Exhibit 99.3 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 consolidated financial statements and notes included elsewhere in this document.
Overview
We are a Delaware limited partnership formed to capitalize on opportunities in the midstream sector of the natural gas industry. We own and operate significant natural gas gathering and processing assets in north Louisiana, east Texas, south Texas, west Texas and the mid-continent region of the United States, which includes Kansas, Oklahoma, Colorado, and the Texas Panhandle. We are engaged in gathering, processing, marketing and transporting natural gas and natural gas liquids, or NGLs. We connect natural gas wells of producers to our gathering systems through which we transport the natural gas to processing plants operated by us or by third parties. The processing plants separate NGLs from the natural gas. We then sell and deliver the natural gas and NGLs to a variety of markets.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin and operating expenses on a segment basis and EBITDA on a company-wide basis.
Volumes.We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
To increase throughput volumes on our intrastate pipeline we must contract with shippers, including producers and marketers, for supplies of natural gas. We routinely monitor producer and marketing activities in the areas served by our transportation system to pursue new supply opportunities.
Segment Margin.We calculate our Gathering and Processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, which also include third-party transportation and processing fees. Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing natural gas. Our contract portfolio impacts our segment margin. See “Our Operations” for a discussion of our contract portfolio.
We calculate our Transportation segment margin as revenue minus the cost of natural gas that we purchase and transport. Revenue primarily includes sales of pipeline-quality natural gas and fees for the transportation of pipeline-quality natural gas. Most of our segment margin is fee-based with little or no commodity price risk. We generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet. We regard the difference between the purchase price and the sale price as the economic equivalent of our transportation fee.
Operating Expenses.Operating expenses are a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total
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revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.
EBITDA.We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
| | § | | financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
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| | § | | the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partners; |
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| | § | | our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and |
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| | § | | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important measure for a publicly traded master limited partnership.
Our Operations
We manage our business and analyze and report our results of operations through two business segments:
| | § | | Gathering and Processing in which we provide “wellhead to market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate the NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and |
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| | § | | Transportation in which we deliver natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project. Our Transportation Segment includes certain marketing activities related to our transportation pipelines that are conducted by a separate subsidiary. |
Gathering and Processing Segment
Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, our current contract portfolio and natural gas and NGL prices.
We measure the performance of this segment primarily by the segment margin it generates, which we define as total revenues, including service fees, less the cost of natural gas and liquids and other cost of sales. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs. We regard the segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements.
Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways,
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including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.
| | § | | Fee-Based Arrangements.Under these arrangements, we generally are paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline in commodity prices, however, could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. |
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| | § | | Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component). |
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| | § | | Keep-Whole Arrangements.Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) provisions that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, (3) fixed cash fees for ancillary services, such as gathering, treating, and compression, or (4) the ability to bypass in unfavorable price environments. |
An important aspect of our contract portfolio management strategy is to decrease our keep-whole contract risk exposure. Immediately following the acquisition of our mid-continent assets in 2003, we terminated our month-to-month keep-whole arrangements and replaced them with fee-based or percentage-of-proceeds agreements or variations thereof. In addition, we seek to replace our longer term keep-whole arrangements as they expire or whenever the opportunity presents itself. At the time of the acquisition of our mid-continent assets, approximately 71 percent of our natural gas volumes associated with those assets was subject to keep-whole arrangements. As of December 31, 2005, we had reduced that number to approximately 22 percent in the mid-continent region.
As part of our previously planned strategy, on August 1, 2005, we suspended operations at our Lakin natural gas processing plant, reserving the right to operate it intermittently. The natural gas that would have been processed at the Lakin plant is now processed at a third party processing plant for our account for a fee. Suspending the operations of the plant allowed us to renegotiate and replace certain unfavorable keep-whole processing arrangements covering natural gas processed at the plant with fee-based contracts. Additionally, by suspending the Lakin plant, we are able to avoid charges for transporting natural gas through a third party pipeline out of the tailgate of the plant. We expect to realize a net benefit to our cash flows and earnings from these changes in addition to a reduced risk portfolio. We are actively seeking to use the 80 MMcf/d of newly
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available processing capacity at the Lakin plant by attempting to contract for additional supply to the plant or by moving the plant to a new location.
In our Gathering and Processing segment, we are a seller of NGLs and are exposed to commodity price risk associated with movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have, since the acquisition of Regency Gas Services LLC by HM Capital Investors, executed swap contracts settled against ethane, propane, butane and natural gasoline market prices, supplemented with crude oil put options (historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil). As of March 30, 2006, we have hedged approximately 95 percent of our expected exposure to NGL prices in 2006, approximately 75 percent in 2007 and approximately 50 percent in 2008. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
We sell natural gas on intrastate and interstate pipelines to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies and utilities. We typically sell natural gas under pricing terms related to market index. To the extent possible, we match the pricing and timing of our supply portfolio to our sales portfolio in order to lock in our margin and reduce our overall commodity price exposure. To the extent our natural gas position is not balanced, we will be exposed to the commodity price risk associated with the price of natural gas.
Until recently, the NGLs produced by our processing plants were sold to third parties as mixed NGLs. In September 2005, we began delivering the mixed NGLs produced by our processing plants to operators of fractionation facilities for fractionation for our account. We then sell the individual components, such as ethane, propane and isobutane, directly to marketing companies, refineries and other wholesalers. We believe this marketing function will allow us to earn additional margins from the sale of the NGLs that otherwise would have been earned by the fractionator.
Transportation Segment
Results of operations from our Transportation segment are determined primarily by the volumes of natural gas transported on our Regency Intrastate Pipeline system and the level of fees charged to our customers or the margins received from purchases and sales of natural gas. We generate our revenues and segment margins for our Transportation segment principally under fee-based transportation contracts or through the purchase of natural gas at one of the inlets to the pipeline and the sale of natural gas at the outlet. In the latter case, we generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that natural gas at the pipeline outlet. The differential in the purchase price and the sale price contributes to our segment margin. The margin we earn from our transportation activities is directly related to the volume of natural gas that flows through our system and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices resulted in a decline in volumes, our revenues from these arrangements would be reduced.
Generally, we provide to shippers two types of fee-based transportation services under our transportation contracts:
| | § | | Firm Transportation.Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a commodity charge with respect to quantities actually transported by us. |
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| | § | | Interruptible Transportation.Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped. |
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We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with the Federal Energy Regulatory Commission (the “FERC”) with respect to transportation authorized under section 311 of the Natural Gas Policy Act of 1978, or NGPA.
In addition, we perform a limited merchant function on our Regency Intrastate Pipeline system. This merchant function is conducted by a separate subsidiary. We purchase natural gas from a producer or gas marketer at a receipt point on our system at a price adjusted to reflect our transportation fee and transport that gas to a delivery point on our system at which we sell the natural gas at market price. We regard the segment margin with respect to those purchases and sales as the economic equivalent of a fee for our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the index price on the date of settlement.
Enhancement Project.Portions of the Regency Intrastate Pipeline system have historically operated at full capacity and represented a significant constraint on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana. In response, we have completed a major expansion and extension of this system, which we refer to as the Regency Intrastate Enhancement Project. This project quadrupled the system’s capacity from the capacity that existed prior to the commencement of the project.
The Regency Intrastate Enhancement Project was a multi-phase project designed to relieve bottlenecks on certain sections of the pipeline and to access new sources of supply and markets. We began planning this project in January 2005 and started construction in May 2005. We completed the project in December 2005. This project included the expansion of our existing Regency Intrastate Pipeline system and the addition of an 80-mile, 30-inch diameter pipeline extension to the Regency Intrastate Pipeline system supported by approximately 9,500 horsepower of additional compression. The project has extended our transportation services into additional major producing fields in north Louisiana, connected our system to additional pipelines in northeast Louisiana and has increased the capacity of the pipeline to 800 MMcf/d.
The total cost of this project is approximately $157,000,000. Our original estimate for this project was approximately $140,000,000. The excess of cost over our estimate includes $2,500,000 of costs that we dispute and otherwise consists primarily of insufficient estimates of materials, right of way and legal expenditures, sales taxes and capitalized interest.
One of our motivations to enhance this pipeline was to enable our customers to reach markets offering more favorable prices by developing interconnects with other pipelines. As of December 31, 2005, the Regency Intrastate Pipeline system could deliver gas to two 250 MMcf/d interconnects. Since then, three additional interconnects have been completed: two 250 MMcf/d interconnections and a 500 MMcf/d interconnection.
The completion of the Regency Intrastate Enhancement Project enables us to provide transportation services from the three largest natural gas producing fields in Louisiana. Prior to the completion of the final phase of the project in December 2005, we were transporting approximately 265 MMcf/d under existing contracts. Through March 28, 2006, we have signed definitive agreements for 466,000 MMBtu/d of firm transportation on the Regency Intrastate Pipeline system and 404,000 MMBtu/d of interruptible transportation. We are engaged in discussions with other parties interested in utilizing the remaining firm system transportation capacity.
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, Demand and Outlook.Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 25.9 Tcf in 2015,
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representing an average annual growth rate of approximately 1.7 percent. During the five years ending December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, while total marketed domestic production averaged approximately 19.8 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.
We believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe that an increase in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.
All of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in all of these areas, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our operations.
Gathering and Processing Segment Margins.In keeping with our strategy of reducing commodity price exposure, we have adjusted our contract portfolio through renegotiation of certain keep-whole contracts, including three large keep-whole contracts that were converted to fee contracts in August 2005, resulting in a shift of our overall natural gas position to a slightly long position going forward, while retaining a long physical NGL position. We believe that this adjusted portfolio effectively hedges our overall exposure to volatility in fractionation spreads. Our profitability is now positively impacted if natural gas or NGLs prices increase and negatively impacted if natural gas or NGLs prices decrease. The prices of natural gas and NGLs are volatile and beyond our control.
Impact of Interest Rates and Inflation.The credit markets recently have experienced 50-year record lows in interest rates. If the overall economy continues to strengthen, we believe that it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2003, 2004 or 2005. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
Recent Developments
On August 15, 2006, the Partnership, through its wholly-owned subsidiary Regency Gas Services, acquired TexStar, an affiliate of HM Capital Partners for $350,000,000, subject to working capital adjustments. See Note 15 for additional information regarding this acquisition.
Formation, Acquisition and Asset Disposal History and Financial Statement Presentation
Our Formation of Regency Energy Partners LP and Our Initial Public Offering
We are a Delaware limited partnership formed in September 2005 to own and operate Regency Gas Services LP. Prior to the completion of our initial public offering, Regency Gas Services LLC was owned by the HM Capital Investors. Prior to the
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closing of our initial public offering on February 3, 2006, Regency Gas Services LLC was converted into a limited partnership named Regency Gas Services LP, and was contributed to us by Regency Acquisition LP, a limited partnership indirectly owned by the HM Capital Investors, in exchange for 5,353,896 common units, 19,103,896 subordinated units, the incentive distribution rights, a continuation of its 2 percent general partner interest in us, and a right to receive $195,757,000 of cash proceeds from our initial public offering. The cash proceeds constituted a reimbursement of a corresponding amount of capital expenditures comprising most of the initial investment by the HM Capital Investors in Regency Gas Services LLC. In addition, approximately $48,000,000 in cash and accounts receivable were distributed by Regency Gas Services LLC to Regency Acquisition LP and then to the HM Capital Investors immediately prior to the contribution of Regency Gas Services LLC to us. These current assets were replenished with proceeds from the offering.
On March 8, 2006, we closed the sale of an additional 1,400,000 common units at a price of $20 per unit as the underwriters’ exercised their over allotment option in part. The net proceeds from the sale were used by us to redeem an equivalent number of common units held by Regency Acquisition LP for the benefit of the HM Capital Investors.
We paid $9,000,000 of the proceeds from our initial public offering to terminate our ten-year financial advisory, monitoring and oversight agreements with HM Capital Partners. In the first quarter of 2006 we expensed these costs.
Acquisition of TexStar Field Services, L.P.
On August 15, 2006, we acquired all the outstanding equity (“TexStar Acquisition”) of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC (together, “TexStar”) for $350,000,000, subject to working capital adjustments. Because the TexStar Acquisition is a transaction between commonly controlled entities, we accounted for the TexStar Acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows for periods in which common control existed, December 1, 2004 forward.
Enbridge Asset Acquisition
TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in East and South Texas (the “Enbridge Assets”) from Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Intrastate), LP and Enbridge Pipelines (Texas Gathering), LP (collectively “Enbridge”) for $108,282,000 inclusive of transaction expenses on December 7, 2005 (the “Enbridge Acquisition”). The Enbridge Acquisition was accounted for using the purchase method of accounting. For convenience, the results of operations of the Enbridge Assets are included in the statements of operations beginning December 1, 2005. The purchase price was allocated to gas plants and buildings ($42,361,000), gathering and transmission systems ($65,002,000) and other property, plant and equipment ($919,000) as of December 1, 2005. TexStar assumed no material liabilities in this acquisition.
The HM Capital Investors’ Acquisition of Regency Gas Services LLC
On December 1, 2004, the HM Capital Investors acquired all of the outstanding equity interests in Regency Gas Services LLC from its previous owners. The HM Capital Investors accounted for this acquisition as a purchase, and purchase accounting adjustments, including goodwill and other intangible assets, have been “pushed down” and are reflected in the financial statements of Regency Gas Services LLC for the period subsequent to December 1, 2004. In our consolidated financial statements, Regency Gas Services LLC is designated as “Predecessor” for periods ended subsequent to December 1, 2004 and the “Regency LLC Predecessor” periods ended before December 1, 2004.
Formation of Regency Gas Services LLC
Regency Gas Services LLC was organized on April 2, 2003 by a private equity fund for the purpose of acquiring, managing and operating natural gas gathering, processing and transportation assets. Regency Gas Services LLC had no operating
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history prior to the acquisition of the assets from affiliates of El Paso Energy Corporation and Duke Energy Field Services, L.P. discussed below.
Acquisition of El Paso Assets
In June 2003, Regency LLC Predecessor acquired certain natural gas gathering, processing and transportation assets from subsidiaries of El Paso Corporation for approximately $119,541,000. The assets acquired consisted of gathering, processing and transportation assets located in north Louisiana and gathering and processing assets located in the mid-continent region of the United States and represent substantially all of our existing north Louisiana and mid-continent assets. At the time of the acquisition, the acquired gathering and transportation systems had an average expected remaining useful life of approximately 20 years and the processing plants had an average expected remaining useful life of approximately 15 years.
Prior to our acquisition of these assets, these assets were operated as components of El Paso’s much larger midstream operations. Immediately following our acquisition of these assets, we changed the manner in which these assets were operated. In that regard, we initiated, and continue to implement, a strategy to reshape the revenue structure of the acquired assets to expand revenues, increase margins and decrease exposure to market volatility.
Acquisition of Duke Energy Field Services Assets
In March 2004, Regency LLC Predecessor acquired certain natural gas gathering and processing assets from Duke Energy Field Services, LP for approximately $67,264,000, including transactional costs. The assets acquired consisted of gathering and processing assets located in west Texas and represent substantially all of our existing west Texas assets.
Prior to our acquisition of these assets, these assets were operated as components of Duke Energy Field Services’ much larger midstream operations. As with the assets acquired from El Paso, immediately following our acquisition of these assets, we implemented significant operational changes designed to expand revenues, increase margins and limit exposure to market volatility. We promptly changed the manner in which pipeline-quality natural gas was marketed from these assets by extending contract terms.
Others
In April 2004, we completed the purchase of gas processing interests located in Louisiana and Texas from Cardinal Gas Services LLC (Cardinal) for $3,533,000 in cash. In May 2005, we sold all of the assets acquired from Cardinal, together with certain related assets, for $6,000,000. After the allocation of $977,000 of goodwill, the resulting gain was $626,000. We have treated these operations as a discontinued operation.
Items Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward, for the reasons described below:
| | § | | Regency LLC Predecessor commenced operations in June 2003 with the acquisition of the El Paso assets. As a result, we do not have any material financial results for periods prior to June 2003 and our results of operations for the period ended December 31, 2003 includes only seven months of financial results. |
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| | § | | Regency LLC Predecessor acquired the Duke Energy Field Services assets in March 2004. As a result, our financial results for periods prior to March 2004 do not include the financial results of the Duke Energy Field Services’ assets. |
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| | § | | In connection with the acquisition of Regency Gas Services LLC by the HM Capital Investors on December 1, 2004, the purchase price was “pushed-down” to the financial statements of Regency Gas Services LLC. As a result of this “push-down” accounting, the book basis of our assets was increased to reflect the purchase price, which had the effect |
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| | | | of increasing our depreciation and amortization expense. Also, the increased level of debt incurred in connection with the acquisition increased our interest expense subsequent to December 1, 2004. |
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| | § | | The TexStar Acquisition is a transaction between commonly controlled entities; therefore, we accounted for this acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows during the periods in which common control existed, December 1, 2004 forward. Most of the TexStar operating activity occurred in December 2005. As a result, the TexStar historical operations, financial position and cash flows are not comparable to prior periods. |
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| | § | | The Enbridge Acquisition was accounted for using the purchase method of accounting. The purchase price was allocated to gas plants and buildings ($42,361,000), gathering and transmission systems ($65,002,000) and other property, plant and equipment ($919,000) as of December 1, 2005. As a result, the TexStar historical operations, financial position and cash flows are not comparable to prior periods. |
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| | § | | In December 2004 we undertook a hedging program as required by our credit facilities. Effective July 1, 2005 we designated certain commodity and interest rate swap instruments for hedge accounting treatment in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For the periods from December 1, 2004 through June 30, 2005 unrealized and realized gains and losses on the commodity swaps were recorded in unrealized/realized gain (loss) from risk management activities in our statements of operations. For the six months ended June 30, 2005 unrealized gains and losses on the interest rate swap were recorded in interest expense, net. Effective July 1, 2005, to the extent the hedges are effective, any unrealized gains or losses on these instruments were recorded in other comprehensive income (loss) during the lives of the instruments, which we believe will lead to financial results that are not comparable for the affected periods. |
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| | § | | We completed a major enhancement of our Regency Intrastate Pipeline system and the pipeline, as expanded and extended, began operations on December 28, 2005. As of March 30, 2006 we were transporting approximately 450,000 MMBtu/d of natural gas. |
Critical Accounting Policies and Estimates
Conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
Revenue and Cost of Sales Recognition. We record revenue and cost of sales on the gross basis for those transactions where we act as the principal and take title to gas that we purchase for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues. In March 2006, the Partnership implemented a process for estimating certain revenue and expenses as actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. Estimated revenues are calculated using actual pricing and nominated volumes. In the subsequent production month, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.
Risk Management Activities.In order to protect ourselves from commodity and interest rate risk, we pursue hedging activities to minimize those risks. These hedging activities rely upon forecasts of our expected operations and financial structure over the next four years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an
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operational cushion between our forecasted transactions and the level of hedging activity executed. We monitor and review hedging positions regularly.
From the inception of our hedging program in December 2004 through June 30, 2005, we used mark-to-market accounting for our commodity and interest rate swaps as well as for crude oil puts. We recorded realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. The settlement amounts varied due to the volatility in the commodity market prices throughout each month.
Effective July 1, 2005, we elected hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended and determined the then current hedges outstanding, excluding crude oil put options, qualified for hedge accounting whereby the unrealized changes in fair value are recorded in other comprehensive income (loss) to the extent the hedge is effective. Prior to July 1, 2005, we had recorded unrealized losses and gains in the fair market value of commodity-related derivative contracts and unrealized gains on an interest rate swap into revenues and interest expense, net respectively.
Purchase Method of Accounting.On December 1, 2004, we were acquired by the HM Capital Investors. We made various assumptions in determining the fair values of acquired assets and liabilities. In order to allocate the purchase price to the business units, we developed fair value models with the assistance of outside consultants. These fair value models applied discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. An economic value was determined for each business unit. The total economic value was equal to the purchase price. We then determined the fair value of the fixed assets based on estimates of replacement costs. We identified intangible assets related to licenses and permits, and renegotiated customer contracts and assigned a fair value of $18,517,000. We made assumptions regarding the period of time it would take to replace these permits. We assigned value using a lost profits model over that period of time necessary to replace the permits. The customer contracts were valued using a discounted cash flow model. We determined liabilities assumed based on their expected future cash outflows. We recorded goodwill of $58,529,000 as the excess of the cost of each business unit over the sum of amounts assigned to the tangible assets, financial assets, and separately recognized intangible assets acquired less liabilities assumed of the business unit.
Accounting for an Acquisition Involving Entities Under Common Control.The August 15, 2006 TexStar Acquisition is a transaction between commonly controlled entities, as such, we accounted for the TexStar Acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows during the periods in which common control existed, December 1, 2004 forward.
Depreciation Expense and Cost Capitalization Policies.Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipeline. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities. We capitalized $2,613,000 of interest related to the Regency Intrastate Enhancement Project. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense. Under certain contractual circumstances our gathering and transmission system includes natural gas or NGL line pack, which is a non-depreciable asset.
As discussed in the Notes to the Consolidated Financial Statements, depreciation of our assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments that extend the useful life of property, plant and equipment are capitalized. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The costs of repairs, replacements and maintenance projects are expensed as incurred.
The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.
46
Environmental Remediation.Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties was added to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. To date, we have not recorded any liability for remediation expenses and we do not believe that any significant liability currently exists. If governmental regulations change, we could be required to incur remediation costs that might have a material impact on our profitability.
We account for our asset retirement obligations in accordance with Statement of Financial Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” and FIN 47 “Accounting for Conditional Asset Retirement Obligations.” These accounting standards require us to recognize on the balance sheet the net present value of any legally binding obligation to remove or remediate the physical assets that we retire from service, as well as any similar obligations for which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. While we are obligated under contractual agreements to remove certain facilities upon their retirement, we are unable to reasonably determine the fair value of any asset retirement obligations as of December 31, 2005 and 2004 because the settlement dates, or ranges thereof, were indeterminable and could range up to ninety-six years, and the undiscounted amounts are immaterial. An asset retirement obligation will be recorded in the periods wherein we can reasonably determine the settlement dates.
Equity Based Compensation. On December 12, 2005, the compensation committee of the board of directors of Regency GP LLC approved a long-term incentive plan (“LTIP”) for the Partnership’s employees, directors and consultants covering an aggregate of 2,865,584 common units. Awards under the LTIP have been made since the completion of the Partnership’s IPO. LTIP awards generally vest on the basis of one-third of the award each year. The options have a maximum contractual term, expiring ten years after the grant date. We adopted SFAS No. 123(R) “Share-Based Payment” in the first quarter of 2006 which had no impact to us as no LTIP awards were outstanding during 2005.
Option grants are valued with the Black-Scholes Option Pricing Model assuming 15 percent volatility in the unit price, a ten year term, a strike price equal to the grant-date price per unit, a distribution per unit of $1.40 per year, a risk-free rate of 4.25 percent, and an average exercise of the options of four years after vesting is complete. The assumption that option exercises, on average, will be four years from the vesting date is based on the average of the mid-points from vesting to expiration of the options.
We will make the same distributions to holders of non-vested restricted common units as those paid to common unit holders. Upon the vesting of the restricted common units and the exercise of the common unit options, we intend to settle these obligations with common units. Accordingly, we expect to recognize an aggregate of $7,641,000 of compensation expense related to the initial grants under LTIP, or $2,547,000 for each of the three years of the vesting period for such grants.
Senior members of management and outside directors who held Class B or Class D units of HMTF Regency, L.P. entered into exchange agreements in connection with the consummation of the Partnership’s initial public offering whereby they exchanged their Class B or Class D units for common and subordinated units in Regency Energy Partners LP and an interest in Regency GP LLC. We have evaluated the impact of the exchange agreements and will not record a material amount of compensation expense related to this exchange.
47
Results of Operations
Year Ended December 31, 2005 vs. Combined Year Ended December 31, 2004
The table below contains key company-wide performance indicators related to our discussion of the results of operations.
| | | | | | | | | | | | | | | | | |
| | | Regency Energy | | | Regency LLC | | | | | | | |
| | | Partners LP | | | Predecessor | | | | | | | |
| | | Year Ended | | | | | | | |
| | | December 31, | | | | | | | |
| | | 2005 | | | 2004 (d) | | | Change | | | % Change | |
| | | | | | | (combined) | | | | | | | | | |
| | | | | | | ($ in thousands) | | | | | | | | | |
| Revenues (a) | | $ | 709,401 | | | $ | 480,178 | | | $ | 229,223 | | | | 48 | % |
| Cost of sales | | | 632,342 | | | | 403,749 | | | | (228,593 | ) | | | (57 | ) |
| | | | | | | | | | | | | |
| Total segment margin (b) | | | 77,059 | | | | 76,429 | | | | 630 | | | | 1 | |
| | | | | | | | | | | | | | | | | |
| Operating expenses | | | 24,291 | | | | 19,605 | | | | (4,686 | ) | | | (24 | ) |
| General and administrative | | | 15,039 | | | | 7,216 | | | | (7,823 | ) | | | (108 | ) |
| Related party expenses | | | 523 | | | | — | | | | (523 | ) | | | n/m | |
| Transaction expenses | | | — | | | | 7,003 | | | | 7,003 | | | | n/m | |
| Depreciation and amortization | | | 23,171 | | | | 11,790 | | | | (11,381 | ) | | | (97 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Operating income | | | 14,035 | | | | 30,815 | | | | (16,780 | ) | | | (54 | ) |
| | | | | | | | | | | | | | | | | |
| Interest expense, net | | | (17,880 | ) | | | (6,432 | ) | | | (11,448 | ) | | | (178 | ) |
| Equity income | | | 312 | | | | 56 | | | | 256 | | | | 457 | |
| Loss on debt refinancing | | | (8,480 | ) | | | (3,022 | ) | | | (5,458 | ) | | | (181 | ) |
| Other income and deductions, net | | | 421 | | | | 194 | | | | 227 | | | | 117 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net (loss) income from continuing operations | | | (11,592 | ) | | | 21,611 | | | | (33,203 | ) | | | (154 | ) |
| | | | | | | | | | | | | | | | | |
| Discontinued operations | | | 732 | | | | (121 | ) | | | 853 | | | | (705 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net (loss) income | | $ | (10,860 | ) | | $ | 21,490 | | | $ | (32,350 | ) | | | (151 | )% |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| System inlet volumes (MMBtu/d) (c) | | | 603,592 | | | | 494,816 | | | | 108,776 | | | | 22 | % |
| | |
| (a) | | Includes $322,000 of net unrealized gains on hedging transactions for the combined year ended December 31, 2004. Includes $9,530,000 of net unrealized losses on hedging transactions and $1,956,000 of put option expiration for the year ended December 31, 2005. |
| |
| (b) | | For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures.” |
| |
| (c) | | System inlet volumes include total volumes taken into our gathering and processing and transportation systems. |
| |
| (d) | | We combined the results of operations for the period from Acquisition (December 1, 2004) of the Predecessor and the period from January 1, 2004 to November 30, 2004 of the Regency LLC Predecessor to provide an annual reporting period for a more meaningful comparison versus the year ended December 31, 2005. To the extent operations for the 2005 period are not comparable to the combined 2004 period; we have disclosed such differences in the discussion of results of operations. See the separate discussion of the one month ended December 31, 2004. |
n/m = not meaningful
48
The table below contains key segment performance indicators related to our discussion of the results of operations.
| | | | | | | | | | | | | | | | | |
| | | Regency Energy | | Regency LLC | | | | |
| | | Partners LP | | Predecessor | | | | |
| | | Year Ended | | | | |
| | | December 31, | | | | |
| | | 2005 | | 2004 (b) | | Change | | % Change |
| | | | | | | (combined) | | | | | | | | |
| | | | | | | ($ in thousands) | | | | | | | | |
Segment Financial and Operating Data: | | | | | | | | | | | | | | | | |
| Gathering and Processing Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
| Segment Margin (a) | | $ | 61,387 | | | $ | 67,609 | | | $ | (6,222 | ) | | | (9 | )% |
| Operating expenses | | | 22,362 | | | | 17,885 | | | | (4,477 | ) | | | (25 | ) |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 345,398 | | | | 305,176 | | | | 40,222 | | | | 13 | |
| NGL gross production (Bbls/d) | | | 14,883 | | | | 15,129 | | | | (246 | ) | | | (2 | ) |
| | | | | | | | | | | | | | | | | |
| Transportation Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
| Segment Margin | | $ | 15,672 | | | $ | 8,820 | | | $ | 6,852 | | | | 78 | % |
| Operating expenses | | | 1,929 | | | | 1,720 | | | | (209 | ) | | | (12 | ) |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 258,194 | | | | 189,640 | | | | 68,554 | | | | 36 | |
| | |
| (a) | | Includes $322,000 of net unrealized gains on hedging transactions for the combined year ended December 31, 2004. Includes $9,530,000 of net unrealized losses on hedging transactions and $1,956,000 of put option expiration for the year ended December 31, 2005. |
| |
| (b) | | We combined the results of operations for the period from Acquisition (December 1, 2004) of the Predecessor and the period from January 1, 2004 to November 30, 2004 of the Regency LLC Predecessor to provide an annual reporting period for a more meaningful comparison versus the year ended December 31, 2005. To the extent operations for the 2005 period are not comparable to the combined 2004 period, we have disclosed such differences in the discussion of results of operations. See the separate discussion of the one month ended December 31, 2004. |
Net Income.Net income for the year ended December 31, 2005 decreased $32,350,000 compared with the combined year ended December 31, 2004. The primary reasons for this decrease are: (1) interest expense, net increased $11,448,000 primarily due to higher net interest expense related to debt incurred to fund the HM Capital Transaction and the TexStar Acquisition; (b) depreciation and amortization expense increased $11,381,000 primarily due to our higher depreciable basis following the fair value adjustments recorded to property, plant and equipment in the application of the purchase method of accounting for the HM Capital Transaction; (3) the increase in debt issuance costs of $5,458,000 for the ended December 31, 2005 due to amending our credit facilities three times; (4) general and administrative expense increased $7,823,000 primarily as a result of higher employee-related expenses and professional and consulting expenses; (5) operating expenses increased $4,686,000 primarily due to our TexStar Acquisition, our west Texas facilities operating twelve months in 2005 versus ten months in 2004 and higher taxes, other than income; and (6) a decrease of $7,003,000 in transaction expenses incurred in 2004 not incurred in 2005.
Total Segment Margin.Total segment margin for the year ended December 31, 2005 increased to $77,059,000 from $76,429,000 for the combined year ended December 31, 2004, representing a 1 percent increase. This increase was attributable in part to increased pipeline throughput volumes in the Transportation Segment, which produced additional margin of $7,200,000. In December 2005, operations from our TexStar Acquisition in the Gathering and Processing Segment contributed approximately $5,200,000 in total segment margin. In the remainder of the Gathering and Processing Segment, pricing effects were negligible, as $10,757,000 of increased total segment margin attributable to commodity prices was offset by $10,757,000 in cash hedge settlements demonstrating the effectiveness of our hedging program. Non-cash losses caused
49
by the net change in the fair value of derivative contracts during such time as the contracts were not designated as hedges in 2005 and the expiration of certain crude oil put options reduced total segment margin by $11,486,000.
Segment margin for the Gathering and Processing Segment for the year ended December 31, 2005 decreased to $61,387,000 from $67,609,000 for the combined year ended December 31, 2004, representing a 9 percent decline. The elements driving this reduction in segment margin are as follows:
| | § | | In December 2005, operations from our TexStar Acquisition contributed approximately $5,200,000 in segment margin; |
| |
| | § | | Other than the TexStar Acquisition margin, pricing effects were negligible, as $10,757,000 of increased segment margin attributable to higher commodity prices was offset by $10,757,000 in cash hedge settlements; |
| |
| | § | | Other than the TexStar Acquisition margin, $300,000 of increased segment margin was attributable to increased pipeline throughput volumes, |
| |
| | § | | $11,486,000 of decreased segment margin attributable to non-cash losses reflecting the net change in the fair value of derivatives contracts during the first six months of 2005 and the expiration of certain crude oil put option in 2005, and |
| |
| | § | | Segment margin in 2004 was increased by $322,000 of non-cash gains reflecting the net change in the fair value of derivative contracts for the period. |
Segment margin for the Transportation segment for the year ended December 31, 2005 increased to $15,672,000 from $8,820,000 for the comparable combined period in 2004, a 78 percent increase. The increase was attributable to increased throughputs across the system in 2005.
Operating Expenses.Operating expenses for the year ended December 31, 2005 increased to $24,291,000 from $19,605,000 for the combined year ended December 31, 2004, representing a 24 percent increase. This increase was attributable in part to operating expenses of $2,479,000 incurred in December 2005 associated with TexStar in the Gathering and Processing segment. Also contributing to the increase were higher operating expenses of $969,000 associated with our west Texas assets in the Gathering and Processing segment for the full year ended December 31, 2005 as compared to ten months in 2004. Higher property taxes in the mid-continent region within the Gathering and Processing segment resulted in an increase of $848,000. Also contributing to the increase in operating expenses were higher materials and parts expense of $713,000 in the Transportation segment. These increases were partially offset by lower employee costs and rental expense of $285,000 in the mid-continent region of the Gathering and Processing Segment related to our previously planned shut down of our Lakin gas processing plant. See the discussion on“Gathering and Processing Segment” for additional information regarding the Lakin shut down.
General and Administrative.General and administrative expense increased to $15,039,000 in the year ended December 31, 2005 from $7,216,000 for the combined year ended December 31, 2004. This increase was primarily attributable to higher employee-related expenses of $3,061,000 for higher salary expense associated with increased headcount and bonus accruals. Also contributing to the increase were increased professional and consulting expenses of $2,931,000, consisting primarily of legal fees for regulatory and contract related matters, business development expenses and consulting fees for Sarbanes-Oxley compliance support. Further contributing to the increase were higher management fees of $694,000, resulting from our relationship with HM Capital Partners.
Transaction Expenses.Regency LLC Predecessor incurred non-recurring expenses related to the HM Capital Transaction in the amount of $7,003,000 in 2004. These expenses were comprised of compensation, legal and other expenses and were paid prior to the HM Capital Transaction.
50
Depreciation and Amortization.Depreciation and amortization increased to $23,171,000 in the year ended December 31, 2005 from $11,790,000 for the combined year ended December 31, 2004, representing a 97 percent increase. Depreciation expense increased $9,602,000 primarily due to the acquisition of Regency Gas Services LLC by the HM Capital Investors in December 2004, which increased the book basis of our depreciable assets to their fair market value. Also contributing to the increase was the amortization of identifiable intangible assets of $1,681,000 in the 2005 period related to definite lived intangible assets that were recorded as part of the HM Capital Transaction.
Interest Expense, Net.Interest expense, net increased $11,448,000, or 178 percent, in the year ended December 31, 2005 compared to the combined year ended December 31, 2004 due to higher net interest expense of $10,611,000, primarily related to debt incurred to fund the HM Capital Transaction and to a lesser extent the TexStar Acquisition, and increased amortization of debt issuance costs of $832,000.
Loss on Debt Refinancing.In the year ended December 31, 2005 and 2004, we wrote-off $8,480,000 and $3,022,000, respectively, of debt refinancing costs related to our amended credit facilities in accordance with EITF No. 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instruments.” The $8,480,000 write-off consisted of (i) $5,800,000 of unamortized debt issuance costs, (ii) $1,924,000 of costs incurred in July 2005 and (iii) $756,000 of costs incurred in November 2005 in connection with amendments to our credit facilities. The write-off for the combined year ended December 31, 2004 consisted of unamortized debt issuance costs.
Federal Income Tax.As a pass-through entity, we are not subject to federal income taxes. The liability for federal income taxes associated with income produced by our business is passed through to and recognized by entities that are investors in our indirect parent.
Discontinued Operations.On April 1, 2004, we completed the purchase of natural gas processing and treating interests located in Louisiana and Texas from Cardinal for $3,533,000. On May 2, 2005, we sold all of the assets acquired from Cardinal, together with certain related assets, for $6,000,000. The results of these operations are presented as discontinued operations, and we recorded a gain on the sale of $626,000 during the year ended December 31, 2005.
The Month of December 2004
The HM Capital Investors purchased Regency Gas Services LLC effective December 1, 2004. As a result of accounting for the acquisition as a purchase and using push-down accounting, we incurred additional depreciation and amortization expense. Depreciation and amortization expense for this one month increased over the preceding monthly amount by $669,000 or 67 percent, resulting primarily from the “step-up” in basis of tangible assets as well as the recording of new identifiable intangible assets from the purchase price allocation. The additional interest expense resulted primarily from higher levels of borrowings associated with the acquisition. These levels of borrowings increased to $250,000,000 at December 1, 2004 from $66,599,000 at December 31, 2003.
51
Period from January 1, 2004 to November 30, 2004 vs. Period from Inception (April 2, 2003) to December 31, 2003
The table below contains key company-wide performance indicators related to our discussion of the results of operations.
| | | | | | | | | | | | | | | | | |
| | | Regency LLC | | | Regency LLC | | | | | | | |
| | | Predecessor | | | Predecessor | | | | | | | |
| | | Period from | | | Period from | | | | | | | |
| | | January 1, | | | Inception | | | | | | | |
| | | 2004 to | | | (April 2, 2003) | | | | | | | |
| | | November 30, | | | to December 31, | | | | | | | |
| | | 2004 | | | 2003 | | | Change | | | % Change | |
| | | ($ in thousands) | |
| Revenues | | $ | 432,321 | | | $ | 186,533 | | | $ | 245,788 | | | | 132 | % |
| Cost of sales | | | 362,762 | | | | 163,461 | | | | (199,301 | ) | | | (122 | ) |
| | | | | | | | | | | | | |
| Total segment margin (a) | | | 69,559 | | | | 23,072 | | | | 46,487 | | | | 201 | |
| | | | | | | | | | | | | | | | | |
| Operating expenses | | | 17,786 | | | | 7,012 | | | | (10,774 | ) | | | (154 | ) |
| General and administrative | | | 6,571 | | | | 2,651 | | | | (3,920 | ) | | | (148 | ) |
| Transaction expenses | | | 7,003 | | | | 724 | | | | (6,279 | ) | | | (867 | ) |
| Depreciation and amortization | | | 10,129 | | | | 4,324 | | | | (5,805 | ) | | | (134 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Operating income | | | 28,070 | | | | 8,361 | | | | 19,709 | | | | 236 | |
| | | | | | | | | | | | | | | | | |
| Interest expense, net | | | (5,097 | ) | | | (2,392 | ) | | | (2,705 | ) | | | (113 | ) |
| Loss on debt refinancing | | | (3,022 | ) | | | — | | | | (3,022 | ) | | | n/m | |
| Other income and deductions, net | | | 186 | | | | 205 | | | | (19 | ) | | | (9 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income from continuing operations | | | 20,137 | | | | 6,174 | | | | 13,963 | | | | 226 | |
| | | | | | | | | | | | | | | | | |
| Discontinued operations | | | (121 | ) | | | — | | | | (121 | ) | | | n/m | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income | | $ | 20,016 | | | $ | 6,174 | | | $ | 13,842 | | | | 224 | % |
| | | | | | | �� | | | | | | |
| | | | | | | | | | | | | | | | | |
| System inlet volumes (MMBtu/d) (b) | | | 495,581 | | | | 423,043 | | | | 72,538 | | | | 17 | % |
| | |
| (a) | | For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures.” |
| |
| (b) | | System inlet volumes include total volumes taken into our gathering and processing and transportation systems. |
n/m = not meaningful
52
The table below contains key segment performance indicators related to our discussion of the results of operations.
| | | | | | | | | | | | | | | | | |
| | | Regency LLC | | Regency LLC | | | | |
| | | Predecessor | | Predecessor | | | | |
| | | Period from | | Period from | | | | |
| | | January 1, | | Inception | | | | |
| | | 2004 to | | (April 2, 2003) | | | | |
| | | November 30, | | to December 31, | | | | |
| | | 2004 | | 2003 | | Change | | % Change |
| | | ($ in thousands) |
Segment Financial and Operating Data: | | | | | | | | | | | | | | | | |
| Gathering and Processing Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
| Segment Margin | | $ | 61,347 | | | $ | 18,805 | | | $ | 42,542 | | | | 226 | % |
| Operating expenses | | | 16,230 | | | | 6,131 | | | | (10,099 | ) | | | (165 | ) |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 303,345 | | | | 211,474 | | | | 91,871 | | | | 43 | |
| NGL gross production (Bbls/d) | | | 15,018 | | | | 9,700 | | | | 5,318 | | | | 55 | |
| | | | | | | | | | | | | | | | | |
| Transportation Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
| Segment Margin | | $ | 8,212 | | | $ | 4,267 | | | $ | 3,945 | | | | 92 | % |
| Operating expenses | | | 1,556 | | | | 881 | | | | (675 | ) | | | (77 | ) |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 192,236 | | | | 211,569 | | | | (18,333 | ) | | | (9 | ) |
Results of operations for the year ended December 31, 2003 comprise the period from inception from April 2, 2003 through December 31, 2003; however, the period included only seven months of active operations which began on June 2, 2003.
Net Income.Net income for the eleven months ended November 30, 2004 increased $13,842,000 compared with the seven months of active operations in 2003. Net income was significantly enhanced due to the contribution of $22,065,000 of segment margin related to the purchase of the west Texas assets in 2004. Interest expense, net increased $2,705,000 primarily due to higher net interest expense related to debt incurred to fund the west Texas assets acquisition. In the eleven months ended November 30, 2004, we wrote off $3,022,000 of debt issuance costs in connection with the amendment of our current credit facilities and the repayment of our prior facility. Depreciation and amortization expense increased $5,805,000 primarily due to our higher depreciable basis following the purchase of the west Texas assets. General and administrative expense increased $3,920,000 primarily as a result of higher employee-related expenses and professional and consulting expenses. Operating expenses increased $10,774,000 primarily due to our west Texas facilities operating seven months in 2004 versus none in the 2003 period.
Total Segment Margin.Total segment margin for the eleven months ended November 30, 2004 increased to $69,559,000 from $23,072,000 for the seven months of active operations in 2003, a 201 percent increase. Of this increase:
| | § | | $22,065,000 was produced by operating assets acquired in west Texas in March of 2004; |
| |
| | § | | $14,500,000 was attributable to the operation of our north Louisiana and mid-continent assets, which were acquired in June 2003, for eleven months in the 2004 period compared with seven months of active operations in 2003 period; |
| |
| | § | | $660,000 resulted from NGL marketing operations, which were present in the eleven months ended November 30, 2004 but absent in the seven months of active operations in 2003; and |
| |
| | § | | the remaining $9,200,000 resulted from increased margins per unit of throughput. |
53
Segment margin for the Gathering and Processing segment increased to $61,347,000 for the eleven months ended November 30, 2004 from $18,805,000 for the seven months of active operations in 2003, a 226 percent increase. Of this increase:
| | § | | $22,065,000 was produced by operating assets acquired in west Texas in March of 2004; |
| |
| | § | | $12,100,000 was attributable to the operation of our north Louisiana and mid-continent gathering and processing assets, which were acquired in June 2003, for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period; |
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| | § | | $660,000 was attributable to NGL marketing operations; and |
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| | § | | the remaining $7,600,00 resulted from increased margins per unit of throughput, primarily as a result of commodity price changes. |
Segment margin for the Transportation segment increased to $8,212,000 for the eleven months ended November 30, 2004 from $4,267,000 million for the seven months of active operations in 2003, a 92 percent increase. Of this increase:
| | § | | $2,400,000 was attributable to operation of the north Louisiana and mid-continent assets for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period; and |
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| | § | | $1,500,000 was attributable to increased margins per unit of throughput, primarily as a result of changes in contract mix in 2004. |
Operating Expenses.Operating expenses for the eleven months ended November 30, 2004 increased to $17,786,000 from $7,012,000 in the seven months of active operations in 2003, a 154 percent increase. The addition of the west Texas assets to our Gathering and Processing segment accounted for $6,459,000 of the increase. The remaining increase is attributable to operations for eleven months in the 2004 period as compared to seven months of active operations in the 2003 period, with $3,640,000 of the increase resulting from the remainder of our Gathering and Processing segment and $675,000 of the increase resulting from our Transportation segment.
General and Administrative Expense.General and administrative expense increased to $6,571,000 in 2004 from $2,651,000 in 2003, a 148 percent increase. The increase is primarily attributable to employee related expenses of $2,067,000 and professional and consulting expenses of $1,315,000. The employee related expenses and the professional and consulting expenses were impacted by the eleven months of expense in 2004 versus seven months of active operations in 2003 as well as an increase in payroll expense in 2004 associated with our west Texas assets.
Transaction Expense.Regency LLC Predecessor incurred internal non-recurring expenses related to the sale of Regency Gas Services LLC to the HM Capital Investors in the amount of $7,003,000 in 2004. These expenses consist of compensation, legal and other expenses and were paid by Regency LLC Predecessor prior to the HM Capital Investors’ acquisition. In 2003, the Regency LLC Predecessor incurred $724,000 of legal and other organization expenses related to the formation of Regency LLC Predecessor.
Depreciation and Amortization.Depreciation and amortization increased to $10,129,000 in 2004 from $4,324,000 in 2003, a 134 percent increase. In 2004, depreciation expense of $2,998,000 was associated with our west Texas assets in the Gathering and Processing segment. The remaining increase in depreciation and amortization expense results from eleven months of expense in 2004 versus seven months of active operations in 2003, primarily in the non-west Texas portion of the Gathering and Processing segment.
Interest Expense, Net.Interest expense increased $2,705,000 or 113 percent in 2004 compared to 2003 primarily due to the increased level of borrowings, which were used to finance acquisitions and provide the necessary working capital for the larger enterprise.
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Loss on Debt Refinancing.We expensed approximately $3,022,000 of unamortized debt issuance costs upon the March 1, 2004 amendment and the December 1, 2004 repayment of our prior credit facility.
Federal Income Tax.We are a limited liability company. Accordingly, we are not subject to federal income taxes. Our members incur the liability for federal income taxes associated with income produced by our business.
Other Matters
Hurricane Katrina and Hurricane Rita.Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of our assets in the region. The storms negatively affected the nation’s short term energy supply and natural gas and NGL prices increased significantly thereafter. These higher commodity prices had a favorable net effect on our results of operations as we were, and continue to be, a net seller of these commodities.
While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to our facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area. As a result of these disruptions, we were forced temporarily to curtail producers in the west Texas region for approximately four days and to operate our north Louisiana processing assets in a reduced recovery mode for approximately six days. We have not experienced ongoing effects from these temporary disruptions.
Environmental.A Phase I environmental study was performed on our west Texas assets in connection with our pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. We have an environmental pollution liability insurance policy that covers any undetected or unknown pollution discovered in the future. The policy pays for clean-up costs and damages to third parties and has a ten-year term (expiring in 2014) with a $10,000,000 limit subject to certain deductibles.
In March 2005, the Oklahoma Department of Environmental Quality, or ODEQ, sent a notice of violation, alleging that we operate the Mocane processing plant in Beaver County, Oklahoma in violation of the National Emission Standard for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities, or NESHAP, and the requirements to apply for and obtain a federal operating permit (Title V permit). After seeking and obtaining advice from the Environmental Protection Agency, the ODEQ issued an order requiring us to apply for a Title V permit with respect to emissions from the Mocane processing plant by April 2006. No fine or penalty was imposed by the ODEQ and we intend to comply with the order. Resolution of this matter will not have a material adverse effect on our consolidated results of operations, financial condition, or cash flows.
In November 2004, the Texas Commission on Environmental Quality, or TCEQ, sent a Notice of Enforcement, or NOE, to us relating to the operation of the Waha processing plant in 2001 before it was acquired by us. We settled this NOE with the TCEQ in November 2005.
Absent the alleged physical or operational changes at the Waha processing plant that precipitated the NOE, the air emissions at the plant would have been limited, based on the plant’s “grandfathered” status under the relevant federal statutory standards, only by historical amounts until 2007. In anticipation of the expiration of that status, we submitted to the TCEQ in early February 2005 an application for a state air permit for emissions from the Waha plant predicated on the construction of an acid gas reinjection well and, after completion of the well and facilities, the reinjection of the emitted gases. That permit has been issued and requires completion of construction of the well by the end of February 2007. We estimate the capital expenditure relating to the well at approximately $6,000,000.
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Liquidity and Capital Resources
We expect our sources of liquidity to include:
| | § | | cash generated from operations; |
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| | § | | borrowings under our credit facilities; |
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| | § | | debt offerings; and |
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| | § | | issuance of additional partnership units. |
We believe that the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and growth capital expenditures for the next twelve months.
Cash Flows and Capital Expenditures
Since the inception of our operations in June 2003 through December 31, 2005, there have been several key events that have had major impacts on our cash flows. They are:
| | § | | the acquisition of the El Paso assets on June 2, 2003 in the amount of approximately $119,541,000 which was financed through equity of $53,750,000 and debt of $70,000,000; |
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| | § | | the acquisition of the Waha assets on March 1, 2004 for $67,264,000 of cash and $1,000,000 of assumed liabilities. We financed this acquisition with $10,000,000 of new equity with the balance in debt; |
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| | § | | the acquisition of Regency Gas Services LLC by the HM Capital Investors on December 1, 2004 for approximately $413,754,000, net of working capital adjustments, which was funded through $243,036,000 of term notes and $171,000,000 of equity; |
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| | § | | construction of our Regency Intrastate Enhancement Project at an estimated cost of $157,000,000, which began in May 2005 and was financed through cash flows from operations, long-term debt and a $15,000,000 equity contribution; |
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| | § | | TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in East and South Texas from Enbridge $108,282,000 inclusive of transaction expenses on December 7, 2005; and |
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| | § | | On August 15, 2006, we acquired all the outstanding equity of TexStar for $350,000,000, subject to working capital adjustments. The purchase price for the TexStar Acquisition was paid by (1) the issuance of 5,173,189 Class B common units of the Partnership to HMTF Gas Partners, (2) the payment of $63,289,000 in cash and (3) the assumption of $167,652,000 of TexStar’s outstanding bank debt, subject to working capital adjustments. |
Working Capital (Deficit).Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was $(5,452,000) at December 31, 2003, $1,272,000 at December 31, 2004 and $(33,572,000) at December 31, 2005.
The net increase in working capital from December 31, 2003 to December 31, 2004 of $6,724,000 resulted primarily from the following factors:
| | § | | an increase in cash and cash equivalents of $1,786,000; |
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| | § | | a $2,767,000 increase in the value of risk management assets, resulting from the purchase of calendar 2005 crude oil put options for $2,002,000 that we partially funded with an equity investment, and from a $765,000 unrealized increase in the value of NGL swap contracts; |
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| | § | | a $9,213,000 reduction in the amount of short-term debt partially offset by; |
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| | § | | the addition of the west Texas operations in March 2004 resulted in an increase in accounts payable that was greater than the increase in accounts receivable resulting in a $6,799,000 decrease in working capital. |
The net decrease in working capital from December 31, 2004 to December 31, 2005 of $34,844,000 resulted from five primary factors:
| | § | | a $21,360,000 increase in accounts payable related to the construction of our Regency Intrastate Enhancement Project. Since June 30, 2005, we have financed the project with long-term debt and a $15,000,000 equity contribution. |
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| | § | | a $12,348,000 decrease in the value of our current risk management net assets. As a result of increases in NGL prices, the market value of these contracts has resulted in a liability which, if prices remained unchanged, would be paid over the course of the next twelve months. |
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| | § | | a $2,597,000 decrease in the net value of related party receivables and related party payables associated with our TexStar Acquisition in our Gathering and Processing Segment. |
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| | § | | the decrease in working capital was offset in part by a $1,300,000 decrease in current portion of long-term debt, primarily due to our second amended credit facility, which no longer requires $2,000,000 of annual, scheduled principal payments. |
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| | § | | the decrease in working capital was also offset in part by a $326,000 increase in cash and cash equivalents and a $500,000 increase in restricted cash from our TexStar Acquisition. |
We expect to improve our working capital position during the first quarter of 2006 as a result of the completion of the Regency Intrastate Enhancement Project and paying the related construction expenses. We cannot predict the impact of our derivative instruments on working capital. With respect to the net risk management liabilities, our cash flows from the sale of products at their market prices will allow us to satisfy these obligations should they materialize.
Cash Flows from Operations.Our cash flows from operations for the eleven months ended November 30, 2004 increased by $25,907,000, or 399 percent, from the seven-month period from our date of commencement of operations (June 2, 2003) through December 31, 2003. For the year ended December 31, 2005, our cash flows from operations increased by $9,250,000, or 33 percent, from the combined year ended December 31, 2004.
The increase in the operating cash flows during the eleven-month period ended November 30, 2004 as compared to the seven months ended December 31, 2003 resulted primarily from the increased volumes attributable to the acquisition of our west Texas assets in March 2004. In addition, we commenced active operations in June 2003 and, as a result, 2003 included only seven months of operations while the 2004 period included eleven months of operations. For the eleven months ended November 30, 2004, the west Texas operations contributed the following increases over the seven months ended December 31, 2003: total revenue of $104,564,000, cost of gas and liquids in the amount of $82,499,000 and segment margin of $22,065,000. During the eleven-month period ended November 30, 2004, higher natural gas prices also contributed to improved operating cash flow.
Net cash provided by operating activities increased to $37,340,000 for the year ended December 31, 2005 compared with $28,090,000 for the combined year ended December 31, 2004. The increase was due in part to increased throughput volumes from the Transportation Segment and north Louisiana region of the Gathering and Processing Segment. The increased price
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levels for NGLs increased our cash flows from operations, but these increases were matched by cash outflows from our risk management activities, achieving the cash stabilization goals of our risk management policy. Also contributing to the increase was the inclusion of operations from our TexStar Acquisition in the Gathering and Processing Segment in 2005. The increase in cash flows from operations was partially offset by an increase in cash interest paid of $10,531,000, as the amount of our debt financing significantly increased following the HM Capital Transaction and in connection with our Regency Intrastate Enhancement Project.
For all periods, we used our cash flows from operating activities together with borrowings under our revolving credit facility for our working capital requirements, which include operating expenses, maintenance capital expenditures and repayment of working capital borrowings. From time to time during each period, the timing of receipts and disbursements required us to borrow under our revolving lines of credit. The maximum amounts of revolving line of credit borrowings outstanding during the eleven months ended November 30, 2004 and during the year ended December 31, 2005 were $15,000,000 and $50,000,000, respectively.
Cash Flows Used in Investing Activities.Our cash flows used in investing activities for the eleven months ended November 30, 2004 decreased by $38,444,000, or 31 percent, over the seven-month period ended December 31, 2003. For the year ended December 31, 2005, our cash flows used in investing activities increased by $64,764,000 compared to the combined year ended December 31, 2004.
Our investing cash flows in 2003 were $123,165,000, consisting of $119,541,000 invested in our mid-continent and north Louisiana assets in the acquisition from El Paso Field Services LP and affiliates and $3,624,000 in capital expenditures.
Items comprising our investing activities during the eleven-month period ended November 30, 2004 primarily include:
| | § | | $67,264,000 invested in our west Texas assets acquired from Duke Energy Field Services in March 2004; |
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| | § | | $3,533,000 invested in gas processing assets acquired from Cardinal on April 1, 2004; |
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| | § | | $15,092,000 invested in capital expenditures partially offset by; |
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| | § | | $1,168,000 received in connection with a distribution from an escrow account relating to the El Paso acquisition. |
For the one month ended December 31, 2004 cash flows used in investing activities were $130,478,000, consisting of $127,804,000 of cash payments in connection with the acquisition of Regency Gas LLC by the HM Capital Investors on December 1, 2004 and $2,581,000 invested in capital expenditures. Also in the one month period ended December 31, 2004, we received $280,000 in distributions from one of our unconsolidated subsidiaries. Our equity investments were acquired as part of the TexStar Acquisition.
Our cash flows used in investing activities for the year ended December 31, 2005 were $279,963,000, primarily consisting of:
| | § | | $172,567,000 invested in capital expenditures relating to our Regency Intrastate Enhancement Project and maintenance capital expenditures; |
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| | § | | $108,282,000 invested for the purchase of certain Enbridge assets; |
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| | § | | $5,808,000 invested in acquisition expenses that were paid in February 2005 relating to the acquisition of Regency Gas Services LLC by the HM Capital Investors partially offset by; |
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| | § | | $6,000,000 of proceeds from the sale of Cardinal assets; and |
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| | § | | $1,099,000 of proceeds from the sale of NGL line pack. |
Cash Flows Provided by Financing Activities.Our cash flows provided by financing activities for the eleven months ended November 30, 2004 decreased by $61,865,000, or 52 percent, from the seven-month period ended December 31, 2003. For the year ended December 31, 2005, our cash flows provided by financing activities increased by $54,054,000, or 29 percent, as compared to the combined year ended December 31, 2004.
Our cash flows in 2003 were $118,245,000, consisting of $53,750,000 of net increases in member equity investments and $70,000,000 in proceeds of borrowings under our credit agreement, all of which were used to finance the acquisition of our
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mid-continent and north Louisiana assets. These amounts were partially offset by principal repayments of $3,401,000 and the payment of debt issuance costs in the amount of $2,036,000.
Our cash flows provided by financing activities during the eleven months ended November 30, 2004 were $56,380,000, consisting of:
| | § | | $10,000,000 in proceeds from member equity investments to finance our investment in our west Texas assets; |
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| | § | | $45,363,000 in proceeds from borrowings under our credit agreement, also to finance our investment in our west Texas assets; |
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| | § | | $10,492,000 of repayments under our credit facilities; |
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| | § | | $13,000,000 of net borrowings under our revolving credit facility to finance our investment in our west Texas assets; and |
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| | § | | payment of $1,491,000 for debt issuance costs associated with the establishment of credit facilities |
For the one-month period ended December 31, 2004, our financing cash flows consisted of:
| | § | | $250,000,000 in proceeds of borrowings under our credit agreement which was established for our acquisition by the HM Capital Investors; |
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| | § | | $114,471,000 of repayments of principal under credit agreements terminated as part of the acquisition by the HM Capital Investors; |
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| | § | | payment of $7,514,000 for debt issuance costs associated with the establishment of our credit facilities; and |
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| | § | | $4,500,000 in proceeds from member equity investments to finance a portion of our purchase of crude oil puts. |
In comparison, our net financing cash flows for the year ended December 31, 2005 were $242,949,000, primarily consisting of:
| | § | | $60,000,000 in proceeds of borrowings under the term loan provisions of our credit facility; |
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| | § | | $70,000,000 in proceeds of borrowings under the loan agreement under a credit facility we acquired in the TexStar Acquisition; |
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| | § | | $57,000,000 in equity contributions from the HMTF Gas Partners; |
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| | § | | $15,000,000 in equity contributions from the HM Capital Investors; |
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| | § | | $50,000,000 in proceeds and repayments of borrowings under our revolving credit facility; |
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| | § | | $6,201,000 in debt issuance costs related to amendments to our credit facility; |
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| | § | | $1,800,000 payment for acquiring assets owned by Black Brush, an affiliated company owned by HMTF Gas Partners; and |
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| | § | | $1,650,000 in scheduled repayments of borrowings under our term loan credit facility. |
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:
| | § | | Growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; or |
| | § | | Maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and extend their useful lives or to maintain existing system volumes and related cash flows. |
During the year ended December 31, 2005, our growth capital expenditures were $176,061,000 and our maintenance capital expenditures were $8,958,000, including non-cash expenditures in accounts payable. The major portion of our growth capital expenditures for 2005 was incurred in connection with our Regency Intrastate Enhancement Project.
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Since our inception in 2003, we have made substantial growth capital expenditures, including those relating to the acquisition of our north Louisiana assets and mid-continent assets in 2003, our west Texas assets in 2004, the construction of the Regency Intrastate Enhancement Project in 2005 and the acquisition of the Enbridge assets in December 2005. We anticipate that we will continue to make significant growth capital expenditures. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.
Our 2006 budget includes $25,100,000 of identified organic growth capital expenditures. These expenditures relate to several projects, including a dewpoint control conditioning facility in our north Louisiana region, a gathering system development project in our mid-continent region, an acid gas reinjection well at the Waha gas processing plant and the remaining expenditures on our Regency Intrastate Enhancement Project. We expect that these growth capital expenditures will be funded by borrowings under our credit facility.
We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we will distribute most of our available cash to our unitholders, we will depend on borrowings under our credit facility and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions.
Second Amended and Restated Credit Agreement
On November 30, 2005, Regency Gas Services LLC, or RGS, our wholly owned subsidiary and operating partnership, amended and restated its $410,000,000 first lien credit agreement in order to increase the facility to $470,000,000 and to increase the availability for letters of credit to $50,000,000. In addition, RGS has the option to increase the term loan commitments under the facility on up to four separate occasions, provided that each such increase must be at least $5,000,000, all such increases must not exceed $40,000,000 in the aggregate, no default or event of default shall have occurred or would result due to such increase, and all other additional conditions for the increase of term loan commitments set forth in the facility have been met.
As of December 31, 2005, the facility consisted of $258,350,000 of outstanding term loans, $50,000,000 of term loan commitments and $160,000,000 of revolving loan commitments. RGS’ obligations under the facility are secured by substantially all of our assets. The revolving loans under the facility will mature on December 1, 2009, and the term loans thereunder will mature on June 1, 2010.
Interest on borrowings under the second amended and restated credit facility will be calculated, at the option of RGS, at either (a) a base rate plus an applicable margin of 1.00 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 2.00 percent per annum. RGS shall pay (i) a commitment fee equal to 0.50 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 2.25 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.
In addition, RGS amended and restated its $50,000,000 second lien credit agreement on November 30, 2005; however, such second lien credit facility was repaid in full through a draw down of the $50,000,000 of term loan commitments under the facility described above and terminated on December 2, 2005.
Third Amended and Restated Credit Agreement
Upon the consummation of our initial public offering, the second amended and restated credit facility was amended and restated automatically, and the third amended and restated credit facility became effective. The revolving loan commitments, the ability to increase its term loan commitments, and the maturity dates under the third amended and restated credit facility are the same as they were under the second amended and restated credit facility and RGS’ obligations are secured by substantially all of our assets.
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The Third Amended and Restated Credit Facility contains financial covenants requiring us to maintain total leverage and interest coverage ratios within certain thresholds.
The Third Amended and Restated Credit Facility restricts RGS’ ability to pay dividends, but it authorizes RGS to reimburse us for expenses, and to pay dividends to us, pursuant to our Amended and Restated Agreement of Limited Partnership (so long as no default or event of default has occurred or is continuing). The Third Amended and Restated Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, RGS’ ability (but not our ability) to:
| | § | | incur indebtedness; |
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| | § | | grant liens; |
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| | § | | enter into sale and leaseback transactions; |
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| | § | | make certain investments, loans and advances; |
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| | § | | dissolve or enter into a merger or consolidation; |
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| | § | | enter into asset sales or make acquisitions; |
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| | § | | enter into transactions with affiliates; |
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| | § | | prepay other indebtedness or amend organizational documents or transaction documents (as defined in the third amended and restated credit facility); |
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| | § | | issue capital stock or create subsidiaries; or |
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| | § | | engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the third amended and restated credit facility or reasonable extensions thereof. |
HMTF Gas Partners Promissory Note
On February 18, 2005, the Partnership entered into a $600,000 promissory note with HMTF Gas Partners. The promissory note bears interest at 8.5 percent and is due on December 1, 2011.
TexStar Loan Agreement
On December 6, 2005, TexStar entered into a credit agreement with a third party financial institution to provide financing for the Enbridge asset purchase. The credit agreement provides for a term loan facility in the principal amount of $70,000,000 and a revolving credit facility in the amount of $15,000,000. The credit agreement also provides for letters of credit in varying amounts not to exceed the unused borrowing base of the revolving credit facility. As of December 31, 2005, there were no letters of credit outstanding. The credit agreement provides for swingline loans not to exceed $3,750,000 on the unused borrowing of the revolving credit facility.
The term, revolving credit facility and swingline loans bear various interest rates based upon the Alternative Base Rate (“ABR”), as defined in the credit agreement dated December 6, 2005, plus an applicable margin, as defined by the credit agreement, which is adjusted based upon the Partnership’s leverage ratio. The credit agreement also provides an interest rate option tied to a London Inter-Bank Offer Rate (“LIBOR”), plus the applicable margin. At December 31, 2005, the applicable margin for the term loan facility was 2.25 percent for the ABR based loans and 3.25 percent for the LIBOR based loans.
The term loan facility and the revolving credit facility accrued interest at rates ranging from an average 7.71 percent for the term loan facility to 9.25 percent for the revolving credit facility during the period from December 7, 2005 to December 31, 2005. Commitment fees of 0.25 percent to 0.50 percent per annum on the unused portion of the loan up to the conversion date are required. The total commitment fees paid during 2005 were immaterial.
The term loan facility and revolving credit facility are collateralized by substantially all of the TexStar assets. TexStar must comply with various restrictive covenants contained in the loan agreement which include maintaining specific debt and interest coverage. The credit agreement also restricts payment of dividends, asset sales, sale leaseback transactions, acquisitions, mergers and consolidations, capital expenditures, and creation of liens and limits additional indebtedness. If the Partnership issues debt, preferred stock or equity securities, the credit agreement requires a repayment of amounts borrowed
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equal to 100 percent of the net cash proceeds of an issuance of debt securities or preferred stock and 50 percent of the net cash proceeds of an issuance of equity securities. The Partnership was in compliance with its debt covenants as of December 31, 2005.
On August 15, 2006, the Partnership received a bank facility commitment (the “Bank Facility Commitment”) from UBS Securities LLC, Wachovia Bank, National Association and Citicorp USA, Inc. to provide a credit facility in the amount of $850,000,000 to be used to fund the cash portion of the consideration, to refinance debt assumed, to refinance bank debt currently outstanding as of August 15, 2006 and to provide an expanded revolving credit facility.
Letters of Credit. At December 31, 2005, the Partnership had outstanding letters of credit totaling $10,700,000 related to our risk management activities. The total fees for letters of credit accrue at an annual rate of 2.38 percent, which is applied to the daily amount of letters of credit exposure. As of March 22, 2006, we had $300,000 outstanding letters of credit related to our risk management activities.
Off-Balance Sheet Transactions and Guarantees.We have no off-balance sheet transactions or obligations.
Credit Ratings and Debt Covenants.The current credit ratings on our debt under our second amended and restated credit facility are B1 with a negative outlook by Moody’s Investor Service and B+ with a stable outlook by Standard and Poor’s. At December 31, 2005, we were in compliance with the covenants of the credit facilities.
Total Contractual Cash Obligations.The following table summarizes our total contractual cash obligations as of December 31, 2005.
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| | | Payments Due by Period | |
| Contractual Obligations | | Total | | | 2006 | | | 2007-2008 | | | 2009-2010 | | | Thereafter | |
| | | | | | | | | | | (in thousands) | | | | | | | | | |
| Regency long-term debt (including interest)(1) | | $ | 483,488 | | | $ | 24,613 | | | $ | 51,538 | | | $ | 407,337 | | | $ | — | |
| TexStar debt (including interest) (2) | | | 102,797 | | | | 6,203 | | | | 12,244 | | | | 12,021 | | | | 72,329 | |
| Operating Leases | | | 1,484 | | | | 521 | | | | 891 | | | | 72 | | | | — | |
| Purchase Obligations (3) (4) | | | 3,750 | | | | 3,750 | | | | — | | | | — | | | | — | |
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| Total Contractual Obligations (5) | | $ | 591,519 | | | $ | 35,087 | | | $ | 64,673 | | | $ | 419,430 | | | $ | 72,329 | |
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| (1) | | Assumes a current LIBOR interest rate of 4.53 percent plus the applicable margin, which remains constant in all periods. The contractual obligations also include the effect of interest rate hedges on a notional amount of $200,000,000 through March 2009. |
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| (2) | | Assumes an interest rate of 7.71 percent, which is the average interest rate from December 7, 2005 through December 31, 2005, which remains constant in all periods. |
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| (3) | | Represents the purchase obligation for a pipeline project in north Louisiana. |
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| (4) | | Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount. |
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| (5) | | These amounts do not include an estimated $4,500,000 and $1,500,000 that we expect to spend in 2006 and 2007, respectively, for the construction of an acid gas reinjection well at our Waha gas processing plant. |
The table above does not include our existing obligations as of December 31, 2005 under our ten year financial advisory and monitoring and oversight agreements between us and an affiliate of HM Capital Partners to pay certain management fees and transaction advisory fees to the affiliate of HM Capital Partners. We paid $9,000,000 of the proceeds from our initial public offering to the affiliate of HM Capital Partners to terminate these agreements. The table above does not include obligations under TexStar’s management services agreement with HMTF Gas Partners. The Partnership paid $3,542,000 to HMTF Gas
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Partners to terminate this agreement. As a result, we do not have any continuing obligation to make payments under these agreements.
Recent Accounting Pronouncements
On October 6, 2005, the Financial Accounting Standards Board (the “FASB”) issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings that are incurred during a construction period. We have considered how this might apply to our payment for rights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of the recently issued Staff Position FAS 13-1.
In May 2005, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This accounting standard is effective for fiscal years beginning after December 15, 2005. We do not believe this accounting standard will have a material adverse effect on our results of operations, financial condition or cash flows.
We account for our asset retirement obligations in accordance with Statement of Financial Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” and FIN 47 “Accounting for Conditional Asset Retirement Obligations.” These accounting standards require us to recognize on the balance sheet the net present value of any legally binding obligation to remove or remediate the physical assets that we retire from service, as well as any similar obligations for which the timing and/or method of settlement are conditional on a future event that may or may not be within our control. While we are obligated under contractual agreements to remove certain facilities upon their retirement, we are unable to reasonably determine the fair value of any asset retirement obligations as of December 31, 2005 and 2004 because the settlement dates, or ranges thereof, were indeterminable and could range up to ninety-six years, and the undiscounted amounts are immaterial. An asset retirement obligation will be recorded in the periods wherein we can reasonably determine the settlement dates.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-based Payment,” which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123 (revised 2004) is effective for the first interim or annual reporting period that begins after June 15, 2005. We adopted SFAS 123(R) “Share-Based Payment” in the first quarter of 2006 which had no impact to us as no LTIP awards were outstanding during 2005.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”,which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever another standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership estimates that the adoption of this standard will not have a material impact on its financial position, results of operations or cash flows.
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