Exhibit 99.2
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 and Oklahoma.
OUR OPERATIONS. We divide our operations into three principal business segments:
| | • | | Gathering and Processing: We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; |
| | • | | Transportation: We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system. The Partnership, GE EFS and Alinda formed a joint venture to finance and construct the Partnership’s previously announced Haynesville Expansion Project. This project will more than double the capacity of RIGS in north Louisiana to bring natural gas from the Haynesville Shale, one of the most active new natural gas plays in the United States. The Partnership has secured commitments from shippers for 925 MMcf/d, which is more than 84 percent of the capacity of the Haynesville Expansion Project, and is in negotiations for the remaining capacity. The agreements are for firm transportation capacity under 10-year contract terms; and |
| | • | | Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 762,000 horsepower of compression in Texas, Louisiana, and Arkansas. In addition, our contract compression segment operates approximately 196,000 horsepower of compression for our gathering and processing and transportation segments. |
| | • | | Corporate and Others: We own and operate an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. This pipeline has a FERC certificated capacity of 150MMcf/d. |
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 and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline in commodity prices, however, could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. |
| | • | | Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we |
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| | retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component). |
| | • | | 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) 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, (2) fixed cash fees for ancillary services, such as gathering, treating, and compression, (3) the ability to bypass processing in unfavorable price environments or (4) “conditioning floor” fees that apply in adverse 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. For example, 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, natural gas, and natural gasoline market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
In addition, we perform a producer services function on our Regency Intrastate Pipeline system. This 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.
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.
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. 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. |
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| | • | | 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.
The Partnership, GECC and the Alinda Investors formed a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas from the Haynesville Shale, one of the fastest growing natural gas plays in the United States. In connection with the joint venture, we will contribute all of our ownership interests in RIGS, valued at $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. GECC and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.
We will serve as the operator of the joint venture, and will provide all employees and services for the operation and management of the joint venture’s assets. We expect to close the joint venture transaction as promptly as practicable following the satisfaction of the closing conditions, but no later than April 30, 2009.
Contract compression segment.We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 778,000 horsepower of compression for third party producers in Texas, Louisiana, and Arkansas. In addition, our contract compression segment operates approximately 196,000 horsepower of compression for our gathering and processing and transportation segments.
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, total 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
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obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) 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 also 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.
Prior to our contribution of our Regency Intrastate Gas System to HPC, we calculated 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.
After our contribution of RIGS to HPC, we will not record segment margin for the transportation segment because the income attributable to HPC will be recorded as income from unconsolidated subsidiary. The income from unconsolidated subsidiary will be shown separately on the key segment performance indicators table.
We calculate our contract compression segment margin as our revenues generated from our contract compression operations minus the direct costs, primarily compressor unit repairs, associated with those revenues.
Total Segment Margin. Segment margin from gathering and processing, transportation, and contract compression segments comprise total segment margin. We use total segment margin as a measure of performance. See “Exhibit 99.1. 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 attributable to Regency Energy Partners LP 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 unitholders 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. |
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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—Selected Financial Data” 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.
Even though overall drilling activity is forecasted to decline, drilling in the Haynesville Shale formation is expected to increase. According to Energy Intelligence (www.energyintel.com), the number of horizontal rigs at work in Haynesville has increased by 6 percent since October 2008. According to the report, several companies are shifting resources from the more developed Barnett Shale formation to the Haynesville Shale formation. The increased level of drilling activity is attributed to its resource potential and the producers’ obligation to drill to maintain the terms of their recently leased acreage.
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 significantly 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.
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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 depreciation, 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, indirect subsidiaries 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 and 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. The Partnership was not required to record any adjustments to reflect the acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions.
Acquisition of FrontStreet. On January 7, 2008, we acquired all of the outstanding equity and noncontrolling interest (the “FrontStreet Acquisition”) of FrontStreet from ASC and EnergyOne. The total purchase price consisted of (a) 4,701,034 Class E common units of the Partnership issued to ASC in exchange for its 95 percent interest and (b) $11,752,000 in cash to EnergyOne in exchange for its five percent noncontrolling interest and the termination of a management services contract valued at $3,888,000. We financed the cash portion of the purchase price with borrowings under our revolving credit facility.
Because the acquisition of ASC’s 95 percent interest is a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method.
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Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of the five percent noncontrolling interest is a transaction between independent parties, for which we applied the purchase method of accounting.
Acquisition of CDM. On January 15, 2008, we and an indirect wholly owned subsidiary consummated an agreement and plan of merger with CDM Resource Management, Ltd. The total purchase price consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations. The results of operations of CDM are included in our statements of operations beginning January 16, 2008.
Acquisition of Nexus. On March 25, 2008, we acquired Nexus by merger for $88,640,000 in cash, including customary closing adjustments. The results of operations of Nexus are included in our statements of operations beginning March 26, 2008.
RESULTS OF OPERATIONS
Year Ended December 31, 2008 vs. Year Ended December 31, 2007
The table below contains key company-wide performance indicators related to our discussion of the results of operations.
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| | | Year Ended December 31, | | | | | | | |
| | | 2008 | | | 2007 | | | Change | | | Percent | |
| | | (in thousands) | | | | |
Total revenues | | $ | 1,863,804 | | | $ | 1,190,238 | | | $ | 673,566 | | | 57 | % |
Cost of sales | | | 1,408,333 | | | | 976,145 | | | | 432,188 | | | 44 | |
| | | | | | | | | | | | | | | |
Total segment margin(1) | | | 455,471 | | | | 214,093 | | | | 241,378 | | | 113 | |
Operation and maintenance | | | 131,629 | | | | 58,000 | | | | 73,629 | | | 127 | |
General and administrative | | | 51,323 | | | | 39,713 | | | | 11,610 | | | 29 | |
Loss on asset sales, net | | | 472 | | | | 1,522 | | | | (1,050 | ) | | 69 | |
Management services termination fee | | | 3,888 | | | | — | | | | 3,888 | | | n/m | |
Transaction expenses | | | 1,620 | | | | 420 | | | | 1,200 | | | 286 | |
Depreciation and amortization | | | 102,566 | | | | 55,074 | | | | 47,492 | | | 86 | |
| | | | | | | | | | | | | | | |
Operating income | | | 163,973 | | | | 59,364 | | | | 104,609 | | | 176 | |
Interest expense, net | | | (63,243 | ) | | | (52,016 | ) | | | (11,227 | ) | | 22 | |
Loss on debt refinancing | | | — | | | | (21,200 | ) | | | 21,200 | | | n/m | |
Other income and deductions, net | | | 332 | | | | 1,252 | | | | (920 | ) | | 73 | |
| | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | 101,062 | | | | (12,600 | ) | | | 113,662 | | | 902 | |
Income tax expense (benefit) | | | (266 | ) | | | 931 | | | | (1,197 | ) | | 129 | |
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Net income (loss) | | | 101,328 | | | | (13,531 | ) | | | 114,859 | | | 849 | |
Net income attributable to noncontrolling interest | | | (312 | ) | | | (305 | ) | | | 7 | | | 2 | |
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Net income (loss) attributable to Regency Energy Partners LP | | $ | 101,016 | | | $ | (13,836 | ) | | $ | 114,852 | | | 830 | |
| | | | | | | | | | | | | | | |
System inlet volumes (MMBtu/d)(2) | | | 1,522,431 | | | | 1,225,918 | | | | 296,513 | | | 24 | % |
| (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.” |
| (2) | System inlet volumes include total volumes taken into our gathering and processing and transportation systems. |
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The table below contains key segment performance indicators related to our discussion of our results of operations.
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| | | Year Ended December 31, | | | | | | |
| | | 2008 | | 2007 | | Change | | | Percent | |
| | | (in thousands) | | | | |
Gathering and Processing Segment | | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | | |
Segment margin(1) | | $ | 266,839 | | $ | 160,515 | | $ | 106,324 | | | 66 | % |
Operation and maintenance(2) | | | 82,689 | | | 53,496 | | | 29,193 | | | 55 | |
Operating data: | | | | | | | | | | | | | |
Throughput (MMBtu/d)(3) | | | 1,025,779 | | | 772,930 | | | 252,849 | | | 33 | |
NGL gross production (Bbls/d) | | | 22,390 | | | 21,808 | | | 582 | | | 3 | |
| | | | |
Transportation Segment | | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | | |
Segment margin(1) | | $ | 66,888 | | $ | 52,548 | | $ | 14,340 | | | 27 | % |
Operation and maintenance(2) | | | 3,540 | | | 4,407 | | | (867 | ) | | 20 | |
Operating data: | | | | | | | | | | | | | |
Throughput (MMBtu/d)(3) | | | 770,939 | | | 751,761 | | | 19,178 | | | 3 | |
| | | | |
Contract Compression | | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | | |
Segment margin(1) | | $ | 125,503 | | $ | — | | | N/A | | | N/A | |
Operation and maintenance(2) | | | 49,799 | | | — | | | N/A | | | N/A | |
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Corporate and Others | | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | | |
Segment margin | | $ | 814 | | $ | 1,030 | | $ | (216 | ) | | 21 | % |
Operation and maintenance | | | 74 | | | 97 | | | (23 | ) | | 24 | |
| (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.” |
| (2) | Combined operation and maintenance expense for our segments differs from consolidated operation and maintenance expense due to inter-segment eliminations. |
| (3) | Combined throughput volumes for the gathering and processing and transportation segment vary from consolidated system inlet volumes due to inter-segment eliminations. |
| N/A | Not applicable as we acquired these assets in January 2008. |
Net Income Attributable to Regency Energy Partners LP.Net income attributable to Regency Energy Partners LP for the year ended December 31, 2008 increased $114,852,000 or 830 percent, compared with the year ended December 31, 2007. The increase in net income attributable to the Partnership was primarily attributable to an increase in total segment margin of $241,378,000 and the absence in the current period of a $21,200,000 loss on debt refinancing related to the termination penalty associated with the redemption of 35 percent of our senior notes. The increase in total segment margin was primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth in the gathering and processing segment. We were required to use the as-if pooling method of accounting described in SFAS No. 141, “Business Combinations” for our FrontStreet acquisition because it involved entities under common control. Common control began on June 18, 2007; therefore the discussion below includes activity from FrontStreet from June 18, 2007 forward even though the acquisition occurred in January 2008. Partially offsetting these increases in net income attributable to the Partnership were:
| | • | | an increase in operation and maintenance expense of $73,629,000 primarily due to our contract compression and FrontStreet assets acquired in January 2008 and increases in organic growth-related maintenance and employee-related expenses mainly in the gathering and processing segment; |
| | • | | an increase in depreciation and amortization expense of $47,492,000 primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth projects primarily in the gathering and processing segment; |
| | • | | an increase in general and administrative expenses of $11,610,000 primarily due to our contract compression assets acquired in January 2008 and increased employee-related expenses, reduced by the |
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| | absence of an $11,928,000 expense associated with the vesting of all outstanding LTIP grants incurred in 2007 when GE EFS acquired our general partner; |
| | • | | an increase in interest expense of $11,227,000 primarily due to increased levels of borrowings; and |
| | • | | a payment of a management contract services termination fee of $3,888,000 in 2008 related to the acquisition of FrontStreet. |
Segment Margin. Total segment margin for the year ended December 31, 2008 increased $241,378,000 compared with the year ended December 31, 2007. This increase was attributable to an increase of $106,324,000 in gathering and processing segment margin, an increase of $14,340,000 in transportation segment margin, a decrease of $216,000 in corporate and others, and the addition of $125,503,000 in contract compression segment margin, discussed below. Combined segment margin for our segments differs from consolidated total segment margin due to inter-segment eliminations of $4,573,000.
Gathering and processing segment margin increased to $266,839,000 for the year ended December 31, 2008 from $160,515,000 for the year ended December 31, 2007. The major components of this increase were as follows:
| | • | | $29,657,000 from non-cash changes in the value of certain risk management contracts related to our hedging programs; |
| | • | | $25,274,000 from a full year’s operation of our FrontStreet assets which were consolidated on June 18, 2007; |
| | • | | $19,200,000 from increased throughput and organic growth in south Texas; |
| | • | | $11,770,000 from increased throughput and organic growth in north Louisiana; |
| | • | | $9,548,000 from increased sulfur prices; |
| | • | | $7,589,000 from the operations of our Nexus assets; and |
| | • | | $4,705,000 in increased margins associated with our producer services function. |
Transportation segment margin increased to $66,888,000 for the year ended December 31, 2008 from $52,548,000 for the year ended December 31, 2007. The major components of this increase were as follows:
| | • | | $12,440,000 from increased operational efficiencies coupled with increased commodity prices; and |
| | • | | $1,684,000 from increased throughput volumes and changes in contract mix. |
Contract compression segment margin was $125,503,000 in the year ended December 31, 2008, which consisted of $137,122,000 of operating revenue and $11,619,000 of direct operating cost.
Operation and Maintenance. Operations and maintenance expense increased to $131,629,000 in the year ended December 31, 2008 from $58,000,000 for the corresponding period in 2007, a 127 percent increase. This increase is primarily the result of the following factors:
| | • | | $45,326,000 related to our contract compression assets acquired in January 2008, net of intercompany eliminations; |
| | • | | $14,972,000 related to our FrontStreet assets, which are operated by a third party; |
| | • | | $8,864,000 related primarily to the gathering and processing segment associated with organic growth projects since December 31, 2007 involving compressor and other maintenance expenses in 2008; |
| | • | | $2,726,000 increase in employee-related expenses primarily related to increases in annual salaries, bonus accrual and employer benefit payments mostly in the gathering and processing segment; |
| | • | | $1,316,000 increase in utility expense due to higher commodity prices primarily in the gathering and processing segment; |
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| | • | | $1,227,000 increase in contractor expense in the transportation segment due to compressor maintenance; and |
| | • | | partially offset by a $1,393,000 increase in insurance proceeds received in August 2008 ($3,134,000) versus November 2007 ($1,741,000) related to a March 2007 compressor fire in the transportation segment. |
General and Administrative. General and administrative expense increased to $51,323,000 in the year ended December 31, 2008 from $39,713,000 for the same period in 2007, a 29 percent increase. In June 2007, the Partnership incurred a one-time charge of $11,928,000 associated with the vesting of all outstanding common unit options upon a change in control of our general partner. Absent this expense, general and administrative expenses increased by $23,538,000 primarily due to:
| | • | | $16,224,000 related to our contract compression assets acquired in January 2008; |
| | • | | $5,788,000 increase in employee-related expenses primarily due to hiring of new employees, employer benefit payments and bonus accruals; and |
| | • | | $958,000 increase in legal expenses. |
Management Services Termination Fee. In 2008, we recorded $3,888,000 for the termination of a long-term management services contract associated with our FrontStreet acquisition.
Depreciation and Amortization. Depreciation and amortization expense increased to $102,566,000 in the year ended December 31, 2008 from $55,074,000 for the year ended December 31, 2007, an 86 percent increase. The increase was primarily due to:
| | • | | $28,448,000 related to our contract compression assets acquired in January 2008; |
| | • | | $8,440,000 related to our FrontStreet assets which for the year ended December 31, 2008 are being depreciated over a shorter useful life as compared to 2007 and the year ended December 31, 2008 includes a full year where as the year ended December 31, 2007 only included six months of depreciation; |
| | • | | $7,428,000 related to various organic growth projects completed since December 31, 2007, primarily in the gathering and processing segment; and |
| | • | | $3,176,000 related to our Nexus assets acquired in March 2008. |
Interest Expense, Net. Interest expense, net increased $11,227,000, or 22 percent, in the year ended December 31, 2008 compared to the same period in 2007. Of this increase, $26,266,000 was attributable to increased levels of borrowings partially offset by $15,039,000 primarily attributable to lower interest rates.
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.
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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) | | | | |
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 | ) | | n/m | |
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 | | | (12,600 | ) | | | (7,244 | ) | | | (5,356 | ) | | 74 | |
Income tax expense | | | 931 | | | | — | | | | 931 | | | n/m | |
| | | | | | | | | | | | | | | |
Net loss | | | (13,531 | ) | | | (7,244 | ) | | | (6,287 | ) | | 87 | |
Net income attributable to noncontrolling interest | | | (305 | ) | | | — | | | | 305 | | | n/m | |
| | | | | | | | | | | | | | | |
Net loss attributable to Regency Energy Partners LP | | $ | (13,836 | ) | | $ | (7,244 | ) | | $ | (6,592 | ) | | 91 | |
| | | | | | | | | | | | | | | |
System inlet volumes (MMBtu/d)(3) | | | 1,225,918 | | | | 1,010,642 | | | | 215,276 | | | 21 | % |
| (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.” |
| (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. |
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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) | | | |
Gathering and Processing Segment | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | |
Segment margin(1) | | $ | 160,515 | | $ | 114,903 | | $ | 45,612 | | 40 | % |
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) | | $ | 52,548 | | $ | 40,788 | | $ | 11,760 | | 29 | % |
Operation and maintenance | | | 4,407 | | | 4,415 | | | 8 | | — | |
Operating data: | | | | | | | | | | | | |
Throughput (MMBtu/d) | | | 751,761 | | | 587,098 | | | 164,663 | | 28 | |
| | | | |
Corporate and Others | | | | | | | | | | | | |
Financial data: | | | | | | | | | | | | |
Segment margin | | $ | 1,030 | | $ | 728 | | $ | 302 | | 41 | % |
Operation and maintenance | | | 97 | | | 73 | | | 24 | | 33 | |
| (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.” |
Net Loss Attributable to Regency Energy Partners LP. Net loss attributable to Regency Energy Partners LP 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 $45,612,000 in gathering and processing segment margin and an increase of $11,760,000 in transportation segment margin as discussed below.
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Gathering and processing segment margin increased to $160,515,000 for the year ended December 31, 2007 from $114,903,000 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; |
| | • | | $1,752,000 of increased margins related to our producer services function; and offset by |
| | • | | $17,449,000 of non-cash losses from certain risk management activities. |
Transportation segment margin increased to $52,548,000 for the year ended December 31, 2007 from $40,788,000 for the year ended December 31, 2006. The major components of this increase were as follows:
| | • | | $11,512,000 attributable to increased throughput volumes; |
| | • | | $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; |
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| | • | | $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.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We expect our sources of liquidity to include:
| | • | | cash generated from operations; |
| | • | | borrowings under our credit facility; |
| | • | | operating lease facilities; |
| | • | | issuance of additional partnership units. |
We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, particularly as a result of our Haynesville Expansion Project. At December 31, 2008, the Partnership has purchase obligations totaling approximately $323,341,000, of which $104,852,000 is related to the purchase of major compression components unrelated to the Haynesville Expansion Project, that extend until the year ending December 31, 2010 and $218,489,000 of which is related to the Haynesville Expansion Project that extend until the year ending December 31, 2009. Some of these commitments have cancellation provisions.
The Partnership, GECC and the Alinda Investors entered into a definitive agreement to form a joint venture to finance and construct our previously announced Haynesville Expansion Project. The project will transport gas
14
from the Haynesville Shale, one of the fastest growing natural gas plays in the United States. In connection with the joint venture, we will contribute all of our ownership interests in RIGS, valued at $400,000,000, in exchange for a 38 percent general partnership interest in the joint venture and a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments. The GE Investor and the Alinda Investors have agreed to contribute $126,500,000 and $526,500,000 in cash, respectively, in return for a 12 percent and a 50 percent general partnership interest in the joint venture, respectively.
In the future, the management committee of the joint venture may request that we make additional capital contributions to support the joint venture’s capital expenditures. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations. In addition, we have agreed to reimburse the joint venture for the first $20,000,000 of cost overruns relating to the Haynesville Expansion Project.
The Partnership has secured commitments from shippers for 925 MMcf/d, which is more than 84 percent of the capacity of the Haynesville Expansion Project, and is in negotiations for the remaining capacity. The agreements are for firm transportation capacity under 10-year contract terms.
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding. The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. We expect that our ability to issue debt and equity at prices that are similar to offerings in recent years will be limited as long as capital markets remain constrained. Our planned internal growth projects continue to require us to bear the cost of constructing these new assets before we begin to realize a return on them. As a result, we will continue to be opportunistic in our approach to funding the remaining expenditures from additional issuances of our equity and long-term debt.
Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. For example, as a result of Lehman filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a subsidiary of Lehman that is a committed lender under our credit facility has declined requests to honor its commitment to lend under our credit facility. The total amount available to us under our credit facility as of February 20, 2009 was $42,410,000, which has been reduced by the amount of Lehman’s commitment of $5,578,000 that is no longer available to us. If we repay any of the amounts we have already borrowed from Lehman, we may not be able to reborrow such amounts. We may be unable to utilize the full borrowing capacity under our credit facility if other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that Lehman’s subsidiary has refused to fund or if any of the remaining committed lenders are unable or unwilling to fund their respective portion of any funding request we make under our credit facility.
In addition, we have entered into a $75,000,000 operating lease facility with Caterpillar Financial Services Corporation and a $45,000,000 revolving credit facility with GECC as further described below.
We expect to reduce our growth capital expenditures in 2009 and 2010, from approximately $300,000,000 per year to approximately $120,000,000 in 2009 and $100,000,000 in 2010. As a result of our reduced capital expenditure plans, our need to access the debt and equity markets will be significantly reduced.
Although we intend to move forward with our planned internal growth projects, we may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our expansion activities may be muted by substantial cost of capital increases during this period. As a result of these costs our cash flows may decrease, which could impair our liquidity position and require us to reduce our distributions to unitholders.
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Finally, if there is a significant lessening in demand for our services as a result of extended declines in the actual and longer term expected price of oil and gas, we may see a further reduction in our own capital expenditures and lesser requirements for working capital, both of which could generate operating cash flow and liquidity compared to the prior period and offset reduced cash generated from operations excluding working capital changes. However, such an environment might also increase the availability of acquisitions which could draw on such liquidity.
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. When we incur growth capital expenditures, we experience working capital deficits as 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 12 months, and so must be viewed differently from trade accounts receivable and accounts payable which settle over a much shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect risk management assets and liabilities to affect our ability to pay bills as they come due. Our contract compression segment records deferred revenues, a current liability. The deferred revenues represent billings in advance of services performed. As the revenues associated with the deferred revenues are earned, the liability is reduced.
Our working capital surplus at December 31, 2008 was $19,453,000 as compared to a working capital deficit of $18,365,000 at December 31, 2007, a $37,818,000 increase primarily due to the following factors:
| | • | | a $69,154,000 increase in working capital due to the value of risk management activities shifting from current liabilities to current assets resulting from a decrease in commodity prices we expect to pay (index prices) on our outstanding swaps versus the fixed commodity prices we expect to receive upon settlement; |
| | • | | $7,170,000 increase in working capital resulting from an increase in net account receivable and payable due to the timing of cash receipts and payments; |
| | • | | a $6,615,000 increase in working capital resulting from an increase in other current assets primarily due to an increase in insurance and other pre-paid expenses of $3,887,000, equipment inventory of $1,567,000, and NGL inventory of $1,041,000; and |
Partially offsetting these increases in working capital were the following factors:
| | • | | a decrease in cash and cash equivalents of $32,372,000 due to the timing of cash receipts and payments associated with ongoing business operations; and |
| | • | | an increase in other current liabilities of $12,749,000 primarily related to an increase in deferred revenues associated with business operations of our contract compression segment. |
Cash Flows from Operating Activities.Net cash flows provided by operating activities increased $101,769,000, or 128 percent, for the year ended December 31, 2008 as compared to the year ended December 31, 2007. Cash generated from operations increased primarily due to increased total segment margin of $241,378,000, primarily due to operating activity of our contract compression, FrontStreet and Nexus assets acquired in the first calendar quarter of 2008 and organic growth in the gathering and processing segment.
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 on June 18, 2007.
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
16
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, 2008 and 2007 were $809,000,000 and $178,930,000, respectively.
Cash Flows from Investing Activities. Net cash flows used in investing activities increased $790,696,000 or 501 percent, in the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase is primarily due to organic growth in the gathering and processing segment and cash consideration paid for the contract compression, FrontStreet, and Nexus assets in the first calendar quarter of 2008.
Growth Capital Expenditures. In the year ended December 31, 2008, we incurred $354,727,000 of growth capital expenditures. Growth capital expenditures for the year ended December 31, 2008 primarily relate to the following projects:
| | • | | $176,740,000 for the fabrication of new compression packages and ancillary assets for our contract compression segment; |
| | • | | $123,383,000 for various projects in the gathering and processing segment, primarily in Louisiana and Texas; and |
| | • | | $54,604,000 in our transportation segment for the Haynesville Expansion Project. |
Maintenance Capital Expenditures. In the year ended December 31, 2008, we incurred $18,247,000 of maintenance capital expenditures. Maintenance capital expenditures primarily consist of compressor and plant overhauls, as well as replacement or repair of equipment.
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 $12,639,000, partially offset by our 2007 Pueblo acquisition ($34,855,000).
Cash Flows from Financing Activities. Net cash flows provided by financing activities increased $635,516,000, or 639 percent, in the year ended December 31, 2008 compared to the year ended December 31, 2007 primarily due to the following:
| | • | | an increase in net borrowings under our revolving credit facility of $585,429,000 due to increased borrowings associated with organic growth primarily in the gathering and processing segment and our contract compression, FrontStreet, and Nexus acquisitions; |
| | • | | the absence in 2008 of the 35 percent redemption of our senior notes in 2007 of $192,500,000; and partially offset by |
| | • | | a decrease in proceeds from equity issuances of $154,231,000. |
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; |
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| | • | | 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; and |
| | • | | an increase in FrontStreet and contribution of $9,695,000 and $13,417,000 respectively. |
Capital Resources
Description of Our Indebtedness. As of December 31, 2008, our aggregate outstanding indebtedness totaled $1,126,229,000 and consisted of $768,729,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes as compared to our aggregate outstanding indebtedness as of December 31, 2007, which totaled $481,500,000 and consisted of $124,000,000 in borrowings under our revolving credit facility and $357,500,000 of outstanding senior notes.
Credit Ratings. Our credit ratings as of December 31, 2008 are provided below.
| | | | |
| | | Moody’s | | Standard & Poor’s |
| | |
Regency Energy Partners LP | | | | |
Corporate rating/total debt | | Ba3 | | BB- |
Senior notes | | B1 | | B |
Outlook | | Negative Outlook | | Negative Outlook |
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 or term loan 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 by the Partnership and each of its subsidiaries with the exception of Finance Corp, which is a co-issuer of the Senior Notes and has no operations. The revolving loans mature at the maturity of the credit facility in August 2011. Interest on revolving loans thereunder will be calculated, at our option, at either: (a) a base rate that is the greater of (i) a base rate plus the applicable margin and (ii) a federal funds effective rate plus 0.50 percent plus the applicable margin, or (b) an adjusted LIBOR rate plus the applicable margin. The applicable margin that is used in calculating interest shall range from 0.50 percent to 1.25 percent for base rate loans and from 1.50 percent to 2.25 percent for Eurodollar loans. 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 6.27 percent for the year ended December 31, 2008. We must pay (i) a commitment fee ranging from 0.300 percent to 0.500 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.
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Credit Agreement Amendment. On March 17, 2009, RGS closed on Amendment No. 7 to its Credit Agreement (the “Amendment”). The Amendment authorized the contribution of RIGS to a joint venture (HPC) and allowed for future investment up to $135,000,000 in the joint venture. The amendment imposed additional financial restrictions that limit the ratio of senior secured indebtedness to EBITDA. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent. The applicable margin shall range from 1.50 percent to 2.25 percent for base rate loans, 2.50 percent to 3.25 percent for Eurodollar loans and commitment fees will range from 0.375 percent to 0.500 percent.
Revolving Credit Facility. On February 26, 2009, we entered into a $45,000,000 unsecured revolving credit agreement with GECC, as administrative agent, the lenders party thereto and the guarantors party thereto (the “Revolving Credit Facility”). The commitments under the Revolving Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC for this GECC Credit Facility.
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Letters of Credit. At December 31, 2008, we had outstanding letters of credit totaling $16,257,000. 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 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. 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 initially guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”), except certain wholly owned subsidiaries. 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, 2008, we were in compliance with these covenants.
Equity Offering. On August 1, 2008, the Partnership sold 9,020,000 common units for an average price of $22.18 per unit. The Partnership received $204,133,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution of $4,082,653. As of December 31, 2008 the Partnership has incurred $34,000 in costs related this equity offering. An affiliate of GECC purchased 2,272,727 of these common units. The Partnership used the proceeds from its equity offering to repay a portion of its credit facility.
Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations as of December 31, 2008.
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Operating Lease Facility. CDM entered into an operating lease facility with Caterpillar Financial Services Corporation whereby CDM has the ability to lease compression equipment with an aggregate value of up to $75,000,000. The facility is available for leases with inception dates up to and including December 31, 2009, and mitigates the need to use available capacity under the existing Credit Facility. Each compressor acquired under this facility shall have a lease term of one hundred twenty (120) months with a fair value buyout option at the end of the lease term. At the end of the lease term, CDM shall also have an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fair market rate at that time. In the event CDM elects not to exercise the buyout option, the equipment must be returned in a manner fit for use at the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions exist at month sixty (60) and at month eighty four (84) of the one hundred twenty (120) month lease term. Covenants under the lease facility require CDM to maintain certain fleet utilization levels as of the end of each calendar quarter as well as a total debt to EBITDAR (Earnings Before Interest, Taxes, Depreciation, Amortization, and Rental expense) ratio of less than or equal to 4:1. In addition, covenants restrict the concentration of revenues derived from the equipment acquired under the lease facility. The terms of the lease facility do not include contingent rentals or escalation clauses.
Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2008.
| | | | | | | | | | | | | | | |
| | | Payment Due by Period |
| | | Total | | 2009 | | 2010-2011 | | 2012-2013 | | Thereafter |
| | | (in thousands) |
Long-term debt (including interest)(1) | | $ | 1,217,870 | | $ | 53,433 | | $ | 747,056 | | $ | 417,381 | | $ | — |
Capital leases | | | 10,099 | | | 612 | | | 1,015 | | | 910 | | | 7,562 |
Operating leases | | | 15,925 | | | 2,357 | | | 4,874 | | | 3,188 | | | 5,506 |
Purchase obligations | | | 323,341 | | | 320,321 | | | 3,020 | | | — | | | — |
| | | | | | | | | | | | | | | |
Total(2)(3) | | $ | 1,567,235 | | $ | 376,723 | | $ | 755,965 | | $ | 421,479 | | $ | 13,068 |
| | | | | | | | | | | | | | | |
| (1) | Assumes a constant LIBOR interest rate of 2.0 plus applicable margin (1.5 percent as of December 31, 2008) for our revolving credit facility. The principal of our outstanding senior notes ($357,500,000) bears a fixed rate of 8 3/8 percent. |
| (2) | Excludes physical and financial purchases of natural gas, NGLs, and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily and 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 $8,156,000 as the amount payable by period can not be readily estimated in light of 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. 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. For information regarding environmental matters, please read “Item 1 Business—Regulation—Environmental Matters.”
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.
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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.
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.
Goodwill Valuation.The Partnership reviews the carrying value of goodwill on a regular basis, including December 31 of each year, for indicators of impairment at each reporting unit that has recorded goodwill. The Partnership determines its reporting units based on identifiable cash flows of the components of a segment and how segment managers evaluate the results of operations of the entity. Impairment is indicated whenever the carrying value of a reporting unit exceeds the estimated fair value of a reporting unit. For purposes of evaluating impairment of goodwill, the Partnership estimates the fair value of a reporting unit based upon future net discounted cash flows. In calculating these estimates, historical operating results and anticipated future economic factors, such as estimated volumes and demand for compression services, commodity prices, and operating costs are considered as a component of the calculation of future discounted cash flows. The estimates of fair value of these reporting units could change if actual volumes, prices, costs or expenses vary from these estimates.
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Based on the Partnership’s annual impairment testing on December 31, 2008, no impairment was identified. If current credit issues and market volatility continue to deteriorate, the Partnership’s goodwill could be impaired and have a material impact on future earnings of the Partnership.
Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, transmission pipelines, and natural gas compression equipment. 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. 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.
As-if Pooling of Interest Method of Accounting. We account for acquisitions where common control exists by following the as-if pooling method of accounting as described in SFAS No. 141, “Business Combinations.” Under this method of accounting, we reflect the historical balance sheet data for both the acquirer and acquiree instead of reflecting the fair market value of acquiree’s assets and liabilities. In common control acquisitions where a minority interest is also acquired, we use the purchase method of accounting for the noncontrolling interest. Further, certain transaction costs that would normally be capitalized are expensed.
Fair Value Measurements. On January 1, 2008, we adopted the provisions of SFAS No. 157 for financial assets and liabilities. SFAS No. 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations. SFAS No. 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:
| | • | | Level 1—unadjusted quoted prices for identical assets or liabilities in active markets accessible by us; |
| | • | | Level 2—inputs that are observable in the marketplace other than those inputs classified as Level 1; and |
| | • | | Level 3—inputs that are unobservable in the marketplace and significant to the valuation. |
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SFAS No. 157 encourages us to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument valuation uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation. Our financial assets and liabilities measured at fair value on a recurring basis are derivative financial instruments consisting of interest rate swaps and commodity swaps.
The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities related to interest rate and commodity swaps. Risk management assets and liabilities are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. The Partnership has no financial assets and liabilities as of December 31, 2008 valued based on inputs classified as Level 3 in the hierarchy.
RECENT ACCOUNTING PRONOUNCEMENTS
See discussion of new accounting pronouncements in Note 2 in the Notes to the Consolidated Financial Statements.
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