Exhibit 99.2. 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 growth-oriented publicly-traded Delaware limited partnership engaged in the gathering, processing, contract compression, marketing and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas, Oklahoma, and Colorado.
OUR OPERATIONS. Prior to the acquisition of CDM in January 2008, we managed our business and analyzed and reported our results of operations through two business segments.
| Gathering and Processing: we provide “wellhead-to-market: services to producers of natural gas, which include transporting raw natural gas from wellhead through gathering system, processing raw natural gas to separate NGLs from raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets an pipeline systems; and |
| Transportation: we deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Interstate Pipeline system. |
On January 15, 2008, we acquired CDM, which now comprises our contract compression segment. Our contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. Our integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs. We are responsible for the installation and ongoing operation, service, and repair of our compression units, which we modify as necessary to adapt to our customers’ changing operating conditions.
Through December 31, 2007, all of our revenue is derived from, and all of our assets and operations are part of our gathering and processing segment and our transportation segment. As such the following discussion of our financial condition and results of operation does not reflect our contract compression segment.
Gathering and processing segment. Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas that 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. 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 fixed 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. The following is a summary of our most common contractual arrangements:
| Fee Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering 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. These arrangements provide stable cash flows, but minimal, if any, upside in high commodity price environments. The FrontStreet acquisition increases the size of our fee based operation and provides us with steady cash flow. |
| · | Percent of Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at price based on published indeed prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and retained sale 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 can’t be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to produce is based pm an agreed percentage of one of the following:(1) the actual 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 correlated directly with the prices of natural gas and NGLs (although there is often a fee-based component to the contract in addition to the commodity sensitive components). |
| 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 processing in unfavorable price environments. |
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, 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. We seek to replace our longer term keep-whole arrangements as they expire or whenever the opportunity presents itself.
Another way we minimize our exposure to commodity price fluctuations is by executing swap contracts settled against ethane, propane, butane, natural gasoline, crude oil, and natural gas market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
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 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 an outlet. 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. If a sustained decline in commodity prices should result 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. When we agree to provide firm transportation service, we become 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. |
| · | Interruptible Transportation. When we agree to provide interruptible transportation service, we become obligated to transport natural gas nominated by the shipper only 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. |
We provide transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with the FERC with respect to transportation authorized under section 311 of the NGPA.
In addition, we perform a limited merchant function on RIGS. 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.
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 a 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.
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 tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin and operating and maintenance 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 affected by (1) the level of work over or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (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 in search of 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, including 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 of natural gas.
We calculate our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchase and sell gas for our account, gas sales revenue minus the cost of natural gas that we purchase and transport. Revenue primarily includes fees for the transportation of pipeline-quality natural gas and the margin generated by sales of natural gas transported for our account. 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.
Total Segment Margin. Segment margin from Gathering and Processing, together with segment margin from Transportation, comprise total segment margin. We use total segment margin as a measure of performance. See “Selected Financial Data — Non-GAAP Financial Measures” for a reconciliation of this non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measures, net cash flows provided by (used in) operating activities and net income (loss).
Operation and Maintenance Expenses. Operation and maintenance expense is 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 and maintenance expense. 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 operation and maintenance expenses from total 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 |
| · | the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unit holders and general partner; |
| · | 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 |
| · | The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
EBITDA should not be considered as 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 non-GAAP financial measure for a publicly traded master limited partnership. See “Exhibit 99.1- Financial Data-Non GAAP Financial Measure” for a reconciliation of EBITDA to net cash flows provided by (used in) operating activities and to net income (loss).
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 incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply, Demand and Outlook. Natural gas remains a critical component of energy consumption in the United States. 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 and additional sources of supply such as liquefied natural gas and other 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.
Effect of Interest Rates and Inflation. Interest rates on existing and 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 effect on our results of operations. 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.
HISTORY OF THE PARTNERSHIP AND ITS PREDECESSOR
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 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 and Duke Energy Field Services Assets. In June 2003, Regency Gas Services LLC acquired certain natural gas gathering, processing, and transportation assets located in north Louisiana and the mid-continent region of the United States from subsidiaries of El Paso Corporation for $119,541,000. In March 2004, Regency Gas Services LLC acquired certain natural gas gathering and processing assets located in west Texas from Duke Energy Field Services, LP for $67,264,000, including transactional costs. ��Prior to our acquisitions, these assets were operated as components of the seller’s much larger midstream operations. There were no material financial results for periods prior to June 2003.
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 our predecessor, 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. This push down accounting increased deprecation, amortization and interest expenses for periods subsequent to December 1, 2004. We refer to this transaction as the HM Capital Transaction. For periods prior to the HM Capital Transaction, we designated such periods as Regency LLC Predecessor.
Initial Public Offering. Prior to the 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.
Enbridge Asset Acquisition. TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in east and south Texas from subsidiaries of Enbridge for $108,282,000 inclusive of transaction expenses on December 7, 2005. The Enbridge acquisition was accounted for using the purchase method of accounting. The results of operations of the Enbridge assets are included in our statements of operations beginning December 1, 2005.
Acquisition of TexStar. On August 15, 2006, we acquired all the outstanding equity of TexStar for $348,909,000, which consisted of $62,074,000 in cash, the issuance of 5,173,189 Class B common units valued at $119,183,000 to an affiliate of HM Capital, and the assumption of $167,652,000 of TexStar’s outstanding bank debt. Because the TexStar acquisition was a transaction between commonly controlled entities, we accounted for the TexStar acquisition in a manner similar to a pooling of interests. As a result, our historical financial statements and the historical financial statements of 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.
Pueblo Acquisition. On April 2, 2007, we acquired a 75 MMcf/d gas processing and treating facility, 33 miles of gathering pipelines and approximately 6,000 horsepower of compression. The purchase price for the Pueblo acquisition consisted of (1) the issuance of 751,597 common units, valued at $19,724,000 and (2) the payment of $34,855,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $108,000. The Pueblo acquisition was accounted for using the purchase method of accounting. The results of operations of the Pueblo assets are included in our statements of operations beginning April 1, 2007.
GE EFS acquisition of HM Capital’s Interest. On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of GECC, acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners. Concurrently, Regency LP Acquirer LP, another indirect subsidiary of GECC, acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management team. As a part of this acquisition, affiliates of HM Capital Partners entered into an agreement to hold 4,692,417 of the Partnership’s common units for a period of 180 days. In addition, a separate affiliate of HM Capital Partners entered into an agreement to hold 3,406,099 of the Partnership’s common units for a period of one year.
GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of GE. For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.” Concurrent with the Partnership's issuance of common units in July and August 2007, GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $7,735,000 to maintain the General Partner’s two percent interest in the Partnership.
Concurrent with the GE EFS acquisition, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units to for a total consideration of $24.00 per unit. Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.
The Partnership was not required to record any adjustments to reflect GE EFS’s acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).
Acquisition of FrontStreet Hugoton, LLC. On January 7, 2008 we acquired FrontStreet Hugoton, LLC from ASC and EnergyOne (the “Sellers”) for a total consideration of (1) the issuance of 4,701,034 Class E common units of the Partnership to ASC and (2) the payment of $11,752,000 in cash to EnergyOne. Because the FrontStreet acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), we accounted for the acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, the FrontStreet acquisition will reflect historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities. Further, as a result of this method of accounting, certain transaction costs that would normally be capitalized will be expensed. The Partnership recast its financial statements to include the operations of FrontStreet from June 18, 2007 (the date upon which common control began) forward.
RESULTS OF OPERATIONS
Year Ended December 31, 2007 vs. Year Ended December 31, 2006
The table below contains key company-wide performance indicators related to our discussion of the results of operations.
| | | Year Ended December 31, | |
| | | 2007 | | | 2006 | | | Change | | | Percent | |
| | | (in thousands except percentages and volume data) | | | | |
| Total revenues | | $ | 1,190,238 | | | $ | 896,865 | | | $ | 293,373 | | | | 33 | % |
| Cost of gas and liquids | | | 976,145 | | | | 740,446 | | | | 235,699 | | | | 32 | |
Total segment margin (1) | | | 214,093 | | | | 156,419 | | | | 57,674 | | | | 37 | |
| Operation and maintenance | | | 58,000 | | | | 39,496 | | | | 18,504 | | | | 47 | |
General and administrative (2) | | | 39,713 | | | | 22,826 | | | | 16,887 | | | | 74 | |
| Loss on asset sales, net | | | 1,522 | | | | - | | | | 1,522 | | | | n/m | |
| Management services termination fee | | | - | | | | 12,542 | | | | (12,542 | ) | | | (100 | ) |
| Transaction expenses | | | 420 | | | | 2,041 | | | | (1,621 | ) | | | (79 | ) |
| Depreciation and amortization | | | 55,074 | | | | 39,654 | | | | 15,420 | | | | 39 | |
| Operating income | | | 59,364 | | | | 39,860 | | | | 19,504 | | | | 49 | |
| Interest expense, net | | | (52,016 | ) | | | (37,182 | ) | | | (14,834 | ) | | | 40 | |
| Loss on debt refinancing | | | (21,200 | ) | | | (10,761 | ) | | | (10,439 | ) | | | 97 | |
| Other income and deductions, net | | | 1,252 | | | | 839 | | | | 413 | | | | 49 | |
| Loss before income taxes and minority interest | | | (12,600 | ) | | | (7,244 | ) | | | (5,356 | ) | | | 74 | |
| Income tax expense | | | 931 | | | | - | | | | 931 | | | | n/m | |
| Minority interest in net income from subsidairy | | | 305 | | | | - | | | | 305 | | | | n/m | |
| Net loss | | $ | (13,836 | ) | | $ | (7,244 | ) | | $ | (6,592 | ) | | | 91 | % |
| | | | | | | | | | | | | | | | | |
System inlet volumes (MMBtu/d) (3) | | | 1,225,918 | | | | 1,010,642 | | | | 215,276 | | | | 21 | % |
(1) For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - - Selected Financial Data-Non -GAAP Measures".
(2) Includes a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common units options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS.
(3) System inlet volumes include total volumes taken into our gathering and processing and transportation systems.
n/m = not meaningful
The table below contains key segment performance indicators related to our discussion of our results of operations.
| | | Year Ended December 31, | |
| | | 2007 | | | 2006 | | | Change | | | Percent | |
| | | (in thousands except percentages and volume data) | | | | |
| Gathering and Processing Segment | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | |
Segment margin (1) | | $ | 154,761 | | | $ | 111,372 | | | $ | 43,389 | | | | 39 | % |
| Operation and maintenance | | | 53,496 | | | | 35,008 | | | | 18,488 | | | | 53 | |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 772,930 | | | | 529,467 | | | | 243,463 | | | | 46 | |
| NGL gross production (Bbls/d) | | | 21,808 | | | | 18,587 | | | | 3,221 | | | | 17 | |
| | | | | | | | | | | | | | | | | |
| Transportation Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
Segment margin (1) | | $ | 59,332 | | | $ | 45,047 | | | $ | 14,285 | | | | 32 | % |
| Operation and maintenance | | | 4,504 | | | | 4,488 | | | | 16 | | | | 0 | |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 751,761 | | | | 587,098 | | | | 164,663 | | | | 28 | |
| | | | | | | | | | | | | | | | | |
(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - Selected Financial Data- Non-GAAP Financial Measures".
Net Loss. Net loss for the year ended December 31, 2007 increased $6,592,000 compared with the year ended December 31, 2006. An increase in total segment margin of $57,674,000, primarily due to organic growth in the gathering and processing segment; the absence in 2007 of management services termination fees of $12,542,000 from our initial public offering and TexStar acquisition; and a decrease in transaction expenses of $1,621,000 associated with acquisitions of entities under common control were more than offset by:
| · | an increase in general and administrative expense of $16,887,000 primarily due to a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS and higher employee related expenses; |
| · | an increase in interest expense, net of $14,834,000 primarily due to increased levels of borrowings used primarily to finance our Pueblo acquisition and growth capital projects; |
| · | an increase in loss on debt refinancing of $10,439,000 primarily due to a $16,122,000 early termination penalty in 2007 associated with the redemption of 35 percent of our senior notes partially offset by a $5,683,000 decrease in the write-off of capitalized debt issuance costs related to paying off or refinancing credit facilities; |
| · | $5,792,000 net income attributable to our FrontStreet assets; |
| · | an increase in depreciation and amortization of $15,420,000 primarily due to higher levels of depreciation from projects completed since December 31, 2006 and our Pueblo acquisition; and |
| · | a net loss on the sale of certain non-core assets of $1,522,000 in the year ended December 31, 2007. |
Segment Margin. Total segment margin for the year ended December 31, 2007 increased $57,674,000 compared with the year ended December 31, 2006. This increase was attributable to an increase of $43,389,000 in gathering and processing segment margin and an increase of $14,285,000 in transportation segment margin as discussed below.
Gathering and processing segment margin increased to $154,761,000 for the year ended December 31, 2007 from $111,372,000 for the year ended December 31, 2006. The major components of this increase were as follows:
| · | $23,233,000 attributable to organic growth projects in the east and south Texas regions; |
| · | $22,184,000 attributable to our FrontStreet assets; |
| · | $15,538,000 attributable to organic growth in the north Louisiana region; and offset by |
| · | $17,449,000 of non-cash losses from certain risk management activities. |
Transportation segment margin increased to $59,332,000 for the year ended December 31, 2007 from $45,047,000 for the year ended December 31, 2006. The major components of this increase were as follows:
| · | $11,512,000 attributable to increased throughput volumes; |
| · | $1,752,000 of increased margins related to our merchant function |
| · | $631,000 attributable to increased margins per unit of throughput; and |
| · | $390,000 of non-cash gains from certain risk management activities. |
Operation and Maintenance. Operations and maintenance expense increased to $58,000,000 in the year ended December 31, 2007 from $39,496,000 for the corresponding period in 2006, a 47 percent increase. This increase is primarily the result of the following factors:
| · | $12,526,000 attributable to our FrontStreet assets; |
| · | $3,217,000 of increased employee related expenses primarily in the gathering and processing segment resulting from additional employees related to organic growth and employee annual pay raises; |
| · | $1,219,000 of increased consumable expenses primarily in the gathering and processing segment largely resulting from additional compression; |
| · | $1,034,000 of increased contractor expense primarily in the gathering and processing segment associated with our Fashing processing plant; |
| · | $811,000 of increased utility expense primarily in the gathering and processing segment resulting from one of our north Louisiana refrigeration plants placed in service in December 2006; and |
| · | $637,000 of unplanned outage expense in the transportation segment in 2007 related to the Eastside compressor fire, which represents our estimated thirty day deductible. |
Partially offsetting these increases in operation and maintenance expense were the following factors:
| · | $1,741,000 of insurance proceeds associated with our unplanned compressor outage in the transportation segment in 2007; and |
| · | $549,000 of decreased rental expense primarily in the gathering and processing segment from fewer leased compressor units. |
General and Administrative. General and administrative expense increased to $39,713,000 in the year ended December 31, 2007 from $22,826,000 for the same period in 2006, a 74 percent increase. The increase is primarily due to:
| · | a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS; |
| · | $3,607,000 of increased employee related expenses resulting from pay raises and the hiring of additional employees; |
| · | $777,000 of increased professional and consulting expense primarily for Sarbanes-Oxley compliance; and |
| · | partially offsetting these increases was the absence in 2007 of management fees of $361,000 in 2006. |
Other. In the year ended December 31, 2006, we recorded charges of $12,542,000 for the termination of long-term management services contracts in connection with our initial public offering and TexStar acquisition. In the years ended December 31, 2007 and 2006, we incurred transaction expenses of $420,000 related to our 2008 FrontStreet acquisition and $2,041,000 related to our TexStar acquisition. Since these acquisitions involve entities under common control, we accounted for these transactions in a manner similar to pooling of interests and expensed the transaction costs. In the year ended December 31, 2007, we sold certain non-core assets and recorded a related net charge of $1,522,000.
Depreciation and Amortization. Depreciation and amortization expense increased to $55,074,000 in the year ended December 31, 2007 from $39,654,000 for the year ended December 31, 2006, a 39 percent increase. The increase is due to higher depreciation expense of $13,914,000 primarily from projects completed since December 31, 2006, our Pueblo acquisition, and our FrontStreet assets. Also contributing to the increase was higher identifiable intangible asset amortization of $1,506,000 primarily related to contracts associated with the Pueblo acquisition and the TexStar acquisition in April 2007 and July 2006, respectively.
Interest Expense, Net. Interest expense, net increased $14,834,000, or 40 percent, in the year ended December 31, 2007 compared to the same period in 2006. Of this increase, $8,243,000 was attributable to increased levels of borrowings and $4,026,000, was attributable to higher interest rates partially offset by the 2006 reclassification of $2,607,000 from accumulated other comprehensive income associated with the gain upon the termination of an interest rate swap.
Loss on Debt Refinancing. In the year ended December 31, 2007, we paid a $16,122,000 early repayment penalty associated with the redemption of 35 percent of our senior notes. We also expensed $5,078,000 of debt issuance costs related to the pay off of the term loan facility and the early termination of senior notes. In the year ended December 31, 2006, we wrote-off $5,626,000 of debt issuance costs to amend and restate our credit facility and we wrote-off $5,135,000 of debt issuance costs associated with paying off TexStar’s loan agreement as part of our TexStar acquisition.
Year Ended December 31, 2006 vs. Year Ended December 31, 2005
The table below contains key company-wide performance indicators related to our discussion of the results of operations.
| | | Year Ended December 31, | |
| | | 2006 | | | 2005 | | | Change | | | Percent | |
| | | (in thousands except percentages and volume data) | | | | |
| Total revenues | | $ | 896,865 | | | $ | 709,401 | | | $ | 187,464 | | | | 26 | % |
| Cost of gas and liquids | | | 740,446 | | | | 632,865 | | | | 107,581 | | | | 17 | |
Total segment margin (1) | | | 156,419 | | | | 76,536 | | | | 79,883 | | | | 104 | |
| Operation and maintenance | | | 39,496 | | | | 24,291 | | | | 15,205 | | | | 63 | |
| General and administrative | | | 22,826 | | | | 15,039 | | | | 7,787 | | | | 52 | |
| Management services termination fee | | | 12,542 | | | | - | | | | 12,542 | | | | n/m | |
| Transaction expenses | | | 2,041 | | | | - | | | | 2,041 | | | | n/m | |
| Depreciation and amortization | | | 39,654 | | | | 23,171 | | | | 16,483 | | | | 71 | |
| Operating income | | | 39,860 | | | | 14,035 | | | | 25,825 | | | | 184 | |
| Interest expense, net | | | (37,182 | ) | | | (17,880 | ) | | | (19,302 | ) | | | (108 | ) |
| Loss on debt refinancing | | | (10,761 | ) | | | (8,480 | ) | | | (2,281 | ) | | | 27 | |
| Other income and deductions, net | | | 839 | | | | 733 | | | | 106 | | | | 14 | |
| Loss from continuing operations | | | (7,244 | ) | | | (11,592 | ) | | | 4,348 | | | | 38 | |
| Discontinued operations | | | - | | | | 732 | | | | (732 | ) | | | (100 | ) |
| Net loss | | $ | (7,244 | ) | | $ | (10,860 | ) | | $ | 3,616 | | | | 33 | % |
| | | | | | | | | | | | | | | | | |
System inlet volumes (MMBtu/d)(2) | | | 1,010,642 | | | | 603,592 | | | | 407,050 | | | | 67 | % |
(1) For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - - Selected Financial Data-Non -GAAP Measures".
(2) System inlet volumes include total volumes taken into our gathering and processing and transportation systems.
n/m = not meaningful
The table below contains key segment performance indicators related to our discussion of our results of operations.
| | | Year Ended December 31, | |
| | | 2006 | | | 2005 | | | Change | | | Percent | |
| | | (in thousands except percentages and volume data) | | | | |
| Gathering and Processing Segment | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | |
Segment margin (1) | | $ | 111,372 | | | $ | 60,864 | | | $ | 50,508 | | | | 83 | % |
| Operation and maintenance | | | 35,008 | | | | 22,362 | | | | 12,646 | | | | 57 | |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 529,467 | | | | 345,398 | | | | 184,069 | | | | 53 | |
| NGL gross production (Bbls/d) | | | 18,587 | | | | 14,883 | | | | 3,704 | | | | 25 | |
| | | | | | | | | | | | | | | | | |
| Transportation Segment | | | | | | | | | | | | | | | | |
| Financial data: | | | | | | | | | | | | | | | | |
Segment margin (1) | | $ | 45,047 | | | $ | 15,672 | | | $ | 29,375 | | | | 187 | % |
| Operation and maintenance | | | 4,488 | | | | 1,929 | | | | 2,559 | | | | 133 | |
| Operating data: | | | | | | | | | | | | | | | | |
| Throughput (MMBtu/d) | | | 587,098 | | | | 258,194 | | | | 328,904 | | | | 127 | |
(1) For reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Exhibit 99.1 - Selected Financial Data- Non-GAAP Financial Measures".
Net loss. Net loss for the year ended December 31, 2006 decreased $3,616,000 compared with the year ended December 31, 2005. The decrease in net loss was primarily attributable to an increase in total segment margin of $79,883,000 largely due to increased contributions from the Transportation segment resulting from the completion on our Regency Intrastate Enhancement Project in December 2005, a full year of segment margin from our TexStar acquisition and increased performance from the remainder of the Gathering and Processing segment. The increase in total segment margin was offset by increases in the following expenses:
| · | interest expense, net increased $19,302,000 primarily due to increased levels of borrowing to fund acquisitions and capital expenditures; |
| · | depreciation and amortization expense increased $16,483,000 primarily due to a full year of expense in 2006 versus a partial year’s expense in 2005 due to the timing of acquisitions and completion of capital projects; |
| · | operation and maintenance increased $15,205,000 primarily due to a full year of expense in 2006 for the TexStar |
| · | management service termination fees of $12,542,000 in 2006, which were not present in 2005; |
| · | general and administrative expenses increased $7,787,000 primarily resulting from TexStar general and administrative expenses, the accrual of non-cash expense associated with our LTIP and higher employee-related expenses associated with the hiring of key personnel to assist in achieving our strategic objectives; |
| · | loss on debt refinancing increased $2,281,000 resulting from increased write-offs of capitalized debt issuance costs related to certain credit facilities that we refinanced in 2006; and |
| · | transaction expenses of $2,041,000 recorded in 2006 related to the TexStar acquisition. |
Segment Margin. Total segment margin for the year ended December 31, 2006 increased to $156,419,000 from $76,536,000 for the year ended December 31, 2005, representing a 104 percent increase.
Gathering and Processing segment margin for the year ended December 31, 2006 increased to $111,372,000 from $60,864,000 for the year ended December 31, 2005, representing an 83 percent increase. The major elements driving this increase in segment margin are as follows:
| · | $23,513,000 attributable to the operations of the other TexStar assets for a full year in 2006 versus one month of operations in 2005; |
| · | $13,986,000 in non-cash losses due to changes to the value of risk management assets for which we applied to mark-to-market accounting in the first six months of 2005 prior to our election of hedge accounting; |
| · | $6,347,000 contributed by the Elm Grove and Dubberly refrigeration plants beginning in May 2006 (Elm Grove) and December 2006 (Dubberly); |
| · | $4,553,000 contributed by the Como assets that were acquired on July 25, 2006;and |
| · | $2,109,000 of other changes. |
Transportation segment margin for the year ended December 31, 2006 increased to $45,047,000 from $15,672,000 for the year ended December 31, 2005, a 187 percent increase. This increase was attributable to the expansion and extension of the line completed in late 2005, as well as additional improvements in 2006. The major drivers of this growth are as follows:
| $15,931,000 attributable to increased volume through-put; |
| $9,443,000 attributable to increased average fees for service; and |
| $4,001,000 of marketing activity generated by our merchant function |
Operation and Maintenance. Operation and maintenance expenses for the year ended December 31, 2006 increased to $39,496,000 from $24,291,000 for the year ended December 31, 2005, representing a 63 percent increase. This increase resulted primarily from $13,248,000 higher expenses associated with TexStar. Also contributing to the increase from the transportation segment were higher employee-related expenses of $421,000 primarily for overtime associated with maintenance events and increased non-income taxes of $1,665,000, primarily property taxes related to the enhancement of our RIGS pipeline.
General and Administrative. General and administrative expenses for the year ended December 31, 2006 increased to $22,826,000 from $15,039,000 for the corresponding period in 2005. The increase was attributable in part to higher employee-related expenses of $3,300,000, including higher salary expense associated with hiring key personnel to assist in achieving our strategic objectives. Also contributing to the increase was the accrual of non-cash expense of $2,906,000 associated with our long-term incentive plan. TexStar contributed $1,519,000 to the increase in general and administrative expense.
Management Services Termination Fee. In the three months ended March 31, 2006 we recorded a one-time charge of $9,000,000 for the termination of two long-term management services contracts in connection with our initial public offering, paid with proceeds from the initial public offering. In the three months ended September 30, 2006 we recorded a one-time charge of $3,542,000 for the termination of a management services contract associated with our TexStar acquisition.
Transaction Expenses. We incurred transaction expenses of $2,041,000 in 2006 related to our TexStar acquisition. Since our TexStar acquisition involved entities under common control, we accounted for the transaction in a manner similar to a pooling of interests and we expensed the transaction costs.
Depreciation and Amortization. Depreciation and amortization expense for the year ended December 31, 2006 increased to $39,654,000 from $23,171,000 for the year ended December 31, 2005, representing a 71 percent increase. Depreciation and amortization expense increased $7,261,000 primarily due to the higher depreciable basis in the transportation segment resulting from the completion of our Regency Intrastate Enhancement Project in December 2005. The new depreciable basis of assets from our TexStar acquisition in the Gathering and Processing segment contributed $6,898,000 to the increase. Depreciation and amortization expense in the remainder of the Gathering and Processing segment increased $1,977,000 due primarily to the completion of various capital projects.
Interest Expense, Net. Interest expense, net for the year ended December 31, 2006 increased to $37,182,000 from $17,880,000 for the prior year period. Of the $19,302,000 increase, $19,226,000 was attributable to increased borrowings, $3,166,000 was attributable to increased interest rates, and $771,000 was attributable to reduced unrealized gains on mark-to-market accounting for interest rate swaps, offset by $3,862,000 of proceeds from the early termination of three interest rate swap contracts reclassified into earnings from accumulated other comprehensive income.
Loss on Debt Refinancing. For the year ended December 31, 2006 we expensed $10,761,000 of debt issuance costs to amend and restate our credit facility, of which $5,135,000 was associated with repaying TexStar’s credit facility as part of our TexStar acquisition. For the year ended December 31, 2005, as required, we wrote off $8,480,000 of debt issuance costs to amend our credit facility.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We expect our sources of liquidity to include:
| · | cash generated from operations; |
| · | borrowings under our credit facility; |
| · | 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 maintenance and growth capital expenditures for the next twelve months.
See “— History of the Partnership and its Predecessor” for a discussion of why our cash flows and capital expenditures may not be comparable, either from period to period or going forward.
Working Capital Surplus (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. During periods of growth capital expenditures, we experience working capital deficits when we fund construction expenditures out of working capital until they are permanently financed. Our working capital is also influenced by current risk management assets and liabilities due to fair market value changes in our derivative positions being reflected on our balance sheet. These represent our expectations for the settlement of risk management rights and obligations over the next twelve months, and so must be viewed differently from trade receivables and payables which settle over a much shorter span of time. Risk management assets and liabilities affect working capital. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect these assets and liabilities to affect our ability to pay bills as they come due.
Our working capital deficit increased by $3,125,000 from December 31, 2006 to December 31, 2007 primarily due to the following:
| · | a $36,331,000 decrease in working capital due to an increase in net current liabilities from risk management activities resulting from an increase in the commodity prices we expect to pay (index prices) on our outstanding swaps as compared to the commodity prices we expect to receive upon settlement; |
| · | a $23,832,000 increase in working capital resulting from an increase in cash and cash equivalents primarily due to the timing of payment of accounts payable; and |
| · | a $8,976,000 increase in working capital resulting from an increase in net accounts receivable and payable due to the timing of cash receipts and payments. |
Cash Flows from Operating Activities. Net cash flows provided by operating activities increased $35,373,000, or 80 percent, for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Cash generated from operations increased primarily due to increased total segment margin of $57,674,000, primarily due to organic growth in the gathering and processing segment and from operating activity of FrontStreet assets acquired in June 18, 2007.
Net cash flows provided by operating activities increased $6,816,000, or 18 percent, for the year ended December 31, 2006 compared to the corresponding period in 2005. The primary reason for the increased cash flow was increased margin contributions resulting from the completion of the enhancement of our RIGS pipeline, the installation of additional capacity on our gathering and processing systems and our acquisition of TexStar. The remaining improvement was attributable to the termination of interest rate swaps in June and December 2006. We terminated the interest rate swap because in the fourth quarter of 2006 because we refinanced the majority of our variable interest rate debt with fixed rate, 8.375 percent senior notes due in 2013. These increases in cash flows from operations were partially offset by higher interest costs primarily due to increased borrowings, the payment of management services contract termination fees, the payment of transaction fees related to our TexStar acquisition and losses on the refinancing of credit agreements.
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 operation and maintenance 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 credit facility. The maximum amounts of revolving line of credit borrowings outstanding during the years ended December 31, 2007 and 2006 were $178,930,000 and $112,600,000, respectively.
Cash Flows from Investing Activities. Net cash flows used in investing activities decreased $65,717,000, or 29 percent, in the year ended December 31, 2007 compared to the year ended December 31, 2006. The decrease is primarily due to our 2006 Como assets acquisition ($81,695,000), proceeds from the asset sales in 2007 of $11,706,000, a decrease in spending on growth and maintenance capital expenditures of $19,121,000, partially offset by our 2007 Pueblo acquisition ($34,855,000).
Growth Capital Expenditures. In the year ended December 31, 2007, we incurred $84,252,000 of growth capital expenditures. Growth capital expenditures for the year ended December 31, 2007 primarily relate to the following projects:
| · | $8,300,000 for constructing 20 miles of 10 inch diameter pipeline, which will connect the Fashing Processing Plant to our Tilden Processing Plant in south Texas and reconfiguring our Tilden Processing Plant, expected to be completed in the first half of 2008; |
| · | $11,500,000 to re-build and activate an existing nitrogen rejection unit at our Eustace Processing Plant, completed in the second quarter of 2007; |
| · | $8,600,000 for constructing 31 miles of 12 inch diameter pipeline in south Texas, completed in the second quarter of 2007; |
| · | $8,100,000 for the electrification and adding an acid gas injection well at our Tilden Processing Plant, completed in the second quarter of 2007; and |
| · | $5,947,000 of capital expenditure projects that were carried out by FrontStreet. |
Our 2008 growth budget includes $208,000,000 of currently identified organic growth capital expenditures, including $118,000,000 for CDM compression for an additional 174,700 horsepower. The significant growth capital expenditures in our gathering and processing segment are for the following projects:
| · | $14,300,000, in addition to the $8,300,000 spent in 2007, for constructing 20 miles of 10 inch diameter pipeline, which will connect the Fashing Processing Plant to our Tilden Processing Plant in south Texas and reconfiguring our Tilden Processing Plant, expected to be completed in the first half of 2008; |
| · | $16,700,000 for constructing a 40 mile, 10 inch diameter pipeline, expected to be completed in 2008; |
| · | $9,394,000 for construction and equipment related to a joint venture in south Texas; |
| · | $6,700,000 for compression and gathering in south Texas; and |
| · | $5,800,000 for Dubach plant expansion. |
We expect to fund these growth capital expenditures out of borrowings under our existing credit agreement. We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we distribute our available cash to our unitholders, we depend on borrowings under our credit facility and the proceeds from the issuance and sale of debt and equity securities to finance any future growth capital expenditures or acquisitions.
Maintenance Capital Expenditures. In the year ended December 31, 2007, we incurred $8,764,000 of maintenance capital expenditures. Maintenance capital expenditures primarily consist of compressor and plant overhauls, as well as new well connects to our gathering systems, which replace volumes from naturally occurring depletion of wells already connected. Our 2008 budget for maintenance capital expenditures is $17,000,000.
Net cash flows used in investing activities decreased $56,313,000, or 20 percent, for the year ended December 31, 2006 compared to the year ended December 31, 2005. The decrease was primarily due to lower levels of spending on asset purchases and growth and maintenance capital expenditures, discussed below. We categorize our capital expenditures as either: (a) 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 (b) maintenance capital expenditures, which are made to maintain the existing operating capacity of our assets and to extend their useful lives or to maintain existing system volumes and related cash flows.
Cash Flows from Financing Activities. Net cash flows provided by financing activities decreased $85,504,000, or 46 percent, in the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily due to the following:
| · | a decrease in borrowings under our credit facility of $599,650,000 due to restructuring our capitalization; |
| · | an increase in partner distributions of $42,789,000 due to increased distributions per unit and an increase in the number of partner units receiving distributions, no partner distributions paid in the quarter ended March 31, 2006 and a partial partner distribution paid in the quarter ended June 30, 2006 resulting from the timing of our initial public offering; |
| · | an increase in FrontStreet distribution and contributions of $9,695,000 and $13,417,0000, respectively; and |
| · | an increase in proceeds from equity issuances of $40,846,000 due to the issuance in 2007 of 11,500,000 common units for $353,546,000, net of issuance costs, the proceeds of which were used to repay 35 percent or $192,500,000 of our senior notes, to repay our $50,000,000 term loan, and to pay down our revolving credit facility. In 2006 we issued 13,750,000 common units in our initial public offering and 2,857,143 Class C common units for $312,700,000, net of issuance costs. |
Net cash flows provided by financing activities decreased $58,002,000, or 24 percent, for the year ended December 31, 2006 compared to the corresponding period in 2005 primarily due to:
| · | 42,975,000 net borrowings under our credit facility to finance our TexStar acquisition, organic growth projects, working capital requirements and the costs to amend and restate our credit facility; |
| · | $37,144,000 of partner distributions made in 2006 not made in 2005; and |
| · | a decrease in member interest contributions of $68,214,000 as HM Capital Investors infused $72,000,000 into us and TexStar in 2005 for growth capital projects. |
Capital Resources
Description of Our Indebtedness. As of December 31, 2007, our aggregate outstanding indebtedness totaled $481,500,000 and comprised of $124,000,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes, respectively, as compared to our aggregate outstanding indebtedness as of December 31, 2006, which totaled $664,700,000 and comprised of $114,700,000 in borrowings under our revolving credit facility and $550,000,000 of outstanding senior notes.
Credit Ratings. Moody’s Investors Service has assigned a Corporate Family Rating to us of Ba3, a B1 rating for our senior notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- and a B rating for our senior notes.
Fourth Amended and Restated Credit Agreement. We have a $900,000,000 revolving credit facility. The availability for letters of credit is $100,000,000. We have the option to request an additional $250,000,000 in revolving commitments with 10 business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the fourth amended and restated credit agreement, or the credit facility, have been met.
Obligations under the credit facility are secured by substantially all of our assets and are guaranteed, except for those owned by one of our subsidiaries, by the Partnership and each such subsidiary. The revolving loans mature in five years. Interest on revolving loans thereunder will be calculated, at the our option, at either: (a) a base rate plus an applicable margin of 0.50 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 1.50 percent per annum. The weighted average interest rate for the revolving and term loan facilities, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs was 8.78 percent for the year ended December 31, 2007. We must pay (i) a commitment fee equal to 0.30 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 1.50 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.
The credit facility contains financial covenants requiring us to maintain the ratios of debt to consolidated EBITDA and consolidated EBITDA to interest expense within certain threshold ratios. The credit facility restricts the ability of RGS to pay dividends and distributions other than reimbursement of the Partnership for expenses and payment of distributions to the Partnership to the extent of our determination of available cash as defined in our partnership agreement (so long as no default or event of default has occurred or is continuing). The credit facility also contains certain other covenants.
Letters of Credit. At December 31, 2007, we had outstanding letters of credit totaling $27,263,000. The total fees for letters of credit accrue at an annual rate of 1.5 percent, which is applied to the daily amount of letters of credit exposure.
Senior Notes. In 2006, the Partnership and Regency Energy Finance Corp., a wholly owned subsidiary of RGS, issued, in a private placement, $550,000,000 in principal amount of senior notes that mature on December 15, 2013 (“senior notes”). The senior notes bear interest at 8.375 percent and interest is payable semi-annually in arrears on each June 15 and December 15, and are guaranteed by all of our subsidiaries. In August 2007, we redeemed 35 percent, or $192,500,000, of the aggregate principal amount of the senior notes with the net cash proceeds from our July 2007 equity offering and we paid an early redemption penalty of $16,122,000. In September 2007, the Partnership exchanged its then outstanding 8 3/8 percent senior notes which were not registered under the Securities Act of 1933 for senior notes with identical terms that have been so registered
The senior notes and the guarantees are unsecured and rank equally with all of our and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees are senior in right of payment to any of our and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees are effectively subordinated to our and the guarantors’ secured obligations, including our credit facility.
The senior notes are guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”), except Finance Corp and FrontStreet. Information regarding the Partnership’s guarantor and non-guarantors is included in Exhibit 99.4 of this Current Report. These note guarantees are the joint and several obligations of the Guarantors. No guarantor may sell or otherwise dispose of all or substantially all of its properties or assets if such sale would cause a default under the terms of the senior notes. Events of default include nonpayment of principal or interest when due; failure to make a change of control offer; failure to comply with reporting requirements according to SEC rules and regulations; and defaults on the payment of obligations under other mortgages or indentures.
We may redeem the senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100 percent of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date.
Upon a change of control, each holder of senior notes will be entitled to require us to purchase all or a portion of its notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the date of purchase. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.
The senior notes contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain types of transactions with our affiliates; and (vi) sell assets or consolidate or merge with or into other companies. If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants. At December 31, 2007, we were in compliance with these covenants.
Equity Offering. In July 2007, the Partnership sold 10,000,000 common units for $32.05 per unit. After deducting underwriting discounts and commissions of $12,820,000, the Partnership received $307,680,000 from this sale, excluding the general partner’s proportionate capital contribution of $6,279,000 and offering expenses to date of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 common units for $32.05 per unit upon exercise by the underwriters of their option to purchase additional units. The Partnership received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000.
The Partnership used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000). With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership redeemed $192,500,000, or 35 percent of its outstanding senior notes, an event which required the Partnership to pay an early redemption penalty of $16,122,000 in August 2007.
Universal Shelf. We have filed with the SEC a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $1,000,000,000 of equity securities, debt securities or a combination thereof. We have remaining $323,747,000 of availability under this shelf registration, subject to customary marketing terms and conditions.
Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations.
Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2007.
| | | Payments Due by Period | |
| Contractual Cash Obligations | | Total | | | 2008 | | | | 2009-2010 | | | | 2011-2012 | | | Thereafter | |
| | | | | | | | | | (in thousands) | | | | | | | | |
Long-term debt (including interest) (1) | | $ | 693,821 | | | $ | 38,955 | | | $ | 77,910 | | | $ | 189,515 | | | $ | 387,441 | |
| Capital leases | | | 10,093 | | | | 402 | | | | 811 | | | | 870 | | | | 8,010 | |
| Operating leases | | | 1,082 | | | | 505 | | | | 390 | | | | 187 | | | | - | |
| Purchase obligations | | | 8,539 | | | | 8,539 | | | | - | | | | - | | | | - | |
Total (2) (3) | | $ | 713,535 | | | $ | 48,401 | | | $ | 79,111 | | | $ | 190,572 | | | $ | 395,451 | |
(2) 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.
(3) Excludes deferred tax liabilities of $8,642,000 as the amount payable by period cannot be reliably estimated considering the future business plans for the entity that generates the deferred tax liability.
OTHER MATTERS
Legal. The Partnership is involved in various claims and lawsuits incidental to its business. In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on our business, financial condition and results of operations.
Environmental Matters. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including our cost of planning, constructing and operating our plants, pipelines and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with environmental laws and regulations.
We have implemented procedures to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our business, results of operations and financial condition.
Under an omnibus agreement, Regency Acquisition LP, the entity that formerly owned our General Partner, agreed to indemnify us in an aggregate amount not to exceed $8,600,000, generally for three years after February 3, 2006, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before that date.
FrontStreet has a construction and operation agreement (“C&O Agreement”) with a third party, whereby the third party is required to comply with all applicable environmental standards. While FrontStreet would be responsible for any environmental contamination as a result of the operation, remedies are provided to FrontStreet under the C&O Agreement allowing it to recover costs incurred to remediate a contaminated site. Additionally, the C&O Agreement states that FrontStreet is specifically responsible for the removal, remediation, and abatement of Polychlorinated Biphenyls (“Remediation Work”). However, under the terms of the C&O Agreement, FrontStreet can include up to $2,200,000 of expenditures for Remediation Work related to conditions in existence prior to October 1994. FrontStreet has obtained an indemnification against any environmental losses for preexisting conditions prior to the acquisition date from the previous owner. Approximately $750,000 has been escrowed in the event the third party does not agree to include in the cost of service expenditures for Remediation Work. As of December 31, 2007, FrontStreet has not recorded any obligation for Remediation Work. The C&O Agreement shall remain in effect until such time as the FrontStreet gathering agreement terminates or the third party is removed as operator in accordance with terms of the C&O Agreement.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to control contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition, and certain state law analogs to CERCLA, including the Texas Solid Waste Disposal Act, do not contain a similar exclusion for petroleum. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or comparable state laws.
We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal RCRA, and comparable state statutes. From time to time, the EPA has considered the adoption of stricter handling, storage, and disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent management standards. It is possible, however, that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense.
We currently own or lease sites that have been used over the years by prior owners and by us for natural gas gathering, processing and transportation. Solid waste disposal practices within the midstream gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or released on or under various sites during the operating history of those facilities that are now owned or leased by us.
Notwithstanding the possibility that these dispositions may have occurred during the ownership of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
Assets Acquired from El Paso. Under the agreement pursuant to which our operating partnership acquired assets from El Paso Field Services LP and its affiliates in 2003, we are indemnified for certain environmental matters. Those provisions include an indemnity by the El Paso sellers against a variety of environmental claims for a period of five years up to an aggregate of $84,000,000. The agreement also included an escrow of $9,000,000 relating to claims, including environmental claims. In response to our submission of a claim to the El Paso sellers for a variety of environmental defects at these assets, the El Paso sellers have agreed to maintain $5,400,000 in the escrow account to pay any claims for environmental matters ultimately deemed to be covered by their indemnity. This amount represents the upper end of the estimated remediation cost calculated by Regency based on the results of its investigations of these assets.
Since the time of this agreement, a Final Site Investigation Report has been prepared. Based on this additional investigation, environmental issues exist with respect to four facilities, including the two subject to accepted claims and two of our processing plants. The estimated remediation costs associated with the processing plants aggregate $2,750,000. We believe that any of our obligations to remediate the properties is subject to the indemnity under the El Paso PSA, and we intend to reinstate the claims for indemnification for these plant sites.
In January 2008, the Board of Directors of the General Partner and the Partnership signed a settlement of the El Paso environmental remediation. Under the settlement, El Paso will clean up and obtain “no further action” letters from the relevant state agencies for three owned Partnership facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities at that site. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. The Partnership will release all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced per a specified schedule as El Paso completes its cleanups and the remainder will be released upon completion.
West Texas Assets. A Phase I environmental study was performed on our west Texas assets in connection with our investigation of those assets prior to our purchase of them 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. At the time of the negotiation of the agreement to acquire the west Texas assets, management of RGS obtained an insurance policy against specified risks of environmental claims (other than those items known to exist). The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles.
Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are becoming subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. We believe that our operations are in substantial compliance with the federal Clean Air Act and comparable state laws.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into waters of the United States. Pursuant to the Clean Water Act and similar state laws, a NPDES, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. The Clean Water Act and comparable state laws and their respective regulations provide for administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and also provide for penalties and liability for the costs of removing spills from such waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financial condition, or results of operations.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitat. While we have no reason to believe that we operate in any area that is currently designated as a habitat for endangered or threatened species, the discovery of previously unidentified endangered species could cause us to incur additional costs or to become subject to operating restrictions or bans in the affected areas.
Employee Health and Safety. We are subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances.
Safety Regulations. Those pipelines through which we transport mixed NGLs (exclusively to other NGL pipelines) are subject to regulation by the DOT, under the HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA requires any entity that owns or operates liquids pipelines to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to submit certain reports and provide other information as required by the Secretary of Transportation. We believe our liquids pipelines are in substantial compliance with applicable HLPSA requirements.
Our interstate, intrastate and certain of our gathering pipelines are also are subject to regulation by the DOT under the NGPSA, which covers natural gas, crude oil, carbon dioxide, NGLs and petroleum products pipelines, and under the Pipeline Safety Improvement Act of 2002, as amended. Pursuant to these authorities, the DOT has established a series of rules which require pipeline operators to develop and implement “integrity management programs” for natural gas pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Similar rules are also in place for operators of hazardous liquid pipelines. The DOT’s integrity management rules establish requirements relating to the design, installation, testing, construction, operation, inspection, replacement and management of pipeline facilities. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements.
The states administer federal pipeline safety standards under the NGPSA and have the authority to conduct pipeline inspections, to investigate accidents, and to oversee compliance and enforcement, safety programs, and record maintenance and reporting. Congress, the DOT and individual states may pass additional pipeline safety requirements, but such requirements, if adopted, would not be expected to affect us disproportionately relative to other companies in our industry. We believe, based on current information, that any costs that we may incur relating to environmental matters will not adversely affect us. We cannot be certain, however, that identification of presently unidentified conditions, more vigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
TCEQ Notice of Enforcement. On February 15, 2008, the Texas Commission on Environmental Quality, or TCEQ, sent us a notice of enforcement, or NOE, relating to the air emissions at our Tilden processing plant. The NOE relates to 15 alleged violations occurring during the period from March 2006 through July 2007 of the emissions event reporting and recordkeeping requirements of the TCEQs rules. Specifically, it is alleged that one of our subsidiaries failed to report, using the TCEQ’s electronic data base for emissions events, 15 emissions events within 24 hours of the incident, as required. These events occurred during times of failure of the Tilden plant sulphur recovery unit or ancillary equipment and resulted in the flaring of acid gas. Of these events, one relates to an alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide and three related to more than 2,500 and less than 40,000 pounds of sulphur dioxide (including two releases of 126 and 393 pounds of hydrogen sulphide). In 2007, the subsidiary completed construction of an acid gas reinjection unit at the Tilden plant and permanently shut down the Sulphur Recovery Unit.
All these emission incidents were reported by means of fax or telephone to the TCEQ pursuant to an informal procedure established with the TCEQ by the prior owner of the Tilden plant and, indeed, the subsidiary paid the emission fines in connection with all the incidents. Using that procedure, all except one were timely. The TCEQ has, prior to our subsidiary acquiring the Tilden facility, established its electronic data base for emissions events, but the subsidiary did not report using that electronic facility. It is the failure to report each incident timely using the electronic reporting procedure that is the subject of the NOE. Representatives of the Partnership are scheduled to meet with the staff of the TCEQ in the near future regarding the NOE. Management of the General Partner does not expect the NOE to have a material adverse effect on its results of operations or financial condition.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Conformity with GAAP 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 gas and liquids 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. We estimate 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. We calculate estimated revenues using actual pricing and measured 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 price 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 three 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 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. We recorded realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. 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 outstanding hedges, excluding crude oil put options, qualified for hedge accounting. Accordingly, we recorded the unrealized changes in fair value in other comprehensive income (loss) to the extent the hedge are effective. Effective June 19, 2007, we elected to account for our entire outstanding commodity hedging instruments on a mark-to-market basis except for the portion of commodity hedging instruments where all NGLs products for a particular year were hedged and the hedging relationship was effective. As a result, a portion of our commodity hedging instruments is and will continue to be accounted for using mark-to-market accounting until all NGLs products are hedged for an individual year and the hedging relationship is deemed effective.
Purchase Method of Accounting. We make various assumptions in determining the fair values of acquired assets and liabilities. In order to allocate the purchase price to the business units, we develop fair value models with the assistance of outside consultants. These fair value models apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. An economic value is determined for each business unit. We then determine the fair value of the fixed assets based on estimates of replacement costs. Intangible assets acquired consist primarily of licenses, permits and customer contracts. We make assumptions regarding the period of time it would take to replace these licenses and permits. We assign value using a lost profits model over that period of time necessary to replace the licenses and permits. We value the customer contracts using a discounted cash flow model. We determine liabilities assumed based on their expected future cash outflows. We record goodwill as the excess of the cost of each business unit over the sum of amounts assigned to the tangible assets and separately recognized intangible assets acquired less liabilities assumed of the business unit.
Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipelines. 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 and is expensed over the life of the constructed asset through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.
We generally compute depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we review depreciation estimates 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.
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Determining whether an impairment has occurred typically requires various estimates and assumptions, including determining which undiscounted cash flows are directly related to the potentially impaired asset, the useful life over which cash flows will occur, their amount, and the asset’s residual value, if any. In turn, measurement of an impairment loss requires a determination of fair value, which is based on the best information available. We derive the required undiscounted cash flow estimates from our historical experience and our internal business plans. To determine fair value, we use our internal cash flow estimates discounted at an appropriate interest rate, quoted market prices when available and independent appraisals, as appropriate.
Equity Based Compensation. Awards under our LTIP have been made prior to the GE EFS Acquisition generally vested over a three year period on the basis of one-third of the award each year. Options have a maximum contractual term, expiring ten years after the grant date. Options granted were valued using the Black-Scholes option pricing model, using assumptions of volatility in the unit price, a ten year term, a strike price equal to the grant-date price per unit, a distribution per unit at the time of grant, a risk-free rate, and an average exercise of the options of four years after vesting is complete. We have based the assumption that option exercises, on average, will be four years from the vesting date on the average of the mid-points from vesting to expiration of the options. There have been no option awards made subsequent to the GE EFS Acquisition.
RECENT ACCOUNTING PRONOUNCEMENTS
See discussion of new accounting pronouncements in Note 2 in the Notes to the Consolidated Financial Statements included in Exhibit 99.4.
