilities, which provided $163.9 million in cash during 2008, compared to providing $45.9 million in cash during 2007, partially offset by an $87.4 million payment during 2008 to terminate certain out-of-the-money commodity derivatives.
Net cash provided by operating activities was $268.3 million for 2007 compared to $169.9 million for 2006. The $98.4 million increase is primarily due to a $58.8 million increase in net income, a $58.5 million increase in accrued interest expense, and a $49.0 million increase in noncash risk management charges, partially offset by a $62.8 million increase in working capital balances and a $7.3 million decrease in amortized debt issue costs.
Investing Activities
Net cash used in investing activities was $86.1 million for 2008 compared to $76.8 million for 2007. The $9.3 million increase is primarily due to increased capital expenditures during 2008. The increase is primarily from increased expenditures related to gathering system expansion projects begun in the third quarter of 2008.
Net cash used in investing activities was $76.8 million for 2007 compared to $54.6 million for 2006. The $22.2 million increase is primarily due to the completion of gathering system expansion projects; high major maintenance expenditures and the completion of construction of our low sulfur natural gasoline unit (see discussion below of “Capital Requirements”).
Financing Activities
Net cash used in financing activities was $175.9 million for 2008 compared to net cash used in financing activities of $139.7 million for 2007. The $36.2 million increase is primarily due to $772.8 million of nonrecurring net proceeds from equity offerings in 2007, a $285.6 million decrease in proceeds from borrowings, a $59.7 million increase in distributions to unitholders, and a $26.8 million repurchase of senior notes in 2008, partially offset by a $671.7 million net decrease in distributions to Targa and a $436.9 million decrease in repayments of indebtedness.
Net cash used in financing activities was $139.7 million for 2007 compared to $110.7 million for 2006. The $29.0 million increase is primarily due to a $760.7 million increase in repayments of indebtedness, a $723.8 million increase in distributions to Targa and $31.2 million in distributions to unitholders, partially offset by $772.8 million of nonrecurring net proceeds from equity offerings in 2007 and a $713.8 million increase in net proceeds from borrowings.
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. 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, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In millions) | |
| Capital expenditures: | | | | | | | | | |
| Expansion | | $ | 55.9 | | | $ | 48.7 | | | $ | 30.6 | |
| Maintenance | | | 40.3 | | | | 30.4 | | | | 25.1 | |
| | | $ | 96.2 | | | $ | 79.1 | | | $ | 55.7 | |
Our planned capital expenditures for 2009, excluding expenditures for the repair of previously discussed hurricane damage, are approximately $46.6 million, of which $21.8 million will be for maintenance. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Expansion capital
expenditures may vary significantly based on investment opportunities. We are currently funding the cost of hurricane damage related repairs for our facilities through operating cash flow.
Description of Senior Notes. On June 12, 2008, we entered into a purchase agreement to issue and sell $250,000,000 in aggregate principal amount of our 8¼% senior unsecured notes due 2016 (the “8¼% Notes”). On June 18, 2008, in connection with the issuance of the 8¼% Notes, we entered into an indenture (the “Indenture”) governing the terms of the 8¼% Notes.
The 8¼% Notes will mature on July 1, 2016 and interest is payable on the 8¼% Notes semi-annually in arrears on each January 1 and July 1. The 8¼% Notes are guaranteed on a senior unsecured basis by certain of our subsidiaries.
The Indenture restricts our ability to make distributions to unitholders if we are in default or an event of default (as defined in the Indenture) exists. It also restricts 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 8¼% Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Credit Facilities and Long-Term Debt
As of December 31, 2008, we had approximately $342.5 million of availability under our credit facility.
We also have senior unsecured debt and affiliated indebtedness to Targa outstanding of $209 million and $773.9 million. See Note 9 of the Notes to Supplemental Consolidated Financial Statements in Exhibit 99.3 for a discussion of our credit agreements.
On September 24, 2009, the entire balance of affiliated indebtedness was repaid to Targa.
Contractual Obligations
Following is a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2008:
| | | Payments Due By Period | |
| Contractual Obligations | | Total | | | Less Than 1 Year | | | 1-3 Years | | | 4-5 Years | | | More Than 5 Years | |
| | | (In millions) | |
| Debt obligations (1) | | $ | 1,470.8 | | | $ | - | | | $ | 773.9 | | | $ | 487.8 | | | $ | 209.1 | |
| Interest on debt obligations (2) | | | 159.8 | | | | 27.0 | | | | 54.0 | | | | 35.7 | | | | 43.1 | |
| Operating leases (3) | | | 53.9 | | | | 10.3 | | | | 15.5 | | | | 11.6 | | | | 16.5 | |
| Capacity payments (4) | | | 8.2 | | | | 5.4 | | | | 2.8 | | | | - | | | | - | |
| Right-of-way | | | 7.3 | | | | 0.5 | | | | 0.9 | | | | 0.8 | | | | 5.1 | |
| Asset retirement obligation | | | 6.2 | | | | - | | | | - | | | | - | | | | 6.2 | |
| | | $ | 1,706.2 | | | $ | 43.2 | | | $ | 847.1 | | | $ | 535.9 | | | $ | 280.0 | |
________
| (1) | Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See Note 9 of the Notes to Supplemental Consolidated Financial Statements in Exhibit 99.3 for information regarding our debt obligations. |
| (2) | Represents interest expense on our debt obligations based on interest rates as of December 31, 2008 and the scheduled future maturities of those debt obligations. |
| (3) | Operating lease obligations include minimum lease payment obligations associated with site leases, railcar leases, office space leases and pipeline right-of-way. |
| (4) | Consist of capacity payments for firm transportation contracts. |
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. Please see the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.
Property, Plant and Equipment. 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 is 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 resource basins, if any.
As of December 31, 2008, the net book value of our property, plant and equipments was $1.7 billion and we recorded $97.8 million in depreciation expense for the year ended December 31, 2008. 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 $10.9 million, 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 $17.2 million. There have been no material changes impacting estimated useful lives of the assets.
Revenue Recognition. Revenues for a period reflect collections to the report date plus any uncollected revenues reported for the period which is reflected as accounts receivable in the balance sheet. As of December 31, 2008, the Partnership’s balance sheet reflects total accounts receivable from third parties of $236.1 million. We have recorded an allowance for doubtful accounts as of December 31, 2008 of $2.2 million.
The Partnership’s exposure to uncollectible accounts receivable relates to the financial health of its counterparties. The Partnership and its 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 an assessment of uncollectibility resulted in a 1% reduction of our third-party accounts receivable, our operating income would decrease by $2.4 million. There have been no material changes impacting accounts receivable.
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.
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 will 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 $138.7 million as of December 31, 2008, 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 $6.5 million as of December 31, 2008. 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 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 $13.9 million.
Recent Accounting Pronouncements.
For a discussion of recent accounting pronouncements that will affect us, see Note 3 to our Supplemental Consolidated Financial Statements in Exhibit 99.3.
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, 2008, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2012 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 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 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 our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline 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. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Waha and Mid-Continent, 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.
Our 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 secure 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.
During 2008, 2007 and 2006, 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 2008, 2007 and 2006, our operating revenues were adjusted by net hedge losses of $33.7 million, $1.0 million and $0.9 million.
As of December 31, 2008, our commodity hedges were as follows:
Natural Gas
| | | | | Avg. Price | | | MMBtu per day | | | | |
| Instrument Type | | Index | | $/MMBtu | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Fair Value | |
| | | | | | | | | | | | | | | | | | (In thousands) | |
| Natural Gas Sales | | | | | | | | | | | | | | | | | | |
| Swap | | IF-HSC | | | 7.39 | | | | 1,966 | | | | - | | | | - | | | | - | | | $ | 1,159 | |
| | | | | | | | | | 1,966 | | | | - | | | | - | | | | - | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Swap | | IF-NGPL MC | | | 9.18 | | | | 6,256 | | | | - | | | | - | | | | - | | | | 9,466 | |
| Swap | | IF-NGPL MC | | | 8.86 | | | | - | | | | 5,685 | | | | - | | | | - | | | | 5,129 | |
| Swap | | IF-NGPL MC | | | 7.34 | | | | - | | | | - | | | | 2,750 | | | | - | | | | 843 | |
| Swap | | IF-NGPL MC | | | 7.18 | | | | - | | | | - | | | | - | | | | 2,750 | | | | 738 | |
| | | | | | | | | | 6,256 | | | | 5,685 | | | | 2,750 | | | | 2,750 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Swap | | IF-Waha | | | 8.73 | | | | 6,936 | | | | - | | | | - | | | | - | | | | 8,627 | |
| Swap | | IF-Waha | | | 7.52 | | | | - | | | | 5,709 | | | | - | | | | - | | | | 2,294 | |
| Swap | | IF-Waha | | | 7.36 | | | | - | | | | - | | | | 3,250 | | | | - | | | | 886 | |
| Swap | | IF-Waha | | | 7.18 | | | | - | | | | - | | | | - | | | | 3,250 | | | | 708 | |
| | | | | | | | | | 6,936 | | | | 5,709 | | | | 3,250 | | | | 3,250 | | | | | |
| Total Swaps | | | | | | | | | 15,158 | | | | 11,394 | | | | 6,000 | | | | 6,000 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Floor | | IF-NGPL MC | | | 6.55 | | | | 850 | | | | - | | | | - | | | | - | | | | 574 | |
| | | | | | | | | | 850 | | | | - | | | | - | | | | - | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Floor | | IF-Waha | | | 6.55 | | | | 565 | | | | - | | | | - | | | | - | | | | 326 | |
| | | | | | | | | | 565 | | | | - | | | | - | | | | - | | | | | |
| Total Floors | | | | | | | | | 1,415 | | | | - | | | | - | | | | - | | | | | |
| Total Sales | | | | | | | | | 16,573 | | | | 11,394 | | | | 6,000 | | | | 6,000 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | $ | 30,750 | |
NGL
| | | | | Avg. Price | | | Barrels per day | | | | |
| Instrument Type | | Index | | $/gal | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Fair Value | |
| | | | | | | | | | | | | | | | | | (In thousands) | |
| NGL Sales | | | | | | | | | | | | | | | | | | |
| Swap | | OPIS-MB | | | 1.32 | | | | 6,248 | | | | - | | | | - | | | | - | | | $ | 66,137 | |
| Swap | | OPIS-MB | | | 1.27 | | | | - | | | | 4,809 | | | | - | | | | - | | | | 39,122 | |
| Swap | | OPIS-MB | | | 0.92 | | | | - | | | | - | | | | 3,400 | | | | - | | | | 8,288 | |
| Swap | | OPIS-MB | | | 0.92 | | | | - | | | | - | | | | - | | | | 2,700 | | | | 6,018 | |
| Total Swaps | | | | | | | | | 6,248 | | | | 4,809 | | | | 3,400 | | | | 2,700 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Floor | | OPIS-MB | | | 1.44 | | | | - | | | | - | | | | 199 | | | | - | | | | 1,807 | |
| Floor | | OPIS-MB | | | 1.43 | | | | - | | | | - | | | | - | | | | 231 | | | | 1,932 | |
| Total Floors | | | | | | | | | - | | | | - | | | | 199 | | | | 231 | | | | | |
| Total Sales | | | | | | | | | 6,248 | | | | 4,809 | | | | 3,599 | | | | 2,931 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | $ | 123,304 | |
Condensate
| | | | | Avg. Price | | | Barrels per day | | | | |
| Instrument Type | | Index | | $/Bbl | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Fair Value | |
| | | | | | | | | | | | | | | | | | (In thousands) | |
| Condensate Sales | | | | | | | | | | | | | | | | | | |
| Swap | | NY-WTI | | | 69.00 | | | | 322 | | | | - | | | | - | | | | - | | | $ | 1,655 | |
| Swap | | NY-WTI | | | 68.10 | | | | - | | | | 301 | | | | - | | | | - | | | | 431 | |
| Total Swaps | | | | | | | | | 322 | | | | 301 | | | | - | | | | - | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Floor | | NY-WTI | | | 60.00 | | | | 50 | | | | - | | | | - | | | | - | | | | 239 | |
| Total Floors | | | | | | | | | 50 | | | | - | | | | - | | | | - | | | | | |
| Total Sales | | | | | | | | | 372 | | | | 301 | | | | - | | | | - | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | $ | 2,325 | |
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.
Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of December 31, 2008, there were borrowings of approximately $487.8 million outstanding under our $850 million credit facility.
As of December 31, 2008 we had the following open interest rate swaps:
| | | | | Notional | | Fair | |
| Expiration Date | | Fixed Rate | | Amount | | Value | |
| | | | | | | (In thousands) | |
| January 24, 2011 | | | 4.00% | | $100 million | | $ | (5,282 | ) |
| January 24, 2012 | | | 3.75% | | 200 million | | | (12,294 | ) |
| | | | | | | | $ | (17,576 | ) |
We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded 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 $1.9 million.
Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We operate under the Targa credit policy and closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with this credit policy. In addition to third party contracts, we have entered into several agreements with Targa. For example, we are party to natural gas, NGL and condensate purchase agreements pursuant to which Targa purchases the majority of our natural gas, NGLs and high-pressure condensate. In addition, we are also a party to an omnibus agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.
As of December 31, 2008, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 67%, 21% and 11% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.
